Federal Register, Volume 80 Issue 58 (Thursday, March 26, 2015)

[Federal Register Volume 80, Number 58 (Thursday, March 26, 2015)]
[Rules and Regulations]
[Pages 16128-16222]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-06658]

[[Page 16127]]

Vol. 80

Thursday,

No. 58

March 26, 2015

Part III

Department of the Interior

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Bureau of Land Management

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43 CFR Part 3160

Oil and Gas; Hydraulic Fracturing on Federal and Indian Lands; Final
Rule

Federal Register / Vol. 80 , No. 58 / Thursday, March 26, 2015 /
Rules and Regulations

[[Page 16128]]

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DEPARTMENT OF THE INTERIOR

Bureau of Land Management

43 CFR Part 3160

[LLWO300000 L13100000.PP0000 14X]
RIN 1004-AE26

Oil and Gas; Hydraulic Fracturing on Federal and Indian Lands

AGENCY: Bureau of Land Management, Interior.

ACTION: Final rule.

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SUMMARY: On May 11, 2012, the Bureau of Land Management (BLM) published
in the Federal Register a proposed rule titled Oil and Gas; Well
Stimulation, Including Hydraulic Fracturing, on Federal and Indian
Lands. Because of significant public interest in hydraulic fracturing
and this rulemaking, on May 24, 2013, the BLM published in the Federal
Register a supplemental notice of proposed rulemaking and request for
comment titled Oil and Gas Hydraulic Fracturing on Federal and Indian
Lands. The BLM has used the comments on the supplemental proposed rule
and the earlier proposed rule in drafting this final rule. Key changes
to the final rule include the allowable use of an expanded set of
cement evaluation tools to help ensure that usable water zones have
been isolated and protected from contamination, replacement of the
``type well'' concept to demonstrate well integrity with a requirement
to demonstrate well integrity for all wells, more stringent
requirements related to claims of trade secrets exempt from disclosure,
more protective requirements to ensure that fluids recovered during
hydraulic fracturing operations are contained, additional disclosure
and public availability of information about each hydraulic fracturing
operation, and revised records retention requirements to ensure that
records of chemicals used in hydraulic fracturing operations are
retained for the life of the well. The final rule also provides
opportunities for the BLM to coordinate standards and processes with
individual states and tribes to reduce administrative costs and to
improve efficiency.

DATES: This final rule is effective on June 24, 2015.

ADDRESSES:
Mail: U.S. Department of the Interior, Director (630), Bureau of
Land Management, Mail Stop 2134 LM, 1849 C St. NW., Washington, DC
20240, Attention: 1004-AE26.
Personal or messenger delivery: Bureau of Land Management, 20 M
Street SE., Room 2134 LM, Attention: Regulatory Affairs, Washington, DC
20003.

FOR FURTHER INFORMATION CONTACT: Steven Wells, Division Chief, Fluid
Minerals Division, 202-912-7143 for information regarding the substance
of the rule or information about the BLM's Fluid Minerals Program.
Persons who use a telecommunications device for the deaf (TDD) may call
the Federal Information Relay Service (FIRS) at 1-800-877-8339 to
contact the above individual during normal business hours. FIRS is
available 24 hours a day, 7 days a week to leave a message or question
with the above individual. You will receive a reply during normal
business hours.

SUPPLEMENTARY INFORMATION:

Executive Summary

The BLM final rule on hydraulic fracturing serves as a much-needed
complement to existing regulations designed to ensure the
environmentally responsible development of oil and gas resources on
Federal and Indian lands, which were finalized nearly thirty years ago,
in light of the increasing use and complexity of hydraulic fracturing
coupled with advanced horizontal drilling technology. This technology
has opened large portions of the country to oil and gas development.
The BLM began work on this rule in November 2010, when it held its
first public forum amid growing public concern about the rapid
expansion of complex hydraulic fracturing. Since that time, the BLM has
published two proposed rules and held numerous meetings with the public
and state officials, as well as many tribal consultations and meetings.
The public comment period was open for more than 210 days. During this
period, the BLM received comments from more than 1.5 million
individuals and groups. The BLM reviewed and analyzed these comments
based on thoughtful analysis and robust dialogue, which resulted in a
rule that is more protective than the previous proposed rules and
current regulations. It also strengthens oversight and provides the
public with more information than is currently available, while
recognizing state and tribal authorities and not imposing undue delays,
costs, and procedures on operators. The final rule fulfills the goals
of the initial proposed rules: To ensure that wells are properly
constructed to protect water supplies, to make certain that the fluids
that flow back to the surface as a result of hydraulic fracturing
operations are managed in an environmentally responsible way, and to
provide public disclosure of the chemicals used in hydraulic fracturing
fluids.
The final rule also: (1) Improves public awareness of where
hydraulic fracturing has occurred and the existence of other wells or
geologic faults or fractures in the area, as well as communicates what
chemicals have been used in the fracturing process; (2) Clarifies and
strengthens existing rules related to well construction to ensure
integrity and address developments in technology; (3) Aligns
requirements with state and tribal authorities with regard to water
zones that require protection; and (4) Provides opportunities to
coordinate standards and processes with individual states and tribes to
reduce costs, increase efficiencies, and promote the development of
more stringent standards by state and tribal governments.
Various types of hydraulic fracturing have long been used on a
relatively small scale to complete or to re-complete conventional oil
and gas wells. More recently, hydraulic fracturing has been coupled
with relatively new horizontal drilling technology in larger-scale
operations that have allowed greatly increased access to shale oil and
gas resources across the country, sometimes in areas that have not
previously or recently experienced significant oil and gas development.
These newer wells can, among other complexities, be significantly
deeper and cover a larger horizontal area than the operations of the
past. This increased complexity requires additional regulatory effort
and oversight.
Rapid expansion of this practice and its complexity have caused
public concern about whether fracturing can lead to or cause the
contamination of underground water sources, whether the chemicals used
in fracturing pose risks to human health, and whether there is adequate
management of well integrity and the fluids that return to the surface
during and after fracturing operations.
The BLM's regulations that address issues surrounding hydraulic
fracturing are at least 25-30 years old, and pre-date the current
common use of the practice. In 2011, the Natural Gas Subcommittee of
the Secretary of Energy's Advisory Board recommended that the BLM
undertake a rulemaking to ensure well integrity, water protection, and
adequate public disclosure. Prior to that, in 2009 the American
Petroleum Institute published a guidance document titled ``Hydraulic
Fracturing Operations-Well Construction and Integrity Guidelines, First
Edition,

[[Page 16129]]

October 2009,'' commonly known as HF1, to provide guidance and
highlight industry recommended practices for well construction and
integrity for those wells that will be hydraulically fractured. The
purpose of the guidance was to ensure protection of shallow groundwater
aquifers and the environment while enabling economically viable
development of oil and natural gas resources. More recently,
regulations from states, such as Colorado and Wyoming, and professional
papers, such as King, George, SPE 152596, (Feb. 2012), focused on the
estimation, analyses, and control of risks from hydraulic fracturing
operations. All of these factors have led to, and informed, this
rulemaking. To ensure that these standards adequately address emerging
technological developments and health and environmental protections,
the BLM will evaluate the adequacy of this rulemaking 7 years after the
date of publication.
Pursuant to the Federal Land Policy and Management Act (FLPMA),
Indian mineral leasing laws, and other statutes, the BLM is charged
with administering oil and gas operations in a manner that protects
Federal and Indian lands while allowing for appropriate development of
the resource. The BLM oversees approximately 700 million subsurface
acres of Federal mineral estate and carries out some of the regulatory
duties of the Secretary of the Interior for an additional 56 million
acres of Indian mineral estate across the United States. Currently,
nearly 36 million acres of Federal land are under lease for potential
oil and gas development in 33 states. As of June 30, 2014, there were
approximately 47,000 active oil and gas leases on public lands, and
approximately 95,000 oil and gas wells. Like other BLM regulations,
this final rule applies to oil and gas operations on public lands
(which include split estate lands, i.e., lands where the surface is
owned by an entity other than the United States), as well as operations
on Indian lands, to ensure that these lands and communities all receive
the same level of protection as provided on public lands.
Oil and gas leasing decisions on public lands are made through a
thorough, deliberative, and transparent process rooted in Resource
Management Plans (RMPs) that cover virtually all BLM-administered
public land and related mineral estate. Oil and gas decisions contained
within BLM RMPs also apply to lands where the surface is privately
owned, but the mineral estate is in Federal ownership. The BLM
establishes, amends, and revises RMPs as required by the FLPMA with
involvement by the community and stakeholders. As part of the land use
planning process, the BLM engages the public in a variety of ways and
conducts environmental reviews as required by the National
Environmental Policy Act (NEPA), and other applicable natural and
cultural resource protection authorities. While the public makes known
to the BLM which lands they are interested in leasing, prior to leasing
any lands, the BLM undertakes the appropriate NEPA review and provides
an opportunity for the public to review and comment on the analyses and
documents that the agency prepares.

Existing Requirements

Relevant existing requirements for oil and gas operations are set
out at 43 CFR 3162.3-1 and Onshore Oil and Gas Orders 1, 2 and 7. Most
of these requirements have been in place for at least 25 years. This
final rule will supplement the existing requirements, which will remain
in place. On either Federal leaseholds, or Indian lands, an operator
may not begin operations until it has filed an Application for a Permit
to Drill (APD) with the BLM and received approval from the BLM to
commence operations. Existing Federal law requires the BLM to post
notices of APDs for oil and gas development on public lands for public
inspection for 30 days, during which time the public may express any
concerns to the BLM's authorized officer as the agency conducts a site-
specific environmental analysis of the proposed well site proposal.
Those concerns and other issues identified earlier in the process, or
during site examinations, may result in conditions of approval (COA) on
the operator's drilling permit that require, forbid, or control
specified activities or disturbances. Examples of COAs include
providing for road improvements and erosion control measures, or
applying seasonal restrictions on some activities. In addition,
baseline water testing is a best management practice that the BLM
encourages. The BLM may require water testing and monitoring,
particularly if water quality impacts are a significant concern based
on local conditions, and where the BLM or a cooperating landowner or
manager manages the surface estate where testing could yield useful
water quality information. This is consistent with what several states,
including California, Colorado, and Wyoming, are already doing. The BLM
does not post for public inspection notices of APDs for Indian oil and
gas leases or agreements because there is no requirement in the Indian
leasing statutes similar to that in Section 17 of the Mineral Leasing
Act.
Under Onshore Oil and Gas Order 1, Approval of Operations, the
location of the well must be identified and important aspects of the
proposed operations described. Onshore Order 2 requires all usable
water zones to be protected by steel casing and cement, and requires
the casing, once in place, to be pressure tested. Casing and cement
must meet specific design criteria, which BLM engineers verify as part
of the permit review process. When a well is no longer capable of
producing, Onshore Order 2 mandates minimum standards for the
placement, quality, and verification of cement plugs to ensure that any
remaining oil and gas cannot migrate into usable water zones. BLM
inspectors witness aspects of drilling and plugging operations to
ensure that the operator is in compliance with Onshore Order 2 and the
permit to drill.

New Requirements

With this rule, the BLM establishes new requirements to ensure
wellbore integrity, protect water quality, and enhance public
disclosure of chemicals and other details of hydraulic fracturing
operations. The rule requires an operator planning to conduct hydraulic
fracturing to do the following:
Submit detailed information about the proposed operation,
including wellbore geology, the location of faults and fractures, the
depths of all usable water, estimated volume of fluid to be used, and
estimated direction and length of fractures, to the BLM with the APD or
a Sundry Notice and Report on Wells (Form 3160-5) as a Notice of Intent
(NOI) to hydraulically fracture an existing well;
Design and implement a casing and cementing program that
follows best practices and meets performance standards to protect and
isolate usable water, defined generally as those waters containing less
than 10,000 parts per million of total dissolved solids (TDS);
Monitor cementing operations during well construction;
Take remedial action if there are indications of
inadequate cementing, and demonstrate to the BLM that the remedial
action was successful;
Perform a successful mechanical integrity test (MIT) prior
to the hydraulic fracturing operation;
Monitor annulus pressure during a hydraulic fracturing
operation;
Manage recovered fluids in rigid enclosed, covered or
netted and screened above-ground storage tanks, with very limited
exceptions that must be approved on a case-by-case basis;

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Disclose the chemicals used to the BLM and the public,
with limited exceptions for material demonstrated through affidavit to
be trade secrets;
Provide documentation of all of the above actions to the
BLM.
Specifically, this final rule will add to existing requirements by
providing information to the BLM and the public on the location,
geology, water resources, location of other wells or fracture zones in
the area, and fracturing plans for the operation before the well is
permitted. To ensure well integrity, the final rule will require
specified best practice performance standards for all wells, including
cement return and pressure testing for surface casing, cement
evaluation logs for intermediate and production casing, and remediation
plans and cement evaluation logs for any surface casing that does not
meet performance standards.
The final rule eliminates the use of ``type wells'' in
demonstrating well integrity, and requires that specified best
practices be used and demonstrated for all wells, not just a sample
well. For surface casing, the final rule does not require a cement
evaluation log (CEL) for each well, substituting other equally or more
protective performance standards, including cement returns and pressure
testing. For any surface casing not meeting these performance
standards, an approved remedial plan and CEL will be required. For
intermediate and production casing not cemented to the surface, a CEL
will be required for all wells.
The final rule will require interim storage of all produced water
in rigid enclosed, covered, or netted and screened above-ground tanks,
subject to very limited exceptions in which lined pits could be used.
Public disclosure of all chemicals, subject to limited exceptions
for trade secret material, will be required after fracturing operations
are complete. The existing database, FracFocus (http://fracfocus.org),
can be used for this disclosure.
FracFocus is managed by the Ground Water Protection Council (GWPC),
a non-profit organization of state water quality regulatory agencies,
and by the Interstate Oil and Gas Compact Commission (IOGCC), a multi-
state government agency charged with balancing oil and gas development
with environmental protection. The BLM will continue to work with
FracFocus in coordination with the U.S. Department of Energy (DOE) to
ensure that the recommendations of the Secretary of Energy's Advisory
Board for improvement of the database are made.\1\ Specifically, the
BLM is in the process of finalizing a Memorandum of Understanding (MOU)
with the GWPC to ensure, among other things, that the database can be
searched and downloaded easily. In a press release \2\ on February 26,
2015 GWPC and the IOGCC, joint venture partners in the FracFocus
initiative, announced the release of improvements to FracFocus' system
functionality. The new features for 2015 include:
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\1\ Secretary of Energy's Advisory Board recommendations can be
downloaded from http://energy.gov/seab/downloads/fracfocus-20-task-force-report.
\2\ http://www.gwpc.org/major-improvements-fracfocus-announced.
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Reducing the number of human errors in disclosures
Expanding the public's ability to search records
Providing public extraction of data in a ``machine
readable'' format and
Updating educational information on chemical use, oil and
gas production, and potential environmental impacts.
As a part of the MOU with GWPC, FracFocus will automatically notify
the BLM when an operator uploads chemical disclosure information about
a Federal or Indian well. The BLM will obtain the information from
FracFocus and keep those records in compliance with all pertinent
record management requirements.
The BLM developed this final rule with the intention of improving
public awareness and strengthening oversight of hydraulic fracturing
operations without introducing unnecessary new procedures or delays in
the process of developing oil and gas resources on public and Indian
lands. Some states, including Alaska, Arkansas, Colorado, Illinois,
Michigan, New Mexico, Ohio, Oklahoma, Pennsylvania, Texas, Utah, and
Wyoming have regulations in place addressing hydraulic fracturing
operations. Operators with leases on Federal lands must comply with
both the BLM's regulations and with state operating requirements,
including state permitting and notice requirements to the extent they
do not conflict with BLM regulations. To address concerns from states
and tribes about possible duplicative efforts, the final rule provides
that in situations in which specific state or tribal regulations are
demonstrated to be equal to or more protective than the BLM's rules,
the state or tribe may obtain a variance. Such a variance will allow
for enforcement of the more protective state or tribal rule.
For many years, the BLM has maintained a number of agreements with
certain states and tribes concerning implementation of the various
regulatory programs in logical and effective ways. The BLM will work
with states and tribes to establish formal agreements that will
capitalize on the strengths of partnerships, and reduce duplication of
effort for agencies and operators, particularly by implementing the
final rule as consistently as possible with state or tribal
regulations.
The provisions in this final rule provide for the BLM's consistent
oversight and establish a baseline for environmental protection across
all public and Indian lands undergoing hydraulic fracturing. The BLM
has analyzed the costs and the benefits of this proposed action in an
accompanying Regulatory Impact Analysis available in the rulemaking
docket. The BLM estimates that the rule will impact about 2,800
hydraulic fracturing operations per year, but that it could impact up
to 3,800 operations per year based on previous levels of activity on
Federal lands and growing activity on Indian lands. The BLM estimates
that the compliance cost will be about $11,400 per well, or about $32
million per year. On average this equates to approximately 0.13 to 0.21
percent of the cost of drilling a well.
Many of the requirements generally are consistent with industry
guidance, the voluntary practice of operators, and some are required by
state regulations. So to the extent that industry is already in
compliance, the cost of several of the provisions may be overestimated.
The improvements also provide significant benefits to all Americans by
avoiding potential damages to water quality, the environment, and
public health. The rule creates a consistent, predictable, regulatory
framework, in accordance with the BLM's stewardship responsibilities
for hydraulic fracturing under the FLPMA and the Indian mineral leasing
statutes.

I. Background
II. Discussion of the Final Rule and Comments on the Proposed Rules
III. Procedural Matters

I. Background

Well stimulation techniques, such as hydraulic fracturing, are
commonly used by oil and natural gas producers to increase the volumes
of oil and natural gas that can be extracted from wells. Hydraulic
fracturing techniques are particularly effective in enhancing oil and
gas production from shale gas or oil formations. Until quite recently,
shale formations rarely produced oil or gas in commercial quantities
because shale does not generally allow the flow of hydrocarbons to
wellbores unless

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physical changes to the properties of the rock can be induced. The
development of horizontal drilling, combined with hydraulic fracturing,
has made the production of oil and gas from shale feasible. Hydraulic
fracturing involves the injection of fluid under high pressure to
create or enlarge fractures in the reservoir rocks. The fluid that is
used in hydraulic fracturing is usually accompanied by proppants, such
as particles of sand, which are carried into the newly fractured rock
and help keep the fractures open once the fracturing operation is
completed. The proppant-filled fractures become conduits for fluid
migration from the reservoir rock to the wellbore and the fluid is
subsequently brought to the surface. In addition to the water and sand
(which together typically make up 98 to 99 percent of the materials
pumped into a well during a fracturing operation), chemical additives
are also frequently used. These chemicals can serve many functions in
hydraulic fracturing, including limiting the growth of bacteria and
preventing corrosion of the well casing. The exact formulation of the
chemicals used varies depending on the rock formations, the well, and
the requirements of the operator.
Some simple types of hydraulic fracturing techniques have been used
on a small scale in oil and gas production for decades. However, as
discussed in different parts of the preamble, hydraulic fracturing
operations in recent years have become more complex, involving the
exploration of and production from significantly deeper formations and
across much larger subsurface areas through the use of horizontal
drilling techniques.
The BLM estimates that about 90 percent of the approximately 2,800
new wells spudded in 2013 on Federal and Indian lands were stimulated
using hydraulic fracturing techniques. Over the past 10 years, there
have been significant technological advances in horizontal drilling,
which is now frequently combined with hydraulic fracturing. This
combination, together with the discovery that these techniques can
release significant quantities of oil and gas from large shale
deposits, has led to production from geologic formations in parts of
the country that previously did not produce significant amounts of oil
or gas. The expansion of exploration and production across the United
States has significantly increased public awareness of hydraulic
fracturing and the potential impacts that it may have on water quality
and water consumption, and increased calls for stronger regulation and
safety protocols. The BLM's engineers and field managers have decades
of experience exercising oversight of these wells during the evolution
of this technology. This expertise, together with input from the
public, industry, state, academic and other experts discussed below,
forms the basis for the decision that new rules are needed and for the
requirements contained in this rule.
The BLM's existing hydraulic fracturing regulations are found at 43
CFR 3162.3-2. Those regulations were established in 1982 and last
revised in 1988, long before the latest hydraulic fracturing
technologies were developed or became widely used. The Department of
the Interior (Department) held a forum on hydraulic fracturing on
November 30, 2010, in Washington, DC, attended by the Secretary of the
Interior and more than 130 interested parties. The BLM later hosted
public forums (in Bismarck, North Dakota on April 20, 2011; Little
Rock, Arkansas on April 22, 2011; and Golden, Colorado on April 25,
2011) to collect broad input on the issues surrounding hydraulic
fracturing. More than 600 members of the public attended the April 2011
forums. Some of the comments frequently heard during these forums
included concerns about water quality, water consumption, and a desire
for improved environmental safeguards for surface operations.
Commenters also strongly encouraged the agency to require public
disclosure of the chemicals used in hydraulic fracturing operations on
Federal and Indian lands. Some commenters from the oil and gas industry
suggested changes that would make the implementation of the rule more
practicable from their perspective, while others opposed adoption of
any such rules affecting hydraulic fracturing on the Federal mineral
estate.
Around the time of the BLM's forums, at the direction of President
Obama, the Secretary of Energy convened a Shale Gas Production
Subcommittee (Subcommittee) of the Secretary of Energy Advisory Board
to evaluate hydraulic fracturing issues. The Subcommittee met with
industry, service providers, state and Federal regulators, academics,
environmental groups, and many other stakeholders. On August 18, 2011,
the Subcommittee issued initial recommendations in its ``90-day Interim
Report.'' The Subcommittee issued its final report, titled ``Shale Gas
Production Subcommittee Second Ninety Day Report'' on November 18,
2011. The Subcommittee recommended, among other things, that more
information be provided to the public about hydraulic fracturing
operations, irrespective of whether those operations occur on the
Federal mineral estate, including disclosure of the chemicals used in
fracturing fluids. The Subcommittee also recommended the adoption of
stricter standards for wellbore construction and testing. The final
report also recommended that operators engaging in hydraulic fracturing
undertake pressure testing to ensure the integrity of all casings, as
well as the use of FracFocus as a means to report the use of hydraulic
fracturing chemicals. These reports are available to the public from
the Department of Energy's Web site at http://www.shalegas.energy.gov.
On May 11, 2012, the BLM published in the Federal Register the
initial proposed rule titled ``Oil and Gas; Well Stimulation, Including
Hydraulic Fracturing, on Federal and Indian Lands'' (77 FR 27691). The
comment period on the initial proposed rule closed on July 10, 2012. At
the request of public commenters, on June 26, 2012, the BLM published
in the Federal Register a notice extending the comment period for 60
days (77 FR 38024). The extended comment period closed on September 10,
2012. The BLM received over 177,000 comments on the initial proposed
rule from individuals, Federal and state governments and agencies,
interest groups, and industry representatives.
After reviewing the comments on the proposed rule, the BLM
published a supplemental notice of proposed rulemaking on May 24, 2013
(78 FR 31636). The BLM received numerous requests for extension of the
comment period on the supplemental proposed rule. Because of the
complexity of the rule and well stimulation procedures, the BLM
extended the comment period on the rule for 60 days. The closing date
of the extended comment period was August 23, 2013. The BLM received
over 1.35 million comments on the supplemental proposed rule.
Substantive comments on the initial proposed and supplemental proposed
rules that informed the BLM's decisions on the final rule are discussed
in the section-by-section discussion of this preamble.
This final rule applies to all wells regulated by the BLM, whether
on Federal, tribal, or individual Indian trust or restricted fee lands.
The lands covered by the rule have not changed since the rule was first
proposed.

Tribal Consultation and Coordination With States

Tribal consultation is a critical part of this rulemaking effort,
and the Department is committed to making sure tribal leaders play a
significant role as the BLM and the tribes work together

[[Page 16132]]

to develop resources on public and Indian lands in a safe and
responsible way. During the proposed rule stage, the BLM initiated
government-to-government consultation with tribes on the proposed rule
and offered to hold follow-up consultation meetings with any tribe that
desired to have an individual meeting. In January 2012, the BLM held
four regional tribal consultation meetings, to which over 175 tribal
entities were invited. To build upon established local relationships,
the individual follow-up consultation meetings involved the local BLM
authorized officers and management, including BLM State Directors. The
BLM distributed copies of a draft rule to affected federally recognized
tribes in January 2012 and invited comments from affected tribes, which
were also considered in developing this final rule. After the issuance
of the proposed rule, tribal governments, tribal members, and
individual Native American mineral owners were also invited to comment
directly on the proposed rule.
In June 2012, the BLM held additional regional consultation
meetings in Salt Lake City, Utah; Farmington, New Mexico; Tulsa,
Oklahoma; and Billings, Montana. Eighty-one tribal members representing
27 tribes attended the meetings. In these sessions, the BLM and tribal
representatives engaged in substantive discussions of the proposed
hydraulic fracturing rule. A variety of issues were discussed,
including, but not limited to, the applicability of tribal laws,
validating water sources, inspection and enforcement, wellbore
integrity, and water management, among others. Additional individual
consultations with tribal representatives have taken place since that
time. Also, consultation meetings were held at the National Congress of
American Indian Conference in Lincoln, Nebraska, on June 18, 2012, and
at New Town, North Dakota on July 13, 2012.
After publication of the supplemental proposed rule, the BLM again
held regional meetings with tribes in Farmington, New Mexico, and
Dickinson, North Dakota in June 2013. Representatives from six tribes
attended. The discussions included a variety of tribal-specific and
general issues. One change resulting from those discussions is the re-
drafting of final section 3162.3-3(k) to clarify that tribal and state
variances are separate from variances for a specific operator. The BLM
again offered to follow up with one-on-one consultations, and several
such meetings were held with individual tribes. Several tribes, tribal
members, and associations of tribes provided comments on the
supplemental proposed rule. The BLM understands the importance of
tribal sovereignty and self-determination, and seeks to continuously
improve its communications and government-to-government relations with
tribes. Responses from tribal representatives informed the agency's
actions in defining the scope of acceptable hydraulic fracturing
operations. One of the outcomes of these meetings is the requirement in
this rule that operators certify to the BLM that operations on Indian
lands comply with applicable tribal laws.
In March 2014, the BLM invited tribes to participate in another
meeting in Denver, Colorado. Representatives from seven tribes
attended. There was significant discussion of issues raised in the
comments on the supplemental proposed rule. The BLM subsequently held
several consultations with individual tribes.
The BLM has been and will continue to be proactive about tribal
consultation under the Department's Tribal Consultation Policy, which
emphasizes trust, respect, and shared responsibility in providing
tribal governments an expanded role in informing Federal policy that
impacts Indian lands.
Several tribal representatives and tribal organizations commented
that the hydraulic fracturing rule should not apply on Indian land, or
that tribes should be allowed to decide not to have the rule apply on
their land (that is, ``opt out'' of the rule). However, the Indian
Mineral Leasing Act (IMLA) provides in a pertinent part as follows:
``All operations under any oil, gas, or other mineral lease issued
pursuant to the terms . . . of this title or any other Act affecting
restricted Indian lands shall be subject to the rules and regulations
promulgated by the Secretary of the Interior.'' 25 U.S.C. 396d. The
Department has consistently applied uniform regulations governing
mineral resource development on Indian and Federal lands. Thus, an
``opt out'' provision would not be consistent with the Department's
responsibilities under IMLA, and the final rule does not provide such
an option.
There has also been a suggestion that the Secretary should delegate
her regulatory authority to the tribes if the tribe has regulations
that meet or exceed the standards in the BLM regulation. The IMLA does
not authorize the Secretary to delegate her regulatory responsibilities
to the tribes, and therefore the final rule does not include a
delegation provision. Nonetheless, there are opportunities for tribes
to assert more control over oil and gas operations on tribal land by
entering into Tribal Energy Resource Agreements under the Indian Energy
Development and Self-Determination Act (part of the Energy Policy Act
of 2005), and to pursue contracts under the Indian Self-Determination
and Education Assistance Act of 1975.
Also, the final rule defers to state (on Federal land) or tribal
(on Indian land) designations of aquifers as either requiring
protection from oil and gas operations, or as exempt from the
requirement to isolate water-bearing zones in section 3162.3-3(b), so
long as those designations are not inconsistent with protections
required pursuant to the SDWA (also see the definition of ``usable
water''). Revised section 3162.3-3(k) provides that for lands within
the jurisdiction of a state or a tribe, that state or tribe could work
with the BLM to craft a variance that would allow compliance with state
or tribal requirements to be accepted as compliance with the rule, for
state or tribal provisions that are found to meet or exceed this rule's
standards. The BLM would enforce the variance as the Federal rule and
the appropriate State or tribe would enforce the variance under its
authority.
The BLM will continue its coordination with states and tribes to
establish or review and strengthen existing agreements related to oil
and gas regulation and operations. During the rulemaking process, the
BLM hosted multiple discussions with state governments to enhance
coordination with oil and gas permitting, inspection, and enforcement.
In August 2013, and then again in March 2014, the Acting Assistant
Secretary for Land and Minerals Management invited the Governors and
their representatives from those states with significant oil and gas
operations, to meet with the BLM and discuss the objectives of the
ongoing rulemaking as well as potential options for establishing
agreements to assist in implementing the BLM's oil and gas program. The
BLM's overall intent for these discussions is to minimize duplication
and maximize flexibility though its coordination with states and
tribes. We anticipate that these new and improved agreements will
reduce regulatory burdens and increase efficiency, while fulfilling the
Secretary's responsibilities mandated by statutes as steward for the
public lands and trustee for Indian lands. As this rule is implemented,
the BLM will continuously review these agreements along with the new
variance process allowed by the rule, and consider improvements as
necessary.
On Federal lands, the BLM enforces BLM regulations and lease
conditions,

[[Page 16133]]

and the states enforce their oil and gas regulations. On Indian lands,
the BLM enforces Federal regulations and the terms of the leases, and
the tribes have the power to enforce their own law.

Disclosure of Chemicals

The BLM is working closely with the GWPC and the IOGCC, in
coordination with the DOE, to provide for the disclosure of chemicals
in the hydraulic fracturing fluids by the operators to the BLM through
the existing public access Web site, www.fracfocus.org. As of June
2013, the FracFocus database was upgraded to FracFocus 2.0. These
upgrades were designed to enhance several aspects of the site's
functionality, such as its search and reports features and geographic
information system mapping, for all users. As mentioned earlier, the
GWPC and IOGCC, joint venture partners in the FracFocus initiative,
announced the release of several improvements to FracFocus' system
functionality. The new features are designed to reduce the number of
human errors in disclosures, expand the public's ability to search
records, provide public extraction of data in a ``machine readable''
format, and update educational information on chemical use,
environmental impacts from oil and gas production, and potential
environmental impacts. The new self-checking features in the system
will help companies detect and correct possible errors before
disclosures are submitted. This feature will detect errors verifying
that Chemical Abstract Service (CAS) numbers meet the proper format.
As of March 1, 2015, this online database includes information
provided by operators concerning oil and gas wells in 20 states, and it
is our understanding that a few more states are considering use of this
database. It includes information from over 72,700 wells and from more
than 500 companies. The list of states currently using FracFocus and
the states considering using FracFocus are listed as follows: \3\
---------------------------------------------------------------------------

\3\ See updated FracFocus link: http://www.fracfocus.org/welcome.

------------------------------------------------------------------------
States proposing to use
States currently using FracFocus FracFocus
------------------------------------------------------------------------
1 Alabama................................. 1 Alaska.
2 California.............................. 2 Florida.
3 Colorado................................ 3 Kentucky.
4 Illinois................................ 4 Nevada.
5 Kansas..................................
6 Louisiana...............................
7 Michigan................................
8 Minnesota...............................
9 Mississippi.............................
10 Montana................................
11 Nebraska...............................
12 North Dakota...........................
13 Ohio...................................
14 Oklahoma...............................
15 Pennsylvania...........................
16 South Dakota...........................
17 Tennessee..............................
18 Texas..................................
19 Utah...................................
20 West Virginia..........................
------------------------------------------------------------------------

The Secretary of Energy Advisory Board's Task Force on FracFocus
2.0 has identified a number of areas in which FracFocus needs
improvement.\4\ The BLM is in continued discussion with the GWPC and
expects further progress in ensuring that the site meets key elements
addressed by the Task Force report. Specifically, the BLM expects
improvement in the database to allow users to search by chemical, well,
company, or geography; in quality control; and in the capacity to
handle high volumes of information.
---------------------------------------------------------------------------

\4\ Secretary of Energy's Advisory Board recommendations (http://energy.gov/seab/downloads/fracfocus-20-task-force-report) includes
the areas of improvement.
---------------------------------------------------------------------------

The BLM recognizes the efforts of some states to regulate hydraulic
fracturing and seeks to avoid duplicative regulatory requirements. It
is important to recognize that a major impetus for a separate BLM rule
is that states are not legally required to meet the stewardship
standards that apply to public lands and do not have trust
responsibilities for Indian lands under Federal laws. Thus, the rule
may expand on or set different standards from those of states that
regulate hydraulic fracturing operations. This final rule encourages
efficiency in the collection of data and the reporting of information
by allowing operators in states that require disclosure on FracFocus to
meet both the state and the BLM requirements through a single
submission to FracFocus.
The BLM encourages the public disclosure of all chemicals used in
any hydraulic fracturing operation. However, because the identities of
some chemicals may be entitled to protection under Federal law as trade
secrets, the BLM is allowing that information to be withheld if the
operator and any other owner of the trade secret submit affidavits
containing specific information explaining the reasons for the claim
for protection. If the BLM has questions about the validity of the
claim for protection, the BLM can require the operator to provide the
withheld information to the bureau, and then would make a determination
as to whether the data is properly withheld from the public.

Existing Oil and Gas Development Process

The BLM has an extensive process in place to ensure that operators
conduct oil and gas operations in an environmentally sound manner that
protects resources. This rule adds specific requirements for hydraulic
fracturing operations, which supplement the existing requirements. The
following is a description of these existing processes and
requirements:
Resource Management Plans. Section 202 of the FLPMA requires the
BLM to develop and maintain land use plans (the BLM refers to these
plans as Resource Management Plans, or RMPs). The RMP serves as the
basis for all land use decisions the BLM makes, including decisions to
allow oil and gas leasing, allow oil and gas leasing under certain
conditions, or prohibit oil and gas leasing altogether. The RMP applies
to public lands, including the Federal mineral estate; however, it does
not apply to Indian land or to surface estates managed by other Federal
agencies such as the USDA Forest Service. The tribes and other Federal
agencies rely on their own planning guidance when determining if their
lands are suitable for oil and gas development. The FLPMA also requires
that the public be given ample opportunity to participate in the
development, maintenance, and revision of land use plans. Regulations
implementing the FLPMA (43 CFR 1610.2) require the BLM field offices to
publish notices to prepare, amend, or revise RMPs in the Federal
Register and local newspapers. In addition, the BLM must send notices
to groups and individuals who have expressed an interest in being
involved in BLM activities or who have participated in the past.
Typically, the first step in the development or revision of an RMP
is for the BLM to hold public scoping meetings to identify the primary
issues that the BLM should consider and address in the RMP. If, for
example, the public identifies tracts of land that are heavily used for
recreational activities or that hold special environmental
significance, the BLM may consider closing these tracts to oil and gas
leasing or placing restrictions on development. Restrictions can
include limiting the timing of oil and gas activities to avoid certain
impacts, setbacks from sensitive resources, establishing limits on
surface disturbance, and prohibiting surface occupancy entirely. Some
areas, such as wilderness areas or land within an

[[Page 16134]]

incorporated city, are closed to leasing by law. In addition to public
scoping, the BLM coordinates with state, county, and local governments,
Indian tribes, and other Federal agencies.
Once various land use options have been developed the BLM generally
analyzes the environmental impacts of the alternatives through an
Environmental Impact Statement (EIS), which offers additional
opportunity for public involvement. For proposed land use decisions,
such as keeping areas open for oil and gas leasing, environmental
impacts are assessed based on a Reasonable Foreseeable Development
(RFD) Scenario that projects the estimated levels and types of industry
activity and the associated surface disturbance that might occur during
the life of the RMP. Because the RMP and EIS generally cover all the
Federal land and mineral estate administered by a BLM field office, the
impact analysis is typically done on a broad scale. Mitigation measures
developed through the draft RMP and EIS process can be implemented as
stipulations on oil and gas leases. In addition to compliance with the
National Environmental Policy Act (NEPA), the BLM must comply with the
National Historic Preservation Act and the Endangered Species Act (ESA)
and engage in a consultation process with the U.S. Fish and Wildlife
Service under the ESA, if threatened or endangered species or critical
habitat may be affected.
Once a draft RMP and EIS are developed, the public has an
additional opportunity to review and comment on the analysis and
proposed mitigation measures in the EIS. When all comments have been
considered, the BLM develops a final RMP and EIS. The Record of
Decision finalizes the RMP, selecting a final action to be adopted from
a reasonable range of alternatives and explaining the rationale for the
decision. Once the Record of Decision is signed, the BLM makes all land
use decisions, including oil and gas development decisions, in
accordance with the RMP.
Leasing Process. The next step in the oil and gas development
process is the designation of parcels to be offered for lease, and an
additional environmental review. Under existing regulations, the public
may nominate tracts of land that they would like to see leased. It is
far more common, however, for members of the industry to express
interest in an area being offered for lease. The BLM first must ensure
that the proposed tracts are under Federal jurisdiction and are open to
leasing in accordance with the RMP. The next step is to conduct a
second NEPA review--typically through an Environmental Assessment
(EA)--to address potential impacts that could be caused by oil and gas
development within the nominated area. The NEPA review conducted at the
leasing stage ``tiers'' from the RMP EIS. In other words, the issues,
analysis of potential impacts, mitigation measures, and decisions in
the RMP EIS are carried through to the NEPA review conducted at the
leasing stage.
An interdisciplinary team consisting of resource specialists
develops the NEPA documentation. The interdisciplinary team visits the
site to gather on-the-ground data on potential impacts and mitigation
measures. After the site visit, an EA is drafted, including
coordination with county, state, and Federal agencies, and consultation
with Indian tribes, if applicable, in the area proposed for leasing.
EAs are posted on the BLM Web site and are available in the public
room(s) at BLM field offices for public review and comment, typically
for a 30-day period. The BLM reviews and addresses comments received
during that 30-day period when it finalizes the EA. Specific mitigation
measures are developed in the context of the NEPA review and are
included in a notice to potential bidders of an oil and gas lease at a
lease sale. If the environmental review concludes with a finding that
the proposed lease issuance would result in no significant impacts to
the quality of the human environment (FONSI), then the lease parcel can
be included in the next scheduled lease sale without any further NEPA
analysis. Upon issuance by the BLM, the lease allows the operator to
conduct operations on the lease.
Exploration and development requirements. The BLM has existing
regulations, including Onshore Oil and Gas Orders, to ensure that
operators conduct oil and gas exploration and development in an
environmentally responsible manner that protects other resources. These
requirements will remain in place and will be supplemented by this
final rule.
Existing section 43 CFR 3162.3-1 and Onshore Order 1 require an
operator to get approval from the BLM prior to drilling a well. The
operator must submit an APD containing all of the information required
by Onshore Order 1. This includes a completed Form 3160-3, Application
for Permit to Drill or Re-Enter, a well plat, a drilling plan, a
surface use plan, bonding information, and an operator certification.
Upon receiving a drilling proposal on Federal lands, the BLM is
required by existing section 3162.3-1(g) to post information for public
inspection for at least 30 days before action to approve the APD. The
information must include: The company/operator name; the well name/
number; and the well location described to the nearest quarter-quarter
section (40 acres), or similar land description in the case of lands
described by metes and bounds, or maps showing the affected lands and
the location of all tracts to be leased and of all leases already
issued in the general area. Where the inclusion of maps in such posting
is not practicable, the BLM provides maps of the affected lands
available to the public for review. The public posting is in the office
of the BLM authorized officer and in the appropriate surface managing
agency office, if other than the BLM. Some field offices also make this
information available on the field office Web site. The public may
review the posted information and provide any input they would like the
BLM to consider during its environmental analysis. If the public has
questions and concerns regarding drilling proposals, they can meet with
BLM staff and share those concerns.
The drilling plan is a critical, detailed, and multi-faceted
component of the APD that allows BLM engineers and geologists to
complete an appraisal of the technical adequacy of, and environmental
effects associated with, the proposed project. The drilling plan must
include:
Geological information, including the name and estimated
tops of all geologic groups, formations, members, and zones as well as
the estimated depths and thickness of formations, members, or zones
potentially containing usable water, oil, gas, or prospectively
valuable deposits of other minerals that the operator expects to
encounter, and their plans for protecting such resources.
Minimum specifications for blowout prevention equipment
that will be used to keep control of well pressures encountered while
drilling.
A description of the proposed casing program, including
the size, grade, weight, and setting depth of each casing string.
Detailed information regarding the proposed cementing
program, including the amount and types of cement the operator will use
for each casing string, which is critical in establishing a barrier
outside the casing between any hydrocarbon bearing zones and usable
water zones. BLM engineers evaluate the proposed cementing program to
ensure that the volume and strength of the cement is adequate to
achieve the desired protections.

[[Page 16135]]

Information regarding the proposed drilling fluid and
proposed testing, logging, and coring procedures.
An estimate of the expected bottom-hole pressure and any
anticipated abnormal pressures, temperatures, or potential hazards that
the well may encounter. BLM geologists and engineers review this
information to determine if any other anticipated hazards exist and to
ensure that there will be adequate mitigation to address those hazards.
Other information that may be pertinent, including the
directional drilling plan for deviated or horizontal wells so that BLM
engineers can look for potential issues with existing wells.
Just as the drilling plan allows the BLM to ensure the down-hole
technical adequacy of the proposed project, the surface use plan
provides the BLM with information needed to ensure safe operations,
adequate protection of the surface resources, groundwater, and other
environmental components in areas where the BLM manages the surface.
The surface managing agency must approve surface use plans where
the BLM does not manage the surface. The Bureau of Indian Affairs is
considered to be the surface management agency for Indian lands. In the
surface use plan, operators must also describe any Best Management
Practices (BMPs) they expect to use. BMPs are mitigation measures
applied to oil and natural gas drilling and production to help ensure
that operators conduct energy development in an environmentally
responsible manner. BMPs can protect water, wildlife, air quality, and
landscapes. The BLM encourages operators to incorporate BMPs into their
plans. Information concerning BMPs is available on the BLM's Web site
at: http://www.blm.gov/wo/st/en/prog/energy/oil_and_gas/best_management_practices.html.
Where the BLM manages the surface, the operator's surface use plan
should incorporate the BLM's ``Surface Operating Standards and
Guidelines for Oil and Gas Exploration and Development,'' which is
commonly referred to as ``The Gold Book.'' The BLM developed ``The Gold
Book'' to assist operators by providing information on obtaining permit
approval and conducting environmentally responsible oil and gas
operations. It is available on the BLM's Web site at: http://www.blm.gov/wo/st/en/prog/energy/oil_and_gas/best_management_practices/gold_book.html.
In general, the surface use plan must include the following:
Location and description of, as well as maintenance plan
for, existing and new roads the operator plans to use to access the
proposed well.
A map showing all known wells, regardless of their status
(producing, abandoned, etc.) within a one-mile radius of the proposed
location so that the BLM can ensure the proposal does not conflict with
any current surface use. The BLM also uses this well information to
identify any potential downhole conflicts or issues between the
existing wells and the proposed well.
A map or diagram showing the location of all production
facilities and lines the operator will install if the well is
successful (a producing well), as well as any existing facilities.
Information concerning the water supply, such as rivers,
creeks, springs, lakes, ponds, and wells that the operator plans to use
for drilling the well.
A written description of the methods and locations it
proposes for safe containment and disposal of each type of waste
materials that result from drilling the proposed well. The narrative
must include plans for the eventual disposal of drilling fluids and any
produced oil or water recovered during testing operations.
A diagram in the surface use plan of the proposed well
site layout.
A plan for the surface reclamation or stabilization of all
disturbed areas.
Another component of the APD is proof of adequate bond coverage as
required by existing 43 CFR 3104.1 for Federal lands and 25 CFR 211.24,
212.24, and 225.30, for Indian lands. These regulations require the
operator or the lessee to have an adequate bond in place prior to the
BLM's approval of the APD. If the BLM determines that the current bond
amount is not sufficient, the BLM can require additional bond coverage.
The BLM determines the need for bond increases by considering the
operator's history of violations, the location and depth of wells, the
total number of wells involved, the age and production capability of
the field, and any unique environmental issues.
Upon receipt of a complete APD, the BLM will schedule an onsite
inspection with the operator so that the BLM and operator may further
identify site-specific resource concerns and requirements not
originally identified in the application.
The onsite inspection team will include the BLM, a representative
of any other surface management agency and the operator or permitting
agent. When the onsite inspection is on private surface, the BLM will
invite the surface owner to attend. The purpose of the onsite
inspection is to discuss the proposal; determine the best location for
the well, road, and facilities; identify site-specific concerns and
potential environmental impacts associated with the proposal; and
discuss the conditions of approval or possible environmental BMPs. If
the BLM identifies resource conflicts, the BLM has the authority to
require the operator to move surface facilities to locations that would
reduce resource impacts while still allowing development of the leased
minerals.
Site-Specific Environmental Review. After the BLM has reviewed the
operator's proposed plans and conducted the onsite inspection, the BLM
will prepare an environmental document in conformance with NEPA and its
implementing regulations. The extent of the environmental analysis
process and the time frame for issuance of a decision will depend upon
the complexity of the proposed action and resulting analysis, the
significance of the environmental effects disclosed, and the completion
of appropriate consultation processes. Regardless of the complexity of
the proposed action, the environmental document will always consider
the impacts to cultural resources, endangered species, surface water,
and groundwater. An interdisciplinary team of BLM resource specialists
will conduct the analysis.
The environmental analysis may be conducted for a single well, a
group of wells, or for an entire field. The public is welcome to
provide input to the BLM for inclusion in the analysis. As discussed
previously, the BLM posts notices of all Federal APDs for public
inspection in the authorizing office. For large projects, such as field
development environmental assessments or environmental impact
statements, the BLM will go through public scoping and may issue a
draft analysis for public comment prior to completing the final
analysis and issuing a decision.
The environmental analysis will identify potential impacts from the
proposed action. The BLM will develop any necessary conditions of
approval to mitigate those potential impacts. If unacceptable impacts
are identified, the BLM will ask the operator to modify its proposal,
or the BLM may deny the application. The BLM will attach the conditions
of approval to the approved APD that the operator must follow. Examples
of conditions of approval include road improvements, additional erosion
control, or seasonal restrictions on some activities. In cases where
the BLM manages the surface, the BLM may also require baseline water
testing prior to drilling.

[[Page 16136]]

Compliance with Onshore Oil and Gas Order No. 2. Upon BLM's
approval of an APD, the operator may commence drilling of the well. In
addition to the approved plan and the conditions of approval, the
operator must also comply with the requirements of Onshore Oil and Gas
Order No. 2, (Onshore Order 2), which details the BLM's uniform
national standards for the minimum levels of performance expected from
operators when conducting drilling operations on Federal and Indian
lands. Many of the requirements of Onshore Order 2 ensure the
protection of usable water.
Onshore Order 2 also requires the operator to:
Conduct the proposed casing and cementing programs as
approved to protect and isolate all usable water zones, lost
circulation zones, abnormally pressured zones, and any prospectively
valuable deposits of minerals. It also requires the operator to report
all indications of usable water.
Employ technical measures to center the casing in the
drilled hole prior to cementing in order to ensure wellbore integrity.
It also requires the operator to cement the surface casing up to the
surface either during the primary cement job or by remedial cementing,
which ensures that all usable water zones behind the surface casing are
isolated and protected.
Wait until the cement for all casing strings achieves a
minimum of 500 pounds per square inch (psi) compressive strength at the
casing shoe prior to drilling out the casing shoe and utilize proper
cementing techniques.
Pressure test the casing prior to drilling out the casing
shoe to ensure the integrity of the casing. The operator must also
conduct a pressure integrity test of each casing shoe on all
exploratory wells, and on that portion of any well approved for a 5,000
psi blowout preventer. The pressure test ensures the integrity of the
cement around the casing shoe.
In addition, Onshore Order 2 identifies the minimum requirements
for blowout prevention equipment and the minimum standards for testing
the equipment. Proper sizing, installation, and testing of the blowout
prevention equipment ensures that the operator maintains control of the
well during the drilling process, which is necessary for protection of
usable water zones.
Post-Approval Inspections and Reporting. The BLM conducts
inspections of drilling operations to ensure that operators comply with
the Onshore Order 2 drilling regulations, the approved permit, and the
conditions of approval. The BLM drilling inspections consist of two
general types of inspections: Technical and environmental. The BLM
petroleum engineering technicians conduct technical inspections of the
drilling operations such as witnessing the running and cementing of the
casing, witnessing the testing of the blowout prevention equipment, and
detailed drilling rig inspections. Such inspections also include review
of documentation such as the third-party cementing job ticket that
describes the cementing operation, including the type and amount of
cement used, the cement pump pressures, and the observation of cement
returns to the surface, if applicable.
The BLM natural resource specialists conduct environmental
inspections of drilling operations that focus primarily on the surface
use portion of the approved drilling permit. This includes inspection
of the access road, the well pad, and pits. While the BLM does not have
the budget or personnel to inspect every drilling operation on Federal
and Indian minerals, the BLM conducts inspections in accordance with an
annual risk-based strategy to ensure compliance with the regulations,
lease stipulations, and permits.
Within 30 days after the operator completes a well, the operator is
required by existing regulations to submit a BLM Well Completion or
Recompletion Report and Log (Form 3160-4), which provides drilling and
completion information. Similar to completion of a new well, an
existing well can be recompleted to restore productivity and thus
produce oil or gas which would have otherwise been abandoned. This
document includes the actual casing setting depths and the amount of
cement the operator used in the well, together with information
regarding the completion interval between, for example, the top and
bottom of the formation, the perforated interval, and the number and
size of perforation holes. The operator is also required to submit
copies of all electric and mechanical logs. The BLM reviews this
information to ensure that the operator set the casing and pumped the
cement according to the approved permit.
Compliance with Onshore Oil and Gas Order No. 7. Once a well goes
into production, water is often produced with the oil and gas. The
water tends to be of poor quality and is not generally suitable for
drinking, livestock, or other uses and, therefore, must be disposed of
properly. Onshore Oil and Gas Order No. 7 (Onshore Order 7) regulates
the disposal of produced water. Under Onshore Order 7, operators must
apply to the BLM for authorization to dispose of produced water by
injecting the water back into a suitable formation, by storing it in
pits, or by other methods approved by the BLM. If the water will be
stored in pits, the BLM requires specific design standards to ensure
the water does not contaminate the environment or pose a threat to
public health and safety.
Post-Drilling Inspections. After a well has been drilled and
completed, the BLM continues to inspect the well until it has been
plugged and abandoned, and the surface has been rehabilitated. During
the production phase of the well, the BLM inspections focus on two
primary issues: Production and the environment. The Federal Government
(Federal leases) or an Indian tribe or individual Indian allottee
(Indian leases) receive a royalty on the oil and gas removed or sold
from the lease based on the volume, quality, and value of the oil and
gas. Royalties from Federal leases are shared with the state as
provided by statute. Production inspections are conducted by the BLM to
ensure the volume and quality of the oil and gas is accurately measured
and properly reported. Environmental inspections are conducted by the
BLM to ensure that wellpads and facilities are in compliance with
regulations, Onshore Orders, and approved permits. Environmental
inspections include ensuring that pits are properly constructed,
maintained, and protected from wildlife; identifying leaking wells or
pipelines; ensuring that the wellsite and facilities are properly
maintained; and ensuring that proper erosion controls and
rehabilitation measures are in place.
Well Plugging, Abandonment and Site Restoration. When a well has
reached the end of its economic life, Federal regulations require that
it be plugged and abandoned to prevent oil and gas from leaking to the
surface or contaminating water bearing zones or other mineral zones. An
operator may request well abandonment or the BLM may require it. In
either case, the operator must submit a proposal for well plugging,
including the length, location, type of cement, and placement method to
be used for each plug. The operator must also submit a plan to
rehabilitate the surface once the well has been plugged. The goal of
surface rehabilitation is to remove obvious visual evidence of the pad
and to promote the long-term stability of the site and vegetation.
The BLM inspects both well plugging and surface restoration. Well
plugging inspections are completed to ensure the plugs are set in
accordance with the

[[Page 16137]]

procedure approved by the BLM. The inspector will witness the depth and
volume of cement used in a plug as well as the physical verification of
the top of a plug. When an operator has completed surface restoration,
it will notify the BLM or the surface management agency. The surface
protection specialists of the BLM or of the surface management agency
will inspect the site to ensure the restoration is adequate. Once the
BLM or the surface management agency is satisfied with the restoration
efforts, the BLM will approve the operator's Final Abandonment Notice.
The regulations and Onshore Orders that have been in place to this
point have served to provide reasonable certainty of environmentally
responsible development of oil and gas resources on public lands, but
are in need of revision as extraction technology has advanced. The
final rule will complement these existing rules by providing further
assurance of wellbore integrity, requiring with limited exception
public disclosure of chemicals used in hydraulic fracturing, and
ensuring safe management of recovered fluids. Taken together these
regulations establish baseline environmental safeguards for hydraulic
fracturing operations across all public and Indian lands.

II. Discussion of the Final Rule and Comments on the Proposed Rules

As was discussed in the initial and supplemental proposed rules,
the BLM is revising its hydraulic fracturing regulations, found at 43
CFR 3162.3-2, and adding a new section 3162.3-3. Existing section
3162.3-3 is retained and renumbered. As stewards of the public lands
and minerals and as the Secretary's regulator for operations on oil and
gas leases on both public and Indian lands, the BLM has evaluated the
increased use of hydraulic fracturing practices over the last decade
and determined that the existing rules for hydraulic fracturing require
updating.
The FLPMA directs the BLM to manage the public lands so as to
prevent unnecessary or undue degradation, and to manage those lands
using the principles of multiple use and sustained yield. The FLPMA
defines multiple use to mean, among other things, a combination of
balanced and diverse resource uses that takes into account long-term
needs of future generations for renewable and non-renewable resources.
The FLPMA also provides that the public lands be managed in a manner
that will protect the quality of their resources, including, but not
limited to, ecological, environmental, and water resources. The Mineral
Leasing Act and the Mineral Leasing Act for Acquired Lands authorize
the Secretary to lease Federal oil and gas resources, and to regulate
oil and gas operations on those leases, including surface-disturbing
activities.
The Act of March 3, 1909, the Indian Mineral Leasing Act and the
Indian Mineral Development Act assign regulatory authority to the
Secretary over Indian oil and gas leases on trust lands (except those
excluded by statute, i.e., the Crow Reservation in Montana, the ceded
lands of the Shoshone Reservation in Wyoming, the Osage Reservation in
Oklahoma, and the coal and asphalt lands of the Choctaw and Chickasaw
Tribes in Oklahoma). The Secretary has delegated to the BLM her
authority to oversee operations on Indian mineral leases through the
Departmental Manual (235 DM 1.K), and the Bureau of Indian Affairs'
regulations provide that 43 CFR part 3160 applies to oil and gas
operations on Indian lands. See 25 CFR 211.4, 212.4, and 225.4. The
Secretary also approved the authorities section of the regulations
which give the BLM authority under the Indian minerals statutes.
As discussed in the background section of this preamble, the
increased use of well stimulation activities over the last decade has
generated concerns among the public about hydraulic fracturing and
about the chemicals used in hydraulic fracturing. This final rule is
intended to increase transparency for the public regarding the fluids
used in the hydraulic fracturing process, provide assurance that
wellbore integrity is maintained throughout the fracturing process and
ensure that the fluids that flow back to the surface from hydraulic
fracturing operations are properly stored, disposed of, or treated. The
BLM's engineers and field managers have decades of experience
exercising oversight of these wells during the evolution of this
technology. This expertise, together with input from the public,
industry, state, academic and other experts discussed below, forms the
basis for the decision that new rules are needed and for the
requirements contained in this rule.
The following chart explains the major changes between the
supplemental proposed rule and this final rule. A similar chart
explaining the differences between the proposed and supplemental
proposed rules appears in the supplemental proposed rule at 78 FR 31641
and a chart explaining the differences between the existing regulations
and the original proposed rule appears in the proposed rule at 77 FR
27694.

------------------------------------------------------------------------
Supplemental proposed
regulation Final regulation Substantive changes
------------------------------------------------------------------------
43 CFR 3160.0-5 Definitions... 43 CFR 3160.0-5 This final rule makes
Definitions. a series of changes
to the definitions
section. The term
``master hydraulic
fracturing plan'' is
added. The
definition of a
cement evaluation
log is moved from
Sec. 3162.2-
3(e)(2) to the
definitions section.
The term ``confining
zone'' is now
defined because that
term is used in
revised Sec.
3162.3-3(d). The
term
``refracturing'' is
deleted from this
section and the rest
of the rule. The
term ``usable
water'' is updated
to remove the
requirement to
identify usable
water only via drill
log. The final rule
also clarifies the
definition of
``usable water''.
43 CFR 3162.3-2 Subsequent 43 CFR 3162.3-2 Paragraph (a) of this
Well Operations. Subsequent Well section is modified
Operations. slightly by removing
the phrase ``the
operator'' because
it is redundant.
43 CFR 3162.3-3(a) Hydraulic 43 CFR 3162.3- The final rule
Fracturing. 3(a) Subsequent clarifies the
Well Operations; application of this
Hydraulic rule to wells at
Fracturing. various stages of
completion on the
publication and
effective date, and
clarifies what
sections of the rule
apply based on a
table which
distinguishes leases
with approved APDs
from leases without
approved APDs, as
well as leases with
approved APDs that
do not have wells
spudded.
43 CFR 3162.3-3(b) Isolation 43 CFR 3162.3- The term
of Usable Water to Prevent 3(b) Isolation ``refracturing'' is
Contamination. of Usable Water deleted.
to Prevent
Contamination.

[[Page 16138]]

43 CFR 3162.3-3(c) When an 43 CFR 3162.3- Paragraphs (c)(1) and
Operator Must Submit 3(c) How an (2) of this section
Notification for Approval of Operator Must are revised non-
Hydraulic Fracturing. Submit a Request substantively and
for Approval of for clarity.
Hydraulic Paragraph (c)(3) is
Fracturing. revised to remove
references to
refracturing. As in
the supplemental
proposed rule, the
operator may submit
the hydraulic
fracturing proposal
either in the APD or
as an NOI. The final
rule removes ``type
wells'' from this
section. In the
final rule a request
to hydraulically
fracture can be
submitted for a
group of wells in a
master hydraulic
fracturing plan.
Paragraph (c)(4) is
added to address and
clarify when an
operator must submit
a new NOI.
43 CFR 3162.3-3(d) What the 43 CFR 3162.3- Consistent with other
Notice of Intent Sundry Must 3(d) What a changes in this
Include. Request for rule, the final rule
Approval of replaces the
Hydraulic procedure for
Fracturing Must submitting an NOI
Include. for multiple wells
through a type well
submission, and
instead allows
submission of a
master hydraulic
fracturing plan.
Paragraph (d)(1) is
revised to require
specific information
regarding wellbore
geology, including
information
regarding the
formation into which
hydraulic fracturing
fluids are to be
injected, the
estimated depths of
the confining zones
and occurrences of
usable water.
Paragraph (d)(2) is
revised to require a
map showing
information
regarding known or
suspected faults and
fractures. Paragraph
(d)(4) is also
revised to require
submission of a map
showing information
about the trajectory
of the wellbore and
estimated direction
and length of the
fractures that will
be propagated and
all existing
wellbore
trajectories for all
wells within one-
half mile of the
wellbore that will
be hydraulically
fractured.
43 CFR 3162.3-3(d)(2)......... 43 CFR 3162.3- The final rule
3(d)(2). deletes the
requirement to
submit occurrences
of usable water by
use of a drill log
and instead allows
flexibility in how
to obtain the
information.
43 CFR 3162.3-3(d)(3)......... 43 CFR 3162.3- The final rule
3(d)(3). eliminates the
requirement to
submit the proposed
measured depth of
perforations or the
open hole interval
and estimated pump
pressures and makes
it clear that the
wells referred to in
this provision are
water supply wells.
43 CFR 3162.3-3(d)(4)......... 43 CFR 3162.3- The final rule
3(d)(4). combines paragraphs
(ii) and (iii) into
a revised paragraph
(ii) to read ``the
maximum anticipated
surface pressure
that will be applied
during the hydraulic
fracturing
process.'' The
revised terminology
encompasses the
intent of the
previous two
paragraphs.
Supplemental
proposed rule
paragraph (iv) is
now paragraph (iii)
and is revised in
the final rule, and
the word
``calculated'' is
deleted, to
reinforce the lack
of certainty of the
information in the
APD or NOI at this
stage of operations.
Supplemental
proposed rule
paragraph (v) is
deleted and replaced
with a revised
paragraph (iv),
which seeks the
estimated minimum
vertical distance to
the nearest usable
water aquifer above
the fracture zone.
New paragraph (v)
asks for the
measured depth of
the proposed
perforated or open
hole interval. Both
the old paragraph
(v) and the new
paragraph (iv) aim
to provide guidance
to the BLM on
protecting usable
water zones.
43 CFR 3162.3-3(d)(5)......... 43 CFR 3162.3- The final rule
3(d)(5). eliminates some of
the specific details
of the fluid
recovery plan,
focusing on
estimated volume,
proposed handling
methods and proposed
disposal methods.
Further, the
timeline is being
clarified to better
reflect the scope of
the plan. This
paragraph is also
revised by adding a
provision asking for
information about
the handling of
recovered fluids
between the time of
the start of
hydraulic fracturing
operations and the
approval of the
disposal of produced
fluids under BLM's
regulations, which
are currently
contained in
existing Onshore
Order 7. Paragraph
(i) is revised by
eliminating the
three circumstances
that were listed
where the volume of
recovered fluid must
be estimated, but
keeping the
requirement to
estimate the volume
of fluid to be
recovered. New
paragraph (ii) asks
for the proposed
methods of handling
recovered fluids by
cross reference to
paragraph (h) of
this section, which
requires the use of
rigid enclosed,
covered or netted
and screened above-
ground tanks to
store these fluids
(with a limited
exception for the
use of lined pits).
Paragraph (iii) of
this section is
revised by making
clear the methods of
handling recovered
fluids that must be
described in the
application.
None.......................... 43 CFR 3162.3- The final rule
3(d)(6). includes a
requirement for a
surface use plan of
operations if the
hydraulic fracturing
operation would
cause additional
surface disturbance.
By reference to
paragraph (e), it
requires
documentation that
an adequate cement
job occurred for all
casing strings
designed to isolate
usable water.
43 CFR 3162.3-3(d)(6)......... 43 CFR 3162.3- Because of new
3(d)(7). paragraph (d)(6),
the former paragraph
(d)(6) is renumbered
as paragraph (d)(7),
and is revised to
make it clear that
the requirement may
apply to an APD as
well as a NOI.

[[Page 16139]]

43 CFR 3162.3(e) Monitoring of 43 CFR 3162.3- The title of this
Cementing Operations and 3(e) Monitoring section is revised
Cement Evaluation Log Prior and Verification to better reflect
to Hydraulic Fracturing. of Cementing the content of the
Operations Prior final rule.
to Hydraulic
Fracturing.
43 CFR 3162.3-3(e)(1)......... 43 CFR 3162.3- This paragraph is
3(e)(1). revised to make it
clear that the
information request
is for any casing
string used to
isolate usable water
zones. The section
is also revised to
require that the
information be
submitted to the
authorized officer
48 hours prior to
the start of
hydraulic fracturing
operations unless
the authorized
officer approves a
shorter time.
43 CFR 3162.3-3(e)(2)......... 43 CFR 3162.3- New paragraph (e)(2)
3(e)(2). replaces
supplemental
proposed rule
paragraph (e)(2) and
requires that prior
to hydraulic
fracturing
operations the
operator must
determine and
document that there
is adequate cement
for all casing
strings to isolate
usable water. For
surface casing, the
operator must
observe cement
returns to the
surface and document
any indications of
inadequate cement
following the new
requirements of this
paragraph. For
intermediate or
production casing,
if the casing is not
cemented to the
surface, the
operator must run a
CEL demonstrating
that there is at
least 200 feet of
adequately bonded
cement protecting
the deepest usable
water zone. If the
casing is cemented
to the surface, then
the operator must
follow the same
requirements as for
surface casing
established earlier
in this section.
43 CFR 3162.3-3(e)(3), (e)(4), 43 CFR 3162.3- Final paragraph (3)
and (e)(5). 3(e)(3). combines revised
supplemental
proposed rule
paragraphs (3), (4),
and (5). For any
well where there is
an indication of
inadequate cement,
the operator must
follow the
provisions of this
paragraph. The
operator must notify
the BLM of the
inadequate cement
within 24 hours of
discovering it
(paragraph (3)(i))
and submit a plan to
the BLM requesting
approval of remedial
action to achieve
adequate cement
(paragraph (3)(ii)).
This section also
addresses emergency
situations where an
operator may request
oral approval of
remedial action to
correct inadequate
cement. Such oral
approvals must be
followed by written
notice within 5
business days
following oral
approval. The
operator must also
verify that the
remedial action was
successful with a
CEL or other method
BLM approves in
advance (paragraph
(3)(iii)).
Consistent with the
supplemental
proposed rule, the
operator must submit
a subsequent report
for the remedial
action including a
certification that
the remedial action
followed the
approved plan and
was successful
(paragraph (3)(iv)).
Under paragraph
(3)(v), the operator
must submit to the
BLM the results of
the CEL or other
testing method that
showed that the
remedial action was
successful at least
72 hours before
starting hydraulic
fracturing
operations.
43 CFR 3162.3-3(f) Mechanical 43 CFR 3162.3- Paragraph (1) of this
Integrity Testing Prior to 3(f) Mechanical section is revised
Hydraulic Fracturing. Integrity to include the words
Testing Prior to ``that will be
Hydraulic applied during the
Fracturing. hydraulic fracturing
process,'' to
clarify the timing
of the requirement.
Paragraph (2) of
this section is
revised by replacing
the word
``treating'' with
the word ``surface''
in the second
sentence of this
paragraph.
43 CFR 3162.3-3(g) Monitoring 43 CFR 3162.3- This paragraph has
and Recording During 3(g) Monitoring been revised to
Hydraulic Fracturing. and Recording delete the term
During Hydraulic ``refracturing,''
Fracturing. and clarifies the
actions that
operators must take
when pressure within
the annulus
increases by more
than 500 pounds per
square inch as
compared to the
pressure immediately
preceding the
stimulation.
43 CFR 3162.3-3(h)............ 43 CFR 3162.3- This section has
3(h) Management undergone numerous
of Recovered changes. The final
Fluids. rule requires that
fluids recovered be
stored in above-
ground tanks prior
to disposal under
BLM's regulations
(currently in
Onshore Order 7).
Paragraphs (1) and
(2) specify the very
limited conditions
under which an
authorized officer
may approve a lined
pit in lieu of a
tank.
43 CFR 3162.3-3(i) Information 43 CFR 3162.3- The heading of this
that Must be Provided to the 3(i) and (i)(1) section is revised
Authorized Officer After Information that to make it clearer.
Completed Operations. Must be Provided Paragraph (i)(1) of
to the this section is also
Authorized revised to require
Officer After the operator to
Hydraulic provide information
Fracturing is about each additive
Completed. in the hydraulic
fracturing fluid.
This will help to
account for
proppants as well as
chemical additives.
43 CFR 3162.3-3(i)(2)......... 43 CFR 3162.3- This section has been
3(i)(2), (i)(3), revised to seek only
and (i)(5). the actual sources
and locations of the
water used in the
hydraulic fracturing
fluid. The pressure
information
requested in the
supplemental
proposed rule is
covered in the final
rule by paragraph
(3) and the depth of
perforations and
open hole interval
is part of new
paragraph (5).
43 CFR 3162.3-3(i)(3)......... 43 CFR 3162.3- The final rule seeks
3(i)(3). the maximum surface
pressure rather than
the actual surface
pressure and no
longer seeks the
flush rate or the
final pump pressure
concentration in the
fracturing fluid.

[[Page 16140]]

43 CFR 3162.3-3(i)(4)......... 43 CFR 3162.3- This section requires
3(i)(4). the report to
include the actual,
estimated, or
calculated fracture
length, height, and
direction. This
section remains as
proposed.
None.......................... 43 CFR 3162.3- New paragraph (5)
3(i)(5). requires information
previously contained
in paragraph (2),
regarding the actual
measured depth of
perforations or the
open-hole interval.
None.......................... 43 CFR 3162.3- New paragraph (6)
3(i)(6). requires operators
to report the total
volume of fluid
recovered between
the time that
hydraulic fracturing
is completed and
when the operator
starts to report
water produced from
the well to Office
of Natural Resources
Revenue (ONRR).
43 CFR 3162.3-3(i)(5)(i)...... 43 CFR 3162.3- The final rule
3(i)(7). revises this
renumbered paragraph
to clearly outline
the timeframe for
reporting
information
pertaining to fluid
recovery.
43 CFR 3162.3-3(i)(5)(ii)..... 43 CFR 3162.3- This final section is
3(i)(7)(i). renumbered, but is
similar to the
supplemental
proposed rule.
43 CFR 3162.3-3(i)(5)(iii).... 43 CFR 3162.3- The final rule would
3(i)(7)(ii). simplify this
section by removing
the reference to
Onshore Order No. 7
and seek information
on disposal method,
such as injection,
recycling, or off-
lease storage.
43 CFR 3162.3-3(i)(6)......... Deleted.......... This section is
deleted and is
unnecessary because
the Authorized
Officer can always
require an
explanation of any
deviation under
(i)(10) of this
section.
43 CFR 3162.3-3(i)(7)......... 43 CFR 3162.3- The final rule
3(i)(8). renumbers this
section. Paragraphs
(8)(ii) and (8)(iii)
are revised to make
it clear that the
provisions only
apply to hydraulic
fracturing fluid
constituents once
they arrive on the
lease.
43 CFR 3162.3-3(i)(8)......... 43 CFR 3162.3- The final rule
3(i)(9). renumbers this
section. The well
logs and records of
adequate cement
bonds, including the
cement monitoring
report and any
cement evaluation
log, are no longer
required to be
submitted under this
section because this
information is
covered either in
the APD or NOI under
paragraph (e) of
this section.
43 CFR 3162.3-3(j) Identifying 43 CFR 3162.3- The final rule at
Information Claimed to be 3(j) Identifying paragraph (j)(1)
Exempt from Public Disclosure. Information strengthens the
Claimed to be affidavit provisions
Exempt from to ensure that
Public operators fully
Disclosure. describe and attest
to the basis for
their claim of
exemption from
public disclosure
for trade secrets.
The affidavit must
be signed by a
corporate officer or
the equivalent
responsible official
of the operator. The
affidavit must
identify and provide
contact information
for the owner of the
withheld
information, if it
is not the operator.
New paragraph (j)(2)
provides that if the
operator relies on
facts supplied by
another entity, it
must include an
affidavit from a
responsible official
of that entity
verifying those
facts. Former
paragraph (j)(2) has
been renumbered
(j)(3) without
substantive change.
Former paragraph
(j)(4) has been
renumbered as
paragraph (j)(5) and
is revised by
requiring that the
operator maintain
records of the
information claimed
to be exempt from
disclosure until the
later of the BLM's
approval of a final
abandonment notice,
or 6 years from
completion of
hydraulic fracturing
operations for
Indian lands, or 7
years from
completion of
hydraulic fracturing
operations for
Federal lands, as is
consistent with
applicable law. Any
subsequent operator
is responsible for
maintaining access
to those records.
The final rule also
adds a new paragraph
(j)(6) to this
section requiring
the operator to
submit the chemical
family name or other
similar descriptor
for information
claimed to be exempt
from disclosure.
43 CFR 3162.3-3(k) Requesting 43 CFR 3162.3- The final rule
a Variance from the 3(k) Requesting revises the variance
Requirements of this Section. a Variance from provisions to allow
the Requirements for individual
of this Section. variances and state/
tribal variances in
different sections.
Most of the
substantive
information in this
section has not
changed, but has
been re-organized
and revised for
clarity. One
revision to this
section is made to
make the rule
consistent with
Onshore Order 1 by
clarifying that the
decision on whether
to approve a
variance request is
not administratively
appealable to either
the State Director
or to the Interior
Board of Land
Appeals under 43 CFR
part 4.
------------------------------------------------------------------------

Section-by-Section Discussion of the Revised Proposed Rule and
Discussion of Comments

Comments Addressed in This Rule
In this preamble, the BLM discusses many of the comments received
on the supplemental and proposed rules. Commenters provided detailed
and helpful information that assisted in framing the issues and
ultimately in producing this final rule. The Department does not
address every comment in this final rule, because the changes in this
rule have mooted some comments on the initial proposed rule and the
supplemental proposed rule. Other comments were not central to the
evaluation the BLM has undertaken, and thus discussion of those few
comments would not contribute to the public's understanding of the
reasons for the final rule.
Additionally, not every change in the final rule responds to a
specific comment. Some revisions clarify the final rule, and still
other revisions allow this final rule to be more effective or reduce
inefficiencies.

[[Page 16141]]

Section Discussion
As an administrative matter, this rule would amend the authorities
section for the BLM's oil and gas operations regulations at 43 CFR
3160.0-3 to include the FLPMA. Section 310 of the FLPMA authorizes the
Secretary of the Interior to promulgate regulations to carry out the
purposes of the FLPMA and other laws applicable to the public lands.
See 43 U.S.C. 1740. This amendment would not be a major change and
would have no effect on lessees, operators, or the public.

Section 3160.0-5 Definitions

This section defines terms related to the regulation and the
hydraulic fracturing process. The terms annulus, bradenhead, cement
evaluation log, confining zone, hydraulic fracturing, hydraulic
fracturing fluid, and proppant are used to describe the requirements of
the rule. The term ``master hydraulic fracturing plan'' (MHFP) would
allow operators to gain certain efficiencies in submitting information
to the BLM. The actual process is explained in sections 3162.3-3(c) and
(d).
The final rule incorporates several changes to the definitions in
section 3160.0-5 from the supplemental proposed rule. The definition of
cement evaluation log is added to this section by moving it from
section 3162.2-3(e)(2) in the supplemental proposed rule to the
definitions section of the final rule. Because the final rule uses the
term several times, the BLM decided to add the definition to this
section.
The term ``master hydraulic fracturing plan'' is added to take the
place of portions of the type well approval in section 3162.3-3(d) of
the proposed rule. The final rule retains the ability for operators to
submit hydraulic fracturing proposals at the APD or NOI stage for a
group of similar wells with a single submission, including the
information regarding geology, etc., required in sections 3162.3-
3(d)(1) through (d)(7) of this rule. The BLM believes that this will
streamline the permitting process without sacrificing the quality of
the review. As a matter of current practice, many oil and gas operators
use the APD review and approval process to satisfy other BLM approval
requirements. For example, the construction of a road to access a
drilling location or a pipeline to transport production from a well
requires a right-of-way (ROW) in certain cases. Many operators submit
their plan of development for their proposed access road or pipeline
and a ROW application with their APD. The BLM performs its review of
the ROW application at the same time it is reviewing the APD. An MHFP
may not be used for the information required to demonstrate well
integrity in section 3162.3-3(e). As discussed later, the ``type well''
concept has been eliminated and each well will be required to be
demonstrated to meet the performance standards in this rule.
In addition, the requirement that an MHFP only apply to wells in
the same field is eliminated primarily because the term ``field'' is
not well defined. Instead, in the final rule, an MHFP applies to any
well where the geologic characteristics are substantially similar. The
geographic area for which an MHFP applies will be at the discretion of
the field office. The MHFP is similar in concept to the Master
Development Plan (MDP) allowed in Onshore Order 1, although the use of
one does not necessarily depend upon the use of the other. The MHFP is
specific to the technical aspects of hydraulic fracturing of a group of
wells; whereas, the MDP's purposes include encouraging logical field
development and ensuring consideration of the environmental effects
associated with development of the field in the accompanying NEPA
analysis and documentation. The MHFP and MDP can apply to different
groups of wells.
The term ``hydraulic fracturing'' was also modified by adding the
phrase ``by applying fluids under pressure.'' This change is based on
comments seeking clarification of the types of operations that fall
under the scope of this rule.
The term ``type well'' was eliminated. The BLM determined that the
use of a type well CEL as a model for other wells that were
geologically similar was not a statistically valid approach for
ensuring wellbore integrity. Because geologic conditions and drilling
procedures can vary significantly from well to well, sometimes even for
wells drilled from the same pad, a CEL on a single sample well cannot
reliably be extrapolated to other wells with any level of confidence.
Therefore, the ``type well'' concept, as it applied to CELs, is
eliminated in the final rule.
The term ``confining zone'' is added to the final rule because the
BLM is requiring the operator to identify both the confining zone and
any known faults or fractures that transect the confining zone in the
APD or NOI for hydraulic fracturing approval. The definition of
confining zone is based on the U.S Environmental Protection Agency
(EPA)'s definition under the Underground Injection Control (UIC)
program, modified to apply specifically to hydraulic fracturing.
The term ``refracturing'' was eliminated from the final rule
because the requirements for permitting, performing, monitoring, and
reporting hydraulic fracturing operations are identical whether the
well is hydraulically fractured for the first time or any subsequent
stimulation.
Usable Water
The BLM made several modifications to the definition of the term
``usable water'' in response to comments received.
The first change in the ``usable water'' definition was to
eliminate paragraph (2) from the definition in the supplemental
proposed rule because it would be unreasonable to expect an operator to
know that other users could be using an aquifer for agricultural or
industrial purposes and because an operator would have no way of
knowing if other users could be adversely affected by hydraulic
fracturing. Decisions on those matters are for state or tribal water
regulators, not the BLM. Thus, paragraph (1)(ii) in the final rule
defers to State (for Federal lands) or tribal (for Indian lands)
determinations that groundwater that does not meet the definition of
``underground sources of drinking water'' (USDWs) in EPA's regulations
are nonetheless sources of drinking water that must be protected. The
other change was to reorganize the clauses in the definition to
separate those items that would be deemed usable water from those items
that would not be deemed usable water.
Numerous commenters were confused about the threshold for Total
Dissolved Solids (TDS) in usable water. Prior to the publication of
this rule, BLM regulations (existing section 3162.5-2(d)) require the
operator to ``isolate freshwater-bearing and other usable water
containing 5,000 ppm or less of total dissolved solids . . .,'' and
Onshore Oil and Gas Order No. 2, Drilling Operations on Federal and
Indian Oil and gas leases (53 FR 46798) (Onshore Order 2), section III.
B. requires casing and cement to ``protect and/or isolate all usable
water zones.'' Usable water is defined in section II.Y of Onshore Order
2 as ``generally those waters containing up to 10,000 ppm of total
dissolved solids.'' The requirement in the CFR was inconsistent with
the requirement in Onshore Order 2.
This rule corrects the inconsistency between the two by removing
the 5,000 ppm standard in 43 CFR 3162.5-2(d) and replacing it with
language that is consistent with Onshore Order 2. The requirement to
protect and/or isolate usable water generally containing up to 10,000
ppm of TDS has been in effect since 1988, when Onshore Order 2 became
effective. This rule does not

[[Page 16142]]

substantially modify the requirements in Onshore Order 2, although it
clarifies the term by incorporating specific inclusions and exclusions
as to what constitutes usable water. The final rule keeps the 10,000
ppm threshold from Onshore Order 2 as the primary determining factor
for what constitutes usable water.
Because of the inconsistency between the supplemental proposed rule
and existing codified regulations, some commenters were under the
impression that this rule was increasing the level of protection for
usable water from 5,000 ppm to 10,000 ppm, while other commenters
believed that this rule was proposing to decrease the level of
protection from 10,000 ppm to 5,000 ppm. Neither impression is true.
This rule maintains the 10,000 ppm standard that has been in place
since 1988. The BLM still believes that a 10,000 ppm threshold is
appropriate because it is consistent with the threshold used as part of
the definition of ``underground sources of drinking water'' in EPA
regulations implementing the Safe Drinking Water Act (SDWA). The SDWA
was enacted in 1974 and is the primary Federal law that ensures the
quality of American's drinking water (www.epa.gov/lawsregs/rulesres/sdwa/). Specific comments that were based on the erroneous assumption
that the BLM was changing the TDS threshold for usable water are
summarized as follows. No changes to the final rule were made as a
result of these comments.
Numerous comments expressed concern that the requirement
to protect usable water (section 3162.5-2) as defined would result in
significantly increased costs because protecting water with TDS levels
up to 10,000 ppm would require running casing and cement much deeper
than it is currently run. Because the definition of usable water has
not substantially changed in this rule, there will be no significant
changes in costs of running casing and cement.
Many commenters thought that there was no use in
protecting water zones with TDS levels greater than 5,000 ppm, because
water with a TDS higher than 5,000 is not suitable for human,
agricultural, or industrial uses. One comment stated that the BLM
considers water with TDS levels greater than 5,000 ppm as hazardous to
wildlife. This rule does not change the primary criteria for protecting
usable water up to 10,000 ppm, which has been in place for the past 26
years. Given the increasing water scarcity and technological
improvements in water treatment equipment, it is not unreasonable to
assume aquifers with TDS levels above 5,000 ppm are usable now or will
be usable in the future.
Some commenters expressed a concern that the conflicting
definitions in Onshore Order 2 and in this rule will cause confusion
for operators. There is no conflict between the definition in this rule
and the definition in Onshore Order 2. This rule clarifies the term and
incorporates specific inclusions and exclusion as to what is deemed to
be usable water.
Several comments stated that the cost of running surface casing and
cement deep enough to protect all usable water zones, as defined, would
significantly increase the cost of drilling wells. This is an erroneous
concern. It is not uncommon for deeper usable water zones to be
protected with intermediate or production casing, which is allowed
under Onshore Order 2 and this rule. No changes to the final rule were
made as a result of these comments.
Several commenters suggested changing the definition of usable
water to exclude aquifers that are not economical or feasible to use.
The commenters said that these would include aquifers that are too
deep, too small, too remote, or are not capable of achieving some set
flow rate. No changes to the rule were made as a result of these
comments. From a practical standpoint, excluding aquifers based on
depth, size, location, flow rate, or other characteristics would be
difficult in a national rule for several reasons. For example, the
depths to which a water user might drill would depend on such factors
as the need for water, the availability of other supplies, and the
hydrologic characteristics of the aquifer (natural pressures might
raise water in a deep well closer to the surface). Excluding aquifers
from protection based on some arbitrary flow rate would be impractical.
Measuring the flow rate potential of an aquifer would be a time-
consuming and expensive process for operators to perform and for the
BLM to review. Just as with oil and gas wells, the flow rate potential
of a water well can depend on the specific location, depth, and
methodology used. Furthermore, a flow rate that is inadequate for one
type of use might be adequate for another type of use. State and tribal
agencies, and EPA under the SDWA, have the expertise and authority to
consider all the factors in characterizing groundwater.
Several commenters questioned the basis for the 10,000 ppm of TDS
in the definition. The 10,000 ppm of TDS used in Onshore Order 2 and
this rule is based on part of the definition of ``underground source of
drinking water'' in EPA's regulations implementing SDWA.
Another change made to this definition in response to comments
involved three exemptions from the definition of usable water listed in
the supplemental proposed rule. The proposed exclusions in paragraphs
(2)(i), (2)(ii), and (2)(iii) of the definition have been modified for
clarity and to better reflect the roles of EPA and states and tribes in
managing groundwater resources.
The proposed exclusion in paragraph (A) of the definition,
regarding hydrocarbon zones, was added to the supplemental proposed
rule based on comments received on the initial proposal (77 FR 27691).
Some commenters noted correctly that developing minerals from a zone
that is also a USDW requires specific authorization under the SDWA. The
BLM has edited the exclusion in former paragraph (A) \5\ to clarify
that the zone which the BLM approves for hydraulic fracturing is not
considered to be usable water only if the operator has obtained all
necessary authorizations from the EPA, the state (for public lands), or
the tribe (for Indian lands), as appropriate, for mineral development
in a USDW area.
---------------------------------------------------------------------------

\5\ For example, any activity authorized under this rule may
also require an aquifer exemption for injection activities in the
same zone if that zone is regulated by the EPA under the SDWA, even
where the zone is not considered to contain usable water under this
rule.
---------------------------------------------------------------------------

The BLM received several comments objecting to any exemptions for
protecting aquifers, as proposed in the definition of ``usable water''
under 3160.0-5. The commenters stated that it is impossible to predict
what will constitute ``usable'' water in the future, especially
considering drought and water scarcity. Therefore, they said that the
BLM should be very conservative in protecting all groundwater with a
TDS of less than 10,000 ppm. The commenters recommended deleting the
exemptions under paragraphs (A), (B), and (C) of the usable water
definition. The BLM disagrees that all groundwater with a TDS of less
than 10,000 ppm must be deemed usable water in this final rule. The TDS
is only one parameter in deciding whether water is usable. The amounts
of other types of contaminants, depth, and available alternatives are
other considerations. The final rule has modified the exemptions in
paragraphs (2)(i), (2)(ii), and (2)(iii) of the usable water definition
to clarify the central roles of states, tribes, and the EPA in
categorizing groundwater and deciding upon the proper level of
protection from

[[Page 16143]]

hydraulic fracturing operations. Those agencies have the expertise and
authority to consider all local factors and to manage groundwater
resources.
Some of the commenters suggested that the BLM should incorporate
the exemption provisions of the SDWA directly into the definition of
usable water instead of relying on designations through the SDWA.
No changes to this provision were made as a result of these
comments. The BLM has neither the authority nor jurisdiction to
designate groundwater as exempt from protection under the SDWA.
Furthermore, the final rule protects usable water, which includes, but
is not limited to USDWs. Aquifers that are not USDWs might be usable
for agricultural or industrial purposes, or to support ecosystems, and
the rule defers to the determinations of states (on Federal lands) and
tribes (on Indian lands) as to whether such zones must be protected.
One industry group seemed to favor requiring operators to determine
the TDS levels of aquifers already deemed by the state or tribe to
require protection, and said that the TDS criterion was arbitrary and
capricious, but included the same criterion in its proposed definition.
That group's argument against the TDS criterion was that it did not
consider other constituents, such as hydrocarbons, heavy metals,
microorganisms, or toxic compounds, which would make waters unsuitable
for use. The BLM's definition of usable water has for many years used a
TDS criterion and TDS is a widely recognized criterion for entities
contemplating use of particular waters. In the United States, most
users prefer waters containing 10,000 ppm TDS or less.
The BLM agrees that different water users would also be concerned
about various other water quality criteria. The most common dissolved
solids in most aquifers encountered by oil and gas operations on
Federal or Indian lands are salts. Operators can estimate salinity
levels from drill logs. Other means of measuring TDS are straight
forward and economical. The BLM declines to require operators to test
aquifers for hydrocarbons, heavy metals, microorganisms or toxic
compounds.
A few commenters mentioned that paragraphs (1) and (3) in the
definition in the supplemental proposed rule are irrelevant because
they would not occur with TDS levels above 10,000 ppm anyway. Paragraph
(1) includes in the definition of usable water all groundwater that
meets the definition of USDWs in EPA's regulations. However, the 10,000
ppm of TDS threshold established in the first sentence of the
definition is based on part of EPA's regulatory definition of
``underground source of drinking water'' under the SDWA. The commenter
concludes, therefore, that paragraph (1) is redundant and unnecessary.
Paragraph (3) includes zones designated for protection by a state or a
tribe. According to the commenters, however, there are no states or
tribes that have designated a TDS threshold higher than 10,000 ppm.
While the commenters are correct in their assertions, the BLM must
anticipate that, in the future, conditions may change. Given the
increasing threat of water scarcity and the advancement of technology,
it is foreseeable that a TDS threshold higher than 10,000 ppm may be
established under applicable law in the future for aquifers supplying
agricultural, industrial, or ecosystem needs. By including these
paragraphs in this rule, such zones would automatically be protected
from contamination by subsequent hydraulic fracturing without requiring
a rule change. No changes to the rule were made as a result of this
comment.
Several commenters stated that the BLM has no jurisdiction over the
waters of the various states. States and tribes generally administer
and regulate rights to use surface water and groundwater within their
jurisdictional boundaries. The EPA has authority over USWD in relation
to injection wells under the SDWA, although EPA can and does approve
states and tribes to implement their programs in lieu of the Federal
program. The BLM understands the importance of states and tribes
regulating the use of groundwater within their jurisdictions and
generally agrees with the commenters. However, the Mineral Leasing Act
(30 U.S.C. 181, et seq.) gives the BLM the authority to lease oil and
gas resources and to regulate the development of those leases. The
Indian mineral statutes require the Secretary to regulate oil and gas
drilling on Indian trust and restricted lands. This authority extends
to the drilling of wells and to subsequent operations on those leases.
Of primary importance when drilling or hydraulic fracturing a well is
the protection of groundwater. The BLM agrees that regulation of
groundwater quality is not within the BLM's authority; however, the
protection of those water zones during well drilling and hydraulic
fracturing is a key component of the BLM's jurisdiction and
responsibility. No changes to the rule were made as a result of these
comments.
The BLM received comments both supporting and objecting to
paragraph (2) of the definition in the supplemental proposed rule,
which included in the definition of usable water, zones in use for
supplying water for agricultural or industrial purposes, regardless of
TDS concentration, unless the operator could demonstrate that zone
would not be adversely affected. The commenters objecting to this
provision said that operators are not in a position to know whether
aquifers are in actual use, or to prove that hydraulic fracturing
operations would not harm the water user, and that BLM should not be
making determinations about groundwater use or harm to users. The BLM
agrees with those comments and removed paragraph (2) in the final rule
as a result.
Commenters supporting paragraph (2) of the definition in the
supplemental rule indicated that even if a zone is not required to be
protected according to the definition of usable water, because that
zone supplies water that is actually being used for agricultural or
industrial purposes, the zone is self-evidently ``usable.'' The BLM
agrees that an aquifer could be in actual use, even if it exceeds
10,000 ppm TDS. However, the rule defers to the state or tribal agency
to make such determinations, as appropriate. Entities using water
exceeding 10,000 ppm TDS may ask the appropriate state or tribal agency
to designate that zone as usable water, in which case it would have to
be isolated and protected from contamination during hydraulic
fracturing.
One comment suggested that the BLM--not the operator--should make
the determination that hydraulic fracturing would not harm aquifers in
use, in paragraph (2) of the definition. The BLM did not make any
changes to the rule based on this comment because proposed paragraph
(2) has been deleted from the final rule based on other comments
received.
The final rule includes a new paragraph (1)(ii) that includes in
the definition of usable water ``[u]nderground sources of drinking
water under the law of the state (for Federal lands) or tribe (for
Indian lands).'' New paragraph (1)(ii) defers to designations of
aquifers as sources of drinking by states and tribes, even if the
aquifer would not meet the definition of USDW in EPA's regulations.
That could occur, for example, if an aquifer cannot supply a public
water system, but is used for drinking water by persons not connected
to a public water system.
Several commenters found the definition of usable water in the
supplemental proposed rule to be

[[Page 16144]]

confusing because of the way it was organized. The BLM agrees with this
comment and has substantially revised the definition.
Several comments stated that the BLM should eliminate the usable
water exemption for zones that states or tribes have designated as
exempt (paragraph (4)(C) of the definition of usable water in the
supplemental proposed rule). The issue raised by the commenters is that
states and tribes typically base their exemptions on water that is
unsuitable for drinking, livestock, or irrigation, and not on
groundwater-dependent ecosystems. According to the comments, by
adopting state or tribal designations, such aquifers would not have to
be protected or isolated during hydraulic fracturing operations and
this could damage or destroy the ecosystems that are dependent on them.
The BLM did not make any changes to the rule based on these
comments for two reasons. First, while the BLM is responsible for
preventing unnecessary or undue degradation of resources on public
lands and exercising part of the Secretary's trust responsibility for
Indian resources, designating the uses of aquifers is a matter for
states and tribes, to the extent not otherwise inconsistent with the
SDWA.
Second, the BLM does not agree with the commenter's assertion from
a practical standpoint. The majority of groundwater-dependent
ecosystems would be dependent on relatively shallow groundwater.
Shallow groundwater (typically less than 1000 feet deep) is protected
by surface casing, regardless. Some commenters said that the criterion
of 10,000 ppm TDS exceeds the recommended standard for USDW. The EPA's
definition is as follows: Underground source of drinking water (USDW)
means an aquifer or its portion ``(a)(1) Which supplies any public
water system; or (2) Which contains a sufficient quantity of ground
water to supply a public water system; and (i) Currently supplies
drinking water for human consumption; or (ii) Contains fewer than
10,000 mg/l total dissolved solids; and (b) Which is not an exempted
aquifer'' (40 CFR 144.3).\6\
---------------------------------------------------------------------------

\6\ The EPA uses a TDS measurement of mg/l while the BLM uses
ppm. While there is a slight difference in the measurements, for
practical purposes they would yield very similar results.
---------------------------------------------------------------------------

The rule seeks to protect usable water, which includes, but is not
limited to, USDWs. In addition to public water supplies, there are many
industrial and agricultural applications that can use water of up to or
more than 10,000 ppm TDS. The final rule is not revised as a result of
these comments.
Some commenters suggested that the 10,000 ppm TDS criterion could
conflict with existing state groundwater standards. However, no
commenter has explained how a requirement for oil and gas wells on
Federal or Indian lands to verify isolation and protection of aquifers
with up to 10,000 ppm TDS will preempt or interfere with states' or
tribes' regulation of their ground water quality or quantity. If a
state or tribe requires aquifers of lower quality to be isolated and
protected, operators would need to comply with those requirements.
Several commenters offered their own definitions of usable water.
One suggestion was to incorporate the entire EPA definition of a USDW
instead of developing the BLM's own definition. The commenters stated
that this would improve consistency and foster cooperation between the
EPA and the BLM. The final rule references USDWs as one of the criteria
that would constitute usable water. However, USDWs do not necessarily
include water zones that have been designated by states or tribes as
usable water for agriculture, industry, or other needs. The BLM
believes that these zones are also worthy of protection. Therefore, the
BLM did not accept this suggestion.
Other suggestions recommended defining usable water as only USDWs
or zones designated by states or tribes. In the final rule, the BLM
adopted this suggestion in part by eliminating paragraph (2) of the
definition in the supplemental proposed rule, which would have also
included zones being used for agricultural or industrial purposes,
regardless of the TDS level.
One commenter stated that the BLM should require that casing used
to isolate usable water be set at least 100 feet below the base of
usable water to ensure the usable water zone is protected. Another
commenter recommended that corrosive zones and flow zones also be
isolated. The BLM did not make any changes to the rule based on this
comment because the scope of this rule is hydraulic fracturing. Well
drilling, including requirements for casing strings and zone isolation,
is regulated by Onshore Order 2 and is based on site-specific downhole
conditions.
One commenter recommended that the rule refer to ``established''
usable water zones to add clarity. The BLM did not make any changes to
the rule based on this comment because the term ``usable water'' is
clearly defined.
Hydraulic Fracturing
Numerous comments objected to the narrow focus of the definition of
hydraulic fracturing and suggested that the BLM reinstate the broader
definition from the May 2012 proposed rule. Some of the commenters
stated that this rule needs to regulate well stimulation and
acidization because these operations pose risks similar to those from
hydraulic fracturing and because the existing regulations are
inadequate to address these risks. The BLM did not revise the rule
based on these comments. This rule specifically addresses risks posed
by the combination of high pressures, chemical constituents, and
procedures used to hydraulically fracture a well. Some commenters said
that ``deep hydraulic fracturing'' should be exempt from this rule. The
definition of hydraulic fracturing includes all hydraulic fracturing
operations regardless of depth. The BLM requires protection and
isolation of usable water regardless of depth of the well or depth at
which hydraulic fracturing occurs. No changes to the rule were made as
a result of these comments.
Several commenters said that the rule should be modified to
redefine hydraulic fracturing. Commenters indicated that the definition
should include a statement regarding applying fluids under pressure.
The BLM agrees and has revised the rule as a result of these comments.
The BLM believes that an integral part of hydraulic fracturing is the
concept of the application of high pressure, and this position is
confirmed by a review of technical literature on hydraulic fracturing
as well as consultation with state regulatory agencies. The definition
in the final rule has been modified accordingly.
Refracturing
Several commenters suggested that the definition of refracturing
should be modified to exempt different stages of a multi-stage
fracturing operation. The commenters were concerned that under the
definition in the supplemental proposed rule, the BLM could consider
each stage as a refracture operation, thereby requiring a separate
permit. It is not the intent of the BLM to require a separate permit
for each stage of a multi-stage hydraulic fracturing operation and
final section 3162.3-3(i) is modified to reflect that a hydraulic
fracturing operation is considered to be complete only after the last
stage is completed. The BLM did not make modifications to the
definition of refracturing as a result of these comments because the
definition of refracturing was deleted in

[[Page 16145]]

the final rule for other reasons discussed in other sections of the
preamble.
Several commenters suggested that the rule should be modified to
treat refracturing differently than fracturing. The BLM disagrees with
these comments because there is no practical purpose in distinguishing
``fracturing'' from ``refracturing.'' The permitting, operational
issues, mechanical integrity test requirements, wellbore integrity,
disclosure and possible variances for newly drilled wells and older
previously fractured wells are the same; therefore, the BLM has removed
the term and definition of refracturing in the final rule. The primary
purpose of differentiating the two in the proposed rule was to
recognize that the information required in section 3162.3-3(e) of the
rule may not be available for older wells that would be
``refractured.'' However, upon further deliberation, the BLM determined
that would be case for any well where approval for hydraulic fracturing
was given subsequent to the drilling and completion of the well,
regardless of whether or not the well had been hydraulically fractured
previously. Therefore, the definition of refracturing is deleted from
the final rule and all references to the term are removed. The
requirements for hydraulic fracturing now apply uniformly to all
fracturing operations that meet the definition in the rule. Section
3162.3-3(a) in the final rule was modified to allow for cases where
hydraulic fracturing is approved subsequent to the drilling and
completion of a well.
Several comments recommended that any hydraulic fracturing done
within a certain amount of time of a previous fracturing job or that is
done under similar conditions as the original hydraulic fracturing,
should not be considered refracturing. The BLM did not make any changes
based on this comment because the term ``refracturing'' was deleted
from the final rule. This rule applies whenever pressure is used to
fracture reservoir rock, regardless of how or when the operation occurs
relative to a previous hydraulic fracturing.
One comment recommended specifically excluding ``enhanced oil
recovery using carbon dioxide'' from the scope of this rule. However,
if carbon dioxide or any other gas is used under pressure to fracture
reservoir rock, the operation poses much the same risk as if the
fracturing was done using a liquid as the fracturing fluid. The term
``fluid'' in the definition of hydraulic fracturing includes both
liquids and gases. However, if the carbon dioxide or other fluid is
injected not to fracture reservoir rock, but to stimulate production by
other means, it would not be a hydraulic fracturing operation.
What constitutes ``completion?''
Several commenters said that the rule should be modified to define
what constitutes the completion of hydraulic fracturing operations. The
commenters indicated that the supplemental proposed rule would require
the submittal of a completion report within 30 days of completion of
hydraulic fracturing operations. The BLM did not revise the rule as a
result of these comments. The BLM does not believe that a definition of
``completion'' is warranted in the context of these regulations. By
definition, hydraulic fracturing ends when pressure is released for the
last stage of the operation. It is at this point that the 30-day
timeframe would begin for each well that is hydraulically fractured.
CEL Definition
Several commenters said that the term ``micro-seismograms'' should
be dropped from the list of CEL tools discussed in supplemental section
3163-3(e)(2). Commenters indicated that the term ``micro-seismogram''
as currently used does not refer to evaluating cement quality and is
therefore confusing when included in cement evaluation provisions. The
commenters said that conventional cement bond logs (CBL) used for the
purposes of evaluating cement integrity around casing can be displayed
by a variety of methods. One of those techniques was termed ``micro-
seismogram'' (MSG) and referred to the x-y presentation of the entire
received signal. Another presentation method, the variable density log
(VDL), only displays the amplitude of that signal. Either, or both, of
these presentation methods can be used to evaluate the integrity of the
cement bond to casing and formation. It is true that the term ``micro-
seismogram'' has much broader implications than just cement evaluation,
and the rule has been modified as a result of these comments. The CEL
discussion has been removed from the regulatory text at proposed
section 3162.3-3(e)(2) and placed as a unique definition in the final
rule in section 3160.0-5. Further, the CEL definition has been revised
to remove any references to ``micro-seismograms.'' The BLM believes
that this clarifies the intent of the rule. Additionally, section
3162.3-3(e)(2)(i) has been revised to provide flexibility for the
authorized officer to approve other appropriate cement evaluation
methods or devices.
Type Well
Numerous commenters suggested that limiting the multiple well
permitting, or type well, availability (referred to as Master Hydraulic
Fracturing Plan in this rule) to a ``field'' in the definition was too
restrictive and would nullify most of the benefits of a group
submittal. Some commenters recommended that the BLM should better
define what is meant by a ``field''. Commenters offered numerous
suggestions on the extent of what an MHFP should cover including
``basin,'' ``pool,'' ``area,'' ``resource play,'' ``geographic area,''
``geologic formation,'' ``section,'' ``unitized area,'' and ``county.''
The BLM agrees that the term ``field'' is potentially too limiting, and
has deleted the requirement that wells included in the scope of an MHFP
must be in the same field. However, the BLM disagrees that other terms
such as those suggested would be preferable. Therefore, in the final
rule, the criteria for the scope of an MHFP are wells that are
geologically similar. Under this rule, the decision on the geographic
or geologic extent of an MHFP is up to the field office reviewing the
application and is based on local geology and drilling practices.
Several commenters asked if there would be any limits on the number
of wells or the timeframe over which a multiple well permit could apply
to other wells in a group submission for hydraulic fracturing. Under
the final rule, the MHFP applies to any number of wells that meet the
criteria in the definition of an MHFP and there is no specific
timeframe for when wells under an MHFP must be drilled. Decisions
regarding the applicability of wells under an MHFP are made at the BLM
field office based on local geologic conditions and drilling practices.
Several commenters suggested two definitions of type well: One that
would apply to permitting and one that would apply to operations such
as running a CEL. The BLM did not revise the rule based on these
comments because the term ``type well'' is deleted in the final rule.
While the option of permitting a group of wells to be hydraulically
fractured is retained in the final rule (now called an MHFP), the
requirement to run a CEL on a type well is deleted and replaced with
new requirements that will help to ensure adequate cementing and
protection of aquifers (see final section 3162.3-3(e)).
The BLM received several comments stating that to be considered a
type well, the operator must demonstrate successful replication of
operations. No changes to the rule were made as a result of this
comment because type

[[Page 16146]]

wells are deleted in the final rule. For group submittals under an
MHFP, the BLM field offices have the discretion to require individual
permitting of wells if the operator is unable to successfully replicate
the operations described in an MHFP.

Section 3162.3-2 Subsequent Well Operations

Revised sections 3162.3-2(a) and (b) no longer contain reference to
nonroutine or routine fracturing jobs. All other injection activities
must still comply with section 3162.3-2, while hydraulic fracturing
operations must comply with the requirements under revised section
3162.3-3.

Section 3162.3-3(a) Scope

Section 3162.3-3 lists the requirements concerning all hydraulic
fracturing operations and paragraph (a) of this section establishes the
conditions under which some wells may be exempted from certain
requirements (or ``grandfathered'' in) as a way to transition from the
previous regulations to these regulations.
The BLM made several changes to paragraph (a) of the final rule.
The term ``refracturing'' is removed from the activities to which this
section applies, because the term ``refracturing,'' and all references
to it are deleted in the final rule.
In addition, a table is added to this section to clarify how the
rule will be implemented with regard to wells in various stages of
permitting, drilling, and completion. In general, any well that is
drilled after June 24, 2015, or that was drilled more than 6 months
before June 24, 2015 must comply with all parts of this rule, including
the permitting, cementing, mechanical integrity testing, monitoring,
handling and storage of recovered fluid, and reporting requirements.
However, in order to reduce the economic and workload impacts of
implementing this rule, there are three categories in which an operator
can hydraulically fracture a well without submitting a new APD or NOI
under sections 3162.3-3(c) and (d).
If an operator has an APD approved within the 2 years immediately
prior to June 24, 2015, but has not commenced drilling operations, or
has commenced drilling prior to June 24, 2015, but has not completed
those operations, or has completed drilling operations within the 6
months immediately prior to June 24, 2015, and commences hydraulic
fracturing operations within 90 days after June 24, 2015, the operator
does not need to submit a new APD or NOI, or await the approval of the
BLM before commencing hydraulic fracturing operations. The operator
will need to comply with the provisions of paragraphs (b), (e), (f),
(g), (h), (i), and (j) of the rule.
Those provisions are added to paragraph (a) to reduce costs and
scheduling conflicts that could arise otherwise, while still ensuring
safe and responsible hydraulic fracturing operations. Operators
typically schedule hydraulic fracturing services 6 months in advance,
though the requirements of every market are different. The BLM
determined that the 90 days between publication of this the final rule
and its effective date, plus an additional 90 days provided in
paragraph (a) will be adequate to accommodate most potential scheduling
conflicts. If the operator wishes to conduct hydraulic fracturing more
than 90 days after June 24, 2015, under each of these three scenarios,
however, the operator must comply with all of the paragraphs in this
section, including submission of an application and obtaining approval
from BLM to conduct hydraulic fracturing operations.
The final category in the table in paragraph (a) is wells for which
drilling operations are completed prior to the effective date of the
rule and hydraulic fracturing operations are conducted more than 6
months after the effective date of the rule. Operators would need to
obtain the BLM's approval to conduct hydraulic fracturing operations,
but not all operators would have the cementing verification records
that are required for new wells. Rather than prohibit hydraulic
fracturing of wells for lack of documentation not required at the time
of construction, the rule provides in section 3162.3-3(e)(1)(ii) that
operators must provide the relevant documentation that is available,
and that the BLM may require additional testing or verifications on a
case-by-case basis. For any existing well, an operator may request
approval to conduct hydraulic fracturing operations by submitting an
NOI under paragraph (c)(2) of the final rule.
Several commenters stated that the rule should be modified to
further clarify the scope of this rule as it relates to injection
activities. The commenters indicated that the provisions at this
section cloud whether or not the majority of this rule applies to other
injection or disposal operations. The BLM has revised the rule as a
result of these comments. Injection activities have been removed from
this section to avoid any confusion because injection is specifically
addressed by existing section 3162.3-2. The BLM believes this change
provides the necessary clarity regarding scope.

Section 3162.3-3(b) Isolation of Usable Water

The only change made to this section of the final rule is the
deletion of the term ``refracturing'' because it, and all references to
it, are removed from the rule. The BLM received no substantive comments
on this section.

Section 3162.3-3(c) How To Apply for Hydraulic Fracturing Approval

This section requires an operator to submit a proposal for
hydraulic fracturing to the BLM for approval. The operator may submit
an application for a single well or for a group of wells under an MHFP.
Prior to this rule, the regulations only required an NOI for ``non-
routine'' hydraulic fracturing operations. The application requirement
in the final rule is a new process. The request for approval of
hydraulic fracturing may be submitted with either an APD or as an NOI.
Numerous changes were made to this section in the final rule. The
description of how to apply for the hydraulic fracturing of multiple
wells is moved from section (d) of the supplemental proposed rule to
section (c)(3) of the final rule because it has more to do with the
permitting process than the information that an operator must submit to
the BLM. This section also references an MHFP instead of a type well,
as proposed in the supplemental proposed rule. A discussion of the MHFP
is given in the definitions section of the preamble.
The final rule revises some of the conditions under which an
operator would have to resubmit a request for approval to hydraulically
fracture a well. In the supplemental proposed rule (section 3162.3-
3(c)(3)(i)), an operator would not have had to get approval to
refracture a well if the refracturing was done within 5 years of the
original fracturing approval. The premise of this requirement was that
an MIT, required prior to fracturing under section 3162.3-3(f) of this
rule, is typically valid for a period of 5 years in some state
regulations (e.g., Colorado, Montana, and Wyoming) for MITs. The BLM
originally believed that because an MIT was required prior to the
original hydraulic fracturing operation, it would not be necessary to
re-run the MIT for a period of 5 years after that. However, upon
further examination, the BLM determined that the 5-year timeframe for
MITs in these state regulations is for the purpose of ensuring wellbore
integrity for injection wells under the UIC program and has little
relevance to hydraulic fracturing.

[[Page 16147]]

The BLM now believes that an MIT should be required prior to any
hydraulic fracturing operation because of the high pressures and
wellbore configurations used (such as a fracturing string) during
hydraulic fracturing operations. Therefore, the final rule is revised
to require approval and compliance with all sections of this rule for
all fracturing operations, whether the well is being refractured or
fractured for the first time (some hydraulic fracturing operations may
not have to comply with sections (c), (d), or (e)--see the table in
section (a)).
The supplemental proposed rule (section 3162.3-3(c)(3)(i)) would
also have required the operator to resubmit an NOI for hydraulic
fracturing if fracturing had not commenced within 5 years of the
original approval. This requirement is deleted in the final rule
because the BLM determined that as long as the proposal for hydraulic
fracturing had not changed and there was no new information regarding
the geology or potential impacts, the 5-year time frame was
unnecessary. If the operator has significant new information about the
geology of the area, the stimulation operation or technology to be used
or potential impacts, it must submit a new NOI.
The final rule also eliminates paragraph (c)(3)(iii) in the
supplemental proposed rule because it dealt with refracturing, a term
that is deleted in the final rule along with all references to it.
Some commenters requested that the BLM eliminate the requirement
for prior approval of hydraulic fracturing operations, suggesting that
it would be unnecessary and costly. As stated in the background section
of this rule, the BLM believes this rule is necessary, and prior
approval is an essential part of this rule. The information included in
the application allows the BLM to evaluate the proposal and to assess
the potential impacts of the proposal. Prior approval allows the BLM to
mitigate potential impacts through modification of the proposal or by
attaching conditions of approval, after compliance with other statutes,
such as NEPA.
Several commenters expressed concern that many of the items
requested in the application, such as estimated total volume of fluid
to be used and anticipated surface treating pressure range, are not
known at the time the application is submitted. The BLM recognizes that
exact volumes and pressures will not be known at the time the
application is submitted, and the provisions at final section 3162.3-
3(d) allow flexibility by requiring estimated or anticipated values.
The items are necessary to allow the BLM to assess the proposal and
ensure adequate storage for the fluids and proper casing strength to
withstand the anticipated pressures.
Another commenter suggested eliminating some of the requirements
needed for approval because Onshore Oil and Gas Order No. 1, Oil and
Gas Operations; Federal and Indian Oil and Gas Leases; Approval of
Operations (72 FR 10308) (Onshore Order 1), section III. D. 3, already
requires them, and they are included with the APD. As stated in final
section 3162.3-3(c)(1), the operator may submit the information
required in paragraph (d) of this section with its APD. If the
information is already included in the APD, it would not need to be
repeated. Another commenter recommended eliminating some of the
requirements in the application, since those items will be included in
the subsequent report of operations. The information in the application
is necessary for the BLM to assess the potential impacts of the
proposed operation; additionally, some of the information requested in
the application is identified as proposed or estimated. The information
required in the Sundry Notice and Report on Wells (Form 3160-5) as a
subsequent report (``subsequent report'') is the actual data from the
completed hydraulic fracturing operations. No revisions to the rule
were made as a result of these comments.
One commenter suggested that the BLM should allow a ``type frack''
approval instead of a type well approval. While the BLM is unclear what
the commenter is specifically referring to, the BLM assumes that the
commenter means that the hydraulic fracturing operation itself be
approved for a group of wells. The BLM believes that the final rule's
MHFP submission addresses this comment. The MHFP will allow an operator
to describe a generic hydraulic fracturing process for a group of wells
by providing the information required in section 3162.3-3(d) for those
wells. No changes to the rule were made as a result of this comment.
Numerous commenters objected to permitting hydraulic fracturing for
a group of wells. Some of the commenters stated that geologic
conditions are too variable to allow any kind of group permitting while
other commenters stated that the extent of the grouping should be
explicitly defined and that strict limitations should be placed on the
maximum allowable extent of an MHFP. The BLM disagrees with these
comments because rigid, detailed criteria for what can be considered in
an MHFP is not practical in a national rule of general applicability.
The local field office must have some flexibility to define the extent
of an MHFP based on local geology, drilling practices, and other
applicable criteria. No revisions to the rule were made as a result of
this comment. The benefits of an MHFP are that it allows the BLM to
frontload its analysis of proposed hydraulic fracturing operations in a
given area where the geologic characteristics for each well are
substantially similar. It also provides early notice to the public of
where such operations are being contemplated, and of the scale or
intensity of the development. This frontloaded analysis provides the
BLM with the tools necessary to perform a more comprehensive and
streamlined review of hydraulic fracturing proposals, while maintaining
the appropriate standards that ensure wellbore integrity and useable
water protection.
Several commenters suggested that exploratory wells could be used
as type wells because they were drilled vertically through the target
formations and lithologic and reservoir data was obtained from them.
Other commenters suggested that wells drilled by other operators could
be used as a type well, while some commenters stated that type wells
must be drilled by the same operator because drilling practices vary
between operators. No revisions to the rule were made as a result of
these comments because the requirement to drill a type well in order to
receive approval to hydraulically fracture a group of wells with a
single permit submittal is deleted in the final rule. The MHFP, which
replaces the type well concept, is required to contain the information
in sections 3162.3-3(d)(1) through (d)(7); however, the well integrity
information required by section 3162.3-3(e) is not required to be
included in the MHFP. Rather, the well integrity information required
by section 3162.3-3(e) must now be submitted for each well 48 hours
prior to commencing hydraulic fracturing. The MHFP only applies to
wells drilled by the same operator. Section 3162.3-3(c)(3) states that
``the operator may submit a MHFP,'' thereby eliminating the possibility
that an MHFP could apply to wells drilled by multiple operators. The
BLM decided to restrict MHFPs to wells drilled by the same operator
because doing otherwise would be difficult to administer and the BLM
believes that drilling by different operators would only apply in rare
instances.
Several commenters asked that the BLM allow the type well concept
to include fracture modeling. The MHFP, which replaces the type well
concept for permitting, requires all information required in sections
3162.3-3(d)(1)

[[Page 16148]]

through (d)(7) to be included in an MHFP. Final section 3162.3-
3(d)(4)(iii) requires the operator to submit a map showing the
estimated fracture direction and length. Although the final rule does
not require fracture modeling, it would fulfill the requirements of
this section. No revisions to the rule are made as a result of these
comments because the rule already allows fracture estimations or
modeling to be applied to a group of wells under an MHFP.
Several commenters stated that the CEL for a type well should be
applicable to wells that meet the criteria for group approval, but were
submitted under a separate NOI. The BLM did not revise the rule as a
result of these comments because the requirements to run CELs on type
wells and submit the results of the CEL as part of the group approval
package are eliminated in the final rule. Several comments suggested
that for group hydraulic fracturing submissions, the operator should be
required to certify that the cement, fracturing fluids, and drilling
practices for all wells included in the submission comply with the
information submitted in the MHFP. The BLM did not incorporate this
suggestion into the final rule because a certification is not necessary
to ensure compliance with the approved NOI for multiple wells, and
because information related to well integrity is now required for each
individual well. Any unapproved deviation from the approved NOI and
MHFP would be considered a violation and would be enforced under
existing subpart 3163, Noncompliance, Assessments, and Penalties. One
comment said that the option to permit multiple wells will not help
operators who do not drill wells in groups. In the final rule, MHFPs
will primarily streamline the permitting process for operators who are
hydraulic fracturing multiple wells within an area having similar
geology. No revisions to the rule were made as a result of this
comment. The fact that not every operator can take advantage of a
provision of the rule designed to streamline the process does not make
that provision undesirable or unnecessary.

Section 3162.3-3(d) Application for Hydraulic Fracturing

This section specifies that the application must include:
Information about the geology and the formation, confining
zones, usable water (depths estimated), faults and fractures, location
of water supply, and transportation method. This information is
generally consistent with the requirements in Onshore Order 1;
Information about the proposed hydraulic fracturing
operation, the volume of fluid to be used, the maximum anticipated
surface pressure, wellbore trajectory, the estimated direction and
length of fractures, and the locations, trajectories, and depths of
existing wellbores within a half mile of the wellbore; and
Information about how the operator will handle recovered
fluids, the estimated volume of fluids to be recovered, and the
proposed disposal method.

Operators planning to conduct hydraulic fracturing should already
possess that information because hydraulic fracturing is a complex
operation and would only be conducted pursuant to a plan for
performance.
The final rule incorporated several revisions to this section.
Requirements relating to an MHFP (referred to as a submission for a
group of wells in the supplemental proposed rule) are moved from
section (d) to section (c) because section (c) has to do with how to
apply for hydraulic fracturing approval. A discussion of the MHFP is
given in the definitions section and the response to comments on the
type well in the proposed rule are addressed in the discussion of
section (c).
Section 3162.3-3(d)(1) in the supplemental proposed rule would have
required the operator to identify the geologic formation that would be
hydraulically fractured, including measured depths of the top and
bottom of the formation. The final rule requires that the operator
identify both the measured depths and the true vertical depths of the
formation to be hydraulically fractured (paragraph (d)(1)(i)). This
section of the final rule also requires the operator to identify the
measured and true vertical depths of the confining zone (paragraph
(d)(1)(ii)).
The requirement to identify usable water zones is moved from
paragraph (d)(2) in the supplemental proposed rule to final paragraph
(d)(1)(iii), along with a new requirement to state the measured and
true vertical depths of the top and bottom of all usable water zones.
The requirement to identify occurrences of usable water with a drill
log in the supplemental proposed rule is deleted in the final rule. The
BLM determined that it is not always necessary or practical to require
a drill log to identify usable water and that there is no reason to be
prescriptive about how usable water is identified. The BLM made these
changes for several reasons. First, the BLM believes that by grouping
all informational requirements relating to wellbore geometry into a
single section, the clarity of the regulation is improved. Second, the
BLM added a requirement to identify the ``true vertical depth'' of tops
and bottoms of all the geologic zones in order to ascertain the
vertical separation between zones. Also, under the final rule, the
operator is required to identify the confining zone that is capable of
preventing fluid migration between the zone that will be hydraulically
fractured and any usable water zones.
Section 3162.3-3(d)(2) is revised in the final rule to require the
operator to submit a map showing any faults or fractures within one-
half mile of the wellbore trajectory that may transect the confining
zone. This will allow the BLM to identify and analyze during the permit
review process any potential for hydraulic fracturing fluid to migrate
outside of the zone being fractured.
Section 3162.3-3(d)(3) in the supplemental proposed rule is
separated in the final rule to improve clarity. This section in the
supplemental proposed rule contained requirements for down-hole
information (e.g., depth of perforations, estimated pump pressures) as
well as information on water supply and transportation routes. In the
final rule, section (d)(3) is now specific to water supply and
transportation routes; downhole information is moved to section (d)(4),
which is specific to the technical aspects of hydraulic fracturing.
Several changes are made to supplemental proposed rule section
3162.3-3(d)(4) to improve clarity and to identify potential ``frack
hits.'' ``Frack hit'' is a common term for a hydraulic fracturing
operation that causes an unplanned surge of pressurized fluid into
another well, often resulting in surface spills. The supplement rule
required three different pressures to be included in the application:
Estimated pump pressure (paragraph (d)(3) in the supplemental proposed
rule), anticipated surface treating pressure range (paragraph
(d)(4)(ii) in the supplemental proposed rule), and maximum injection
treating pressure (paragraph (d)(4)(iii) in the supplemental proposed
rule). In the final rule, those three pressures are replaced with a
single pressure to be reported: The maximum anticipated surface
pressure that will be applied during operations. The BLM determined
that this was the clearest and most useful pressure because this will
be the pressure at which the MIT must be run under section 3162.3-3(f)
of the rule. This change is also made to eliminate the term
``treating,'' which may not be universally understood.

[[Page 16149]]

Section 3162.3-3(d)(4)(iii) in the supplemental proposed rule would
have required the operator to submit the estimated fracture direction,
length, and height, along with a map showing the estimated fracture
propagation. The final rule adds several additional requirements to
this section that will allow the BLM to determine during the permit
review process the potential for ``frack hits.'' In addition to the
fracture propagation (including direction and length), the map must
also show the trajectory of the wellbore into which hydraulic
fracturing fluid will be injected and the trajectory of all existing
wellbores and trajectories within one-half mile of the wellbore that
will be used for hydraulic fracturing. Additionally, the required map
must identify the true vertical depth of each wellbore shown on the
map.
Section (d)(4)(v) in the supplemental proposed rule, requiring the
estimated vertical distance to the nearest usable water aquifer above
the fracture zone, is reworded for clarity. In the final rule, section
(d)(4)(iv) requires the estimated minimum vertical distance between the
top of the fracture zone and the nearest usable water zone.
Section (d)(5) in the supplemental proposed rule, regarding the
handling of recovered fluid, is reworded in the final rule to conform
to changes made to section (h). The only period for which information
on handling recovered fluid is necessary under the final rule is the
period between the completion of hydraulic fracturing operations and
the approval of a water disposal plan under Onshore Order 7. A complete
discussion of this change is given under section (h) of this preamble.
Section (d)(5)(iii) in the supplemental proposed rule is clarified
in the final rule by better defining ``handling'' versus ``disposal.''
In the supplemental proposed rule, disposal included injection, hauling
by truck, or transporting by pipeline. The BLM recognizes that hauling
by truck or transportation by pipeline are not disposal methods, but
transportation methods. In the final rule, the disposal options include
injection, storage, and recycling.
Section (d)(6) of the final rule is added to include additional
information requirements if the operator requests approval for
hydraulic fracturing in an NOI instead of in an APD. One of these
requirements (section (d)(6)(i)) is a surface use plan of operations if
the hydraulic fracturing operation would include additional surface
disturbance. If the request was received as part of an APD, the surface
use plan of operations would already be included.
The other requirement is, by reference to paragraph (e),
documentation that an adequate cement job was achieved for all casing
strings designed to isolate usable water zones.
Pre-Disclosure
A few commenters asked that the volume and chemical composition of
flowback water be disclosed in the permit application. Section 3162.3-
3(d)(5)(i) of the final rule requires the operator to provide the
estimated volume of fluid to be recovered in its application. The
projected chemical composition of this fluid is not required. Providing
the chemical composition of the recovered fluid would require
speculation as to the chemistry of fluids in the target zone, and their
reactions, if any, with the hydraulic fracturing fluids and therefore
would be impractical to request, and not likely to be useful. The BLM
has determined that operators often change the chemical composition of
hydraulic fracturing fluids after approval of fracturing operations, in
response to such factors as availability of chemicals, changes in
vendor, and unexpected geologic conditions. Thus, the reliability of
the pre-operational estimated composition of flowback fluids likely
will not be known with precision at the application stage. It is
important at the approval stage, however, for the operator to show that
it has an adequate plan to manage and contain the recovered fluids that
would prevent them from contaminating surface water or groundwater
without regard to their specific chemical composition. The rule
presumes that all recovered fluids would pose hazards to surface or
ground water if they are not properly isolated. No revisions to the
rule were made as a result of these comments.
Some commenters requested that the BLM require up-front disclosure
of the chemicals proposed for use in the hydraulic fracturing fluid and
that this information be publicly available. Commenters asserted that
chemicals must be disclosed both before and after well stimulation in
order to achieve the BLM's goals of protecting public health and the
environment. The rule is not revised based on these comments. Analysis
of the impacts from hydraulic fracturing is done as part of the NEPA
analysis conducted prior to the issuance of permits. The exact
composition of the fluid proposed for use is not required because the
BLM's goal is to ensure that operators contain all fluids regardless of
their composition. All fluids are conservatively treated as if they are
hazardous and need to be contained. In undertaking NEPA analysis to
support the Bureau's decision to issue a permit, the BLM will assume
that the chemicals used in conducting hydraulic fracturing operations
may be hazardous. The BLM believes that the post-fracturing disclosures
and certifications of chemicals and additives provide adequate
information for other purposes, such as to inform the community of the
chemicals involved, and to assist in clean-up of any spills.
Several commenters suggested that all of the information required
in the subsequent report should be disclosed in the application for
hydraulic fracturing approval. The BLM did not make any changes to the
rule as a result of these comments because not all of the information
required in the subsequent report is relevant or available at the time
the operator submits the application. When the proposal for hydraulic
fracturing is submitted with an APD, items such as well logs are not
available because the well has not yet been drilled.
The original proposed rule required the NOI to contain a
certification signed by the operator that the proposed treatment fluid
complies with all applicable permitting and notice requirements as well
as all applicable Federal, tribal, state, and local laws, rules, and
regulations. That requirement was deleted in the supplemental proposed
rule. Some commenters supported eliminating this requirement while
other commenters requested that the originally proposed requirement be
reinstituted. As was stated in the preamble of the supplemental
proposed rule, the BLM believes that requiring this certification after
the operator has completed hydraulic fracturing operations (see final
section 3162.3-3(i)(8)) adequately protects Federal and Indian lands
and resources and, therefore, the burden on industry of providing the
information and on the BLM of reviewing that information at the
application stage is not justified. The commenters requesting the
requirement be reinstituted stated the rule removes the first layer of
accountability for industry by not even requiring them to say they will
comply with permitting, and the lack of certification removes a tool to
hold operators accountable to follow the regulations. The BLM
disagrees. The operators are required to comply with all applicable
laws and regulations, regardless of when the information is submitted.
A certification in the NOI does not add any value to the permit and
lack of a certification in the notice does not restrain enforcement in
the future. Therefore, no revisions to the

[[Page 16150]]

rule are made as a result of this comment.
Several comments suggested that the BLM allow a ``master chemical
plan'' to be submitted for wells that are proposed for hydraulic
fracturing in the same field. According to the commenter, this plan
could be used for routine hydraulic fracturing operations to help
streamline the permitting process. However, the BLM is not requiring
chemical disclosure prior to hydraulic fracturing, so a specific
``master chemical plan'' is unnecessary.
Confining Zone
Numerous comments said that the rule should be modified to add a
definition of ``confining zone.'' Additionally, the commenters
indicated that the NOI required at 43 CFR 3162.3-3(d) should include
the identification of an impermeable confining zone that would protect
water sources from vertical migration of hydraulic fracturing fluids
and associated brines. The BLM agrees with these comments. The final
rule includes a definition of confining zone and a requirement that
operators identify the measured and true vertical depths of the top and
bottom of the confining zone in their permit application. In addition,
in the final rule the operator must identify all known faults and
fractures within one-half mile of the wellbore that transect the
confining zone. These additions will allow the BLM to further ensure
that the hydraulic fracturing fluid will not migrate outside of the
intended zone in order to protect usable water.
Several comments asked that the BLM specify a minimum ``vertical
buffer'' between the zone that is to be hydraulically fractured and the
deepest aquifer. The BLM did not include this requirement in the final
rule because the BLM must maintain the flexibility for field offices to
review hydraulic fracturing applications on a case-by-case basis and
apply site-specific conditions of approval. A minimum vertical distance
that is appropriate in one area might be inadequate or overly
restrictive in other areas based on the intervening geology.
Furthermore, fracking technologies are likely to continue to improve an
operator's control over the propagation of fissures.
Master Drilling Plan
Several commenters said that the rule should be modified to allow
operators to submit a field-specific casing design and cementing plan
and subsequently submit verification of a successful cement job. The
BLM did not revise the rule as a result of these comments. This comment
addresses the concept of a Master Development Plan (MDP) that is
already described in and provided for by Onshore Order 1 for newly
drilled wells. The MDP addresses the casing and cementing design of all
of the wells within that MDP. Drilling operations and the associated
MDP process is outside the scope of this rulemaking.
One commenter suggested that fracture modeling could be done for a
group of wells instead of requiring a model for every well. The BLM did
not revise the rule as a result of this comment for two reasons. First,
neither the proposed rules nor the final rule require fracture
modeling. Both allow for submittal of ``estimated'' fracture data.
Second, fracture estimates for zones that are in substantially similar
geologic regimes could be included in the MHFP under final section
3162.3-3(c).
Use of Estimates
One commenter expressed concern with the use of the term
``estimate'' in the supplemental proposed rule as it pertains to
operator submissions under section 3162.3-3(d). The commenter stated
that the BLM would be unable to ensure the protection of usable water
zones if the operator is allowed to submit estimates. The BLM disagrees
with this comment. This provision allows the operator to estimate some
items, such as the depth of usable water and the pump pressure, in the
APD and NOI. Allowing estimates in the APD and NOI instead of actual
information does not compromise the safeguards for protection of usable
water. At the time the APD and NOI is submitted, in many instances some
of the required information cannot be known for certain, because the
well has not yet been drilled. The estimates provide the BLM with
sufficient information to evaluate the potential impacts of the planned
operation and to ensure that usable water zones are adequately
protected. No revisions to the rule are made as a result of this
comment.
Changes From Original Proposed Rule
One commenter expressed concern that the changes made to the
requirements in the NOI from the original proposed rule to the
supplemental proposed rule do not seem designed to provide adequate
safeguards for ecological and human resources. The BLM disagrees with
this comment. The changes from the original proposed rule to the
supplemental proposed rule were based on the comments received from
individuals, Federal and state Governments, and agencies, interest
groups, and industry representatives. The changes to each section and
the rationale for the changes were discussed in the preamble of the
supplemental proposed rule. One of the primary goals of the rule is to
provide adequate safeguards for resources in and on the public lands
and tribal lands, and thus for the persons who use those resources. The
BLM believes the changes proposed in the supplemental proposed rule and
the provisions of the final rule, along with existing processes for
reviewing and approving oil and gas development proposals, accomplish
that goal.
Permitting Multiple Wells With an NOI
The supplemental proposed rule would have allowed an NOI to be
submitted for a group of wells within the same geologic formation. One
commenter suggested that the rule be required to specify the location
of all wells where fracturing will take place. The commenter was
concerned that if this is not specified, and notice is submitted in the
form of a Sundry Notice for a group of wells, the location of each well
will not be clear. The BLM disagrees with the commenter. Operators use
Sundry Notices (Form 3160-5) to request approval to conduct operations
and to subsequently report on operations after they are finished.
Sundry Notices are used for all operations, not just hydraulic
fracturing, and have been required for many years. The Sundry Notice
form itself requires the operator to identify the lease number, the
well number, and the location of the well. If a Sundry Notice is
submitted for multiple wells, the Sundry Notice must contain a list of
all of the wells including the lease number for each well and the legal
land description of the location of each well. While this is not
explicitly stated in the rule, the Sundry Notice form requires it. No
revisions to the rule were made as a result of this comment.
Submission of State/Tribal Data
Numerous commenters said that in states where there is already a
regulatory process for hydraulic fracturing, an operator should be
allowed to submit the same information to the BLM as it does to the
state. Both the supplemental and final rules include provisions that
address the commenters concern. The first (section 3162.3-3(d)) allows
information submitted in accordance with state law to be submitted to
the BLM if the information meets the standards of this rule. The second
(section 3162.3-3(k)) allows the BLM to issue a statewide or regional
variance to use particular state or tribal regulations and processes
for permitting hydraulic fracturing

[[Page 16151]]

operations if they meet or exceed the objectives of this rule. Because
the commenter's concerns were already addressed in the rule, no changes
were made as a result of these comments.
One commenter requested that the BLM clarify the following
statement in section 3162.3-3(d): ``If information submitted in
accordance with state (on Federal lands) or tribal (on Indian lands)
laws or regulations meets the standards prescribed by the BLM, such
information may be submitted to the BLM as part of the Sundry Notice.''
This language has been clarified in the final rule. Many of the
comments received in response to the initial proposed rule and the
supplemental proposed rule were critical of duplication between state
or tribal regulations and the supplemental proposed rule. The statement
in this section is meant to address those concerns and minimize any
duplication. If the information submitted to states or tribes meets the
standards in this section, the operator does not need to generate any
new information. Operators may submit the information that was
generated to meet the state or tribal requirements to the BLM. To
better reflect the BLM's intent, the statement has been modified in the
final rule for additional clarity, although no substantive change was
made to the statement.
Restructure Items for Clarity
Some commenters recommended that sections 3162.3-3(d)(3) and
3162.3-3(d)(4) be restructured to add clarity to the requirements.
Commenters said that the information required in section 3162.3-3(d)(3)
of the supplemental proposed rule included the proposed measured depth
of the perforations or the open-hole interval and included information
concerning the source and location of the water to be used during
hydraulic fracturing. While this information is still needed, the items
are distinct, and therefore should be separate requirements. The BLM
agrees with these comments and sections 3162.3-3(d)(3) and 3162.3-
3(d)(4) are restructured in the final rule. Section 3162.3-3(d)(3) now
requires information concerning the source and location of the water
supply. In addition, the requirement for the measured depth of the
proposed perforated or open-hole interval is moved to section 3162.3-
3(d)(4)(v). The information regarding the proposed perforated interval
is now a distinct requirement, and this information relates more
closely with the other information required by section 3162.3-3(d)(4).
Identification of Usable Water
Some commenters expressed concern that the requirement to identify
usable water zones placed an increased and substantial burden on
operators. The commenters stated that the current practice is not for
operators to identify ``usable water'' zones for protection and then
submit the information to state oil and gas agencies or BLM offices for
approval, but instead for these agencies to prescribe to operators
which zones must be protected. The commenters' perception of existing
requirements is incorrect. Section III.D.3.b. of Onshore Order 1
requires operators to provide the estimated depth and thickness of
formations, members, or zones potentially containing usable water, and
the operator's plans for protecting such resources. Section III.B. of
Onshore Order 2 requires that the proposed casing and cementing
programs be conducted as approved to protect and/or isolate all usable
water zones. It goes on to require that determination of casing setting
depth must be based on all relevant factors, including usable water
zones. It also requires that all indications of usable water be
reported. This final rule requires the operator to identify the
measured or estimated depths (both top and bottom) of all occurrences
of usable water. This requirement is consistent with the existing
requirements in Onshore Orders 1 and 2 and does not place an increased
burden on the operators. No revisions to the rule were made as a result
of these comments. The BLM agrees, however, that in many instances
state or tribal oil and gas regulators, or water regulators, will be
able to identify for operators some or all of the usable water zones
that will need to be isolated and protected.
One commenter recommended that the operator must inform the BLM of
the locations, geologic formations, and depth of the usable water zones
prior to initiating fracking operations. The commenter stated that this
is of prime importance to people living in the vicinity of fracking and
they need some certainty that the fracking operations will not impact
their water resources. The BLM agrees. Some of this information is
already required of the operators prior to drilling the well. Section
III.D.3.b. of Onshore Order 1 requires operators to provide the
estimated depth and thickness of formations, members, or zones
potentially containing usable water, and the operator's plans for
protecting such resources. The BLM uses this information in the
evaluation of the well proposal to ensure that usable water zones are
adequately protected by the proper placement of casing and cement.
Since this information is already required to be submitted with the
APD, it is not repeated in the rule. No revisions to the rule were made
as a result of this comment. However, the information that would be
required to be submitted as part of this rule will be made available to
the public, consistent with the requirements of Federal law.
Some commenters recommended using a research agency such as the
United States Geological Survey (USGS) to identify usable water. Other
commenters recommended developing Federal and state partnerships to map
water resources. The BLM agrees that those entities can be helpful in
identifying usable water. However, the BLM cannot mandate their
participation. We note that the use of information developed by the
USGS or state agencies is acceptable information for operators to use
to identify usable water. In many areas, the USGS, state agencies, or
tribal agencies have developed water resource maps. Operators may use
this information, along with any other available information, including
logs from nearby wells, to identify usable water zones. No revisions to
the rule were made as a result of these comments.
Section 3162.3-3(d) in the supplemental proposed rule required that
the NOI include the measured or estimated depths (both top and bottom)
of all occurrences of usable water by use of a drill log from the
subject well or another well in the vicinity and within the same field.
Many commenters expressed concern that identification of usable
water by drill log is very difficult and expensive. Other commenters
stated that the BLM is incorrect to assume that drill logs can be used
to identify usable water. The commenters stated that these logs do not
directly measure water quality or TDS.
Operators often run resistivity logs for intermediate and
production casing, and these logs might allow the qualitative
identification of high salt content zones. These logs do not, however,
directly measure TDS, and there are too many variables for the
signature these logs record to be converted into accurate TDS data.
Some commenters expressed concern that the term ``drill log'' is very
broad and should be specifically defined. The BLM agrees with these
comments. It was not the BLM's intent to mandate a prescriptive method
of estimating the depths of usable water. Final section 3162.3-3(d) has
been revised and the phrase ``by use of a drill log from the subject
well or another well in the vicinity and with the same field,''

[[Page 16152]]

has been deleted in the final rule. This change will make the
requirement less prescriptive, and it will make it consistent with the
existing requirements in section III.D.3.b. of Onshore Order 1.
Section III.D.3.b. of Onshore Order 1 requires operators to provide
the estimated depth and thickness of formations, members, or zones
potentially containing usable water, and the operator's plans for
protecting usable water. It does not specify what information the
operator must use to determine the estimated depth of usable water. The
expectation is that the operator will use the best available
information to estimate the depths of usable water. The expectation in
this final rule is the same. Available information could include data
and interpretation of resistivity logs run on nearby wells. In many
areas, information can be obtained from state or tribal regulatory
agencies. Many states have requirements that protect known water zones.
For example, the North Dakota Industrial Commission requires that
surface casing be set and cemented at a point not less than 50 feet
below the base of the Fox Hills Formation (N.D. Admin Code 43-02-03-21
(2012)). The Wyoming Oil and Gas Conservation Commission uses regional
water studies to identify known zones with potential to contain usable
water such as the Fox Hills Formation in the Powder River Basin of
Wyoming and bases its casing requirements on such information. Other
information on usable water may be available from local BLM offices.
For example, the BLM Pinedale Field Office Web site provides
information regarding usable water. That Web site also provides typical
casing and cementing designs for different areas under jurisdiction of
the Field Office.
Some commenters stated the rule will impose additional casing and/
or cementing costs on operators because, unlike Onshore Order 2, the
proposed rule would require cement behind pipe across all usable water
zones. The commenters state that even though the proposed rule uses the
word ``isolate,'' it uses the word differently than Onshore Order 2.
The commenters go on to say this is clear from the requirement to run a
CEL for each casing string that protects usable water. The BLM
disagrees with these comments. The requirements in the supplemental
proposed rule are consistent with the requirements in Onshore Order 2.
For many wells, the isolation of usable water will be accomplished by
setting cement across the usable water zones. However, in some wells,
cementing across the usable water zone may not be feasible. In these
situations, isolation of the usable water zones from any hydrocarbon
bearing formations is warranted. The BLM modified some of the
requirements in the final rule to eliminate confusion over the
requirement to isolate and protect usable water. In the final rule, a
CEL is not required on each string of surface casing that isolates
usable water if certain performance standards are met. A few examples
of performance standards to be met include cement return to surface, a
successful formation integrity test confirming good cement bonding, and
no lost circulation or other cementing problems. For wells where a CEL
is required, the operator must run a CEL to demonstrate that there is
at least 200 feet of adequately bonded cement between the zone to be
hydraulically fractured and the deepest usable water zone. Meeting this
requirement would demonstrate isolation and protection of the usable
water zone from the zone to be hydraulically fractured.
Another commenter recommended that all cementing requirements be
eliminated from the rule. The commenter asserts that cementing
operations are part of drilling operations and information is already
submitted to state regulatory agencies for such operations. The
commenter asserted that cementing operations have little to do with
hydraulic fracturing. The BLM disagrees with this comment. While
cementing information is already submitted to state regulatory agencies
and the BLM, this rule expands on the requirements by including cement
monitoring, cement remediation, and cement evaluation which are all
related to protection of usable water from hydraulic fracturing
operations. No revisions to the rule were made as a result of this
comment.
Identification of Water Sources and Access Routes
Section 3162.3-3(d)(3) requires the operator to identify the
anticipated access route for all water planned for use in fracturing
the well. One commenter recommended that the BLM require the disclosure
of all proposed and existing access routes, including those used to
transport proppant (sand), equipment, and chemicals for use in the
hydraulic fracturing fluids. The BLM disagrees with this comment. The
BLM already requires the operator to submit its proposed access route
to the well location in the APD (see Onshore Order 1, section
III.D.4.a.). In this rule, the BLM requires the operator to
specifically identify the access route for the water to be used in
fracturing operations because the access route from the water source
may be potentially different from the route approved in the APD. The
BLM uses this information provided by the operator to determine
potential environmental impacts under NEPA and if a right-of-way to
cross public lands is needed, and to assure compliance with other
statues such as the FLPMA. All other travel to and from the location
should be on the route described in the approved APD. However, the BLM
has no authority to require its approval for transportation not on
public lands. No revisions to the rule were made as a result of this
comment.
Some commenters disagreed with the requirement to provide
information concerning the water source and location of water supply
because they were unsure what the information would be used for, and
others were concerned that the BLM would disapprove or condition the
withdrawals, in violation of state authority over water use. Other
comments stated that the water source could change and filing a Sundry
Notice for the BLM to approve the change is burdensome. The BLM
requires this information about the proposed source of the water in
order to conduct and document an environmental effects analysis that
takes a hard look at the impacts of its Federal action and meets the
requirements of NEPA. The BLM has always required operators to file a
Sundry Notice for changes to the approved permit--whether it is an APD
or an NOI for hydraulic fracturing or for other operations requiring
BLM approval. No changes to the final rule were made as a result of
these comments.
Some commenters stated that information regarding the water source
would have already been provided as part of the APD. The BLM agrees in
part. Section III.D.4.e. of Onshore Order 1 requires the operator to
identify the location and types of water supply to be used during the
drilling operations in the APD. That water supply for such things as
mixing drilling mud and cement may or may not be the same as the water
supply for hydraulic fracturing operations, which often needs much
greater quantities of water, but may be able to use water of different
quality. Since the water supply may be different, this information must
be included in the application for hydraulic fracturing. No revisions
to the rule were made as a result of these comments.
One commenter expressed concern about identifying the source and

[[Page 16153]]

location of reused or recycled water. The commenter stated that they
will often send produced waters to a centralized recycle or reuse
facility. These waters will not have one single source, and once
commingled, could not readily be identified as coming from one
particular well. The rule does not require the sources of water that
the reuse or recycling facility receives. If the water is coming from a
centralized recycling facility, identifying the water as reused or
recycled, and providing the location of the recycling facility is
sufficient for the information required in the permit application.
One commenter requested clarification of the term ``water supply.''
The commenter said it was unclear whether the requirement was
requesting the source and location of the water to be used in the
hydraulic fracturing operation or if the requirement was requesting the
source for drinking water/agricultural water/industrial water in the
area. The requirement is referring to the source water used as a base
fluid in the hydraulic fracturing operations.
Another commenter recommended that the BLM strengthen the language
regarding identification of the water supply to say ``must'' instead of
``may.'' The language in the rule requires the applicant to provide
information on the source and location of the water supply, ``which may
be shown by quarter-quarter section on a map or plat, or which may be
described in writing.'' The BLM believes the rule is clear as written.
The applicant must provide the information requested, but they have the
option of either showing it on a map or plat, or by describing it in
writing. No revisions to the rule were made as a result of these
comments.
Hydraulic Fracturing Plan--Water Volume
The BLM received one comment suggesting that the BLM should require
the operator to provide the volumes of water to be used during
hydraulic fracturing operations in its application. Another commenter
asked if section 3162.3-3(d)(4)(i) refers to the volume of hydraulic
fracturing fluid or the volume of water from the water supply. Section
3162.3-3(d)(4)(i) requires the submission of the estimated total volume
of fluid to be used. This requirement does not specifically require the
volume of water. However, since most all of the fracking fluid is water
(assuming a water-based fracturing fluid), it is a good indicator of
the estimated volume of water to be used. Some hydraulic fracturing
operations, however, use other fluids such as nitrogen or carbon
dioxide. For these operations, the estimated total volume of fluid
would include all fluids, including the nitrogen or carbon dioxide.
Hydraulic Fracturing Plan--Pressures
Several comments suggested clarification of the pressures required
in the permit application (supplemental proposed rule section 3162.3-
3(d)). In the supplemental proposed rule, paragraph (d)(3) would have
required ``estimated pump pressures,'' paragraph (d)(4)(ii) would have
required the ``anticipated surface treating pressure range,'' and
paragraph (d)(4)(iii) would have required the ``maximum injection
treating pressure.'' The commenters expressed some confusion over the
need for the three different pressures and also some confusion over the
terminology. The BLM agrees with these comments and consolidated the
requirements in proposed paragraph (d) to one requirement to provide
the ``maximum anticipated surface pressure that will be applied during
the hydraulic fracturing process'' (final section 3162.3-3(d)(4)(ii)).
The primary reason for requesting this information was to ensure the
pressures used during the hydraulic fracturing process were no greater
than the pressures used in the MIT (see section 3162.2-2(f)) prior to
hydraulic fracturing and to ensure that the wellbore is adequately
designed to handle these pressures. Therefore, the requirement for
``pressure ranges'' in the supplemental proposed rule (paragraph
(d)(4)(ii)) is not necessary--only the maximum pressure is required for
the intended purpose. The phrase ``treating pressure'' is eliminated
because the meaning of the word ``treating'' may not be universally
understood.
Also in response to these comments, the BLM changed the wording in
sections 3162.3-3(f)(1) and (i)(3) of the final rule to match the
terminology used in section 3162.3-3(d)(4)(ii).
Hydraulic Fracturing Plan--Fracture Data
The BLM received several comments regarding the submittal of
fracture design information. Some commenters fully supported the
requirement. These commenters indicated the data is necessary for BLM
evaluation. These commenters were in general agreement with the
provisions of this section, e.g., fracture length, height, and
direction data can be actual, estimated, or calculated.
Some commenters objected to allowing fracture design estimates
instead of actual fracturing data and other commenters requested that
the data submitted include three dimensional reservoir and fracturing
modeling. The primary objective of the additional requirements
requested by the commenters was to give the BLM better information to
ensure that the fractures would not extend into any usable water zones
or intersect other wells (i.e., ``frack hits''). The BLM did not make
any changes to the rule as a result of these comments for several
reasons. First, information presented in an application is only
estimated because actual conditions encountered during the drilling and
hydraulic fracturing process can change significantly from the
conditions anticipated in the application as operations progress.
Therefore, any modeling would be calculated from best estimates of
conditions, introducing significant uncertainty in the calculations as
to render them no more useful than the estimated fracture data required
in the proposed rule. Second, the intent of requiring this information
in the hydraulic fracturing application is to give the BLM a general
idea of the extent of the fractures as a tool to identify potential
hazards such as other wells and to assure that there will be adequate
margins of protection for the closest zone containing usable water.
Exact calculations, speculative or not, are not required under this
section of the final rule. Although no changes to the rule were made
directly as a result of these comments, the final rule does expand the
informational requirements relating to fractures and potential frack
hits. Under the final rule, operators must submit the estimated
fracture data on a map that also shows all known wellbore trajectories
within one-half mile of the well that is proposed to be fractured.
The BLM also received numerous comments objecting to the
requirement to specify the fracture length in the application for
hydraulic fracturing. Several commenters stated that expensive modeling
would be required to estimate fracture length. As discussed earlier,
although it can be used, modeling is not required. The intent of this
requirement is to provide the BLM with enough information about the
proposed hydraulic fracturing operation that potential hazards, such as
other wells and fracture propagation into usable water zones, can be
identified and mitigated. Estimated fracture dimensions are sufficient
to meet this intent. Because the rule already requires ``estimated or
calculated'' fracture data, no changes to the rule were made as a
result of the comments.
A few commenters expressed concern about confidentiality of the
information

[[Page 16154]]

in providing the required details on the estimated fracture length,
height, and direction. The BLM believes that the submission of these
estimated values would not routinely meet any of the criteria within
the Freedom of Information Act regulations (43 CFR part 2) which would
require such information to be held as confidential information. The
BLM did not revise the rule as a result of these comments.
One commenter said that fracture data has nothing to do with
wellbore integrity or protecting groundwater. The BLM disagrees. One of
the purposes of submitting fracture estimates is to allow the BLM to
analyze hydraulic fracturing proposals for potential interference with
other wells. There is a potential for groundwater contamination if
high-pressure hydraulic fracturing fluid intersects the drainage radius
of another wellbore. The BLM did not revise the rule as a result of
these comments.
Meaning of ``Wellbore''
In response to comments, the BLM determined that it should be made
clear that the rule was not requiring only the locations of vertical
segments of wells. The rule at paragraph (d)(4)(iii)(C) requires
submission of a map showing the location of all wellbores within one-
half mile horizontally of the wellbore to be hydraulically fractured. A
wellbore is not merely the vertical component of a well. A wellbore is
commonly understood to be ``[t]he hole made by a well.'' Williams &
Myers Manual of Oil & Gas Terms, p.1173 (10th ed. 1997). It thus
includes all vertical, directional, and horizontal legs of a well.
Thus, any part of an existing well that comes within one-half mile
horizontally of the trajectory of the well to be hydraulically
fractured (regardless of any difference in depths) must be shown on the
map submitted with the operator's application. The information will
allow the authorized officer to work with the operator to prevent
``frack hits.''
Distance to Aquifers
The BLM received a few comments regarding the vertical distance
from the intended hydraulic fracture zone to the nearest aquifer. One
commenter recommended that the rule be revised to require the operator
to report the vertical distance from the intended hydraulic fracture
zone to the nearest aquifer. The BLM did not revise the rule as a
result of these comments since this is already required in final
section 3162.3-3(d)(4)(iv) for all requests for approval of hydraulic
fracturing.
Some commenters recommended that the rule be modified to clarify
the requirement regarding the NOI estimated vertical distance to the
nearest usable water aquifer above the fracture zone. The commenters
indicated that the BLM should specify if this is the distance between
the surface down to the aquifer or the distance between the aquifer to
the fracture zone. The BLM agrees that the proposed language was
unclear and has modified the rule as a result of these comments. The
intent of this section is to estimate the vertical distance between the
top of the fracture zone and the nearest usable water zone. The BLM
believes that this information is necessary to properly evaluate the
potential impacts of a hydraulic fracturing proposal and had revised
the language accordingly.
Handling of Recovered Fluids
Some commenters stated that requiring disclosure of proposed
methods of handling the recovered fluids prior to drilling is an
unreasonable administrative burden for operators when the requirement
does nothing to further protect public health and welfare, the
environment, nor facilitate efficient production. The BLM disagrees
with these comments. The BLM requires the information about the
handling of recovered fluids in order to conduct and document an
environmental effects analysis that takes a hard look at the impacts of
its Federal action and meets the requirements of NEPA and to assure
that recovered fluids will not contaminate resources on or in public
lands or Indian lands.
Other commenters requested that this section be expanded to include
language that requests amounts, locations, facilities for storage, and
options for recovering fluids for treatment. The rule requires
reporting to the BLM of estimated volumes of recovered fluid along with
the proposed methods of handling and disposal of those fluids. The BLM
believes the information required in the final rule addresses the
commenter's concern and is adequate to assess any potential impacts
from the proposed methods of handling the produced fluids and to ensure
protection of resources. No changes were made to the final rule based
on this comment.
Commenters asked why the estimated chemical composition of the
flowback fluid is required, and requested this requirement be struck
from the rule. While the original proposed rule required the operator
to submit the estimated chemical composition of the flowback fluid, the
supplemental proposed rule did not. The rationale for deleting the
requirement was discussed in the preamble of the supplemental proposed
rule. This final rule does not require the estimated chemical
composition of the flowback and therefore the BLM did not revise the
rule as a result of these comments.
Additional Data
Some commenters recommended that section 3162.3-3(d)(7), which
allows the authorized officer to request additional information prior
to the approval of the NOI, be deleted. The commenters expressed
concern that the provision creates too much uncertainty for operators
and does not include any standards under which the BLM can request
additional information. The BLM believes that the provision in the rule
is necessary to provide the flexibility essential to regulating
operations over a broad range of geologic and environmental conditions.
Any new information that the BLM may request will be limited to
information necessary for the BLM to ensure that operations are
consistent with applicable laws and regulations, or that the operator
is taking into account site-specific circumstances. Requests for
information from the authorized officer are subject to administrative
review if an operator believes the directive lacks a proper basis. The
BLM did not revise the rule as a result of these comments.
Duplication of State Process
Several commenters stated that many parts of the rule are
duplicative of state requirements, and therefore were unnecessary and
would increase the regulatory and permitting burdens on operators. Some
of the comments were generic while others specifically identified
states such as Colorado, New Mexico, and Wyoming. The BLM has
determined that the collections of information in the rule are
necessary to enable the BLM to meet its statutory obligations to
regulate operations associated with Federal and Indian oil and gas
leases; prevent unnecessary or undue degradation; and manage public
lands using the principles of multiple use and sustained yield; and
protect resources associated with Indian lands. The information that
states, tribes, or other Federal agencies collect is neither uniform
nor uniformly accessible to the BLM. For these reasons, the BLM has
determined that the collections in the rule are necessary, and are not
unnecessarily duplicative of existing Federal, tribal, or state
collection requirements. If the data required by a state is the same as
the data required by this rule, it is permissible for the operator to
attach it to the APD or NOI required for Federal and Indian lands,

[[Page 16155]]

thus substantially reducing the reporting burden for operators.
Timeframes
Some commenters were concerned over possible delays in BLM approval
of their applications and requested that the BLM include processing
timeframes in the rule. Specific timeframes suggested were from 10 to
30 days. Some commenters recommended that the permit be automatically
approved after 30 days. Other commenters did not offer any specific
suggestions on timeframes. The BLM did not revise the rule as a result
of these comments because the imposition of a timeframe or
``automatic'' approvals could limit the BLM's ability to ensure
protection of usable water and other resources. The BLM cannot abdicate
its statutorily mandated responsibilities to prevent unnecessary or
undue degradation of public lands and to protect Federal and Indian
resources by establishing an arbitrary deadline. Furthermore, the BLM
has obligations to assure compliance with relevant statutes and
Executive Orders, which in some cases would require more than 30 days.
As discussed in other sections, however, the rule would make several
changes to the permitting process that could reduce the potential for
processing delays.
Flowback Fluid
One commenter suggested that the BLM allow the flowback data
required in section 3162.3-3(d)(5) of the supplemental proposed rule to
be submitted either in the Sundry Notice or through a database. The BLM
did not revise the rule because there is no existing database suitable
for that purpose and the BLM believes that submission under this final
rule is adequate. However, the BLM is considering expanding the use of
its Well Information System for electronic submittal of various types
of Sundry Notices.
One commenter requested that the BLM require operators to have a
water management plan for flowback fluid. No changes to the rule were
made as a result of this comment because the BLM requires the
equivalent of a water management plan in final section 3162.3-3(d)(5)
of the rule.
Approval Standards
Several commenters suggested that the BLM define clear standards
for approving or denying an application for hydraulic fracturing. No
changes to the rule were made as a result of this comment because the
decision to approve or deny a particular application will be made by
the authorized officer based on the site-specific conditions for that
application and based on whether or not the application complies with
this rule and applicable law.

Section 3162.3-3(e) Cement Monitoring

This section requires operators to:
Monitor and record their cementing operations--This is
consistent with industry guidance stressing the importance of using
data from reports, logs, and tests to evaluate the quality of a cement
job, including drilling reports, drilling fluid reports, cement design
and related laboratory reports, open-hole log information including
caliper logs, and cement placement information including a centralizer
program, placement simulations and job logs, etc.;
Cement the surface casing to the surface--This is already
required by Onshore Order 2 and most state regulations, and is
consistent with industry practice;
For both the intermediate and production casing strings
where they serve to protect usable water, the operator must either
cement to the surface or run a CEL to demonstrate that there is at
least 200 feet of adequately bonded cement between the deepest usable
water zone and the formation to be fractured. This is generally
consistent with industry guidance and specified in some state
regulations. The American Petroleum Institute's (API) guidance titled
``Hydraulic Fracturing Operations-Well Construction and Integrity
Guidelines, First Edition, October 2009,'' commonly known as HF1,
states that ``if the intermediate casing is not cemented to the
surface, at a minimum, the cement should extend above any exposed USDW
or any hydrocarbon bearing zone'' and that operators may run a CEL and/
or other diagnostic tools to determine the adequacy of the cement
integrity and that the cement reached the desired height.
If there is an indication of inadequate cement, the operator must
notify the BLM within 24 hours, submit a plan to perform remedial
action, verify that the remedial action was successful with a CEL or
other approved method, and submit a subsequent report including a
signed certification and results of the corrective action.
Section (e)(1) of the final rule is revised to require submission
of the cement monitoring report to the BLM at least 48 hours prior to
commencing hydraulic fracturing operations, instead of 30 days after
the completion of hydraulic fracturing operations, as was proposed in
the supplemental proposed rule. The BLM made this change to allow field
office engineers time to review the cement monitoring report,
consistent with ensuring wellbore integrity. The 48-hour period will
allow the BLM sufficient time to review the report, while not creating
an unreasonable burden on the operators. In most wells, any usable
water is isolated with the surface casing that is set many days or even
months before the well reaches total depth, so there is plenty of time
for the operator to submit the report. For wells where usable water is
isolated by intermediate or production casing, the operator would still
have ample time to submit the cement monitoring report. Typically,
after the operator completes drilling and cementing operations, the
operator moves the drilling rig off the well and moves on a completion
rig with hydraulic fracturing following. This transition period will
allow the operators sufficient time to submit the cement operations
monitoring report at least 48-hour prior to commencing hydraulic
fracturing.
For any well completed pursuant to an APD that did not expressly
authorize hydraulic fracturing operations, there is a new section
3162.3-3(e)(1)(ii) that requires the operator to submit documentation
to demonstrate that adequate cementing was achieved for all casing
strings designed to isolate or to protect usable water. The operator
must submit the documentation with its request for approval of
hydraulic fracturing operations, or no less than 48 hours prior to
conducting hydraulic fracturing operations if no prior approval is
required pursuant to paragraph 3162.3-3(a). The authorized officer may
approve the hydraulic fracturing of the well only if the documentation
provides assurance that the cementing was sufficient to isolate and to
protect usable water, and may require such additional tests,
verifications, cementing, or other protection or isolation operations,
as the authorized officer may deem necessary.
This provision would apply to wells subject to the transition
period as shown in the table in section 3162.3-3(a), and to other wells
that might have been completed as conventional wells or fractured prior
to this rule, but subsequently are proposed to be re-completed by
hydraulic fracturing. Many if not most operators would have the
information required in section 3162.3-3(e)(1)(i), and could readily
provide it to the authorized officer. However, if the operator did not
maintain all of those records, it could provide the available
information to the authorized officer, who could approve the operator's
request once there is assurance that the hydraulic fracturing

[[Page 16156]]

operation in the well would be consistent with the requirements of
proper isolation and protection of the usable water zones.
Sections 3162.3-3(e)(2) and (e)(3) of the supplemental proposed
rule were deleted in the final rule and replaced by a new section
3162.3-3(e)(2). The supplemental proposed rule (section 3262.3-3(e)(2))
used a ``type well'' concept and would have required that a CEL be run
on all casing strings that protect usable water unless the well was
permitted with an NOI for a group of wells, was drilled with the same
specifications and geologic characteristics as the type well, the
cementing operations monitoring data paralleled the type well, and the
type well CEL indicated successful cement bonding (section 3162.3-
3(e)(3) of the supplemental proposed rule). The final rule no longer
requires a CEL to be run on all casing strings that protect usable
water and the type well provisions in the supplemental rule are
deleted. Instead, section 3162.3-3(e)(2) of this rule sets performance
standards for ensuring adequate cement bonding on all casing that
protects usable water and applies to all wells, not just type wells.
For casing strings that are cemented to the surface, which includes
surface casing, the primary indicator of adequate cement bonding is
cement monitoring. This includes such criteria as good returns to the
surface, the absence of gas-cut mud, and properly functioning equipment
throughout the cement job. The final rule also includes a criterion (10
percent of casing setting depth or 200 feet, whichever is less) for the
amount of allowable fall-back. The BLM believes that these criteria
will more effectively and less subjectively ensure the protection of
usable water on all wells that will be hydraulically fractured than the
CEL that would have been required in the supplemental proposed rule.
For intermediate and production casing designed to protect usable
water and where cement is not brought to the surface, this final rule
requires that a CEL demonstrate that there is at least 200 feet of
adequately bonded cement between the zone to be hydraulically fractured
and the deepest usable water zone. The supplemental proposed rule would
have only required a CEL in this situation if the well was defined as a
type well or if there were indications of an inadequate cement job.
However, indications of an inadequate cement job are much more
difficult to observe when cement is not brought to the surface.
Therefore, the final rule requires a CEL on all intermediate or
production casing strings designed to protect usable water when the
cement is not circulated to the surface. This section also defines the
amount of adequately bonded cement necessary to allow hydraulic
fracturing, which was not defined in the supplemental proposed rule.
The BLM made several revisions to section 3162.3-3(e)(3) of the
final rule (section 3162.3-3(e)(4) of the supplemental proposed rule),
which address the course of action an operator must take if there are
indications of an inadequate cement job. The final rule explicitly
requires the operator to submit an NOI to the BLM for approval of
remedial action to address inadequate cementing, where the supplemental
proposed rule would have only required the operator to report the
remedial action to the BLM. The BLM believes that the final rule's
requirement that the operator receive BLM approval prior to remediating
inadequate cementing will help to ensure protection of aquifers. The
final rule also establishes a procedure for granting approval to take
remedial action in emergency situations.
The supplemental proposed rule would have required the operator to
submit a written report to the BLM within 48 hours of discovering an
inadequate cement job. The final rule requires the submission of an NOI
for BLM approval in lieu of the written report and also deletes the 48-
hour timeframe. The BLM believes that in most cases prompt submission
of an NOI would be in the operator's best interest because they cannot
proceed with hydraulic fracturing until the NOI is approved and
therefore the 48-hour timeframe is unnecessary. Both the supplemental
proposed rule and the final rule require the operator to run a CEL
verifying that the remedial action was successful.
Final section 3162.3-3(e)(3) contains revised requirements for what
an operator must do if there are indications of an inadequate cement
job. In the supplemental proposed rule (section 3162.3-3(e)(4)), prior
to commencing hydraulic fracturing, the operator would have been
required to notify the BLM within 24 hours, submit a written report
within 48 hours, run a CEL showing the inadequate cement had been
corrected, and at least 72 hours prior to commencing operations, submit
a certification and documentation indicating the cement job had been
corrected.
However, the supplemental proposed rule did not have a provision
that would have allowed the BLM to review the documentation required or
approve a plan for remedial action. The final rule requires the
operator to notify the BLM within 24 hours and submit an NOI to the BLM
for remedial action along with supporting documentation and logs. This
gives the BLM the opportunity to review the documentation and logs
submitted to ensure that the remedial action proposed by the operator
is appropriate. The requirement to submit an NOI takes the place of the
48-hour written notification in the supplemental proposed rule,
although the BLM determined that no timeframe is required because the
operator will be required to submit the NOI and receive approval prior
to commencing fracturing operations.
Type Well CEL
Very few commenters were supportive of the type well concept for
cement evaluation. In the supplemental proposed rule, a type well CEL
would have been required to demonstrate successful cement bonding;
thereafter, other wells in an approved group would not have been
required to have a CEL unless there were indications of inadequate
cement. The subsequent wells would also have needed to have the same
specifications and geologic characteristics as the type well, and the
cementing operations monitoring data would have needed to parallel that
of the type well. Many commenters stated that the definition of a type
well was too vague. Some commenters wanted the BLM to limit the type
well concept to a certain number of wells, to a certain distance
between wells, or to a certain time between the hydraulic fracturing of
wells. Other commenters recommended requiring a minimum number of
successful wells rather than just a single type well. Other commenters
wanted the type well concept to be greatly expanded to include all
wells within a county or within a geologic basin. Many commenters
stated that successful cementing operations on one well were not
indicative of subsequent successful cementing of another well,
regardless of the proximity. Some commenters wanted a clearer, more
specific set of standards and procedures to guide the determination of
what constitutes a type well for a given set of wells. Other commenters
were critical that the rule did not elaborate upon the meaning of
``substantially similar geological characteristics within the same
geologic formation'' (language used in the definition of type well) or
the manner in which the BLM makes that determination. Still others
expressed concern that the use of type wells assumes that geologic
zones are compositionally, texturally, and mechanically homogeneous
media, even though this is often not true. Other commenters stated the
type well

[[Page 16157]]

approach fails to address risk by ignoring fundamental geologic
principles and sound engineering practice. Other commenters stated the
type well concept allows the BLM to bring significant judgment to the
well permitting process rather than specific standards.
After reviewing the comments on the use of type wells, type wells
are eliminated from the final rule. The BLM agrees that successful
cementing operations on one well are not necessarily indicative of
subsequent successful cementing of another well regardless of the
proximity or geologic characteristics, and that implementation of the
type well concept would be difficult to achieve. Rather than
restructure the definition, or develop a specific set of standards, the
BLM instead made the decision to eliminate the type well concept and to
establish cementing operations monitoring requirements and usable water
isolation requirements that apply to every well.
CEL
Numerous commenters objected to the requirement to run a CEL on
each casing string that protects usable water. Many of these commenters
stated that the use of CELs on surface casing is unprecedented for
onshore wells. The commenters pointed out that state regulations do not
require CELs on surface casing and that API guidelines do not mention
cement logs in the section specifically devoted to surface casing. Many
commenters stated that where cement is circulated to the surface and
pressure tests are satisfactory, CELs do not provide any additional
assurance of protection. Many commenters were concerned about the costs
associated with running a CEL on surface casing. Many other commenters
said that CELs are not commonly run on surface and intermediate casing
unless other indicators of an unsuccessful cement job are present. Many
of the commenters were critical that the BLM was relying on the CEL as
the ``sole diagnostic tool'' to evaluate cement integrity. Many
commenters stated that CEL data can be difficult to interpret properly
and often yields false positives. The BLM agrees with many of these
comments and has revised the final rule as a result. The final rule
does not require a CEL on the surface casing unless there are
indications of inadequate cement. Final section 3162.3-3(e)(2)(i)
requires that the operator determine that there is adequate cement for
surface casing used to isolate usable water zones. The operator must
observe cement returns to the surface and document any indications of
inadequate cement (such as, but not limited to, lost returns, cement
channeling, gas cut mud, failure of equipment, or fallback from the
surface exceeding 10 percent of surface casing setting depth or 200
feet, whichever is less). If there are indications of inadequate
cement, then under final section 3162.3-3(e)(2), the operator must
determine the top of cement with a CEL, temperature log, or other
method or device approved by the authorized officer.
Many other commenters recommended that a CEL be required on every
string of casing in every well. Commenters expressed concern that
anything less would greatly increase the risk of contamination. The
commenters were opposed to allowing operators to run CELs on type wells
only. The commenters expressed the view that CELs are the only way to
ensure adequate cementing of the casing on each well.
Numerous other commenters stated that the best way to confirm the
adequacy of a cement job is through proper monitoring of the cementing
operations and direct observation of a variety of factors; the most
important being cement returns to the surface. Many commenters
expressed concern about the reliability of CELs, stating that CEL data
can be difficult to interpret properly and often yield false positives.
Commenters said that this can lead to unnecessary attempts at
remediation, which will actually weaken the wellbore integrity.
Some commenters said that allowing operators to use CELs, rather
than just CBLs, alleviates some, but not all of the interpretation
concerns. Other commenters stated that CBLs are not effective until the
cement has reached a certain compressive strength because CBLs work on
the principle of acoustic attenuation. At low compressive strengths,
commenters stated that the acoustic properties of cement and water are
very similar and it is difficult to delineate between the two when
interpreting logs. The commenters went on to state that the problem is
also inherent in the CELs, which can sometimes provide a risky basis
for evaluating the integrity of the cement. The commenters claim that
the logs do not ``see'' the cement. The logs merely allow a competent
professional to draw inferences about the evenness of the cementing
around the pipe, based on readings of sonic or ultrasonic waves passing
through the pipe into the cement and the rock beyond. The commenters
quoted API Technical Report 10TR1, September 2008, which cautions that
cement bond log interpretation ``is not recommended as a best practice
for cement evaluation.''
After further researching these concerns, the BLM agrees that the
monitoring of data and direct observations of various factors,
including cement return to the surface, are good indicators of an
adequate cement job, and the BLM acknowledges the potential
difficulties of running and interpreting CELs. As a result, the BLM has
determined that requiring CELs on the surface casing of every well will
not provide increased protection beyond cement operations monitoring
and circulation of cement to the surface. Therefore, the final rule
requires operators to monitor their cementing operations, including
verification of cement returns to the surface, and to submit the
cementing operations monitoring report to the BLM prior to commencing
hydraulic fracturing operations.
Some commenters disagreed with the proposed regulation allowing the
operator to wait to submit a cement monitoring operations report to the
BLM until after completion of the hydraulic fracturing operations.
These commenters said that the operator should submit the report to the
BLM prior to the commencement of hydraulic fracturing operations. The
BLM agrees and revised the rule as a result of these comments. Final
section 3162.3-3(e)(1) requires that during cementing operations on any
casing used to isolate usable water zones, the operator must monitor
and record the flow rate, density, and pump pressure and submit a
cement operation monitoring report, including that information, to the
authorized officer at least 48 hours prior to commencing hydraulic
fracturing operations, unless the authorized officer approves a shorter
time. This would allow the BLM time to review the monitoring report to
verify compliance with these regulations. If the monitoring report
indicates problems with the cementing operations, the operator must
correct the issue prior to hydraulically fracturing.
The final rule also has more specific criteria for the operator to
follow to determine that there is adequate cement for all casing
strings used to isolate usable water zones. Onshore Order 2 (section
III.B.1.c.) requires surface casing in all wells to be cemented to the
surface. For surface casing, this final rule requires the operator to
observe cement returns to the surface and to document any indications
of inadequate cement (such as, but not limited to, lost returns, cement
channeling, gas cut mud, failure of equipment, or fallback from the
surface exceeding 10 percent of

[[Page 16158]]

surface casing setting depth or 200 feet, whichever is less). If there
are indications of inadequate cement, then the operator must determine
the top of the cement with a CEL, temperature log, or other method or
device approved by the authorized officer. For intermediate or
production casing, this rule requires that if the casing is not
cemented to the surface, then the operator must run a CEL to
demonstrate that there is at least 200 feet of adequately bonded cement
between the zone to be hydraulically fractured and the deepest usable
water zone. If the casing is cemented to surface, then the operator
must follow the surface casing cementing requirements.
The BLM believes that the final rule's requirements described
earlier, in conjunction with the casing and cementing requirements of
Onshore Order 2, will sufficiently isolate and protect usable water. As
discussed earlier, Onshore Order 2 (section III.B.1.c.) requires that
the operator cement the surface casing to the surface. Onshore Order 2
(section III.B.1.f.) also requires that the surface casing shall have
centralizers on the bottom three joints of casing in order to keep the
casing in the center of the wellbore to help ensure efficient placement
of cement around the casing string. Onshore Order 2 (section
III.B.1.h.) requires the operator to pressure test all casing strings
to ensure the integrity of the casing. Onshore Order 2 (section
III.B.1.i.) also requires a pressure integrity test of each casing shoe
on all exploratory wells and on that portion of any well approved for a
5M (5,000 pounds per square inch) BOPE (blowout preventer equipment).
This test insures that a good, leak-tight cement job has been obtained.
Final section 3162.3-3(e) strengthens the requirements that
operators must follow when there is an indication of inadequate
cementing. The operator must notify the authorized officer within 24
hours of discovering the inadequate cement. For the surface casing,
this will likely be immediately following the cementing operations. For
intermediate or production casing that is not cemented to the surface,
this may not be until after the operator has run the CEL. Early
notification will ensure that the BLM is involved with the remediation
of the cement. Under the final rule the operator must submit an NOI to
the authorized officer requesting approval of a plan to perform
remedial action to achieve adequate cement. The plan must include
supporting documentation and logs. The BLM will review the plan, work
with the operator to modify the plan if necessary, and attach any
conditions of approval to the plan. Upon approval, the operator can
commence the remedial actions. After completing the remediation
process, the operator must verify that the remedial action was
successful with a CEL or other method approved in advance by the
authorized officer. The operator must submit a subsequent report for
the remedial action, including a signed certification that the operator
corrected the inadequate cement job in accordance with the approved
plan, and the results from the CEL or other method approved by the
authorized officer and documentation showing that there is adequate
cement. As required by existing section 3160.0-9(c), the subsequent
report is due 30 days after the operations are completed. This final
rule, however, also requires the operator to submit the results from
the CEL or other method approved by the authorized officer at least 72
hours before starting hydraulic fracturing operations. This will
provide the BLM the opportunity to verify the remediation process was
successful and that will help to ensure adequate protection of aquifers
in advance of hydraulic fracturing operations.
Conductor Pipe
Several commenters said that section 3162.3-3(e) should be modified
to specify that a CEL requirement does not apply to conductor pipe. The
BLM agrees with this comment and has modified the rule at sections
3162.3-3(e)(1) and 3162.3-3(e)(2) to clarify that CELs are only
required on casing strings designed to protect usable water. Conductor
pipe does not typically protect aquifers. Conductor pipe is a large
diameter pipe set to relatively shallow depths which serves as a
conduit for all other casings and well operations. The formations close
to the surface are often unconsolidated and during the commencement of
drilling operations these formations erode or wash out from the
circulating drilling muds. The conductor pipe's purpose is to prevent
this near-surface erosion from interfering with subsequent drilling and
operating activities. Based on the surface formation's conditions,
certain wells do not have conductor casing set, in other instances
conductor pipe is mechanically driven into the surface formations
without any cement, and in other instances the conductor pipe consists
merely of corrugated pipe and is cemented with construction cement. One
of the roles of the surface casing, the first casing string set, is to
protect the near-surface usable-quality waters. Because conductor
casing is not designed to protect usable water zones, the CEL
requirement does not apply. In addition, the surface casing would be
adequately cemented inside the conductor pipe, thus protecting near-
surface zones.
What is inadequate cement?
Several commenters stated that section 3162.3-3(e)(2) (proposed
section 3162.3-3(e)(4)) regarding indications of inadequate cement
should be modified. Commenters indicated that the inadequate cement job
criteria listed were not good indicators of an inadequate cement job.
The commenters did not offer any suggestions of what would be good
indicator(s). The BLM did not revise the rule as a result of this
comment. The provision regarding indicators of inadequate cement, at
final section 3162.3-3(e)(2)(i), expressly includes the language ``such
as, but not limited to'' to indicate that the subsequent list is not an
exhaustive list of possible indications of inadequate cement.
The BLM also received comments that this section should be revised
to exempt cement fall back from being classified as an indication of
inadequate cement. Commenters indicated that there should be a specific
exception for those instances where the only remedy is to top-fill
cement that has settled in the annulus after curing. The BLM agrees and
has revised the rule as a result of these comments. Section 3162.3-
3(e)(2) now addresses adequate cement for surface casing or
intermediate and production casing separately. Additionally, the BLM
believes that the fallback indicator for inadequate cement should
incorporate a performance standard. Based on the BLM's experience, 10
percent of surface casing setting depth or 200 feet, whichever is less,
is the limit that routine ``top-jobs'' are successfully performed;
therefore, the rule has been revised to incorporate this exception as a
fall back indicator for inadequate cement. Appropriate remedial
operations are to be conducted in either event; however, determination
of the cement top via a CEL would not be required under this exception.
Certifications
Numerous commenters stated that the rule provisions dealing with
self-certification should be modified. The supplemental proposed rule
proposed self-certification statements for remedial cement jobs,
wellbore integrity, fluids used, and compliance with laws and
regulations.
Some commenters indicated that certifications are unnecessary and
require the operator to certify the actions of third parties over whom
they

[[Page 16159]]

have no direct control; in addition, concern was expressed with the
potential liability issues of certification for operations conducted by
another party. The BLM did not make any changes to the rule as a result
of these comments. By definition, in existing section 3160.0-5, the
operator is the entity that is responsible for the operations conducted
under the terms and conditions of the lease. As such, the BLM believes
it is appropriate that the operator be responsible for all aspects of
hydraulic fracturing operations, regardless of the party that conducts
the work. The BLM will hold the operator responsible for all actions of
third party contractors on a Federal or tribal lease. Requiring the
operator to submit the certifications is appropriate and provides added
assurance that hydraulic fracturing operations were conducted in
compliance with the regulations.
Some commenters objected to the requirement that the operator
certify proper execution of remedial cement jobs, the mechanical
integrity of casing, and legal compliance related to hydraulic
fracturing fluids, among other issues. They asserted that it is
impossible for the operator to have one individual who can certify all
of those matters and said that the possibility of criminal enforcement
is an unreasonable imposition. The BLM disagrees. The operator has
always been responsible for everything that occurs on the permitted
well site. See existing section 3100.5(a). If an operator uses one or
more service contractors for specific tasks, the operator remains fully
responsible for those operations. See existing section 3162.3(b). If
the operator's contractor, as its agent under existing section
3162.3(b), submits a certification, it is deemed to have come from the
operator. Since 1948, the law has provided for criminal liability for
certain false statements in public land matters, whether sworn or
unsworn. 43 U.S.C. 1212. The certification requirement underscores the
importance of operators taking responsibility for reporting accurate
information necessary to assure that hydraulic fracturing operations
were properly conducted and is intended to ensure that contractor
activities on the lease are properly overseen by the operator. The
final rule is not revised in response to these comments.
Other commenters were concerned that despite taking all prudent
steps, implementing accepted industry standards, and complying with all
regulatory requirements in the final rule, the operator could in good
faith provide a certification that later in time is found invalid based
on circumstances or facts unknown to the operator or that were out of
his or her control. The BLM did not make any changes to the rule based
on these comments. The BLM would take an operator's diligence and good
faith into consideration in exercising enforcement discretion where a
certification was later shown to have been in error.
Other commenters said that additional certifications should be
required, including fracture propagation and the protection of usable
water. The BLM did not make any changes to the rule as a result of
these comments. The BLM believes that the subsequent report adequately
details fracture design considerations, including fracture propagation.
Additionally, usable water considerations are addressed at both the APD
and hydraulic fracturing review stages.
Cement Monitoring Report
Several commenters suggested that the rule require the cement
monitoring report in paragraph section 3162.3-3(e)(1) to be submitted
to the BLM prior to commencing hydraulic fracturing operations. This
would give BLM field offices the opportunity to review the report to
ensure the cement job was adequate. The proposed rule would have given
operators 30 days from the completion of hydraulic fracturing
operations to submit the cement monitoring report. The BLM agrees with
this comment and revised final section 3162.3-3(e)(1) to require that
the report be submitted at least 48 hours prior to commencing hydraulic
fracturing operations.
One commenter suggested that the cement contractor's report should
be acceptable to the BLM. The requirements of the cement report are
detailed in section 3162.3-3(e)(1) of this rule. Any report meeting
these requirements would be acceptable to the BLM, including a report
submitted by the cement contractor as an agent of the operator. See 43
CFR 3162.3(b). No changes to the rule were made as a result of this
comment.
One commenter suggested that the cement monitoring report in
section 3162.3-3(e)(1) should be submitted to the BLM within 30 days of
cementing, not within 30 days after completion of hydraulic fracturing
operations as stated in the supplemental proposed rule. This, according
to the commenter, would give the BLM adequate time to review the report
prior to hydraulic fracturing. The rule is revised based on other
comments to require the cement monitoring report at least 48 hours
prior to hydraulic fracturing, which addresses the commenter's concern.
In addition, the BLM does not believe that operators would proceed to
fracture a well if the monitoring report showed a failure to ensure
isolation and protection of usable water, knowing that if the BLM
discovered the failure, the operator would be subject to enforcement
action.

Section 3162.3-3(f) Mechanical Integrity Test

This section requires the operator to conduct a Mechanical
Integrity Test (MIT). The MIT required by this rule is a pressure test
of the casing through which the hydraulic fracturing will occur or
through the fracturing string (if used). Industry guidance and many
state regulations are consistent with this requirement. The API's
guidance \7\ clearly indicates the need for the MIT. The threshold of
30 minutes with no more than 10 percent loss of applied pressure is
used by many states (TX, LA, CO, WY, and others).
---------------------------------------------------------------------------

\7\ Hydraulic Fracturing Operations--Well Construction and
Integrity Guidelines, API Guidance Document HF1 (1st ed., Oct.
2009).
---------------------------------------------------------------------------

Industry guidance on hydraulic fracturing states that the operator
should pressure test the production casing. ``Prior to perforating and
hydraulic fracturing operations, the production casing should be
pressure tested (commonly known as a casing pressure test). This test
should be conducted at a pressure that will determine if the casing
integrity is adequate to meet the well design and construction
objectives.'' (API Guidance Document HF1, First Edition, October 2009)
This casing pressure test meets the intent of the MIT required by the
rule.
Two changes were made to the MIT requirements in the final rule.
The reference to refracturing in the supplemental proposed rule is
deleted because the final rule no longer makes any distinction between
refracturing and fracturing. The requirement to only perform an MIT on
vertical sections of the wellbore in the supplemental proposed rule is
also deleted in the final rule. This change ensures that the entire
length of casing or fracturing string, not just the vertical section,
prior to the perforations or open-hole section of the well, is able to
withstand the applied pressure and contain the hydraulic fracturing
fluids. In addition, it was unclear to what the term vertical section
would apply in a directionally drilled well.
The BLM received numerous comments on performing a successful MIT
prior to hydraulic fracturing. These comments ranged from concerns
involving need, type wells, MIT reporting, well configurations,

[[Page 16160]]

terminology, test pressures and finally, alternative testing
procedures.
Several commenters stated that the MIT requirement in general is
unnecessary and costly. Other commenters indicated that because MITs
are already completed as a matter of industry practice prior to any
pumping procedure, regulating such procedure is merely bureaucratic and
serves no environmental protection. The BLM realizes that many
operators perform MITs; however the BLM believes that ensuring casing
integrity prior to hydraulic fracturing is essential and that the only
way to verify the integrity of the casing is to require a test to the
anticipated hydraulic fracturing pressure. An MIT conducted immediately
preceding the hydraulic fracturing operation to the specified test
pressure would suffice. No change was made to the rule as a result of
these comments.
Some commenters were concerned that an MIT would not be required on
every well if the type well concept was adopted. As discussed, the
proposed type well concept is not included in the final rule.
Elimination of the type well concept clarifies any confusion regarding
the requirement for an MIT for type wells. The final rule now requires
that a successful MIT be performed on every well prior to hydraulic
fracturing. The BLM believes that this is the only method that will
ensure that each well to be hydraulically fractured demonstrates the
appropriate structural capabilities to withstand the intended applied
pressures.
Some commenters said that the rule requiring MITs for refracturing
should be modified. The commenters stated that the requirement to
perform an MIT before refracturing operations is unjustified. The
commenter suggested that the BLM should put a timing restriction on
when an MIT must be performed when refracturing a well. As previously
discussed, the final rule has eliminated the term ``refracturing'' in
its entirety. An MIT will be required prior to the first hydraulic
fracturing operation in any well, and prior to all subsequent hydraulic
fracturing operations in that well. To ensure proper wellbore integrity
for protection and isolation of the usable water, an MIT will be
required to ensure that an existing well is properly bonded and
sheathed to sustain high pressures during a hydraulic fracturing
operation. The BLM did not revise the rule as a result of these
comments.
Other commenters recommended that the BLM require reporting the
results of the MIT prior to hydraulic fracturing. The BLM does not
believe that a requirement to report the results of the MIT prior to
fracturing is necessary to ensure wellbore integrity. Final section
3162.3-3(f) requires a successful MIT prior to hydraulic fracturing;
therefore, if the MIT failed and the operator proceeded with hydraulic
fracturing operations, the operator would be in violation of the rule
and would be subject to enforcement actions. No revisions to the rule
were made as a result of this comment. In addition, final section
3162.3-3(i)(8)(i) requires a certification to be signed by the operator
that it had performed a successful MIT under section 3162.3-3(f).
Some commenters recommended that the BLM clarify the requirement
for conducting the MIT when the well configuration contains a pressure-
actuated valve or sleeve at the end of a lateral completion. The
commenters expressed concern that pressure testing this valve or sleeve
to maximum anticipated pressure will possibly open the valve or sleeve,
causing the pressure test to fail the proposed standard of 30 minutes
with no more than a 10 percent pressure loss. The BLM also received
comments urging modification to the MIT requirements for open-hole
completions. The BLM appreciates the concerns expressed by the
commenters. The BLM believes that ensuring casing integrity prior to
hydraulic fracturing is essential and the best way to ensure the
integrity of the casing is to test to the anticipated hydraulic
fracturing pressure. No revisions to the rule were made as a result of
these comments. Also, because this is a national rule, it cannot
address all the possible wellbore configurations, and the BLM
recognizes that certain wellbore configurations may require
modifications to perform this test. Many wellbores will require the
setting of packers, or other acceptable methods, to isolate existing,
sensitive downhole components or open-hole completions. Operators are
encouraged to anticipate these complications and provide details to the
BLM's authorized officers in their hydraulic fracturing APDs and NOIs.
Several commenters requested clarification regarding at what point
in the process should results of the MITs be submitted and for how long
must the operator keep the results of the MIT. The final rule was not
revised as a result of these comments; however, the rule was
reorganized to better reflect the BLM's intent. As required by final
section 3162.3-3(i)(9), the MIT results are required to be submitted to
the BLM authorized officer, via a subsequent report, within 30 days
after the completion of the last stage of the hydraulic fracturing for
each well. Existing section 3162.4-1(d) requires that the operator
maintain all required records and reports, including MITs, for 6 years
from the date that it was generated.
Some commenters said that the rule should be modified to change the
term ``MIT'' to ``casing pressure test.'' Other comments asked if the
MIT was the same casing pressure test required by Onshore Order 2. The
BLM did not make any changes to the rule as a result of these comments.
The BLM believes that the term ``Mechanical Integrity Test'' is widely
understood by industry, is used by many state regulatory agencies, and
accurately describes the test. The MIT required by final section
3162.3-3(f) is not equivalent to either the casing pressure test
required by Onshore Order 2, section III.B.1.h., or the casing shoe
pressure test as currently required by Onshore Order 2, section
III.B.1.i. The MIT is a specific test conducted on a wellbore in its
hydraulic fracturing configuration and to the maximum anticipated
pressure for the hydraulic fracturing operation being contemplated.
Some commenters suggested various alternative testing pressures or
procedures to be used for the MIT. Commenters recommended lower
pressures than the proposed rule provided or suggested that alternative
methods, including ultrasonic imaging, could be utilized. Final section
3162.3-3(f) requires the operator to perform a successful MIT to not
less than the maximum anticipated surface pressure that will be applied
during the hydraulic fracturing process. This testing is necessary to
help ensure the integrity of the wellbore during hydraulic fracturing
operations. This test demonstrates that the casing provides sufficient
structural strength to protect usable water and other subsurface
resources during hydraulic fracturing operations. The BLM specifically
chose the MIT over other alternative tools so that the test could be
accomplished without requiring additional equipment, such as ultrasonic
imaging tools. No revisions to the rule were made as a result of these
comments. However, the BLM may consider a proposal by the operator to
use alternative tools to an MIT. If such tools meet or exceed the
objectives of performing an MIT, then the BLM may authorize an operator
to use such tools as a variance to this requirement.
Commenters suggested alternative MIT failure indicator levels.
Section 3162.3-3(f)(3) requires the well to hold the pressure for 30
minutes with no more than a 10 percent pressure loss. As previously
pointed out, this test

[[Page 16161]]

confirms the mechanical integrity of the casing and is the same
``failure'' standard that the BLM established for drilling operations
in Onshore Order 2, section III.B.h.; therefore, this language does not
set a new standard in the BLM's regulations. The MIT, together with the
other requirements, demonstrate not only the wellbore's structural
competency, but that reasonable precautions have been taken to protect
usable water and other subsurface resources during hydraulic fracturing
operations. Some commenters also indicated that this requirement is
duplicative of state requirements and therefore is unnecessary. The BLM
acknowledges that although this requirement may be duplicative of some
states' requirements, not all of the states to which this final rule is
applicable have the same requirements and, therefore, this standard is
necessary to protect Federal and tribal lands. Many commenters
expressed that the requirement is common industry practice and that
they support the requirement. No revisions to the rule were made as a
result of these comments.

Section 3162.3-3(g) Monitoring During Hydraulic Fracturing Operations

This section requires the operator to continuously monitor and
record the annulus pressure at the bradenhead during the hydraulic
fracturing operation.
In the final rule, the BLM removed the term ``refracturing'' from
the title of the section because the final rule no longer defines or
uses the term ``refracturing.'' The final rule also clarifies that when
pressures within the annulus increase by more than 500 psi, the
operator must stop fracturing operations and determine the reasons for
the increase. Prior to recommencing hydraulic fracturing operations,
the operator must perform any remedial action required by the
authorized officer and successfully perform an MIT required under
paragraph (f) of the rule. The BLM believes that these actions are
necessary in these cases to ensure that the integrity of a wellbore is
confirmed through an MIT prior to recommencing hydraulic fracturing
operations.
One commenter believed that the requirements for the operators in
section 3162.3-3(g) of the supplemental proposed rule to continuously
monitor and record annulus pressure at the bradenhead were too vague
and wanted more specificity in the rule. The commenter also believed
that the requirement was unnecessary. The commenter explained that
operators already monitor pressures during hydraulic fracturing
operations using sophisticated and expensive equipment. Another
commenter said that the monitoring requirement could not be achieved
because the bradenhead is not accessible. The BLM reviewed the language
in the supplemental proposed rule and has determined that the language
in this section is clear as written. In fact, the language in this
section is very similar to the requirements in Colorado rule 341
(Colorado Oil and Gas Conservation Commission, February, 2014, http://cogcc.state.co.us/). Changes in pressure, while not necessarily caused
by mechanical failure due to hydraulic fracturing, provide an
indication that mechanical failure may have occurred. The BLM
appreciates the fact that operators already monitor pressures during
hydraulic fracturing using sophisticated equipment. However, as
indicated by comments, not all hydraulic fracturing operations utilize
the same equipment and therefore specific requirements are necessary.
The BLM finds no merit in the comment that the bradenhead is not
accessible. Common industry practice is to construct wells that allow
bradenhead access. Many states, including Colorado, Wyoming, Montana,
and North Dakota, require bradenhead monitoring during hydraulic
fracturing, and API guidance, ``Hydraulic Fracturing Operations-Well
Construction and Integrity Guidelines, First Edition, October 2009,''
commonly known as HF1, recommends annular pressure monitoring during
hydraulic fracturing.
Other commenters recommended that the monitoring should continue on
a daily basis for the first 30 days after hydraulic fracturing and then
monthly for 5 years thereafter. The BLM disagrees with this comment.
Upon completion of pumping the hydraulic fracturing fluids, the
wellbore is no longer subject to the pump pressure. Therefore,
continual monitoring for wellbore issues caused by the hydraulic
fracturing operation is unnecessary. No revisions to the rule were made
as a result of these comments.
Some commenters suggested that the reporting requirements of
pressure increases by more than 500 psi during hydraulic fracturing
operations in the annulus during hydraulic fracturing under section
3162.3-3(g)(2) of the supplemental proposed rule is unnecessary because
it duplicates state requirements. Another commenter asserted the need
for a more comprehensive regulatory approach for hydraulic fracturing
operations in state and tribal lands. The BLM acknowledges that some
states have similar requirements, but not all states have the same
requirements. Since this rule applies to all Federal and Indian
minerals, this requirement is necessary. Even in states that do have a
similar requirement, the BLM needs to know about the pressure increase
so that the BLM can work closely with the operator to correct the issue
and take the appropriate action.
Another commenter recommended that in addition to the oral
notification of a pressure increase, written notice should also be
required. The BLM believes oral notification is sufficient in this
situation. If warranted, the BLM may require additional documentation
regarding the pressure increase and the corrective measures that were
taken to abate the situation.
One commenter recommended that the BLM adopt the language in the
original proposed rule which required the operator to file a subsequent
report of the corrective actions taken within 15 days, instead of the
language in the supplemental proposed rule which requires the
submission of the subsequent report within 30 days of completion of the
hydraulic fracturing operations. As stated earlier, the BLM will work
closely with the operator following notification of the pressure
increase. Since the BLM will be aware of the incident by the oral
notification and will be involved with the corrective action from the
start, the timing of submission of the subsequent report is not
critical to the BLM. The 30-day requirement is consistent with all of
the other documentation required to be included in the subsequent
report. No revisions to the rule were made as a result of these
comments.
One comment made numerous suggestions about additional monitoring
that should take place on producing wells. The suggestions include:
Submit monthly and annual production reports including
volume of oil and gas to the BLM;
Monitor pressure of each well daily for the first 30 days
of operation;
Maintain production and monitoring reports for 5 years;
Conduct periodic well tests to determine flow rate and
pressure;
Maintain and test wellhead equipment over the life of the
well;
Annually report casing pressures to the BLM and notify the
BLM if pressures approach the design limits of the casing;
Install pressure relief valves, especially on high-
pressure or high-volume wells; and
Monitor all wells for corrosion and potential hazards.

[[Page 16162]]

The BLM did not revise the rule as a result of these comments
because these comments apply to producing wells whether or not they are
hydraulically fractured. The BLM believes that the existing monitoring,
maintenance, and reporting requirements for producing wells are
adequate. See 43 CFR part 3160, and http://www.blm.gov/mt/st/en/prog/energy/oil_and_gas/operations/orders.html.
For example, operators of Federal and Indian wells already must
report production to the Office of Natural Resource Revenue (ONRR).
Furthermore, the supplemental notice of proposed rulemaking did not
propose to amend the onshore orders or other operating regulations.
Several commenters suggested that the rule require operators to
notify the BLM if the annular pressure exceeds 80 percent of the casing
internal yield rating during hydraulic fracturing. Both the
supplemental and the final rules require the operator to notify the BLM
if the annular pressure exceeds 500 psi. The BLM determined that the
standard for notifying the BLM should be an objective and easily
measured parameter. The 500 psi limit can be detected by observing a
pressure gauge. A standard based on casing yield ratings as the
commenters suggested would be more difficult to detect and implement,
especially if the person observing the gauge was not familiar with the
weight, grade, and depth of the casing run, or the weight of the mud in
the hole. In addition, as part of the BLM's review of hydraulic
fracturing applications, the engineer will ensure that a 500 psi
increase in annular pressure will not jeopardize the integrity of the
casing. No revisions to the rule were made as a result of this comment.

Section 3162.3-3(h) Storage of Recovered Fluids

This section requires operators to manage recovered fluids in rigid
enclosed, covered, or netted and screened above-ground tanks. Those
tanks may be vented, unless Federal, state or tribal law, as
appropriate for the surface estate involved, require vapor recovery or
closed-loop systems. The tanks must not exceed a 500 barrel (bbl)
capacity unless approved in advance by the authorized officer. In
certain very limited circumstances, the operator may apply for approval
to use a lined pit.
Tanks that are not enclosed will need to be covered, netted, or
screened to exclude wildlife. This is not a new requirement. In 2012,
the BLM issued an instructional memorandum to its authorized officers
to assure that pits, tanks, and similar structures are netted or
screened to prevent entrapment and mortality of wildlife. (See http://www.blm.gov/wo/st/en/info/regulations/Instruction_Memos_and_Bulletins/national_instruction/2013/IM_2013-033.print.html.). These mitigation
requirements are used to help prevent deaths of animals protected under
the Migratory Bird Treaty Act and other laws.
The supplemental proposed rule would have required that recovered
fluids be stored in lined pits or tanks unless otherwise required by
the BLM. The final rule incorporates two significant changes. First,
the BLM decided not to distinguish flowback fluid from produced water.
Instead, in the final rule the requirements for the storage of flowback
fluid only apply to the interim period between the completion of
hydraulic fracturing and the implementation of an approved plan for the
disposal of produced water under Onshore Order 7. Fluids produced from
the well during this period are referred to as ``recovered fluid'' in
the final rule and the term ``flowback'' is deleted from the rule.
Second, instead of allowing lined pits or tanks, as proposed in the
supplemental proposed rule, the final rule requires that all recovered
fluids to be stored in above-ground tanks unless otherwise approved by
the BLM in advance of generating recovered fluids. In addition, a list
of minimum criteria for the approval of storage in lined pits is
included in the final rule.
Pits vs. Tanks
In the supplemental proposed rule, the BLM asked for comments on
whether flowback fluids should only be stored in closed tanks. The BLM
received comments that both supported and objected to this proposal.
Comments supporting a ``tanks only'' approach stated that the risk of
impacts to air, water, and wildlife is too great, even if a pit is
lined. Those commenters stated that lined pits are still subject to
breaching, failure, and leaking. In addition, because pits are open to
the atmosphere, fumes from the fluid in the pits can become airborne
and cause health and environmental problems. The commenters also raised
the possibility of wildlife getting into pits and dying or becoming ill
from exposure to the chemical constituents in the fluids. Some of these
comments suggested that flowback fluid should only be stored in
``closed systems'' that would not only use tanks, but the tanks would
be vapor tight to eliminate the possibility of air contamination.
Many of the comments objecting to a ``tanks only'' approach raised
the issue of increased cost if tanks or ``closed systems'' were
required. Most of these comments preferred the flexibility of lined
pits or tanks, depending on the location or the specific situation. For
example, the extra cost of storing flowback fluid in tanks may have no
benefits in remote areas where there are no water sources which could
be contaminated and no human populations that could be affected by
airborne contaminants. Some of the comments suggested that the rule
could require geo-textile or composite liners or double-lined pits with
leak detection systems in order to reduce the risks of leakage. Other
commenters raised the concern of unintended consequences of requiring
tanks, such as increased truck traffic.
After reviewing these comments and comments relating to the
definition of ``flowback,'' the BLM decided to make a number of
modifications to final section 3162.3-3(h). First, because the BLM is
not differentiating ``flow back'' fluid from produced water, the
requirements in paragraph (h) will only apply to the fluids recovered
between the completion of hydraulic fracturing and the implementation
of a plan for the disposal of produced water approved under BLM
regulations, which currently are in Onshore Order 7. This will ensure
that recovered fluids are stored and handled in a way that minimizes
the risk of impacts to air, water, and wildlife during the interim
period (up to 90 days) while the BLM is reviewing the operator's long-
term plan for the disposal of produced water. When the information is
available, the BLM highly encourages operators to submit their plans
for long-term storage of recovered fluids with their APD or NOI for
proposed hydraulic fracturing operations to allow the BLM to evaluate
the various aspects of an operator's development proposal under one
review process, rather than multiple processes.
Second, the BLM agrees with the comments stating that the storage
of flowback, or recovered fluid in pits, poses a risk of impacts to
air, water, and wildlife. Therefore, this rule requires storage of
recovered fluids in rigid enclosed, covered, or netted and screened
above-ground tanks during the interim period before the operator
implements a BLM-approved plan for the disposal of produced water under
its regulations (currently in Onshore Order 7). The BLM believes that
above-ground tanks, when compared to pits, are less prone to leaking,
are safer for wildlife, and will have less air emissions. The BLM
generally considers tanks as being constructed from a rigid material
such as steel or fiberglass. The BLM realizes

[[Page 16163]]

that, if enclosed, tanks will still need to be vented to prevent the
tanks from bursting or collapsing when filling or emptying the tanks
and to compensate for changes in temperature. Venting will release some
vapors into the atmosphere. Although a ``closed loop'' system would be
approvable, we do not currently have an adequate basis to require such
a system nationwide. However, the BLM supports states and tribes that
require vapor-recovery or ``closed loop'' systems. Also, from the BLM's
observations in the field, many operators already choose to use tanks
in lieu of pits for temporary storage of recovered fluids to manage
costs and timing of operations, and to control impacts to the
environment and any resulting liability.
Third, the BLM agrees with the comments asking for the flexibility
to allow lined pits based on site-specific conditions, but believes
such exceptions should be limited and rarely granted. As a result,
final section 3162.3-3(h)(1) allows the BLM to approve the storage of
recovered fluids in lined pits on a case-by-case basis and only if the
applicant demonstrates that the use of an above-ground tank is
infeasible for environmental or public health or safety reasons only
and all of the listed criteria are met. In circumstances where use of
above-ground tanks has concomitant impacts to the environment, public
health, and safety, the rule allows BLM to exercise its discretion to
approve lined pits, but only if they meet all of the listed criteria.
These criteria include minimum distances from water sources, public
places, and residences, as well as potential floodplain impacts. If
approved, the lined pit would be required to be constructed and
maintained in accordance with final section 3162.3-3(h)(2), which
requires the pit to be properly located, lined with a durable, leak-
proof synthetic material and equipped with a leak detection system.
Onshore Order 7 already establishes a standard for leak detection
systems when disposing of produced water into lined pits. The minimum
distances found in this section are similar to requirements found in
Title 19, Chapter 15, Part 17 of the New Mexico Administrative Code.
The BLM considers the criteria in this section as minimum
requirements--if an operator proposes to store recovered fluid in a
lined pit that does not meet one or more of these minimum requirements,
the BLM would not approve the storage method. However, the BLM has the
discretion to deny proposals to use lined pits that meet or exceed the
minimum criteria, based on site-specific conditions. In no cases would
the BLM allow the storage of recovered fluids in unlined pits.
Moreover, in the BLM's experience, the use of tanks in lieu of pits
in high-volume operations limits potential environmental impacts,
allows for quicker site preparation, reduces reclamation requirements,
eliminates longer term environmental risk, reduces risks of spills or
leaks, and increases safety. A tank can be removed in a day and there
is no waiting required to recontour and seed the surface for
reclamation purposes. The use of tanks for temporary storage of
recovered fluids also provides the additional advantage of not
requiring any long-term monitoring and mitigation. Pits also require
periodic upkeep, monitoring, and fences. Several comments suggested
that treatment and injection is the safest and most effective way to
dispose of flowback fluids. The BLM did not revise the rule based on
these comments because the ultimate disposal of recovered fluids is
outside the scope of this rule, and, except for disposal on or in
public lands, is outside of the BLM's regulatory authority.
In the BLM's experience, most operators use rigid, truck- or
trailer-mounted tanks for temporary storage of recovered fluids, and
those tanks are usually no larger than 500 bbl capacity. Large open-
topped tanks, often called ``semi-rigid,'' can be susceptible to
failures of seams or welds. Failure of a large-capacity tank containing
recovered fluids would pose particular risks of harm to humans and
wildlife because of the amount of fluid involved. Failures of large-
capacity open-topped tanks have been documented. For example, between
October 2011 and June 2013, there were five catastrophic failures of
large-volume tanks reported to the Colorado Oil and Gas Conservation
Commission (none of those tanks contained recovered fluids). Colorado
has banned the storage of recovered fluids from such large-volume
tanks.\8\ For these reasons, the rule provides that tanks used for
temporary storage of recovered fluids must not exceed 500 bbl capacity,
unless approved in advance by the authorized officer.
---------------------------------------------------------------------------

\8\ Link to the Final COGCC Policy: https://cogcc.state.co.us/RR_Docs_new/Policies/MLVTPolicyFinal20140613.pdf.
---------------------------------------------------------------------------

Flowback vs. Produced Water
In the supplemental proposed rule, the BLM asked for comments on
whether or not the rule should differentiate flowback fluids from
produced water and, if so, how the two should be distinguished.
Flowback fluids generally refer to the fluids recovered from the well
immediately after hydraulic fracturing, presumably containing a high
percentage of the fluids injected during hydraulic fracturing. Produced
water is generally considered to be water from the hydrocarbon zone
that is produced along with oil and gas.
Onshore Order 7 establishes requirements for the handling and
disposal of produced water. If this rule did not distinguish flowback
fluid from produced water, then Onshore Order 7 could be applied to all
water produced from the well, including that water recovered from the
well immediately after hydraulic fracturing. If this rule did
distinguish flowback fluid from produced water, then unique handling,
disposal, and reporting requirements could be imposed for the flowback
fluid.
The majority of comments received regarding this issue recommended
that the rule not try to distinguish flowback fluid from produced
water. The primary reasons given were: (1) There is no way to define
the difference between the two; and (2) They are both potentially
hazardous and should be treated in the same manner. A minority of
comments recommended that the rule establish special handling,
disposal, and reporting requirements for flowback fluid. However, no
clear or enforceable means of making the distinction was given. Several
comments suggested a time-based approach (e.g., flowback would end 10
days after the completion of hydraulic fracturing), while others
suggested that the flowback period end when oil and gas production
begins.
The BLM considered numerous different criteria on which to
differentiate flowback fluid from produced water, including all the
methods suggested in the comments. The BLM decided that any method of
differentiation would be either arbitrary (e.g., 10 days after the
completion of hydraulic fracturing) or difficult to implement. For
example, several states define flowback fluid as the fluid recovered
prior to the production of oil and gas. However, the time at which the
production of oil and gas begins is not always clear, therefore making
this alternative difficult to apply. Often, some quantity of oil or gas
is produced from the well almost immediately after hydraulic
fracturing. In other cases, it might be days or weeks later.
``Production'' could mean whenever measureable amounts of oil and gas
are detected in the recovered fluid or it could mean when oil and gas
is produced in marketable quantities. Any method based on the quantity
or quality of oil and gas production would need to

[[Page 16164]]

be measured and tracked. Additionally, it is unlikely that the chemical
constituency or toxicity of the recovered fluid would change
significantly once oil and gas was detected; therefore, there would be
no practical reason to make such a distinction.
Ultimately, the BLM decided not to make a distinction between
flowback fluid and produced water and all references to the term
``flowback'' were removed in the final rule (sections 3162.3-3(d)(5),
(i)(6), and (i)(7)). Instead, the term ``recovered fluid'' is used in
the final rule for all fluids coming from the well after a hydraulic
fracturing operation is complete. Also Onshore Order 7 generally
applies to all recovered fluids, including those fluids recovered
immediately after hydraulic fracturing. However, under Onshore Order 7,
section III.A., an operator has permission to temporarily dispose of
produced water from newly completed wells for up to 90 days, until an
application for the disposal of produced water is approved by the
authorized officer. This 90-day interim period is typically when the
highest percentage of hydraulic fracturing fluid is recovered. The BLM
determined that special handling provisions are necessary for fluids
recovered during this interim period after hydraulic fracturing and
revised section 3162.3-3(h) of the final rule as a result (see the
discussion of pits versus tanks under section 3162.3-3(h)).
The BLM also revised the provision for reporting the volume of
fluid recovered during flowback, swabbing, or recovery from production
vessels in final section 3162.3-3(i)(6). Instead of reporting volumes
of ``flowback'' in the subsequent report for an undefined period of
time, the BLM determined that the ultimate goal is to have a complete
record of all volumes recovered from a well, regardless of how it is
defined or when it is recovered. ONRR requires operators to report the
monthly volume of all fluids (oil, gas, and water) produced from wells
on the Oil and Gas Operations Report, Part A (OGOR A). However, some
operators do not start reporting on OGOR A until royalty-bearing
quantities of oil and gas are produced, thereby leaving a potential gap
in the reporting of recovered fluids. To fill this gap, paragraph
(i)(6) in the final rule requires operators to report the volume of
fluid recovered between the completion of hydraulic fracturing and the
start of reporting on OGOR A. Because the subsequent report is due 30
days after the completion of the last stage of hydraulic fracturing,
there may be situations where the subsequent report is filed prior to
the start of reporting on OGOR A. In these cases, the operator would
have to file an amended subsequent report showing the total volume of
fluid recovered prior to the start of reporting on OGOR A.
Refer to Figures A and B for an example of how the BLM will
implement the provisions of this rule. Both figures show the flow rate
of fluid recovered after hydraulic fracturing over some time period.
Typically, the initial flow rate is high and declines over time as the
excess pressure caused by hydraulic fracturing is relieved. The area
under the flow-rate curve represents the volume of fluid recovered over
a given time period. In Figure A, the operator begins reporting
produced volumes on OGOR A 10 days after the completion of hydraulic
fracturing and submits its subsequent report 20 days after the
completion of hydraulic fracturing. Because reporting of recovered
volumes on OGOR A precedes submittal of the subsequent report, only
that volume recovered between the completion of hydraulic fracturing
operations and the start of reporting produced fluids on OGOR A would
be reported on the subsequent report--12,000 bbl in this example. The
additional 5,000 bbl recovered before the submittal of the subsequent
report will be captured by the volumes reported on OGOR A, thereby
providing a continuous record of the volume of fluid recovered for the
life of the well.
In Figure B, the subsequent report is submitted on its due date (30
days after the completion of hydraulic fracturing), but reporting of
produced fluids on OGOR A does not occur until 40 days after the
completion of hydraulic fracturing. In this example, the operator would
have to submit a supplemental subsequent report showing the total
volume of 24,000 bbl recovered between the completion of hydraulic
fracturing and the start of reporting on OGOR A.
BILLING CODE 4310-84-P

[[Page 16165]]

[GRAPHIC] [TIFF OMITTED] TR26MR15.000

BILLING CODE 4310-84-C

[[Page 16166]]

Other Flowback Requirements
Several comments suggested that the BLM require that flowback fluid
be tested prior to disposal. The BLM did not revise the rule as a
result of this comment because disposal of recovered fluids is
generally done off-site and under the authority of other agencies such
as the EPA (for underground injection). Disposal on Federal or Indian
land would be covered under Onshore Order 7.
One commenter suggested that the BLM create a manifest system to
assure proper disposal of recovered fluids. While the commenter did not
expound on what was meant by a ``manifest system,'' the BLM assumes it
to mean a system of formal documented custody transfer ensuring that
all flowback fluid removed from the site arrives at its destination (a
disposal facility). Onshore Order 7 already requires the operator to
submit a copy of the disposal facility's permit, and a right-of-way
authorization if the wastewater would travel over Federal or Indian
lands off of the lease. Other agencies regulate the transport and
disposal of chemical wastes, and this rule does not interfere with
those regulatory programs.
One comment suggested that the BLM should get rid of the Onshore
Order 7 provision that allows the disposal of pit liquids through
evaporation. No revisions to the rule were made as a result of this
comment because it cannot be addressed at this final rule stage, but
the BLM will evaluate and consider options for updating requirements
under all of its existing Onshore Orders. This rule sets standards for
the handling of recovered fluid until a disposal plan is approved by
the BLM under Onshore Order 7. This rule does not amend Onshore Order
7.
Several commenters suggested that the rule should require the
monitoring of constituents of flowback fluid. The BLM did not
incorporate this suggestion because the goal of the rule is to contain
the recovered fluids regardless of their chemical constituents.
Disposal facilities often require an analysis of the fluid to be
disposed; however, that is outside the scope of this rule.

Section 3162.3-3(i) Subsequent Report

This section lists information that the operator must submit to the
BLM after the completion of a hydraulic fracturing operation and
requires a disclosure of the chemicals used during the operation to
FracFocus, the BLM, or another database that the BLM specifies.
The BLM strongly encourages operators to submit the chemical
disclosure data through the FracFocus database. If data is submitted
directly to the BLM, the BLM will upload it to Fracfocus.org. This will
meet the goals and requirements of the rule most effectively by
providing a direct public disclosure of the chemical additives used in
the hydraulic fracturing operation. If the BLM finds that operators are
avoiding use of FracFocus without a justification, such as temporary
problems with the FracFocus site, the BLM will consider requiring a
filing fee for chemical disclosure data submitted directly to the BLM.
Numerous changes are made to this section of the final rule. In the
supplemental proposed rule, the 30-day time period for submitting the
subsequent report would have begun when hydraulic fracturing operations
were complete. In the final rule, the start of the time period begins
after the last stage of hydraulic fracturing operations on each well is
complete. This change is to clarify that in a multi-stage hydraulic
fracturing operation, the operation is not complete until the last
stage of hydraulic fracturing on each well is complete.
In section 3162.3-3(i)(1), the final rule clarifies that a
description of the base fluid and each chemical added to the hydraulic
fracturing fluid must be reported, instead of each chemical used. The
BLM made this change to clarify that operators do not have to report
chemicals that are found in the water used as a base fluid, whether
taken from surface or groundwater, or reuse or recycled water. The word
``description'' is added for clarity.
The downhole information in section 3162.3-3(i)(2) of the
supplemental proposed rule is moved to a new section (i)(5) of the
final rule for clarity and to be consistent with the informational
requirement of section (d)(3). Section (i)(2) of the final rule is now
specific to water sources and section (i)(5) is specific to downhole
information.
The pressure information in section 3162.3-3(i)(3) of the
supplemental proposed rule is changed in the final rule to clarify that
the maximum surface pressure at the end of each stage is required. The
supplemental proposed rule would have required the ``actual surface
pressure,'' which could be ambiguous. The maximum surface pressure is
needed for the BLM to ensure that the pressure used in the MIT, as
required in section 3162.3-3(f) of the final rule, was not exceeded.
Section 3162.3-3(i)(6) of the final rule redefines the period over
which the volume of recovered fluids must be given in the subsequent
report. In the supplemental proposed rule (section (i)(5)(i)) the
volume of fluid to be included in the subsequent report was the amount
recovered during flowback, swabbing, or recovery from production
vessels. However, the supplemental proposed rule did not define the
flowback period, or the period over which fluid recovery from swabbing
or recovery from production vessels would have to be reported. The BLM
determined that the goal of reporting recovered fluids is to have a
complete history of everything that comes out of the well, regardless
of how it is defined. Once an oil and gas well begins producing oil and
gas, the monthly volumes of gas, oil, and water produced from each well
must be reported on the OGOR A under 30 CFR 1210.102(a). Therefore, the
only additional volumes that are needed to provide a complete history
of fluids produced after hydraulic fracturing is the water produced
immediately after hydraulic fracturing, but prior to the production of
oil and gas that would trigger reporting on the OGOR A. If reporting on
OGOR A does not start for more than 30 days after hydraulic
fracturing--the timeframe in which the subsequent report is due--an
amended subsequent report would have to be filed when OGOR A reporting
started, showing the total volume of fluid produced since the
completion of hydraulic fracturing.
Section 3162.3-3(i)(7) of the final rule (section 3162.3-3(i)(5) of
the supplemental proposed rule) is revised to apply only to the
handling and disposal of fluids recovered between the completion of
hydraulic fracturing operations and the approval of a plan for the
disposal of produced water under Onshore Order 7. The supplemental
proposed rule would have required information on the handling and
disposal of recovered fluids, but did not define what constituted
``recovered fluids.'' In addition, the examples of handling and
disposal methods are revised to coincide with the information
requirements in the hydraulic fracturing application in section (d)(5).
Section 3162.3-3(i)(7)(i) in the supplemental proposed rule would
have required that the operator to certify that wellbore integrity was
maintained under section (b) of the rule. Section 3162.3-3(i)(8)(i) of
the final rule is reworded so that it is clear that the certification
refers to compliance with paragraphs (b), (e), (f), (g), and (h) of
this rule.
Section 3162.3-3(i)(9) of the final rule (section 3162.3-3(i)(8) of
the supplemental proposed rule) is revised to eliminate the need to
submit well logs and records of adequate cement (including CELs) under
this section because the operator must already

[[Page 16167]]

submit these under other sections of this rule and with the BLM Well
Completion or Recompletion Report and Log (Form 3160-4).
Subsequent Report Fracture Data
Several commenters were concerned that the specific fracture
dimensions data required by this section (fracture length, height, and
direction) could only be obtained through fracture modeling and
requested that the BLM allow the use of fracture data gathered and
modeled for similar wells, as opposed to requiring new modeling for
every well. The BLM did not make any changes as a result of these
comments. As provided by this section, fracture length, height and
direction data can be actual, estimated, or calculated. The BLM is
anticipating only hydraulic fracturing design estimates, and that
hydraulic fracturing modeling is not required to meet this requirement.
These data are obtained by some operators during the fracturing
operation using microseismic fracture mapping, a diagnostic technique
that measures created hydraulic fracture dimensions and their azimuth.
The purpose of fracture data is to avoid potential interconnectivity
between fractured pathways and either existing wellbores, i.e., so
called ``frack hits,'' or zones containing usable water.
Several comments suggested that the subsequent report compare the
actual fracture dimensions with those estimated in the NOI. The BLM did
not make any changes to the rule in response to these comments because
the only method of verifying actual fracture dimensions is with a
microseismic array, which the BLM is not requiring. The BLM believes
that for the purpose of protecting ground water and identifying
potential ``frack hits,'' estimated fracture dimensions are adequate.
The estimated fracture dimensions are based on actual volume and
pressure used during the hydraulic fracturing operation, and knowledge
of the perforated string and the geology.
Timeframe for Submittal
Several commenters stated that the BLM should allow 60 days after
completion of hydraulic fracturing operations for submitting the
completion reports required under section 3162.3-3(i). Some commenters
added that it takes the operator some time after the completion of
operations to gather the information from their service contractors and
to then compile the report accurately prior to submission. One
commenter also indicated that for consistency with existing chemical
disclosure reporting requirements of a couple of states (Colorado and
North Dakota), the timeframe for submittal should be modified to 60
days. Another commenter suggested that the information could be
submitted in an annual report. The BLM requirement to submit completion
reports within 30 days after completion is consistent with the BLM's
existing requirements under Onshore Order 1, section IV.e. Given
experience with industry submission of information to the BLM, 30 days
has been demonstrated to be an acceptable timeframe for accurate
submissions. The BLM did not make any changes as a result of these
comments.
``Fluid'' Ambiguity
One commenter suggested that the word ``fluid,'' as it is used in
the rule to provide an estimated volume of fluid in the initial
submission of hydraulic fracturing proposal under section 3162.3-
3(d)(4)(i) and for reporting the volume of fluid recovered under
section 3162.3-3(i)(6), is ambiguous. The commenter recommended that
the BLM require reporting of the total volume of ``hydraulic fracturing
fluid,'' including gas, used or injected into the well, stated in
gallons or other appropriate volumetric units of measurement. The BLM
recognizes that a fluid includes both liquids and gases and any device
employed to measure liquid volume would also measure any suspended or
dissolved solids in the liquid. The BLM has defined the term
``hydraulic fracturing fluid'' in section 3160.0-5 in this rule. This
should provide the needed clarity. Therefore, under this rule, the word
``fluid'' includes the liquid or gas, and any associated solids used in
hydraulic fracturing, including constituents such as water, chemicals,
and proppants. The BLM did not revise the rule based on this comment
because the wording in the supplemental and final rules addresses the
commenter's concern.
Third-Party Certification and Reporting
One commenter stated that the term ``wellbore integrity,'' as used
in section 3162.3-3(i)(7)(i) of the supplemental proposed rule is vague
and undefined. The BLM agrees with that comment and has deleted the
separate reference to ``wellbore integrity'' in the final rule, which
is now designated section 3162.3-3(i)(8)(i).
One commenter stated that the BLM should remove the requirement to
certify wellbore integrity that cross-references to usable water zonal
isolation. The commenter states that section 3162.3-3(i)(7)(i) of the
supplemental proposed rule would require that operators certify that
well integrity was maintained prior to and throughout the hydraulic
fracturing operation, as required by section 3162.3-3(b). Section
3162.3-3(b) directly refers to the performance standard in section
3162.5-2(d) on isolation of all usable water. The commenter stated that
isolation of useable water does not ensure wellbore integrity. The BLM
agrees. This section of the final rule, which is now designated section
3162.3-3(i)(8)(i), has been rewritten to require the operator to
certify that the operator complied with the requirements in paragraphs
(b), (e), (f), (g), and (h) of the section.
Another commenter said that operators should not be required to
certify that isolation of usable water and mineral zones was achieved,
and should only be required to use best efforts to isolate those zones,
because isolation cannot be measured directly, but only inferred. The
final rule is not revised in response to that comment. Isolation of
zones of usable water or minerals is shown or inferred by data
indicating that hydraulic fracturing fluids, recovered fluids, or oil
and gas have not been lost from the wellbore in or around those zones.
It is appropriate to require operators to review the reasonably
available data concerning their operations and to certify that the data
indicate that zonal isolation was achieved.
A commenter was critical of the certification requirement, arguing
that it added nothing because operators are required to comply with all
applicable regulations, and that terms such as ``treatment fluid'' and
``wellbore integrity'' are ambiguous. The commenter stated that an
operator could in good faith believe that its certification was valid,
but later it could be proved that there was an undiscovered problem.
Although the BLM agrees that operators must comply with all applicable
regulations, the BLM disagrees with the commenter's conclusions. The
term ``treatment fluid'' is not used in the regulations. The reference
to wellbore integrity has been deleted. The function of the self-
certification is to require operators to conduct a good-faith review of
the construction and operational data for any indication of problems.
Certification of compliance with the requirements in paragraphs (b),
(e), (f), (g), and (h) of the section is appropriate.
A commenter said that the requirement for an operator to certify
its compliance with applicable law for operations on an Indian
reservation is unnecessary and could result in ``serious litigation.''
The BLM disagrees. An operator on an Indian reservation is

[[Page 16168]]

responsible for knowing and complying with the applicable tribal and
Federal law, just as an operator on non-tribal lands is responsible for
knowing and complying with applicable state, local, and Federal law.
The certification is an appropriate requirement in exercise of the
Secretary's trust responsibilities to assure that the operator has
reviewed and verified its own compliance with tribal law. A certificate
signed in good faith and following reasonable efforts to verify
compliance would not increase any risk of litigation.
One commenter recommended that the rule model its reporting and
certification requirements (final section 3162.3-3(i)(1) and (i)(8),
respectively) on the Colorado Oil and Gas Conservation Commission
(COGCC) Rule 205 and 205A because these rules strike a balance between
reporting obligations of operators versus service companies. Rule 205A
is specific to hydraulic fracturing and is most relevant to this rule.
The BLM did not revise the rule as a result of these comments. The
reporting requirements under 3162.3-3(i)(1) and Rule 205A, paragraph b,
are very similar. Both require the disclosure of the hydraulic
fracturing operations, including the well name, the total volume of
water used, and the types and amounts of chemicals used in the
operation (with exceptions for trade secrets). Both also require that
the information be submitted by the operator (Rule 205A.b(2)). The
Colorado rule requires vendors and service companies to provide water
volume and chemical data to the operator; however, the operator is
ultimately responsible for submitting the information to COGCC. In this
respect, this rule is consistent with the Colorado rule. Section
3162.3-3(i)(8) in the final rule requires the operator to certify that
it complied with paragraphs (b), (e), (f), (g), and (h) of the rule,
and that the hydraulic fracturing fluid constituents comply with all
applicable Federal, tribal, state, and local laws, rules, and
regulations. There is no corollary requirement in the Colorado rule.
The BLM primarily has authority over the parties who hold or operate
the lease--the lease being the instrument through which the BLM
exercises its authority over the lessee or operator. No changes to the
rule were made as a result of this comment.
One commenter said that the rule should be revised to improve the
readability of sections 3162.3-3(i)(8)(ii) and (iii), which contain the
phrase ``the hydraulic fracturing fluid used complied . . . .'' The
commenter indicated that this phrasing makes no sense linguistically
since hydraulic fracturing fluid does not comply, the operator
complies. The BLM did not revise the rule as a result of these
comments. The lead-in section for this certification section of the
rule, now designated as section 3162.3-3(i)(8), clearly indicates that
the certification signed by the operator contains the information that
the hydraulic fracturing fluids used complies with all applicable
permitting and notice requirements.
FracFocus
Some of the commenters noted that reporting requirements of the
rule would reduce duplication of effort for the operators. They
supported the provision in the rule that allows operators in states
that require disclosure on FracFocus to meet both the state and BLM
requirements through a single submission to FracFocus. The BLM agrees
with these comments and did not make any changes to the rule.
Other commenters were critical of FracFocus for not being user-
friendly and for not allowing republication or linking with other
databases. The BLM has been in discussions with the GWPC, which is
responsible for the FracFocus database, to address some of these
concerns. As of June 2013, the FracFocus database was upgraded to
FracFocus 2.0. Their latest upgrades are explained on their Web site
under ``Frequently Asked Questions'' at www.fracfocus.org/faq. The BLM
is in continued discussion with the GWPC and expects further progress
and improvement of the site to ensure an effective chemical disclosure
registry for the hydraulic fracture fluids. The BLM did not make any
changes to the rule as a result of these comments.
Some commenters suggested that additional information, such as the
APD, well status, compliance, volume of fluid recovered, and complaint
process, should be reported through the FracFocus submission. While
some of this information is available through the BLM, FracFocus only
publishes information related to disclosure of chemicals used in
hydraulic fracturing fluids. The BLM did not revise the rule as a
result of this comment.
Some commenters were critical of FracFocus because of the unknown
future condition and long-term reliability of this organization in
hosting and retaining the data. A few commenters expressed concern
about future funding, access, and data backup issues of FracFocus.
Other commenters suggested that the disclosure registry should be
searchable across forms and allow for meaningful cross-tabulation of
search results. One of the commenters specified that each of the
disclosure submissions should have a date stamp showing the actual date
of submission to the database and validate/reject the correct/incorrect
CAS Registry Numbers of the disclosed chemicals/ingredients when
submitted. Another commenter suggested that the BLM should develop a
new public disclosure platform tailored to the agency needs. The BLM
considered these comments as valuable suggestions and will continue to
work to improve any platform used for public disclosure. However, it
did not make any changes in the rule because of these comments.
The BLM has reviewed the Secretary of Energy Advisory Board's
FracFocus 2.0 Task Force Report, dated March 28, 2014, and its concerns
and recommendations for FracFocus improvements as cited earlier in the
preamble. Key issues raised include: The ability to search and generate
information by chemical, well, company, and geography; quality control
of data; and the capacity to handle large volumes of data. The BLM is
committed to working with the DOE and FracFocus to ensure these issues
are addressed so that public information gathered as a result of this
rule is of high quality, accessible, and usable. As mentioned earlier,
the GWPC and IOGCC, joint venture partners in the FracFocus initiative,
announced the release of several improvements to FracFocus' system
functionality. The new features are designed to reduce the number of
human errors in disclosures, expand the public's ability to search
records, provide public extraction of data in a ``machine readable''
format, update educational information on chemical use, environmental
impacts from oil and gas production, and potential environmental
impacts. The new self-checking features in the system will help
companies detect and correct possible errors before disclosures are
submitted. This feature will detect errors verifying that CAS numbers
meet the proper format. These improvements to the system will address
many of these concerns.
Many commenters addressed the use of the FracFocus database and Web
site. Some commenters supported the BLM's proposal to allow submission
of data through FracFocus. Other commenters, however, were critical of
the proposal. Some commenters were concerned that the ownership of the
data on FracFocus and the applicability of public disclosure laws, such
as the Federal Freedom of Information Act (FOIA), are unknown. The
Federal FOIA does not apply to FracFocus, because it is operated by the
GWPC, which is not an

[[Page 16169]]

agency of the Federal Government. However, information on FracFocus
concerning Federal or tribal wells is public information.
A commenter suggested that the BLM adopt a procedure used in Texas
that requires operators to submit to the state commission a copy of the
information that they upload to FracFocus. Under this final rule,
submission of the required information through FracFocus is optional;
an operator may instead submit it directly to the BLM, and the BLM will
upload it to FracFocus. The BLM's intent, however, is to reduce the
paperwork burden on operators by allowing them to submit information
through FracFocus, if they so choose. Thus, in states that require
submission on FracFocus, there would be no additional burden of
complying with this requirement of the rule.
Some commenters said that using FracFocus would violate an
Executive Order requiring new government information to be available to
the public in open, machine-readable formats, and the implementing
guidance from the Office of Management and Budget. See Executive Order
13642, 78 FR 93 (2013), and Memorandum for the Heads of Executive
Departments and Agencies, M-13-13 (OMB 2013). That Executive Order
provides, in pertinent part, that the policy of the Executive Branch is
that new and modernized Government information resources must be open
and machine readable. The order is subject to several conditions,
including available appropriations.
That Executive Order does not prohibit the BLM from allowing
operators to submit information through FracFocus. The BLM believes
that FracFocus is the quickest, most cost-effective way to make the
information public. Working with FracFocus to meet the policy goals of
the Executive Order, including machine-readable formats, will be more
prompt and will use taxpayer dollars more efficiently than would the
BLM creating and managing its own database solely for chemical
disclosures.
A commenter was concerned that using FracFocus could cause a
conflict of interest because the GWPC is a trade association for the
oil and gas industry. The BLM disagrees with this comment. The members
of GWPC are the state agencies (www.gwpc.org/state-agencies) that
protect and regulate ground water resources. They do not have a
conflict of interest in operating FracFocus to serve as vehicle for
operators to submit data to the BLM, or in making that information
available to the public.
A commenter said that using FracFocus would fail to meet minimum
standards for managing government records. The commenter misconstrues
the role of FracFocus. FracFocus will not be the official repository of
the chemical information required by the rule. Whether an operator
submits information to BLM directly or through FracFocus, the BLM will
keep the information in its records. The information will also be
available on FracFocus for the benefit of the public and state and
tribal agencies.
A commenter raised an issue of implementation and enforcement--that
because FracFocus does not show the date that information is uploaded,
it will be difficult for the BLM to know if the information was
submitted within the time period required by the rule. The BLM will
closely monitor FracFocus to ensure that operators submit information
in a timely manner consistent with these regulations. The BLM will be
working with the GWPC to improve the ability of FracFocus to meet the
BLM's needs and of operators on Federal or tribal lands. The final rule
is not revised in response to those comments.
Report Route Changes
One commenter expressed concern that operators may change their
access route and transportation methods for water used in fracturing
wells after the initial approval. The commenter suggested that
operators be required to report any changes in approved access routes
and transportation methods. Although not explicitly stated, operators
are required to follow the approved plan along with any conditions of
approval. This requirement includes using the approved access route and
transportation method. Any change to the approved plan requires the
BLM's approval. The Sundry Notice form itself addresses a change of
plans. If the operator has a need to change the access route or
transportation methods for water, they must file a change of plans. If
the operator does not follow the approved plan along with any
conditions of approval, the operator would be in noncompliance with the
approval. The BLM would then take enforcement actions under 43 CFR part
3163. No revisions to the rule were made as a result of this comment.
Need for a Subsequent Report
Some commenters stated the information required to be submitted to
the authorized officer within 30 days after the completion of the last
stage of hydraulic fracturing operations under section 3162.3-3(i), is
redundant, unnecessary, and burdensome. The commenters stated that much
of the information is provided in the NOI and some of the information
is already required with the completion report. The information in the
application and the information in the subsequent report serve
different purposes. The information in the application allows the BLM
to analyze the proposed operations to ensure that there will not be any
unnecessary or undue degradation of public lands or breach of trust on
Indian lands, and to develop any necessary mitigation to protect
resources. The purpose of the subsequent report is to provide
information on what was done and how it was done, as compared to how it
was planned. Some information, such as the results of the MIT and the
cement operations monitoring report, are not included in the APD or
NOI, and can only be submitted after the operations are complete. The
information included with the subsequent report also differs from the
information required with the well completion report. Examples include
the results of the MIT and the operator certification that it complied
with paragraphs (b), (e), (f), (g), and (h) of the rule prior to and
throughout the hydraulic fracturing operation. However, final section
3162.3-3(i)(9) is revised in response to comments pointing out that the
proposed requirement to submit well logs and records of adequate cement
duplicates a requirement in the well completion report.
Fluid Volume Data
One commenter requested that the total volume of fluid injected
during a hydraulic fracturing operation should be reported. Another
commenter requested further subcategorization of water volumes, such as
surface, subsurface, and recycled water. The BLM did not revise the
rule as a result of these comments. During a water-based hydraulic
fracturing operation, water and proppant generally make up
approximately 98-99 percent of the fluid injected during a fracturing
operation and other additives, such as friction reducers, surfactants,
gelling agents, and scale inhibitors make up the remaining, usually
about 1-2 percent. The difference between total fluid used and volume
of water used is insignificant from a volumetric perspective. Other
commenters were critical of the fact that the volumes of each chemical
were not required to be reported in addition to the percentages of
ingredients used. The maximum ingredient mass can be calculated from
the percentages of ingredients reported. The BLM did not revise the
rule because of these comments.

[[Page 16170]]

One commenter suggested that the BLM require operators to report
their water usage to a public database to assure that water usage
complies with state law and require operators to provide evidence of
their water rights. The BLM does not need to see evidence of an
operator's water right. Policing water rights is the duty of states and
tribes, not the BLM. The rule already requires operators to report the
total water volume used for each well. The BLM expects that most
operators will report that information through FracFocus. This rule
does not preempt any state or tribal law requiring operators to report
water usage to another database.
Hydraulic Fracturing Fluid Constituent Data
One commenter stated that the post-fracking reporting requirements
should clarify that the chemical disclosure is just for the chemicals
added to the hydraulic fracturing fluids and do not include naturally
occurring chemicals in the formation. The BLM concurs with this comment
and section 3162.3-3(i)(1) is revised to clarify that the operator must
submit a description of each additive in the hydraulic fracturing
fluids. The chemical disclosure will include each additive in the
hydraulic fracturing fluid used by the operator for conducting the
hydraulic fracturing operation. Surface or ground water usually
includes naturally occurring chemicals and may have pollutants from
other sources. Re-used or recycled water will usually not be distilled,
but rather have traces of chemicals from prior uses or by-products from
processing. Those chemicals are not additives to the hydraulic
fracturing fluids and will not be required to be reported as part of
the disclosure. If the final rule required expensive chemical analysis
of reused or recycled base fluids, it would discourage the use of
reused or recycled water and put additional demands on surface or
ground waters needed for drinking, agriculture, industry or ecosystems,
and would increase the volume of recovered fluids needing permanent
disposal. However, even if chemicals are naturally occurring in the
formation, the same chemicals need to be disclosed if they are added to
base fluid for hydraulic fracturing.
One comment stated that not all chemical compounds have CAS numbers
and therefore could not be reported. CAS stands for Chemical Abstracts
Service, a division of the American Chemical Society. The CAS number is
a unique numerical identifier assigned to every chemical substance
described in the open scientific literature. This registry is
maintained by CAS and is internationally recognized. The BLM's review
of disclosure reports on FracFocus indicates that the chemical
substances added to base fluids are registered and have a CAS number.
Therefore, the requirement for reporting a CAS number has not been
changed. Multiple CAS numbers may be used if multiple chemical
constituents are reported for one chemical compound.
Some of the commenters suggested that the BLM require both maximum
and actual concentration of chemicals used. The BLM made no change to
the rule because of this comment. Considering the objective of the
chemical disclosure, the maximum concentration provides the worst case
scenario, which is more important for environmental exposure, health,
and safety of the operation. Percent by mass of each chemical is
required in the hydraulic fracturing fluid to quickly evaluate
potential exposure. Also, the actual concentration of chemicals may
change as the operator fractures different stages of a single well.
Thus, the maximum concentration provides the most useful information
toward achieving the goal of protecting groundwater and developing
potential response criteria.
A few commenters asserted that listing the maximum concentration of
the non-MSDS-listed ingredients within an additive imparts no real
value while increasing the risk that the disclosures could be used to
reverse-engineer proprietary formulas for hydraulic fracturing
additives. The BLM disagrees with this comment. The chemicals listed on
Material Safety Data Sheets (MSDS) are believed to be hazardous to
workers in an occupational setting as determined by the Occupational
Safety and Health Administration (OSHA). Other chemicals which do not
require MSDS, however, might be hazardous to humans in an environmental
setting (such as in ground water used for drinking) or might be harmful
to the environment. Therefore, disclosure of these chemicals, including
the maximum concentration, is necessary. Section 3162.3-3(j)(1) of the
final rule requires affidavits to validate the trade secret claims.
This requirement will allow legitimate exemptions with proper
documentation and attestations in compliance with the previously
mentioned section. The BLM did not revise the rule as a result of this
comment. Several commenters requested disclosure of the volume of
proppant to be used along with the location where the proppant was
mined or extracted. Final section 3162.3-3(i)(1) is revised to require
a description of each additive in the hydraulic fracturing fluid,
rather than just each chemical. While section 3162.3-3(i)(1) does not
specifically require the volume of proppant to be reported, it does
require that each additive to the hydraulic fracturing fluid be
reported along with the maximum ingredient concentration in the
hydraulic fracturing fluid. Because a proppant is an additive, it must
be reported. The volume of proppant can be calculated from the
percentages of ingredients reported. The BLM does not believe it to be
appropriate to require the location where the proppant was mined or
extracted because the BLM would have no authority over proppant
extraction if it were not on public land. If it were on public land, it
would require a separate authorization unrelated to these regulations.
No changes to the rule were made as a result of this comment.
Some commenters asked that the BLM defer to states on matters of
disclosure of information, including disclosure of chemicals used in
hydraulic fracturing operations. These commenters said that states have
the best knowledge of the geology, and have the experience and
expertise to make the right decisions. The BLM agrees that state
agencies are well-informed and have much experience and expertise, as
does the BLM. However, chemical reporting requirements are not
dependent on geological conditions. The final rule assures that the
BLM, states, and the public will have access to information on the
chemicals used in hydraulic fracturing operations on Federal and Indian
land without imposing unreasonable burdens on operators.
Handling and Disposal
Several commenters suggested clarifying the language in sections
3162.3-3(i)(7)(i) and (7)(ii) (paragraphs (5)(ii) and (5)(iii) in the
proposed rule) to better differentiate handling methods from disposal
methods. The commenters pointed out that hauling by truck and
transporting by pipeline are not disposal methods. The BLM agrees and
modified the requirement to differentiate handling methods (e.g.,
hauling by truck, holding ponds) from disposal methods (e.g.,
injection, off-site disposal facility, recycling).
Several comments objected to the requirement that operators report
the volume of fluid recovered from production facility vessels. The BLM
agrees with this comment and has reworded this requirement in final
section 3162.3-3(i)(6). See the preamble discussion under flowback
fluids for a further explanation.

[[Page 16171]]

One comment requested that the composition of the recovered fluid
be required as in the original proposed rule (77 FR 27710). The BLM did
not revise the rule as a result of this comment because this was not a
requirement in the supplemental proposed rule and because the BLM
believes providing such information would not be useful. This rule aims
to treat all recovered fluid as potentially hazardous regardless of
what the chemical constituents may be.
Deviation From Permit
Numerous commenters stated that the rule should be modified to
define what is meant by a ``deviation from the approved plan'' as
required in the subsequent report after hydraulic fracturing operations
have concluded. The commenters indicated that it is possible for
numerous minor deviations to occur while conducting hydraulic
fracturing operations, and that the BLM should identify any deviations
it considers critical. Other commenters indicated that the BLM should
request an explanation and additional information regarding issues
believed to be potentially significant after the completion reports
have been reviewed. The BLM agrees and has modified the rule as a
result of these comments by deleting supplemental section 3162.3-
3(i)(6). The BLM believes that due to the nature of hydraulic
fracturing operations it is not practical to define, or list, all the
myriad of outcomes and has deleted this specific requirement in the
final rule. Anomalies or deviations are better handled through
implementation, including both policy and training, and BLM engineers
will identify and resolve deviations when reviewing completion reports
as the BLM handles deviations involving approved APDs. This rule and
the operating regulation provides for the authorized officer to request
any additional information deemed necessary for review of the post-
hydraulic fracturing operation on Federal or Indian leases.
Submission of Logs
Several commenters expressed concern about the requirement under
the supplemental proposed rule (section 3162.3-3(i)(8)) requiring
operators to submit well logs within 30 days of completion of hydraulic
fracturing. A commenter stated this requirement is duplicative of the
requirements of the BLM Well Completion or Recompletion Report and Log
(Form 3160-4). The commenter stated that all logs are already provided
with the completion report. The BLM agrees with this comment. As the
commenter pointed out, operators are required to submit all logs with
the BLM Well Completion or Recompletion Report and Log. Item 21 of the
form requires the operator to specify the type of electric and other
mechanical logs run and indicates operators are to submit a copy of
each. Item 33 of the form requires the operator to indicate which items
have been attached by placing a check in the appropriate boxes. The
first box is for electrical/mechanical logs and in parentheses, the
operator is reminded that ``1 full set req'd.'' Submission of the
completion report and the logs is required by existing section 3162.4-
1(b). Since the operators are already required to submit all logs, the
requirement in supplemental section 3162.3-3(i)(8) has been deleted in
the final rule.
Additional Information
Numerous commenters objected to the requirement in the supplemental
proposed rule that the BLM can ask for additional information when
reviewing an application for hydraulic fracturing. The commenters
stated that this requirement is vague, unnecessary, and could lead to a
broad interpretation by local BLM offices. The BLM did not revise the
rule in response to this comment because the BLM must have the ability
to ask for whatever information it needs to adequately review an
application and fulfill our stewardship or trustee obligation. Because
geology and operations vary widely, the BLM needs the flexibility to
request information relevant to a specific or unique proposal and it
would be unworkable for the BLM to list every possible piece of
information that would cover all hydraulic fracturing applications.
Pressure
Several comments expressed confusion over which pressure the BLM
required in the subsequent report. Supplemental proposed rule section
3162.3-3(h)(2) asked for the actual pump pressure, and section 3162.3-
3(h)(3) asked for the actual surface pressure. The BLM agrees that
these requirements were confusing and revised the final rule to only
require the maximum surface pressure that was applied during the
hydraulic fracturing operations. The requirements in this section were
also revised to make them consistent with the requirements of the NOI
in section 3162.3-3(d).

Section 3162.3-3(j) Information Exempt From Public Disclosure

This section sets out the circumstances and procedure under which
operators may withhold information from public disclosure under the
rule. An operator may withhold information as exempt from public
disclosure only if it identifies a Federal statute or regulation that
would prohibit the BLM from disclosing the information if it were in
the BLM's possession. The BLM anticipates most if not all exemption
assertions will be made under the Federal Trade Secrets Act, 18 U.S.C.
1905, a criminal statute which prohibits Federal employees from
divulging trade secrets and other confidential information without
authorization. The supplemental proposed rule would have allowed
operators to withhold information otherwise required to be submitted by
executing an affidavit affirming that the information was a trade
secret. The final rule modifies the supplemental proposed rule at
section 3162.3-3(j) in several respects. The list of items that the
operator must affirm has been expanded to more completely address the
factors that are needed to support a claim of exemption from public
disclosure. The operator's affidavit must also identify any other
entity, such as a contractor or supplier, which would be the owner of
the withheld information. The operator must submit an affidavit from
such entity that provides any information upon which the operator
relies in executing the operator's affidavit. The operator must affirm
that it has possession of the withheld information so that BLM would
have access to it upon request. A corporate officer, managing partner,
or sole proprietor must sign the operator's affidavit. Finally, the
operator must maintain the withheld information for the later of the
BLM's approval of the final abandonment notice for the well, or for
Indian lands, 6 years, or for Federal lands, 7 years, as provided under
existing applicable law discussed below. As in the supplemental
proposed rule, the BLM may require the operator to provide the withheld
information.
The BLM received numerous comments concerning trade secrets and
confidential business information. Some commenters were critical of
allowing operators to withhold any information from the public. Other
commenters were critical of the role of the BLM in deciding whether
information would be entitled to protection.
A commenter suggested that the BLM defer to states on the handling
of trade secrets claims, asserting that they were state and tribal
issues, and should be regulated by those authorities. Further, the
commenter believed that states and tribes were better versed in
hydraulic fracturing operations, and could be

[[Page 16172]]

stricter than the Federal Government. The BLM did not revise the rule
in response to this comment. No Federal statute allows the BLM to defer
to decisions of states or tribes about what information in the BLM's
possession will be released to the public, or what information the BLM
would allow operators to withhold from the public.
Some commenters were critical of the supplemental proposed rule for
not being the same as state rules on trade secrets. Many states have
adopted the Uniform Trade Secrets Act, or have other laws governing
protection of proprietary information. Those state statutes do not
govern the BLM's compliance with the Federal Trade Secrets Act, and the
Federal Trade Secrets Act does not apply to state governments. Thus,
the BLM is not in a position to concur or to disagree with a state's
``trade secret list,'' as suggested by a commenter. The BLM understands
concerns about duplication of efforts or the potential for inconsistent
determinations. If a state agency has released information to the
public without restrictions, that information would not qualify as a
trade secret and the BLM would not withhold it from the public. Nothing
in this rule preempts state or tribal laws requiring disclosure of
information or protecting proprietary information.
Several commenters stated that if the BLM continues to allow
exemptions from public disclosure for information on chemical
identities in the final rule, it should at least require identification
of the chemical family of the substance. The commenters stated this
basic information does not implicate an operator's trade secrets, but
provides at least some information about what types of chemicals were
used by the operator in well stimulation. The commenters point out that
such a rule is feasible because a number of states require that the
chemical family be disclosed where a chemical's identity is withheld as
a trade secret. Those states include Arkansas, Colorado, Louisiana,
Montana, Oklahoma, Pennsylvania, and Texas. The BLM reviewed numerous
hydraulic fracturing disclosure reports in FracFocus. The review
revealed that many operators are providing the chemical family name or
other similar descriptor for those chemicals that are protected as
trade secrets. Those include reports from states that do not have a
specific requirement to report on FracFocus, and thus were voluntarily
disclosed.
A commenter recommended that the rule require disclosure of the
generic chemical name as required under EPA's guidance implementing
section 5 of the Toxic Substances Control Act (TSCA). See Instruction
Manual for Reporting Under the TSCA Sec. 5 New Chemicals Program, p.33
(EPA 2003). The BLM believes that the generic chemical name that was or
should be provided to the EPA under TSCA or other statutes and
published in the Federal Register would not constitute a trade secret
because it is or should be public, and the operator can still withhold
the specific chemical identity. The BLM also concludes that requiring
the generic chemical name would promote consistency with the EPA's
implementation of TSCA and other statutes for confidential chemical
information, and thus would be less confusing for owners of information
and the public. Therefore, final section 3162.3-3(j)(6) requires the
operator to include the generic chemical name for each such chemical.
The BLM expects that the generic chemical name submitted pursuant to
this rule will be the same as that submitted to EPA; if the generic
chemical name is less descriptive than that submitted to EPA, the owner
of the information should have a credible explanation for the
difference.
The supplemental proposed rule at section 3162.3-3(j)(4) would have
required operators to retain in their records the information they
claimed to be exempt from disclosure for 6 years, by reference to the
existing regulations at 43 CFR 3162.4-1(d). The rule expressly
requested comments on whether another retention time would be more
appropriate. The BLM received many comments on that topic. A few
commenters favored the 6-year retention period, though more favored
shorter periods. Many other commenters favored longer retention
periods; several favored that records be retained for the life of the
well, and a few advocated perpetual retention.
Final rule section 3162.3(j)(5) requires operators to retain
information that is withheld from the BLM until the later of the
approval of the notice of final abandonment of the well (i.e., the
``life of the well''), or 6 years after the completion of hydraulic
fracturing operations on Indian lands, or 7 years after completion of
hydraulic fracturing operations on Federal lands. The BLM's need to
have access to information about chemicals injected into Federal or
Indian minerals may arise at any time. However, a perpetual retention
requirement would not be appropriate because an operator's
responsibility for a well ends (for purposes of most of the BLM's
regulations) when the BLM approves the operator's notice of final
abandonment of the well.
A 6-year minimum retention period on Indian lands is not burdensome
because operators are already required under the Federal Oil and Gas
Royalty Management Act (FOGRMA) and regulations to retain all records
for a minimum of 6 years, including records and reports they submit to
the BLM. See 30 U.S.C. 1713(b); 43 CFR 3162.4-1(d).
A 7-year minimum retention period is not burdensome because
operators on Federal lands are already required under the Federal Oil
and Gas Royalty Simplification and Fairness Act of 1996 (FOGRSFA), 30
U.S.C. 1724(f), to retain all records for determining compliance with
any regulation with respect to Federal oil and gas leases for 7 years.
BLM's regulations at 43 CFR 3162.4-1(d) have not been updated to
reflect that statutory obligation, but there is no impediment to this
final rule requiring retention of data for a minimum of 7 years.
Although FOGRSFA precludes the BLM from requiring longer retention of
records pertaining to financial obligations (such as royalties), it
does not preclude longer retention of records pertaining to other
requirements for onshore oil and gas operations. FOGRSFA does not apply
to Indian lands, and therefore the 6-year retention period in 30 U.S.C.
1713(b) applies to those lands.
Requiring trade secret records to be retained for the life of the
well, if that life is longer than 6 or 7 years, is fair and reasonable
because if an operator withholds the information under the rule
(section 3162.3-3(j)(1)) the operator's records of the withheld
information may be the only records of the chemicals injected into
Federal or Indian minerals. Therefore, the BLM believes that it is
necessary to have access to that information for the life of the well,
and that the 6-year and 7-year retention periods in the pertinent
statutes are minimum requirements with respect to records that do not
pertain to financial obligations.
Some commenters said that the rule would fail to protect trade
secrets, or that it mandated disclosure, putting the BLM and its
employees at risk of lawsuits. The BLM disagrees. This rule, like the
supplemental proposed rule, allows operators initially to withhold
specific information by submitting an affidavit from the operator
demonstrating that the information is protected from disclosure by law.
The BLM retains authority to require operators to submit any of the
initially withheld information. If the BLM decides that the information
is not a trade secret, it would provide advance notice so that the
operator or owner of the information could seek a court order

[[Page 16173]]

restraining disclosure to the public. The rule provides the same
procedural safeguards for hydraulic fracturing information as for all
other information obtained by the Department.
Some commenters expressed confusion about who would determine
whether identities of chemicals were entitled to be withheld from the
public as trade secrets. Under this final rule, in the first instance,
the operator would either disclose the information or would withhold
specific information and submit an affidavit. If the BLM requested the
withheld information, the operator would be required to provide it. The
BLM would determine if the information is a trade secret. As described
earlier, if the BLM determines that the information is not a trade
secret, the operator and owner of the information would have an
opportunity to challenge the BLM's determination in Federal district
court.
Some commenters were critical of the revised proposed rule for not
defining trade secrets. The Federal Trade Secrets Act does not define
trade secrets, and does not expressly authorize Federal agencies to
define trade secrets. The BLM will make any decisions regarding trade
secrets and other confidential information based on relevant Federal
judicial opinions. See, e.g., Canadian Commer. Corp. v. Air Force, 514
F.3d 37, 39 (D.C. Cir. 2008) (``We have long held the Trade Secrets Act
. . . is `at least co-extensive with . . . Exemption 4 of FOIA.' '')
(citation omitted); National Parks & Conserv'n Ass'n v. Morton, 498 F.
2d 765 (D.C. Cir. 1974) (discussing meaning of privileged or
confidential commercial or financial information); Public Citizen
Health Research Group v. FDA, 704 F.2d 1280, 1288-89 (D.C. Cir. 1983)
(``trade secret'' in exemption 4 means a ``commercially valuable plan,
formula, process, or device that is used for the making, preparing,
compounding, or processing of trade commodities and that can be said to
be the end product of either innovation or substantial efforts'').
Other commenters asserted that 10 business days' notice before
releasing information was insufficient, and one said that it would
stifle development of more environmentally benign chemicals. The BLM
disagrees. Similar to the Department's FOIA regulations, the final rule
requires a minimum of 10 business days' notice prior to releasing
information determined not to be exempt from disclosure. Cf. 43 CFR
2.33(c). That time is sufficient for the submitter to seek a temporary
restraining order from a court. Also, the BLM would give due
consideration to all relevant factors, including whether the
information is the end product of innovation, in deciding whether the
information is a trade secret.
Many commenters objected to the requirement that the operator
certify that withheld chemical information is a trade secret. They said
that the trade secrets are owned by the service contractors, and that
the operator has no knowledge of them or ability to certify. Some said
that the BLM should place the burden on the service contractors and not
the operator. One commenter said that chemical manufacturers invest
great sums in developing their products, and should not have to rely on
oil and gas operators (or apparently, service providers) to assert and
defend their trade secrets. The BLM disagrees in part. The BLM is aware
that the common practice is for operators to engage service companies
to conduct hydraulic fracturing services. The existing regulations are
clear, however, that an operator cannot use a contract with a third
party to escape responsibility for all operations on the permitted well
site. See existing section 3162.3(b). Whether or not chemical suppliers
or service contractors would ``own'' the information about the
chemicals, it is the operator who has voluntarily taken responsibility
for all operations in and on its wells, including hydraulic fracturing,
and it is the operator who is responsible for submitting all required
reports and information. Nonetheless, because the operator will not
always be in the best position to declare why certain information
should be withheld, the final rule allows the operator to submit an
affidavit from the owner of the information attesting to the
confidential status of the information in addition to the affidavit
required from the operator. When the BLM is deciding whether alleged
trade secret information it has received may be disclosed to the
public, both the operator and the owner of the information may provide
the BLM with any materials that would substantiate a claim of trade
secret status, and both the operator and the owner of the information
would receive advance notice of any BLM decision that the information
is not a trade secret.
Some commenters asked that trade secret protection be extended to
other required information, such as elements in the NOI. As with any
submission of information to a Federal agency, the submitter may
segregate the information it believes is a trade secret, and explain
and justify its request that the information be withheld from the
public.
Many commenters addressed other issues concerning trade secrets.
Some commenters opposed allowing operators to withhold trade secrets
from public disclosure. Other commenters asserted that the BLM was
arbitrarily ignoring the recommendations of the Secretary of Energy's
advisory task force that all chemicals should be disclosed to the
public without exception. The BLM has no authority to require public
disclosure of information that is entitled to protection under the
Federal Trade Secrets Act. There is nothing arbitrary in assuring the
compliance of BLM employees with a Federal criminal statute.
Some commenters said that the BLM's authority to promulgate
regulations provides the BLM authority to require public disclosure by
regulation, obviating protection under the Trade Secrets Act, citing,
e.g., Chrysler Corp. v. Brown, 441 U.S. 281 (1979) [Chrysler]. The
Supreme Court in Chrysler established a three-part test for determining
whether an agency rule may exempt information from the Trade Secrets
Act: (1) The rule must be substantive; (2) It must be issued in
accordance with statutory procedures; and (3) The rule must be based on
a statutory grant of authority allowing the agency to disclose
privileged information. This rule satisfies parts 1 and 2 of the
Chrysler test. But the BLM's authorizing statutes do not expressly
authorize regulations requiring disclosure of privileged information.
Thus, the final rule is not revised in response to those comments.
Some commenters urged the BLM to require operators to submit trade
secret information to the BLM, even if the BLM was required to maintain
confidentiality, in order to encourage operators to make only good
faith claims of trade secret protection. Some commenters said that the
BLM should require operators to justify their trade secret claims. Some
commenters said that the BLM should individually validate each claim of
trade secret status. The BLM believes that the affidavit requirements
are sufficient to assure that the vast majority of operators will
assert only good faith claims for trade secret protection. But although
the BLM will not be individually adjudicating each claim of trade
secret status, the BLM agrees with those commenters in part. The BLM
has revised the affidavit requirements to address all of the factors
that the BLM would need to consider in deciding whether to release the
information. The final rule requires the operator to affirm that it or
any other owner of the information is in actual competition, identify
competitors that would be interested in the withheld information, and
affirm that release of the

[[Page 16174]]

information would likely cause substantial competitive harm and provide
the reasons for that affirmation. If the operator is relying on
information from its contractors or suppliers, the operator will need
to provide affidavits from those entities supporting that reliance.
Although additional supporting facts might be required if the BLM had
to decide whether the information is a trade secret, the BLM could
request those additional facts. Furthermore, the final rule requires
that the affidavit be signed by a corporate officer, managing partner,
or sole proprietor of the operator. That will discourage bad-faith
assertions of trade secret protection.
A commenter suggested that, in addition to the affidavit, an
operator should be required to provide independent verification that
the information is a trade secret. The BLM will not require an operator
to disclose proprietary information to an industry trade group as
suggested by the commenter, in order to assert trade secret protection.
Even if it were within the BLM's discretion, it would place industry
trade groups in a role they have not requested.
Some commenters suggested that the BLM establish a procedure for
citizens to challenge affidavits for withholding trade secret
information. The BLM's resources will be better devoted to implementing
this rule to assure protection of usable water from hydraulic
fracturing fluids than in adjudicating uncontrollable numbers of
challenges to affidavits. If the BLM has reason to believe that an
affidavit is incomplete or inaccurate, or that it needs the information
for any purpose, including a random inspection, it can demand the
withheld information and make a determination if it is truly a trade
secret. Additionally, the BLM encourages voluntary disclosure of
fracturing fluids to the public, as some companies in the oil and gas
industry have begun to do. Some commenters urged the BLM to require
operators to disclose trade secret information in the event of a
medical emergency. Other commenters stated that the material safety
data sheets (MSDS) required by the OSHA are adequate for disclosure to
medical personnel and first responders. The BLM understands the need
for first responders and medical personnel to have complete information
about potential chemical exposures in the event of an accident.
However, unlike many state laws, the Federal Trade Secrets Act does not
include an exception for medical or other emergencies. If the BLM
requests the withheld information, and any Federal law required the BLM
to provide it to another entity, the BLM would comply with that law.
Note though, however, that nothing in this rule exempts operators or
their contractors from complying with all applicable regulations of the
OSHA, including requirements concerning MSDS. Furthermore, nothing in
this rule preempts laws of states and localities (on Federal lands) or
of tribes (on tribal land) requiring disclosure of information to first
responders or to medical personnel.
Some commenters doubted the BLM's ability to make informed
management decisions without complete information about the chemicals
being used. The BLM disagrees. The BLM understands that hydraulic
fracturing operations will use chemicals that are potentially
hazardous. Compliance with this rule will assure that those chemicals
are isolated from sources of usable water.
A commenter suggested deleting the ``maximum ingredient
concentration in additive (percent by mass)'' requirement, arguing that
it would have the effect of creating more trade secret exemptions, and
that from an environmental perspective, what matters is the total
concentration of a chemical. The BLM believes that the comment has
merit, but there are costs and benefits to either approach. On balance,
the rule is not revised in response. On the one hand, it is possible
that if the rule does not require the percent by mass maximum
ingredient concentration, more of the chemicals used in hydraulic
fracturing operations would be disclosed because the risk of reverse-
engineering would be reduced. On the other hand, the GWPC requests the
percent by mass on its FracFocus data sheet and the industry has shown
a willingness to furnish that information. As a result, the final rule
requires disclosure of the percent by mass. The BLM notes that
operators may seek to withhold the percent by mass as a trade secret,
and to disclose the identity of the particular chemicals. That could be
appropriate where the particular chemicals are not unusual, but the
operator believes it has a valuable formula that optimizes the
concentrations.
A commenter recommended that trade secret protection be denied
unless there were a patent or a patent application pending for the
chemicals. The Federal Trade Secrets Act does not have such a
restriction and the BLM has no authority to impose one in this
regulation. The final rule is not revised in response to that comment.
Some commenters recommended that operators should be able to obtain
trade secret protection prior to conducting hydraulic fracturing
operations, either in an NOI, or in a ``master chemical plan.'' The BLM
disagrees. The BLM is not requiring submission of the identities of
chemicals proposed to be used in hydraulic fracturing operations. Only
the chemicals actually used in those operations would need to be either
disclosed, or withheld by submitting an affidavit. The final rule is
not revised in response to those comments.
Some commenters expressed uncertainty about what statute would
prohibit disclosure of the identities of chemicals for purposes of
final section 3162.3-3(j)(1)(ii). The BLM believes that most claims
would be made under the Federal Trade Secrets Act, but the final rule
leaves the category open in case any other statute might apply to
certain information. The final rule is not revised in response to these
comments.
A commenter recommended changing the affirmation required in the
affidavit to ``the best of the operator's knowledge at the time.'' The
final rule is not revised in response to that comment. Withholding the
identities of chemicals injected into Federal or Indian minerals is a
privilege, and to earn that privilege the operator must make informed
declarations in the affidavit. If the operator is relying on
information from a contractor or supplier, the rule requires that the
operator provide an affidavit from that entity setting forth that
information.
A commenter recommended deleting the affirmation as unnecessary.
The BLM disagrees. The BLM believes that the affirmation is appropriate
and has not revised the rule in response to that comment.
Some commenters urged that the records of the chemical identities
withheld as trade secrets should be retained by the service
contractors, not by the operators. As previously explained, operators
are responsible for their contractors' actions on the well sites.
Maintaining accurate and complete well records with respect to all
lease operations is the operator's responsibility. See existing section
3162.4-1(a). Indeed, the admissions in comments that some operators are
not currently retaining all information about hydraulic fracturing
operations raise concerns. Note though, that nothing in the rule
prevents an operator from maintaining the confidential information
under a physical or an electronic seal that would notify the owner of
the information when it was accessed, as long as the BLM will have
access to it upon request.

[[Page 16175]]

Furthermore, in response to comments stating that owners of trade
secret chemical information would not allow operators to possess it,
the final rule provides that an operator will be deemed to be
maintaining the required information if it can promptly provide it to
the BLM upon request, even if the information is in the custody of its
owner. Any successor operator will be responsible for maintaining that
access for the retention period in this rule.

Section 3162.3-3(k) Variances

This section allows operators to request a variance from the
requirements of this final rule. Variance language is common among BLM
regulations. Under this provision, the BLM will consider alternatives
if an operator can demonstrate that the objectives of the rule would be
met using an alternate approach.
Three changes are made to this section. First, this section is
reorganized for clarity, segregating requirements for individual
variances and state or tribal variances. Second, this section has been
revised to clarify that the authority to approve a variance that
applies to all wells within a state or within Indian lands, lies with
the State Director. Third, this section has been revised to make
paragraph (k)(3) consistent with existing regulations in Onshore Order
1 by adding language stating that the decision on a variance request is
not subject to administrative appeal either to the State Director or
under 43 CFR part 4.
Numerous commenters said that the rule should be revised to
prohibit blanket variances for operators. The BLM did not revise the
rule as a result of these comments. No blanket variance provisions for
hydraulic fracturing operations exist in the rule. As provided,
variances may be granted on a case-by-case basis from a specific
provision of the rule, within a state, or on a tribal basis. Individual
variances could only be granted where the operator's proposal meets or
exceeds the objectives of the rule, and state or tribal variances may
only be granted if the state or tribal provisions meet or exceed the
objectives of the rule. A variance granted pursuant to this rule would
not be an exemption from the goals of this rule, and would not be an
abdication of the Secretary's stewardship responsibilities on Federal
lands or trust responsibilities on Indian lands.
Numerous commenters stated that the rule should be revised to
disallow variances of any kind or that variances should be limited. The
BLM did not make any changes as a result of these comments. The BLM
believes that it is practical to include a variance provision since the
rule cannot contemplate all possible hydraulic fracturing circumstances
which may be encountered on a national basis and must include
provisions to address those unique or local circumstances, or improved
technologies. The BLM believes, however, that variances should only be
granted when it is clear that the alternative requirement is equally or
more protective than the BLM's rule.
Several commenters indicated that the variance definition is vague
and could allow for waiving of hydraulic fracturing requirements. Other
commenters requested further clarification or suggested alternative
language for this section. The BLM did not revise the rule as a result
of these comments. While the rule does not contain a specific variance
definition, the variance provisions in the rule are substantially
similar to existing provisions in 43 CFR 3162.7-5(b)(9) as well as in
Onshore Orders 2 through 7 regarding variances. All hydraulic
fracturing operations on Federal or Indian leases must still meet or
exceed the objectives of the requirement for which a variance is being
requested.
Several commenters said that the rule should be revised to include
the procedure and criteria for requesting a variance. The commenters
indicated that the rule should provide clarification on the variance-
issuance process and expressed concern that the supplemental proposed
rulemaking contained no mechanism to notify the public. The BLM did not
revise the rule as a result of these comments. Throughout this
rulemaking the BLM has been aware that members of the public are
concerned about hydraulic fracturing. While specific processing details
regarding hydraulic fracturing variances have yet to be developed, the
notification process may be made available to the public for statewide
and tribal variances. The BLM will post all variances on its Web site.
Several commenters said that the rule should be revised to address
how variances will be implemented. Other commenters indicated that all
variances should be written; that no oral variances should be allowed.
The BLM did not revise the rule as a result of these comments. The
final rule specifies the procedural steps for several different
variance processes.
Additionally, final section 3162.3-3(k)(1) contains no provision
for oral variances. The BLM envisions that the majority of case-by-case
variances will be authorized in the same manner as existing variances
are authorized and that is via Sundry Notices. Each variance request
must contain specific information justifying why a variance is needed.
For state or tribal variances, the provisions will depend on the formal
agreement between the involved agency and the BLM. It is not possible
to envision or regulate all the possibilities and therefore these rules
provide flexibility and discretion to the local BLM manager.
Several commenters expressed concern regarding section 3162.3-
3(k)(5) in the final rule (paragraph 3162.3-3(k)(4) in the supplemental
proposed rule) which allows the BLM the right to rescind a variance.
The commenters stated that this is extraordinarily broad language that
does not provide any factual criteria that the BLM must meet before
modifying or revoking a variance. In their view, the proposed variance
process fails to provide operators with a reasonable assurance that
regulatory requirements will not arbitrarily change. Commenters also
stated that if the variance language remains in the rule, the BLM
should be required to provide operators notice of its intent to rescind
or modify a variance in writing, provide operators at least 30 days to
respond, and provide that any final decision on variances not become
effective until at least 30 days after receipt by the operator. The BLM
agrees in part. The authorized officer will grant a variance only if
the BLM determines that the proposed alternative meets or exceeds the
objectives of the regulation for which the variance is being requested.
The BLM understands that operators are likely to rely on a variance in
planning and executing their operations. A decision to rescind a
variance would only occur after a thorough internal process has been
undertaken. But if the BLM later determines that a particular variance
fails to meet the objectives of the regulation, the BLM must retain the
right to rescind that variance. In addition, changes in Federal laws or
changes in technology may dictate the need to rescind a variance. While
the BLM appreciates the issues raised by the commenters, these concerns
do not override the BLM's responsibility to manage the public lands to
prevent unnecessary or undue degradation, and to assure proper resource
protection on Federal and Indian lands. While no timeframe is
described, the rule requires that the authorized officer provide a
written justification if a variance is rescinded. The rule does not
require prior notification, but it also does not prohibit the local BLM
manager from providing prior notification of a rescission of a variance
when

[[Page 16176]]

appropriate. No revisions to the rule were made as a result of these
comments.
State and Tribal Variances
Numerous commenters said that the rule should be revised to
establish the process for state-initiated variances. Commenters
indicated that the rules lacked specificity in this regard and provided
specific language for a ``state equivalency determination'' process
which enumerated the steps a state agency would utilize as well as the
process that binds the BLM in reviewing and approving such proposals.
The BLM did not revise the rule as a result of these comments. State or
tribal variances would be approved as a result of discussions among the
BLM and the state or tribal agencies, which do not require a rigid
process specified in regulations. A state or tribal variance is not a
delegation of full or partial regulatory primacy, so a ``state
equivalency determination'' process is neither necessary nor
appropriate.
One commenter supported section 3162.3-3(k), which allows for the
BLM to work in cooperation with a tribe and issue a variance that would
apply to all wells within Indian lands or to specific fields or basins
within Indian lands. The commenter, however, recommended that the rule
be expanded to include the process that tribes would use to initiate a
variance. The BLM does not believe the rule needs to be expanded to
include the specific mechanism for approving variances with tribes
since it may vary from tribe to tribe. The BLM will work cooperatively
with any tribe or state to craft variances that would allow
technologies, processes, or standards required or allowed by the state
or tribe to be accepted as compliance with the rule. Such variances
would allow the BLM and the states and tribes to improve efficiency and
reduce costs for operators and for the agencies.
Numerous commenters stated that the rule should be revised to
provide for statewide exemptions from the hydraulic fracturing rule.
Other commenters suggested modifying the variance section so that the
BLM's hydraulic fracturing rule should only apply in those states which
do not have hydraulic fracturing rules. The BLM did not revise the rule
as a result of these comments. The Secretary of the Interior has
stewardship responsibilities on public lands and trust responsibilities
on Indian land. Accordingly, the BLM is promulgating a rule that
governs hydraulic fracturing operations on all Federal and Indian
leases. While the BLM does not provide for statewide exemptions from
the entire hydraulic fracturing rule, variances may be granted for
individual provisions of the rule, if the variance proposal meets or
exceeds the objectives of the rule. The BLM encourages formal
agreements with state or tribal agencies to avoid overlap and promote
cooperation amongst regulatory bodies and to reduce compliance burdens
on operators.
Numerous commenters said that the rule should be revised to
recognize existing state agency rules. The commenters indicated that
under such a provision the need for any variance would then be
redundant because all proposals would clear the ``meets or exceeds''
state threshold. The BLM did not revise the rule as a result of these
comments. While numerous states have hydraulic fracturing rules in
place or are currently contemplating hydraulic fracturing rules, the
applicability and content of these rules are not consistent across all
BLM-managed public lands in those states. Additionally, certain states
do not have hydraulic fracturing rules at all. In addition, state rules
may not apply to tribal lands. The BLM will work closely and
cooperatively with state and tribal agencies to implement these rules
to avoid overlap and duplication where possible. Formal agreements with
state and tribal agencies are encouraged.
Numerous commenters said that the rule should be modified to allow
for statewide or tribal variances. Commenters indicated that states
should regulate hydraulic fracturing operations on all lands within
that state by memorandum of understanding. The BLM agrees with those
comments in part, and has modified the rule as a result of these
comments. The rule has been edited to clarify that there are two types
of variances: Individual (or operator-specific), and state or tribal
(for wells on all or designated portions of state or tribal lands). As
provided, variances may be granted to states and tribes, only if the
state or tribal requirements meet or exceed the objectives of the rule.
The rule also provides that state or tribal variances maybe initiated
by the involved state, tribe, or the BLM.
The BLM may approve a variance under paragraph 3162.3-3(k) from one
or more specific requirements of the rule, but not from the entire
rule. The variance provision does not allow the BLM to delegate
regulation of hydraulic fracturing operations on public or Indian lands
to state agencies. Unlike several other environmental statutes, none of
the BLM's statutory authorities authorize delegation of the BLM's
regulatory duties to state or tribal agencies.

Section 3162.5-2(d) Isolation of Usable Water

The changes to this section conforms the out-of-date language in
this section with the Onshore Order 2 requirements. Onshore Order 2
superseded the existing regulations in 1988, because it was promulgated
pursuant to notice-and-comment rulemaking. Since the final rule is
consistent with Onshore Order 2, it does not represent a change in
policy.
The BLM received numerous comments on the subject of usable water.
Those comments are addressed under the section 3160.0-5 discussion in
this preamble. This section is not revised in the final rule and
remains as proposed.

General Comments

Incorporate API Standards
Several commenters recommended that the BLM adopt American
Petroleum Institute (API) Guidance Document HF1, First Edition (October
2009) (HF1) instead of developing its own standards. During the
development of the rule, the BLM not only considered all comments
received but also consulted numerous other sources including API HF-1,
state regulations, and academic and professional papers such as King,
George, SPE 152596, ``Hydraulic Fracturing 101: What Every
Representative, Environmentalist, Regulator, Reporter, Investor,
University Researcher, Neighbor, and Engineer Should Know About
Estimating Frac Risk and Improving Frac Performance in Unconventional
Gas and Oil Wells,'' Society of Petroleum Engineers, Hydraulic
Fracturing Technology Conference, (Feb. 2012). The BLM does not believe
that the rule should incorporate any particular guidance. Although the
BLM has carefully considered the API HF1 and HF2 guidance as we
developed this rule, the BLM cannot fully incorporate the guidance
documents because they do not meet all of the BLM's areas of concern
for protection of resources on Federal and Indian lands. Moreover,
nothing in this final rule precludes an operator from following
recommended industry guidance. See the following table for a comparison
of applicable components of API HF1 guidance and the final rule.

[[Page 16177]]

------------------------------------------------------------------------
Final rule/Onshore
Subject API HF-1 Order 2
------------------------------------------------------------------------
Surface casing.............. Set at least 100' Usable water must be
below lowest USDW isolated by casing
(deep water zones (not necessarily by
can be isolated by surface casing).
intermediate or
production casing).
Cement to surface... Cement to surface
(Onshore Order 2).
If no cement to
surface, must
identify top of
cement with CEL or
temperature log.
If fallback >200
feet or 10 percent
of surface casing
depth, must
identify top of
cement with CEL or
temperature log.
Monitor and record
flow rate, density,
and pump pressure.
Intermediate casing......... Cement above any
USDW or hydrocarbon
bearing zone.
CBL recommended..... CEL required if
casing is used to
isolate usable
water and not
cemented to surface
Monitor and record
flow rate, density,
and pump pressure
if casing used to
isolate usable
water.
Production casing........... Tail cement (the 200 feet of
last cement system adequately bonded
pumped during cement between the
primary cementing fractured zone and
which covers the the deepest usable
lower sections of water zone, could
the well) should be be either
brought 500' above production or
producing formation. intermediate
casing.
Tail cement should
extend above the
top of confining
formation.
Should consider CBL CEL required if
for cement casing is used to
evaluation. isolate usable
water and not
cemented to surface
Monitor and record
flow rate, density,
and pump pressure
if casing used to
isolate usable
water.
All casing.................. Pressure test....... Pressure test
(Onshore Order 2).
Formation integrity Formation integrity
test after drilling test if exploratory
out. well or if the
blowout prevention
equipment is 5,000
psi or greater
(Onshore Order 2).
Take remedial action Take remedial action
if pressure tests if there are
fail. indications of
inadequate cement.
Pressure test prior to Test all hydraulic Mechanical Integrity
hydraulic fracturing. fracturing surface Test: Pressure test
equipment. casing or
fracturing string
to maximum
anticipated
pressure.
Baseline water monitoring... Test water samples ....................
from nearby water
sources prior to
drilling.
Monitoring during hydraulic During hydraulic Monitor and report
fracturing. fracturing, monitor actual pump
injection pressure, pressure, fluid
slurry rate, rate, and flush
proppant volume.
concentration,
fluid rate, and
proppant rate.
Monitor annular Monitor annular
pressure (all pressure (all
annuli). annuli).
Monitor unexplained Annular pressure
deviations from increase greater
plan. than 500 psi
requires corrective
action.
Pressure should not
exceed working
pressure of weakest
component.
Relief valve on
intermediate casing
annulus--set not to
exceed working
pressure of casing;
flowline diverted
to lined pit or
tank.
Monitoring after HF......... Monitor annular
pressure after
hydraulic
fracturing; assign
max/min.
------------------------------------------------------------------------

Enforcement and Implementation of Rules
Several commenters stated that there is concern that the BLM is
imposing new rules when the BLM does not have the staffing, budget, or
the number of experts needed to implement the rule or requisite
expertise to evaluate fracturing proposals, which would cause delays in
approvals and decreased Federal and Indian oil and gas production. The
BLM does not agree with the assertion regarding the lack of BLM staff
expertise. The BLM employs qualified and experienced petroleum
engineers and geologists. The BLM understands the time-sensitive nature
of oil and gas drilling and well completion activities and does not
anticipate that the review of additional information related to
hydraulic fracturing with an APD will impact the timing of the approval
of drilling permits. The BLM believes that the additional information
that would be required by this rule would be reviewed in conjunction
with the APD and within the normal APD processing timeframe. If an
operator submits a request in an NOI, however, further processing time
should be expected. The BLM understands that delays in approvals of
operations can be costly to operators and the BLM intends to avoid
delays whenever possible. Also, the revisions made from the
supplemental rule to final rule would reduce the amount of staff time
required to implement the rule and limit any permitting delays. The
changes include eliminating the type well concept and the requirement
for a CEL to be run and submitted for a type well prior to completing
additional wells.
Several commenters said that the rule should be modified to provide
enforcement provisions. The commenters stated that the BLM must monitor
hydraulic fracturing operations on Federal and tribal lands to ensure
compliance with the rules. The BLM did not make any changes as a result
of these comments. Monitoring performed by the BLM is a matter of
implementation and policy, not regulation, and therefore, revision of
the rule for monitoring is not warranted.

[[Page 16178]]

Additionally, enforcement is outside the scope of this rulemaking. The
rule does not address compliance and enforcement issues because those
issues are already covered by existing regulations in subpart 3163.
More specifically, existing section 3163.1 addresses the remedies for
acts of noncompliance. The remedies include written notices of the
violation, assessments, and shut down of operations. Continued
noncompliance could lead to civil penalties and possible lease
cancellation. See existing section 3163.2. The law also provides for
criminal liability for certain false statements in public land matters,
whether sworn or unsworn. 18 U.S.C. 1001; 43 U.S.C. 1212.
Commenters also expressed concern that depending on self-reporting
by the operators would be unreliable. The BLM, in line with its
authority, has historically relied on self-reporting throughout the oil
and gas program (e.g., production volumes and completion information).
In order to verify the self-reporting, the BLM conducts regular
inspections of operations. The BLM conducts inspections in accordance
with an annual risk-based strategy to ensure compliance with the
regulations. The BLM has a funding request in place that will lead to
improved Inspection and Enforcement resources and performance. The
BLM's oil and gas program has no greater priority than ensuring that
development is done safely and responsibly. No revisions to the rule
were made as a result of these comments.
One commenter expressed concern over how the BLM will know if an
operator fails to report a wellbore issue. The BLM has a number of
mechanisms that would indicate if an operator failed to report a
wellbore issue. The BLM routinely conducts inspections of ongoing
operations. These inspections consist of witnessing operations, such as
the cementing of casing, onsite review of the drillers log at the rig,
or the review of documentation such as the third-party cementing
ticket. Through witnessing the operation or the review of the
documentation, the BLM inspectors can verify that operations were
conducted in accordance with the approved plan and that no wellbore
issues exist. Operators also must submit a subsequent report as
required by final section 3162.3-3(i). BLM staff will review the
information included in the subsequent report to identify any
deviations from the approved plan, or any indications of wellbore
issues. In addition, under final section 3162.3-3(i), the operator must
certify that it complied with the paragraphs of the rule that assure
wellbore integrity was maintained prior to and throughout the hydraulic
fracturing operation. No revisions to the rule were made as a result of
this comment.
One commenter recommended that each operator designate one or more
individuals to be prosecuted criminally if criminal negligence, fraud,
or conspiracy were found in any hydraulic fracturing operation. The
commenter also recommended that an independent counsel be appointed to
investigate death or disability caused by hydraulic fracturing
operations, and a freezing of corporate stock pending such
investigation. While criminal liability and criminal investigations are
beyond the scope of this rulemaking, any information of potential
criminal violations would be appropriately addressed by law enforcement
authorities.
Some commenters wanted the BLM to add an appeal process for
decisions to condition or to deny a hydraulic fracturing proposal, and
wanted rules for the standing of third parties. The Department's
regulations already provide procedures for administrative review of
adverse decisions by the BLM. E.g., 43 CFR 3165.3(b). Issues of
standing to participate in an administrative review or appeal of a BLM
decision are beyond the scope of this rulemaking.
Allow State Agencies To Regulate
Several commenters suggested that the rule allow state oil and gas
commissions to regulate hydraulic fracturing on Federal and tribal
lands. Commenters believed that the BLM rule adds no value, and
increases the layers of approval necessary to develop on Federal and
tribal land. Other commenters stated that BLM rules duplicate state
rules, and that because the states adequately protect and manage
hydraulic fracturing, the BLM's rules are unnecessary, add costs and
burdens for compliance, and present regulatory inconsistencies when
enforced alongside state rules. Several commenters said that hydraulic
fracturing should be regulated at the state level because implementing
a national rule would be unworkable due to the widely varying geology
and techniques used from region to region. Other commenters recommended
that in those states which already have an established regulatory
process for hydraulic fracturing, operators should automatically be
exempt from this rule.
The BLM did not revise the rule as a result of these comments. The
BLM recognizes that many states have made efforts to update their
hydraulic fracturing regulations in recent years, but those regulations
continue to be inconsistent across states. Further, those state rules
may not apply to Indian lands. The rule will establish a consistent
standard across Federal and Indian lands and fulfill BLM's stewardship
and trust responsibilities. In addition, the BLM is not allowed to
delegate its responsibilities to the states. The BLM has worked
diligently to reduce the compliance burden on operators, and will
continue to work with the states and tribes to develop cooperative
agreements to help align hydraulic fracturing regulations at the state,
Federal, and tribal levels. Although no changes to the rule were made
as a result of these comments, final section 3162.3-3(k) establishes a
process for state or tribal variances, if the BLM determines that
certain state or tribal rules meet or exceed the objectives of this
rule.
Several commenters objected to the use of state regulations.
Commenters believed that state regulations were uneven and
inconsistent, which could present problems for implementation and
enforcement of the rule. The BLM did not revise the rule as a result of
these comments. The rule applies on all Federal and Indian lands.
Some commenters urged the BLM to defer to state regulations that
are more stringent in protecting resources than this rule. All state
laws apply on Federal lands, except those that are preempted by Federal
law. This rule does not preempt any more stringent state or tribal law.
Operators on Federal leases must comply both with this rule and any
applicable state requirements, just as they already must comply with
both BLM rules and state rules on a variety of drilling and completion
issues. For example, if a state law required recovered fluids to be
held in above-ground tanks, the BLM would not approve an application to
use a lined pit.
Some commenters objected to what they perceived as a suggestion
that states do not have adequate regulatory authority. Those commenters
are mistaken as to the BLM's intent. This rule is not about state
regulatory programs. It is about the Secretary fulfilling her
obligations under the statutes that assign to her stewardship over
public lands and trusteeship over Indian lands.
Approve Service Companies
Several commenters asked that the BLM regulate service companies.
The commenters sought a list of ``approved'' service companies that
would constitute the only eligible service companies who

[[Page 16179]]

could operate on Federal and Indian land and so that operators would
not be compelled to submit chemical disclosure records to a BLM
authorized officer. The BLM did not revise the rule because of these
comments. The BLM believes the appropriate approach is to establish
regulations that would apply to any service company selected by the
operator rather than limiting the specific service companies that
operate on Federal and Indian lands.
Ban or Restrict Hydraulic Fracturing
Many commenters asked that the BLM ban hydraulic fracturing, unless
the chemicals used in hydraulic fracturing can be contained. The BLM
did not revise the rule as a result of these comments. The goals of the
rule include groundwater protection, wellbore integrity, and chemical
disclosure. Chemical management, containment, and public disclosure are
core purposes behind the regulation, and the BLM fully intends to
contain chemicals used in hydraulic fracturing through this rule.
Numerous commenters called for a moratorium or permanent ban on
hydraulic fracturing on Federal and tribal lands. The BLM did not
revise the rule as a result of these comments. The BLM has a
responsibility under the FLPMA to act as a steward for the development,
conservation, and protection of Federal lands, by implementing multiple
use principles and recognizing, among other values, the Nation's need
for domestic sources of minerals from the public lands. A ban or
moratorium would not satisfy the BLM's multiple-use responsibilities
under the FLPMA when regulations can adequately reduce the risks
associated with hydraulic fracturing operations. Similarly, hydraulic
fracturing operations on Indian lands result in substantial benefits to
tribes and to individual Indians. By updating the requirements for
hydraulic fracturing, this rule protects usable water on Indian lands
without a ban or moratorium that could reduce royalty payments and
employment. The BLM understands the risks and the environmental impacts
of hydraulic fracturing operations, and the BLM believes that those
risks and impacts can be managed by the rule. The rule will provide
adequate assurance that hydraulic fracturing operations on Federal and
Indian lands will continue to provide the Nation with domestically
produced oil and gas and at the same time protect public lands and
trust resources.
Many commenters asked that the rule require minimum setback
distances for hydraulic fracturing operations. Some commenters
requested setbacks from sensitive areas, including conservation areas,
areas of critical environmental concern, wilderness and roadless areas,
wild and scenic river corridors, surface waters, drinking water
supplies, homes, schools, hospitals, other buildings, and recreation
areas. Some commenters proposed setback distances ranging from 1,000
feet to half a mile. No revisions were made to the rule in response to
these comments.
The BLM has processes in place to ensure protection of sensitive
areas. For example, the BLM has rules at 43 CFR 3100.0-3(a)(2)(iii)
that prohibit the leasing of Federal minerals beneath incorporated
cities, towns, and villages, which is where the majority of homes,
schools, hospitals, and other buildings are located. In addition,
during development of a Resource Management Plan (RMP), the BLM
identifies areas needing protection as areas closed to leasing or areas
open to leasing, but with stipulations that limit or prohibit surface
occupancy. Other sensitive areas are protected by seasonal and
controlled surface use restrictions that are also developed during the
land use planning process. When specific drilling proposals are
received, the BLM conducts onsite inspections, which identify any
sensitive areas and/or occupied dwellings. As part of the NEPA review
for the specific proposal, the BLM then develops proper mitigation
measures to protect these areas. Mitigation could include moving the
well location and including site-specific conditions of approval
(COAs). In addition, if unnecessary or undue degradation impacts are
identified (for public lands), or unacceptable impacts (on Indian
lands), which cannot be mitigated, the BLM may deny the proposal.
Through existing regulations, the RMP process, and the subsequent site-
specific analyses, the BLM has measures in place to ensure protection
of sensitive areas, drinking water supplies, and occupied buildings.
Furthermore, state set-back requirements would normally apply on
Federal lands, and tribal set-back requirements would apply on tribal
lands (see also existing section 3162.3-1(b)). Minimum setbacks are
more effective when they are determined and set at a site-specific
level rather than in a nationwide rule because the unique circumstances
of each drill site can be considered. Since setback requirements are
already addressed in existing regulations and internal processes and
policy, minimum setback distances are not necessary in this rule.
Cooperative Agreements
Several commenters asked that the BLM pursue cooperative agreements
with states in order to establish more local control over hydraulic
fracturing. Generally, the commenters believed that states have
enhanced knowledge of the hydrological and geological conditions of
their local oil and gas resources. The BLM did not make any rule
changes based on these comments. The BLM intends to continue to pursue
memoranda of understanding with states, and encourage further
cooperation at the BLM State and field office level. The BLM cannot,
however, delegate its stewardship responsibility to state or local
officials, as some commenters suggested. The BLM must make the final
decisions provided by statutes and regulations concerning operations on
Federal lands and Indian lands. However, the BLM expects that by
cooperatively working with states and through the variance process to
appropriately consider state and tribal law and rules so as to reduce
regulatory redundancies and compliance burdens.
Some commenters asserted that the rule should include a formal
memorandum of understanding mechanism whereby state approval of
hydraulic fracturing operations would constitute BLM approval. No
statute authorizes the BLM to delegate its responsibilities to states.
The rule provides for statewide variances that could result in aligning
state and BLM requirements to reduce compliance burdens for operators
while assuring that resources in and on public lands are protected.
Compliance With Other State and Federal Laws
One commenter asked that the BLM include a statement in this rule
requiring operators to comply with other Federal laws and with state
laws. Section 3162.3-3(i)(8)(i) of this rule already requires that the
operator certify that the hydraulic fracturing fluid constituents
complied with all Federal, state, and local laws, rules, and
regulations, in addition to other certifications. In addition, the
BLM's Federal oil and gas lease form requires the lessee to comply with
all applicable laws, and that includes other Federal and state and
local laws, rules, and regulations. That requirement is repeated in the
existing regulations at sections 3162.1(a) and 3162.5-1(a). No
revisions to this rule were made as a result of this comment because
the commenters concern is already addressed in the rule and other BLM
regulations.

[[Page 16180]]

Ensure Chemicals Are Safe
A commenter suggested that the BLM require all chemicals used in
hydraulic fracturing on Federal and Indian lands to be proven safe by
an independent third party, or otherwise banned from use. The BLM did
not revise the rule in response to this comment. The emphasis of this
rule is to ensure that hydraulic fracturing fluid is confined to the
intended zone and does not contaminate usable water zones, and that
recovered fluids do not contaminate surface or ground water. Though
this comment is beyond the scope of this rule, the BLM encourages the
use of safer chemicals. Developing and using safer chemicals in all
stages of hydraulic fracturing activities can help minimize potential
environmental and health concerns while promoting greater public
confidence.
Need for the Rule
Numerous commenters said that the rule disrupts the balance between
environmental protection and energy development. The commenters stated
that the rule would negatively affect jobs, revenue, and effective
government. The BLM did not revise the rule as a result of these
comments. The BLM evaluated these concerns as part of its economic
analysis and found the impacts to be nominal in relation to current
overall costs of drilling operations. The economic analysis is
available upon request.
Several commenters stated that operators currently submit
information regarding casing and cementing programs as part of the
existing APD process under Onshore Order 1. The commenters stated that
the existing regulatory program already ensures well integrity, thereby
making the provisions in the supplemental proposed rule unnecessary.
The BLM did not revise the rule as a result of these comments. While
the APD process does include many similar components regarding casing
and cementing specifics related to well construction, this rule
addresses specific hydraulic fracturing operational aspects to verify
the integrity of the casing that existing rules do not address.
Several commenters said that the rule is unnecessary and offers no
change to the existing situation. The commenters indicated that the
rule does not increase safety or transparency, and the supplemental
proposed rule offered no solution. The BLM disagrees and did not make
changes to the rule as a result of those comments. The BLM believes
that compliance with these rules will increase transparency of the
hydraulic fracturing approval process and provide a means for
disclosure to the public of the fluids utilized in the hydraulic
fracturing process.
Several commenters said that the BLM had no reason to promulgate
the regulations because there was no evidence that hydraulic fracturing
operations have caused contamination of groundwater. The BLM disagrees.
The need to assure that hydraulic fracturing fluids are isolated from
surface waters, usable groundwater, and other wells is clear. The BLM
also notes that those commenters' arguments would apply equally to
state regulations, which the same commenters champion. The final rule
is not revised in response to those comments.
Several commenters stated that the rule is unnecessary because it
codifies common industry practice which has been successful in
preventing groundwater contamination. The BLM did not make any changes
to this rule as a result of these comments because the BLM has the
responsibility of ensuring for the public and tribes that specific
minimum standards are adhered to, and does not depend upon voluntary
compliance.
Several commenters requested that the BLM wait for EPA to complete
its study of hydraulic fracturing and its potential impact on drinking
water resources before promulgating a rule. The BLM does not believe it
is necessary to wait for the EPA study to implement requirements that
will help ensure the protection of water resources and the environment.
Nothing prevents the BLM from updating its hydraulic fracturing
regulations in light of a finalized EPA study. However, it is necessary
to have adequate requirements in place without further delay. No
revisions to the rule were made in response to this comment.
Implementation or Grandfathering
Many commenters asked whether the rule would apply to existing
wells and requested that certain requirements be waived for those
wells. The BLM agrees that the rule needs clarity on how it will
address existing wells and added a table in section 3162.3-3(a) to
specify which section of the rule would apply to which activity and
when. Groundwater protection remains one of the principal reasons for
applying the rule to all wells, existing or new. The BLM recognizes,
however, that it may be impossible for an operator of an existing well
to comply with all requirements of the rule. An example of this would
be the requirements in section 3162.3-3(e)(1)(i) to monitor the casing
and cementing operations, because the casing and cementing activities
would have already occurred. Although most responsible operators retain
that monitoring data and will be able to submit it to the BLM, not all
of the data has been required by existing regulations. To comply with
this section for existing wells, section 3162.3-3(e)(1)(ii) requires
that the operator submit documentation demonstrating that an adequate
cement job was achieved for all casing strings designed to isolate
usable water, and provides that the BLM may require additional testing,
verification, or other measures necessary to assure that the well will
withstand hydraulic fracturing operations.
Several commenters suggested a phased or delayed implementation of
the rule to give industry time to comply with the provisions of the new
rule. One commenter requested a 180-day implementation period, instead
of the 60-day implementation period required by statute and executive
order (Congressional Review Act (5 U.S.C. 801-808) and Executive Order
12866). The BLM agrees that a longer implementation time is required
given the complexity of the rule, the potential impacts of the rule on
industry, the coordination needed with other entities, such as the GWPC
for FracFocus, and for the development of internal training and policy.
However, the public also expects new requirements for hydraulic
fracturing to be implemented in a timely manner. Therefore, the final
rule will be effective 90 days after publication in the Federal
Register. Outreach to industry and the public is also anticipated
during this implementation period. The table in section 3162.3-3(a)
provides for an additional 90 day phase-in of the requirement to obtain
the BLM's prior approval under limited circumstances. No well (existing
or otherwise) proposed for hydraulic fracturing after June 24, 2015
will be exempt from paragraphs (b), (e), (f), (g), (h), (i), and (j),
the substantive requirements of the rule.
One commenter requested that the term ``New Well'' be added to the
definitions section. The commenter recommended the following
definition: ``New well means an oil and gas well for which surface
casing was set and cemented on or after 60 Days after publication in
the Federal Register.'' The commenter was concerned that existing wells
could not meet the cement monitoring and CEL requirements in the
supplemental proposed rule. The commenter also suggested the cementing
monitoring and CEL requirements should only apply to new wells as
defined. The BLM recognizes the potential challenges with

[[Page 16181]]

the cement monitoring requirements on existing wells. The BLM, however,
did not include a definition for ``New Well'' in the rule. Instead,
final section 3162.3-3(a) of the rule clarifies that for wells drilled
prior to the effective date of the rule, the operator must provide the
documentation required in 3162.3-3(e) or demonstrate to the authorized
officer that the casing and cement have isolated usable water zones.
Ban Diesel
Several commenters asked that the BLM completely ban the use of
diesel fuel in hydraulic fracturing fluids. The BLM did not make
changes as result of these comments. Congress has authorized regulation
of the use of diesel fuels in hydraulic fracturing fluid by the
Environmental Protection Agency (EPA), Underground Injection Control
(UIC) Program. The EPA has provided technical guidance for protecting
underground sources of drinking water (USDWs) from potential
endangerment posed by hydraulic fracturing operations by requiring a
permit under the UIC program where diesel fuels are used. See EPA
Underground Injection Control Program Guidance # 84 for issues
concerning diesel fuels during hydraulic fracturing operations (79 FR
8451). If, however, a state (on Federal lands) or a tribe (on tribal
lands) prohibited the use of diesel, this rule would not ordinarily
preempt such regulations.
Bonding
Many commenters requested that the BLM increase liability bonds to
account for the increased risk caused by hydraulic fracturing
operations. The BLM did not revise the rule as a result of these
comments. Existing section 3104.5(b) authorizes the BLM to adjust bond
amounts to appropriately reflect the level of risk posed by an oil and
gas operation. The BLM may increase the bond amount if there is a
history of previous violations, if there are uncollected royalties due,
or if the total cost of plugging existing wells and reclaiming lands
exceeds the present bond amount based on the estimates determined by
the authorized officer. The BLM believes that it has authority under
existing regulations to adjust bond amounts to address any increased
liability that may be present as a result of hydraulic fracturing
operations. The BLM will make a liability determination for hydraulic
fracturing on a case-by-case basis and increase the bond amount as
necessary.
Prior Approval for All Changes
Many commenters stated that the rule should be modified to require
prior approval for all significant changes to the proposed hydraulic
fracturing plan. The commenter stated that the regulation only requires
that the operator provide notice to the BLM after the hydraulic
operations are complete. The BLM did not revise the rule as a result of
these comments. The requirements that the commenter is referencing are
specific to hydraulic fracturing operations that did not proceed as
planned. Any change of plans from any approved permit must be submitted
to the BLM for a new approval. This is the same requirement for changes
to all authorizations for oil and gas operations, including APDs and
Sundry Notices.
One commenter requested that the BLM establish criteria that would
rise to the level of a ``change in scope'' that would necessitate the
operator filing a subsequent Form 3160-5 Sundry Notice in the event of
a change or deviation from the previously approved hydraulic fracturing
operation. Too many possible scenarios exist to develop criteria that
would address all issues that could arise. The BLM expects the operator
to follow the approved plan along with any COAs. The BLM, however,
recognizes that the operator may make minor changes in the design
criteria prior to the hydraulic fracturing operations. This recognition
is already acknowledged in the rule. Many of the items required in the
permit application can be estimates (see final section 3162.3-3(d)).
For example, the rule requires estimated pump pressures and the
estimated total volume of fluid to be used. Slight deviations from
these estimates would not trigger the need for a new Sundry Notice.
Those items that cannot be estimated, however, such as the location of
the water supply or the method of handling the recovered fluids, would
have to be disclosed on an additional Sundry Notice requesting changes
to the original approval. No revisions to the rule were made as a
result of this comment.
Mitigation Measures
Many commenters asked that the rule require a number of specific
actions from the operator such as:
The installation of air and water monitoring equipment on
all hydraulic fracturing operations. The commenters stated that more
comprehensive monitoring, including air and groundwater quality
monitoring, could help build a knowledge base regarding hydraulic
fracturing and its effects on the environment;
Dust abatement on county roads;
The power washing and inspection of all vehicles entering
a well site to prevent non-native invasive plant species from becoming
established;
The installation of sound dampening devices;
Prohibiting the use of jake (engine) brakes on trucks
operating near residential areas;
Provisions to control stormwater runoff;
Capturing or controlling greenhouse gas emissions during
hydraulic fracturing operations; and
The prohibition of flaring in sensitive areas.
The BLM did not make any changes to the rule as a result of these
comments. First, the requested changes are outside the scope of this
rule, which is specific to hydraulic fracturing operations. With the
exception of the installation of air and water monitoring equipment,
all of the other requested changes would apply to oil and gas
operations in general and are not unique or specific to hydraulic
fracturing or appropriate to address in a hydraulic fracturing rule.
Second, the BLM believes that it is not appropriate to require specific
mitigation measures in a national rule of general applicability.
Requiring specific actions such air monitoring, dust abatement, or
power washing of vehicles is best left to the discretion of the local
BLM offices, determined through NEPA analysis on a case-by-case basis
and applied as lease stipulations, and conditions of approval in
permits to drill, or through best management practices that operators
may propose in their APDs. The rule must allow for some degree of
flexibility to accommodate the wide range of geologic and environmental
conditions encountered on Federal and Indian leases. If water quality
or other impacts are anticipated due to hydraulic fracturing
operations, the BLM would then develop mitigation measures, such as
water quality monitoring, dust emission control, and any other relevant
actions on a case-by-case basis. These requirements will be included as
specific conditions of approval (COA) in the drilling permit to the
extent consistent with the lease rights.
``Frack Hits''
Several commenters expressed general concern over ``frack hits''
(i.e., unplanned interconnectivity of wells during a hydraulic
fracturing operation through the underground formations between the
well undergoing a fracturing operation and an existing

[[Page 16182]]

well), and that the NOI review process should include an area of review
to identify nearby wells and fractures, in addition to prescribing
reporting, evaluation, and corrective actions for frack hits.
The BLM revised the rule as a result of these comments. As provided
in this final rule, hydraulic fracture design, including estimated
fracture length and direction data, are required to be submitted as
part of the APD or NOI. In addition, the final rule requires the
operator to provide a map showing the extent of the fractures along
with all known wellbore trajectories within one-half mile of the well
that is proposed to be fractured. One purpose of fracture design data
is to avoid potential intersection between fractured pathways to
existing nearby wellbores. These data will be reviewed during the
review process for hydraulic fracturing approval. The provisions of
Notice to Lessees and Operators of Onshore Federal and Indian Oil and
Gas Leases (NTL-3A), March 1, 1979, (44 FR 2204) and other regulations
already contain operator obligations for reporting, evaluation, and
corrective actions in the event of an environmental release.
Enforcement provisions for releases into the environment involving
Federal or tribal leases already exist in the regulations and are
outside the scope of this rulemaking.
Independent Review of Hydraulic Fracturing
Several commenters stated that the rule should be modified to
establish an independent review of hydraulic fracturing proposals. The
BLM did not revise the rule as a result of these comments. The BLM has
the necessary expertise to properly review hydraulic fracturing
proposals.
Public/Landowner Participation
Several commenters stated that the rule should require notice to
landowners, communities, and other stakeholders when hydraulic
fracturing is proposed. Commenters said that the rule should require
notice to parties located at various distances from 500 feet to 10
miles away from the hydraulic fracturing operation. The BLM did not
revise the rule as a result of these comments. Public notice of Federal
oil and gas operations is already provided to both the public and
nearby landowners. By statute and regulations, notice of Federal APDs
are publicly posted in BLM field office public rooms for a minimum of
30 days before the BLM issues a permit to drill (see existing section
3162.3-1(g)). Some field offices also make this information available
on the field office Web site.
Furthermore, the BLM is working on improvements to make additional
information available on a Web site for all Federal APDs in the near
future. The information would include the operator name, well name and
number, surface location legal land description, the date the BLM
received the application, the date the BLM approved the application,
the date the well was spudded, and the date the well was completed.
Additionally, surface owners of split estate lands are invited to
attend the onsite inspection before an APD is approved, and other
agencies and interested parties can request to attend the onsite well
inspection. Also, the APD surface use plan of operations lists all
wells and water wells within prescribed distances from the proposed
wells, which provides additional information to the public about
potential concerns. Although stakeholders could assume that any
proposed well would be hydraulically fractured, the BLM will be
exploring ways to provide additional public notice of proposed
hydraulic fracturing operations. Information that would be required to
be submitted as part of this rule will be made available to the public,
consistent with the requirements of Federal law. Note, though, that the
rule does not preempt notification requirements of states (on Federal
lands) or tribes (on tribal lands).
Several commenters stated that the rule should be modified to
provide for stakeholder participation in the permitting process for
hydraulic fracturing operations. The BLM did not revise the rule as a
result of these comments. The BLM already provides numerous
opportunities for stakeholder participation during the Federal oil and
gas leasing process as well as the APD process on Federal lands and
stakeholders are specifically invited to participate during the NEPA
process.
Ensuring Wellbore Integrity
Several commenters stated that Onshore Order 2 is inadequate to
ensure wellbore integrity during hydraulic fracturing operations.
According to these commenters, the BLM needs more requirements specific
to casing centralization, intermediate and production casing standards,
cement types, cement compressive strength, ensuring proper wellbore
condition prior to cementing, and ensuring a static wellbore during
cementing operations. The BLM did not revise the rule as a result of
these comments. Onshore Order 2 provides uniform national standards for
the minimum levels of performance expected from operators when
conducting drilling operations, including casing design, casing
centralization, and cement compressive strength. The BLM reviews each
drilling proposal to ensure that operations will meet these minimum
standards. If the BLM's review determines that additional requirements
regarding casing centralization, cement types, cement compressive
strengths, etc., are necessary for wellbore integrity or isolation of
usable water, the BLM can require the operator to modify its proposal
or add COAs. The BLM believes that the requirements for well drilling,
casing, or cementing in Onshore Order 2 along with the new requirements
established by this rule are sufficient to assure that wellbores can
withstand hydraulic fracturing operations.
Seismicity
Several comments stated that the rule should be modified to limit
hydraulic fracturing activities in those areas with seismic zones. The
BLM did not revise the rule as a result of these comments. The research
on the phenomena of induced seismicity from hydraulic fracturing
operations is still ongoing and inconclusive. For hydraulic fracturing
operations proposed in seismically active areas or when the BLM
determines through the internal and public scoping process that seismic
impacts are an issue, risks of induced seismicity would be evaluated
through the NEPA analysis, including analysis of the proposed drilling
and fracturing operations. These final regulations also require
submittal of additional geologic information prior to hydraulic
fracturing to help further that review.
Tracers
Several commenters stated that the rule should be revised to
require tracer surveys in production and injection wells. The
commenters indicated that if tracer efficacy could be validated, then
the BLM should require its use. One commenter suggested that some of
the constituents in flow back fluid could be used for tracers. The BLM
did not revise the rule as a result of these comments. One of the
rule's major emphases is the prevention of groundwater contamination
from hydraulic fracturing operations through ensuring wellbore
integrity and the isolation of usable water zones. Additionally, while
the BLM believes that tracers may have value in certain situations,
their overall effectiveness is questionable due to dilution and
detection issues. These limitations render tracer surveys inappropriate
for universal application

[[Page 16183]]

for all hydraulic fracturing operations on Federal or Indian lands.
Baseline Monitoring
Numerous commenters asked that the BLM require baseline air and
water monitoring prior to hydraulic fracturing. The commenters stated
that without baseline air and water quality data, it would be
impossible to prove (or disprove) that hydraulic fracturing caused
changes in air or water quality. Several commenters noted that the API
guidance document on hydraulic fracturing (HF-1) recommends baseline
water quality monitoring of both surface and groundwater prior to
hydraulic fracturing.
The BLM agrees that baseline air and water quality data and
monitoring are good policies with benefits for land managers, the
public, and the oil and gas industry, and fully endorses the API
guidance with respect to baseline water monitoring. The BLM supports
and encourages baseline testing and monitoring, and will require those
activities on a case-by-case basis where appropriate, but is not
requiring baseline monitoring in this nationwide rule for several
reasons. First, there is such a wide variety of hydrogeological
conditions that it would be unworkable to establish a single
requirement for baseline water monitoring for all Federal and Indian
lands. For example, some locations may not have surface or ground water
resources, while other locations may have a mix of different types of
water resources.
Second, there are many places where the BLM either does not manage
the surface above the leased minerals, or the locations where baseline
testing and monitoring would be necessary or most useful would be off
of BLM-managed land. The BLM has no authority to require air or water
quality monitoring on non-Federal lands, and limited authority on non-
Federal surface estates (``split estates''). If the final rule were to
require baseline testing and on-going monitoring, it would need to have
so many exceptions that it would be confusing and of limited value.
Given the fact that the BLM cannot rationally and consistently
implement baseline monitoring requirements, no revisions to the rule
were made as a result of these comments. Nonetheless, analysis of
potential impacts to both air and water quality are common elements of
any NEPA review that the BLM prepares on proposals for drilling and
hydraulic fracturing operations. If air or water quality impacts are
anticipated, then, if not already part of the proposed operation, the
BLM could require mitigation measures to address those impacts. These
include baseline testing and monitoring that would be developed on a
case-by-case basis taking into account local hydrogeologic or airshed
factors, plans for field development, land ownership, and existing data
and monitoring programs required or implemented by other agencies.
These mitigation measures would be imposed as a condition of the BLM's
approval for a given project. There are a number of cases where the BLM
has required the baseline testing and monitoring of air and water
resources as part of its decision to approve the development of oil and
gas resources. For example, the Records of Decision (ROD) for the
Pinedale Anticline Project Area Environmental Impact Statement (EIS)
(see Appendix A-3 at http://www.blm.gov/wy/st/en/info/NEPA/documents/pfo/anticline.html), the Pinedale Anticline Project Area Supplemental
EIS (see Chapter 4 at http://www.blm.gov/wy/st/en/info/NEPA/documents/pfo/anticline/seis.html), and the Greater Natural Buttes Final EIS (see
Appendix C at http://www.blm.gov/ut/st/en/fo/vernal/planning/nepa.html)
include requirements for oil and gas operators to test/identify
baseline air and water (surface and subsurface) conditions, and monitor
trends in resource conditions throughout the project. Furthermore, if
the Federal surface management agency (such as the U.S.D.A. Forest
Service) required air or water monitoring as part of the surface use
plan, then those requirements would be enforceable.
Some commenters said that BLM could require operators to obtain
permission to test water on non-Federal lands. Although states' or
tribal police powers may authorize such requirements, the BLM's
statutory authority does not extend to non-federal, non-Indian lands,
absent a threat to Federal resources. We therefore decline to revise
the rule as suggested.
Other comments recommended that the BLM require baseline monitoring
of soil, plants, human sickness, and environmental degradation before,
during, and after hydraulic fracturing. Additionally, one commenter
asked that the BLM provide landowners information on how to test their
water to document baseline conditions. The BLM did not revise the rule
as a result of those comments. Similar to the recommendation in the API
Guidance \9\ (section 10.2) for conducting a baseline assessment once
the location for a well has been selected and before it is drilled, as
part of the NEPA analysis, the BLM examines the baseline condition of
the site, evaluates the potential effects of the proposed operation,
and suggests mitigation and monitoring needs when necessary. As with
baseline water monitoring, the BLM could require monitoring of
resources on Federal lands, and with the surface owner's consent on
split-estate lands, as a site-specific mitigation measure based on an
environmental analysis prepared under NEPA. Although the BLM has
expertise in management of Federal lands, monitoring the health of
persons or of natural resources on non-Federal lands is entrusted to
other local, state, tribal or Federal agencies with appropriate
authority and expertise. Similarly, this rule does not attempt to
advise landowners or tenants on how to test their water. Other agencies
and private consultants have the expertise to provide that advice.
---------------------------------------------------------------------------

\9\ American Petroleum Institute (API) guidance, ``Hydraulic
Fracturing Operations-Well Construction and Integrity Guidelines,
First Edition, October 2009.''
---------------------------------------------------------------------------

Water Use
Several commenters requested that the rule address the potential
stresses on local fresh water supplies. The commenters expressed
concern that local fresh water supplies will be diminished by the
demand for water for hydraulic fracturing. Some commenters suggested
placing restrictions on the use of local fresh water and requiring the
use of non-fresh water sources or recycled water to help reduce
potential impacts to local fresh water. Other commenters requested the
rule include restrictions on water usage. The BLM understands the
concerns raised by the commenters. The BLM encourages operators to
treat and recycle the water returned after performing hydraulic
fracturing along with the water produced from the formation. In fact
many operators on public lands are currently considering options of
using produced water or recycled water for their hydraulic fracturing
operations. The BLM, however, does not have regulatory authority over
the use of local fresh water. State and tribal governments, through
administration of water rights and permitting water wells, regulate
water usage. Existing state and tribal laws require operators to obtain
the proper permits and rights to use surface and groundwater. No
revisions to rule were made as a result of these comments.
Some commenters expressed concern about the lack of groundwater use
regulation in the rule. Commenters recommended that the rule include an
assessment of water availability, provisions for reducing water use
during droughts, and require that

[[Page 16184]]

companies monitor the level of the water table. Other comments
suggested that the rule provide for protection of over-appropriation of
water and disclosure of water take that should occur prior to the start
of hydraulic fracturing operations. All of these items are beyond the
scope of this rule. States and tribes have regulatory authority over
water usage. However, as a matter of course, the BLM requires the
submission of information on water sources to assist the BLM in
assessing the environmental effects of individual drilling operations.
The NEPA process requires that Federal agencies assess the
environmental impacts of their proposed actions to inform their
decision-making and this includes effects on water resources. The
information on water sources will be part of an environmental analysis
of hydraulic fracturing operations. No revisions to the rule were made
as a result of this comment.
One commenter recommended operators should pay for monitoring wells
when there is suspected contamination. Other commenters recommended
that the rule be strengthened by requiring the operator to physically
replace any water supply that is contaminated. These recommendations
are beyond the scope of this rule. The goal of the rule is to ensure
proper wellbore construction and handling of produced fluids to prevent
any contamination. If a situation arises where contamination from
hydraulic fracturing operations is suspected, the BLM will work closely
with states and tribes to determine the proper course of action. The
proper course of action for any given situation will depend on the
unique circumstances of that situation. No revisions to the rule were
made as a result of this comment.
Mandatory Recycling
Some commenters asked that the rule include a requirement that some
quantity of the water used in hydraulic fracturing operations must be
recycled water. The commenters did not offer specific quantities. The
BLM encourages operators to treat and recycle the water returned after
performing hydraulic fracturing along with the water produced from the
formation. Many operators are currently looking at options for using
produced water and/or recycled water for their hydraulic fracturing
operations. However, mandating the recycling of water is outside of the
scope of this rule. No revisions to the rule were made as a result of
these comments.
Breach of Contract
Some commenters asserted that the rules would make oil and gas
operations uneconomic, and that would result in Federal liability for a
breach of the lease. Federal oil and gas leases clearly provide that
the lease rights are subject to all current and future regulations. The
rule is an operational regulation and does not change any financial
term of any Federal or Indian lease. The BLM does not expect the rule
to dissuade operators from drilling in geologically promising areas.
Lessees and operators routinely decide not to drill on leases found to
be geologically unpromising or uneconomic, but the BLM is not required
to waive drilling and completion regulations to improve profitability.
Tribal Issues
Some commenters asserted that the rule would be a breach of trust
on Indian lands. The BLM disagrees. As all the other provisions of 43
CFR part 3160, the rule protects trust resources to the same extent
that it protects resources in or on Federal lands. The commenters did
not identify any provision of the Constitution, or a treaty, statute,
or regulation that the rule violates. One tribe in its comments
proposed 10 specific conditions of approval that it wanted to apply to
hydraulic fracturing operations on its tribal lands. The BLM imposes
conditions of approval on a case-by-case basis based on unique on-the-
ground geologic, environmental, and operational circumstances. Specific
conditions of approval are beyond the scope of this rulemaking and are
inappropriate in a rule of general applicability. If hydraulic
fracturing is proposed for specific tribal lands and the tribe proposes
specific conditions for the BLM to apply, the BLM will consider the
tribe's proposal for that development.
Some commenters said that the BLM has no authority under the FLPMA
to promulgate regulations on Indian lands. The BLM agrees. The BLM's
authority to regulate oil and gas operations on Indian lands does not
come from the FLPMA. The Act of March 3, 1909 (25 U.S.C. 396), the
Indian Mineral Leasing Act (IMLA) (25 U.S.C. 396d), and the Indian
Mineral Development Act (25 U.S.C. 2107) assign regulatory authority to
the Secretary over Indian oil and gas leases on trust lands (except
those excluded from the IMLA, i.e., the Crow Reservation in Montana,
the ceded lands of the Shoshone Reservation in Wyoming, the Osage
Reservation in Oklahoma, and the coal and asphalt lands of the Choctaw
and Chickasaw Tribes in Oklahoma). The Secretary delegated to the BLM
the authority to oversee oil and gas operations on Indian mineral
leases through the Departmental Manual (235 DM 1.K.). The Bureau of
Indian Affairs' regulations provide that BLM's operating regulations at
43 CFR part 3160 apply to oil and gas leases on trust and restricted
Indian lands, both tribal and individually owned. See 25 CFR 211.4,
212.4, and 225.4.
Some commenters said that the FLPMA prohibits the BLM from
exercising any part of the Secretary's trustee responsibilities over
Indian lands. On the contrary, the FLPMA expressly provides that the
Director of the BLM ``shall perform such duties as the Secretary may
prescribe with respect to the management of lands and resources under
[her] jurisdiction according to the applicable provisions of [the
FLPMA] and any other applicable law.'' 43 U.S.C. 1731(a). Indian trust
and restricted lands and minerals are resources under the Secretary's
jurisdiction under applicable law. Therefore the delegation of
operational oversight to the BLM of oil and gas development on Indian
lands as exercised in this final rule is proper.
Several commenters said that the BLM's consultation process was not
adequate. In light of statutory responsibilities and executive
policies, including the Department's Tribal Consultation Policy
(Secretarial Order 3317) and Executive Order 13175, the BLM attaches
great importance to tribal consultation. During the proposed rule
stage, the BLM initiated government-to-government consultation with
tribes on the proposed rule and offered to hold follow-up consultation
meetings with any tribe that desired to have an individual meeting. In
January 2012, the BLM held four regional tribal consultation meetings,
to which over 175 tribal entities were invited. Individual follow-up
consultation meetings involved the local BLM authorized officers and
management, including State Directors. After the publication of the
initial proposed rule, tribal governments and tribal members were also
invited to comment directly on the proposed rule.
In June 2012, the BLM held additional regional consultation
meetings in Salt Lake City, Utah; Farmington, New Mexico; Tulsa,
Oklahoma; and Billings, Montana. Eighty-one tribal members representing
27 tribes attended the meetings. In those sessions, the BLM and tribal
representatives engaged in substantive discussions of the proposed
hydraulic fracturing rule. A variety of issues were discussed,
including, but

[[Page 16185]]

not limited to, the applicability of tribal laws, validating water
sources, inspection and enforcement, wellbore integrity, and water
management. Additional individual consultations with tribal
representatives took place. Consultation meetings were also held at the
National Congress of American Indian Conference in Lincoln, Nebraska,
on June 18, 2012, and at New Town, North Dakota on July 13, 2012.
After publication of the supplemental proposed rule, the BLM again
held regional meetings with tribes in Farmington, New Mexico, and
Dickinson, North Dakota, in June 2013. Representatives from six tribes
attended. The discussions included a variety of tribal-specific and
general issues. One change resulting from those discussions is the re-
drafting of paragraph 3162.3-3(k) to clarify that tribal and state
variances are separate from variances for a specific operator. The BLM
again offered to follow up with one-on-one consultations, and several
such meetings were held with individual tribes. Several tribes, tribal
members, and associations of tribes provided comments on the revised
proposed rule.
In March 2014, the BLM invited tribes to participate in another
meeting in Denver, Colorado. Twelve tribal representatives attended the
meeting. There was significant discussion of issues raised in the
comments on the revised proposed rule. The BLM believes its tribal
consultation efforts were thorough.
Nonetheless, some commenters assert that the BLM failed to follow
the stages of consultation set out in the Departmental consultation
policy and Executive Order 13175. The BLM believes that it has complied
with that Executive Order and with Secretarial Order 3317. The BLM
understands the importance of tribal sovereignty and self-
determination, and seeks to continuously improve its communications and
government-to-government relations with tribes.
Some commenters said that the rule continued to apply the same
requirements to operations on Indian lands as on Federal lands. They
said that the BLM should promulgate different rules for Indian lands,
citing as examples the authority of the BIA over cancellation of Indian
leases, and ONRR's royalty valuation criteria for operations on Indian
lands. The BLM does not assert that implementing its operational
regulations on oil and gas operations on Indian lands is the only
possible way to carry out the Secretary's trust responsibilities under
the Indian mineral statutes cited earlier. Nonetheless, it is the means
chosen by the Secretary and the BIA, and is more economic than creating
a parallel set of regulations and regulatory personnel in the BIA. The
BLM believes it is fulfilling its part of the Secretary's trust
responsibilities by requiring operations on Indian lands to meet the
same standards as those on Federal lands.
Some commenters urged the BLM to allow tribes to opt out of the
final rule. A commenter also cited to BIA's regulations that provide
for a tribal constitution or charter issued under the Indian
Reorganization Act of 1934, or resolution authorized by such
constitution to supersede the regulations in 25 CFR part 211 (which
includes 25 CFR 211.4). See 25 CFR 211.29. That section, however, also
includes a proviso that tribal law may not supersede the requirements
of Federal statutes applicable to Indian mineral leases, and that the
regulations in that part apply to tribal leases and permits that
require the Secretary's approval. The commenters have not explained
why, among all the other requirements of 43 CFR part 3160, an opt-out
should be provided for this rule. Some commenters said that the final
rule should be ``inoperative'' on tribal lands once the tribe has
demonstrated that its regulatory program is ``sufficient'' to govern
hydraulic fracturing operations. The Indian mineral leasing statutes
previously cited do not authorize tribes to opt-out of the Secretary's
regulations, and, unlike some environmental statutes, do not authorize
tribal ``primacy.'' Furthermore, the BLM has no way of terminating the
Secretary's trust responsibilities for hydraulic fracturing operations
if a tribe were to opt out of having the BLM's regulations apply on
that tribe's lands, or if the BLM failed to implement the final rule
because a tribe was implementing its own program.
Several commenters addressed the variance provision approvingly.
Some urged the BLM to recognize tribal regulations. The BLM recognizes
that some tribes have been proactive in regulating hydraulic fracturing
on their lands. It is not the BLM's intent to preempt tribal
regulations. Commenters did not bring to the BLM's attention any tribal
regulation or lease provision that the final rule would preempt. In the
absence of preemption, tribal law would apply to leases of tribal and
individually owned Indian land in addition to the final rule.
The variance provision of the rule allows the BLM, in cooperation
with a tribe, to issue a variance that would apply to all wells within
that tribe's lands, or to specific fields or basins within those lands,
if the State Director determines that the proposal meets or exceeds the
objectives of the provision for which a variance is requested. A
variance would not necessarily adopt tribal regulations as the Federal
rule. However, a variance would, for example, be a way of doing such
common-sense things as aligning reporting requirements of the two
sovereigns, addressing unique geological conditions, or facilitating
technological innovation, while maintaining the performance standards
and adequate margins of protection provided in the final rule.
Some commenters said that the variance provision does not comply
with policies promoting tribal sovereignty, self-determination, and the
Federal government's trust responsibility. The BLM believes that the
rule is consistent with the Federal government's trust responsibility
because it assures that Indian lands receive the same substantive
protection as Federal lands, and that it promotes tribal sovereignty by
facilitating coordination to achieve the goals of both sovereigns. By
recognizing tribal regulations, it accords with tribal self-
determination to the extent that could be expected from a rule
governing hydraulic fracturing operations.
A commenter stated that tribal variances should not be subject to
public comment. The rule does not provide for public notice and comment
on tribal variances and the rule is not revised as a result of this
comment.
Some commenters asked that the BLM provide more information about
how to obtain contracts and funding under Public Law 93-638, the Indian
Self-Determination and Education Assistance Act of 1975, 25 U.S.C. 450
et seq., as amended. Implementation of Public Law 93-638 and its
amending statutes is beyond the scope of this rulemaking, and is
governed by regulations in Title 25 of the CFR. If a tribe wishes to
apply for a contract to perform any of BLM's functions under 43 CFR
part 3160, it should contact the BLM.
Some commenters opposed the rule, or said that it should not apply
on Indian lands, stating that it would increase operators' costs, and
thereby make Indian lands less attractive to the oil and gas industry,
potentially resulting in reductions of revenue to the tribes. The rule
would not render Indian lands more or less attractive than Federal
lands. In reviewing the comments and preparing the final rule, the BLM
has looked for ways to reduce costs and burdens for operators, and to
focus on requirements that promote the

[[Page 16186]]

goals of assuring isolation and protection of usable water. As shown in
the economic analysis, the costs of complying with the final rule on
Federal or Indian lands will be a small percentage of an operator's
costs of drilling and completing a well. Those additional costs would
be easily outweighed by revenues that operators might anticipate from a
geologically attractive area. Tribes and their members will also
benefit from the substantial increase in assurance that their usable
water will be isolated and protected.
Cost Recovery
Some commenters supported the rule and suggested that the rule
include a cost recovery fee for hydraulic fracturing approval and
inspection. The BLM did not propose a separate cost recovery fee for
hydraulic fracturing approval and inspection in the initial and
supplemental proposed rules. Section 365 of the Energy Policy Act of
2005 prohibits the Secretary from implementing a rulemaking that would
enable an increase in fees to recover additional costs related to
processing drilling-related permit applications and use authorizations
until the end of fiscal year 2015. The BLM fully expects to process
requests for hydraulic fracturing concurrently with the processing of
drilling applications. The final rule does not include such fees,
however, the BLM may address that in any future cost recovery
adjustments.
BLM's Jurisdiction
Some commenters asserted that the rule is beyond the Secretary's
jurisdiction because protection of surface waters and groundwaters are
under the EPA's jurisdiction, not the BLM's jurisdiction. The BLM
agrees that regulation of the quality of surface waters under the Clean
Water Act, and the regulation of groundwater under the SDWA, are the
duties of EPA and states and tribes. The requirements of this rule do
not interfere with those programs. The rule does not address discharges
to surface waters at all. The rule clarifies the existing definition of
usable water to defer to state or tribal designations of aquifers as
underground sources of drinking water or as exempted aquifers under the
SDWA, so long as these designations are not inconsistent with the SDWA.
Some commenters challenged the Secretary's authority to regulate
well construction and operation. Some claimed that the Secretary has no
authority to disapprove or to require revisions to a hydraulic
fracturing proposal. Some claim that the Secretary has no authority
other than to lease lands and collect royalties. The BLM disagrees. The
Secretary has authority to promulgate this rule, as the Secretary had
for the other sections in 43 CFR part 3160 and the onshore oil and gas
orders. That authority includes the FLPMA, the MLA, the Mineral Leasing
Act for Acquired Lands, and the various Indian mineral statutes. Each
lease is expressly subject to existing and future regulations. The BLM
has authority to condition or to deny APDs, and this rule extends that
authority to proposals for hydraulic fracturing operations.
Some commenters objected to the rule on the grounds that protection
of water is a states' rights issue. The BLM agrees to a certain extent,
and has revised the rule, as discussed elsewhere, to reduce potential
conflicts with states' water allocation and water quality regulations.
Other commenters said that the BLM lacks statutory authority to control
water quality and usage because that authority is vested with the EPA
and the states.
The BLM is not controlling water quality or usage under this rule.
Operators are responsible for complying with state or tribal
requirements for obtaining water for use in hydraulic fracturing
operations and for discharges into surface or groundwater. The BLM will
not be issuing or vetoing rights to use water or discharge permits.
However, the BLM will need to know an operator's proposed source of
water and planned disposal method in order to consider the potential
environmental impacts and compliance with NEPA, but the BLM will not be
adjudicating water rights.
Federalism Assessment
Some commenters believed that the rule requires a Federalism
assessment under Executive Order (EO) 13132. The BLM believes that
there will be no financial impacts to the states as a result of this
rule. Operators will have some increases in costs, but the BLM does not
believe that production from Federal lands will be reduced as a result
of this rule. Therefore, a Federalism assessment is not required.
Compliance With E.O. 12866 and E.O. 13175
Many commenters suggested that the annual costs of the rule would
exceed $100 million per year and that the BLM failed to comply with
E.O.12866 and E.O.13175. One commenter suggested that the costs would
be $345 million per year, broken out as follows: $310 million for
enhanced casing costs; $5.6 million for initial delay costs; $1.7
million for administrative costs; $2.6 million for cement logs; $5.9
million for log delays; and $19.6 million if the BLM were to require
tanks to manage flowback. Other commenters referenced these cost
figures. Another commenter suggested the costs of the rule could be as
low as $30 million per year or as high as $2.7 billion per year. The
range was due to uncertainty about the rule's effect on field
operations. The areas of uncertainty in the comments are related to
drilling delays and completion schedules, the number of impacted wells,
additional requirements resulting from the usable water definition, and
costs to conduct CELs on surface and intermediate casing. Another
commenter suggested a range of possible costs of $0-$750 million per
year.
The BLM has complied with E.O.12866 and E.O.13175. After reviewing
and analyzing the submitted data, the BLM found that many of the
assertions that the commenters made are based on flawed assumptions or
confusion about the requirements in the rule. Commenters have also
provided constructive feedback about rule provisions that would pose
costs to operators that the BLM had not anticipated. Through the course
of this rulemaking, the BLM adjusted requirements to better reflect the
best management practices of operators conducting hydraulic fracturing
operations and to resolve the unintended consequences that the proposed
rules would have caused. The following discussion details comments by
topic area.
Commenters suggested that usable water is not fully defined, that
there are costs associated with identifying usable water zones, and
that the costs are variable and uncertain. Various commenters suggested
per-well costs of $4,000-$5,000, $8,000-$10,000, $60,000, and $400,000.
Activities associated with identifying usable water include drill logs,
water sampling, geologic characterization ($3,000-$8,000 or up to
$408,000 per field development), and drill stem testing ($200,000 per
test).
As explained in the discussion of section 3162.3-3(d), the final
rule removes the requirement that an operator must identify the usable
water zones with a drill log. Existing Onshore Order 1 already requires
that an operator's drilling plan include the estimated depth and
thickness of zones potentially containing usable water. In the final
rule, the BLM expects operators to use all available information to
identify usable water zones, consistent with Onshore Order 1. As such,
and since this information will likely already be readily available to

[[Page 16187]]

operators, and is already required for the drilling plan, the BLM does
not anticipate any incremental costs associated with identifying usable
water zones.
Commenters suggested that the BLM's definition of usable water
would pose additional costs, since the 10,000 ppm TDS standard in the
proposed rule is higher than the 5,000 ppm TDS standard in the previous
43 CFR 3162.5-2(d). Our detailed response to these comments appears in
the discussion of the definition of usable water and in section 3162.3-
3(d) of this preamble. In short, the current requirements regarding
usable water exist in Onshore Order 2, which was published after the
requirements in the previous section 3162.5-2(d). Onshore Order 2
specifies a 10,000 ppm TDS standard that is consistent with our
definition in the proposed and final rules. While the previous section
3162.5-2(d) specified a lower standard, it was superseded by Onshore
Order 2 in 1988. This final rule clarifies any confusion between the
regulations in the CFR and Onshore Order 2 standards. Since the 10,000
ppm TDS standard is not new, it does not result in additional costs.
Several commenters suggested that the rule would require operators
to perform additional cementing that would pose costs to operators. A
commenter's analysis suggests that the rule would require operators to
run deeper surface casing, two-stage cementing on the production
casing, or the addition of an intermediate string of casing, for a
total cost of $310M (calculated as 2,350 feet per well of additional
casing at $37 per foot for 3,566 wells). Another commenter suggested
that, by requiring operators to run a CEL on all strings that protect
usable water, operators would need to run cement for the entire lengths
of these casings.
As explained in the discussion of the definitions section and
section 3162.3-3(d) of this preamble, because the definition of usable
water has not substantially changed in this rule, and because existing
Onshore Order 2 already requires casing and cementing to protect and
isolate all usable water zones, there will be no significant changes in
costs of running casing and cement.
Commenters generally believe that the economic analysis
underestimates the costs of running CELs, particularly for CELs on the
surface casing. One commenter's analysis accepted the BLM's cost
estimates for the CEL requirement. Another commenter suggested the CEL
costs would be $24,000-$109,000 per well ($3,500-$5,700 for a CBL log,
or $5,000-$6,500 for a CBL on the surface casing, $20,000 for a CBL on
the intermediate casing, and rig delay costs up to $100,000). One
commenter suggested the BLM neglected to include $50,000 per day in rig
time from the analysis. One commenter suggested using delay costs of
$1,833.33/hour ($1,000 for rig costs and $833.33 for ancillary costs).
Commenters referenced EPA guidance that cement should harden for 72
hours for each casing.
As explained in the section 3162.3-3(c) discussion in this
preamble, in the final rule the requirements for a CEL on the surface
casing of a type well when cement returns to the surface with no
indication of inadequate cementing are removed. The final rule instead
requires well logging in a manner that is consistent with industry
standards. The economic analysis is revised to account for this change.
A commenter identified a formatting error in calculating the costs
of a CEL on the intermediate casing. The commenter was correct, and the
formatting error is corrected.
Commenters suggested that MIT costs should be considered at a cost
of $10,000 per test. The BLM disagrees that the costs of an MIT are
attributable to the final rule. The requirements of the rule are
consistent with industry guidance on hydraulic fracturing and with
state regulations. Industry guidance states that the operator should
pressure test the casing string through which the hydraulic fracturing
will occur prior to commencing the hydraulic fracturing operation. API
Guidance Document HF1 titled ``Hydraulic Fracturing Operations--Well
Construction and Integrity Guidelines'' (First Edition, October 2009)
states that ``prior to perforating and hydraulic fracturing operations,
the production casing should be pressure tested (commonly known as a
casing pressure test). This test should be conducted at a pressure that
will determine if the casing integrity is adequate to meet the well
design and construction objectives'' (p. 12). In addition, ``prior to
beginning the hydraulic fracture treatment, all equipment should be
tested to make sure it is in good operating condition. All high-
pressure lines leading from the pump trucks to the wellhead should be
pressure tested to the maximum treating pressure'' (p. 16). The BLM
also reviewed state regulations in California, Colorado, Montana, New
Mexico, North Dakota, Oklahoma, Texas, Utah, and Wyoming. From FY 2010
to FY 2013, the number of well completions on Federal and Indian lands
in those states accounted for 99.3 percent of the total well
completions on Federal and Indian lands nationwide. The state
regulations in those states either require pressure tests on all casing
strings or on the casing strings through which the completion operation
will occur. Therefore, we believe that the MIT requirement will not
pose an incremental cost to most responsible operators.
Several commenters suggested that in order to provide the actual
length and height of the fractures (see section 3162.3-3(d)), an
operator would have to conduct a ``frack model'' and that the
associated costs are not accounted for in the analysis. They suggested
that costs may range from $4,500-$200,000 per well depending on the
sophistication of the modeling required. The BLM does not intend to
require that operators undertake modeling. The BLM revised the
requirement in section 3162.3-3(d) of the final rule to allow for
greater operational flexibility, for example, by allowing operators to
report the estimated length and height. Operators would not undertake
the expense of hydraulically fracturing a well without an estimation or
calculation of the propagation of the fissures. The final rule does not
require additional modeling.
In the supplemental proposed rule, the BLM solicited comments
concerning the incremental costs of a requirement to manage flowback
with tanks instead of lined pits. One commenter suggested lined
impoundments or semi-rigid atmospheric tanks are more cost effective
than steel tanks. It estimated the 5-year net present value costs at:
Impoundments $2.3 million, semi-rigid tanks $2.42 million, steel tanks
$23 million). A commenter's analysis suggested a tank requirement would
cost $19.6 million per year (or $11,500 per well). Another commenter
suggested that an open pit costs $447,000 and a closed-loop system
costs $267,000 (an $180,000 cost advantage). Section 3162.3-3(h) of the
final rule requires that operators manage recovered fluids in enclosed
above-ground tanks until approval of a produced water plan pursuant to
Onshore Order 7. The economic analysis has been revised to address the
costs associated with this revision.
One commenter suggested that hydraulic fracturing operations have
additional ancillary costs that are borne by the public, including
wider roads and more road maintenance. The economic analysis measures
the incremental costs of implementing the rule, not all costs
associated with

[[Page 16188]]

hydraulic fracturing. The BLM did not revise the rule or the analysis
as a result of this comment.
Several commenters suggested that the analysis should consider the
cost of remedial cement squeezes. The practice of squeeze cementing is
an operation in a well whereby a cement slurry is forced (squeezed)
under pressure into a formation, or a channel behind the casing, or
through holes purposely placed in the casing. One commenter suggested
that costs for remedial cement squeezes may range between $0-$120,000,
or $142,000 per well. Another commenter suggested that typical costs
for cement remediation could include: Perforating casing--$12,000;
squeeze cementing--$30,000; and post-squeeze CBLs--$6,000-$20,000.
Further, the commenter believes that one cement squeeze would require 4
days and two squeezes would require 9 days to complete. The commenter
estimated the minimum total cost to be $128,000 for a single cement
squeeze and $284,000 for two squeezes, considering rig delay time and
direct remediation costs only. Further, the commenter suggests that
there is uncertainty in how many cement remediation jobs would be
required after the hydraulic fracturing operation occurs.
The concerns about remedial cement squeezes were predicated on two
arguments--that CELs are interpretive and that in implementing the
rule, the BLM would require operators to perform remedial cement
squeezes whenever the CEL detected a cement void. Final section 3162.3-
3(e) does not require operators to run a CEL on the surface casing in
every case. When there are indications of inadequate cement, the final
rule specifies actions that an operator must take that are in line with
current remedial procedures. Operators typically run CELs on the cement
behind intermediate casings that protect usable water when they do not
witness cement returns to surface. Therefore, the BLM believes that the
CEL requirements in the final rule would not compel operators to take
remedial action that they normally would not have taken otherwise.
Thus, the revised requirements do not pose any incremental costs to
operators.
Commenters suggested that the type well concept is unclear and
undefined. Commenters presented a range of estimates for type well
applicability. A commenter suggested 3 percent to over 50 percent per
field depending on the maturity. A 5 percent increase in type well
applicability is associated with a $34 million increase in industry
costs. Another commenter suggests 14.29 percent of all wells because 6-
8 wells can be drilled from the same platform. Another commenter
suggested it could mean one type well per section (10 type wells per
640-acre section).
The final rule does not carry forward the type well concept or the
CEL requirement for the surface casing. Thus, neither the costs of CELs
for all surface casings, nor the cost savings from the type well are
relevant for the final rule.
Commenters suggested that the economic analysis should consider
legal challenges and delays to APDs. The BLM did not revise the final
rule or alter the analysis to consider potential legal challenges or
APD delays, because any potential delays that might arise as a result
of legal challenges are speculative and not the result of the rule
itself.
One commenter suggested that the analysis should account for the
cost of labor required to implement the rule. In the economic analysis
for both the initial proposed and the supplemental proposed rules, the
BLM considered the additional BLM workload and cost required as a
distributional cost. The BLM agrees with the comment and has revised
the final analysis to include the labor costs as part of the total
costs of the rule.
Some commenters agreed with the BLM's administrative cost estimate,
while others thought that the estimate should be reevaluated. The
administrative workload was based on the estimated agency review time.
In the final rule's analysis, the BLM reevaluated the administrative
costs given the changes to the rule. The results of the BLM
reevaluation are discussed later in the Paperwork Reduction Act section
of this rule.
Commenters suggested that the BLM failed to consider the effects on
tribal governments, and that the rule will have a disproportionate
effect on tribes. Commenters suggested that the compliance costs of the
rule will discourage operators from developing resources on Federal and
Indian lands, reduce royalties, and harm local economies. Some
commenters suggest that there could be negative spillover effects on
state and private lands as well.
The analysis for the proposed and supplemental proposed rules
included impacts on tribal lands. The BLM revised the final rule's
analysis to addresses these impacts. The BLM believes that the rule
will not have a disproportionate effect on tribes, given the
requirements are consistent with current industry best practices.
Many commenters suggested that the economic analysis failed to
quantify or describe the benefits of the rule and that the benefits
must support the BLM's proposed action. Commenters disagreed with the
characterization of risk and of the incidence of problems. Commenters
also acknowledged that the risk of hydraulic fracturing is largely
unknown. One commenter suggests estimating the environmental risk or
determining society's willingness to pay for risk reduction.
The BLM does not quantify the benefits of the rule, because it is
unable to monetize the incremental reduction in risk that the rule
confers. It further believes that determining society's willingness to
pay for risk reduction would need to rely on a firm understanding of
the incremental risk reduction. However, this does not mean that the
rule is without benefits. The final rule includes requirements, many of
which are already consistent with industry guidance, to ensure that
operators conduct hydraulic fracturing in a manner that minimizes
environmental and health risks associated with these activities. These
requirements are also generally consistent with several state
regulations governing hydraulic fracturing.
One commenter suggested that Federal Remediation Technologies
Roundtable case studies referenced in the proposed rule's economic
analyses are inappropriate because none of the studies are studies of
hydraulic fracturing operations. One commenter referenced testimony
that the remediation of groundwater contaminated by oil and gas wastes
can range from $100,000 to $1 million. The BLM included these figures
in the analysis to provide context about the cost of potential
problems, but it does not use the figures to quantify a benefit.
Commenters suggested that the rule lacks economic justification and
is unnecessary, that there have been no events of groundwater
contamination, and the benefits must outweigh the costs. Elsewhere in
this preamble we have discussed the need and purpose for the rule and
it is prudent for the BLM to be proactive in the protection of
resources on Federal and Indian lands. Throughout the rulemaking
process, the BLM has been mindful of the potential compliance costs to
the operator. The requirements in the final rule are consistent with
industry best practices and the burden should be minimal. In addition
to that, the rule is necessary given the overall scale of development
and emergence of increasingly complex hydraulic fracturing operations
that apply increased pressures and volumes of fluid within the
subsurface. The BLM agrees that efforts to trace contaminants in
groundwater to specific hydraulic

[[Page 16189]]

fracturing operations have been controversial, in light of the
technical difficulties and scientific uncertainties. But no law
requires the BLM to wait for a significant pollution event before
promulgating common-sense preventative regulations. Also, the numerous
official reports of frack hits (unplanned surges of pressurized fluid
from hydraulic fracturing operations into other wells) show that the
industry is in need of regulation to protect other wells and to prevent
contamination of surface and possibly sub-surface resources caused by
frack hits.
Commenters suggested that some of the requirements in the rule are
duplicative of state rules, that the rule is duplicative and
unnecessary, and that the analysis should reflect that. The economic
analysis accounts for areas in which the rule's requirements are
consistent with existing requirements (whether in current BLM onshore
orders or in state regulations) or consistent with current industry
best practice. For activities required by the rule that are already
performed by operators, the economic analysis does not attribute the
costs of those activities to the final rule.
Commenters suggested that wells that have been constructed prior to
this rule should be grandfathered. Otherwise, operators would have to
workover wells to comply with cement repair provisions. If not, those
costs should be considered. As described in the discussion of final
section 3162.3-3(a), the final rule clarifies which paragraphs of the
final rule will apply to wells constructed prior to the effective date
of the rule, and the economic analysis reflects the terms of the final
rule.
Operators planning to conduct hydraulic fracturing on existing
wells will need to submit documentation that demonstrates that adequate
cementing was achieved for all casing strings designed to isolate and
protect usable water. Monitoring reports of cement jobs are common in
the industry and the operator should be able to provide such
documentation to the BLM without any burden even for wells drilled
prior to this rule. For older completed wells, to the extent that these
reports are not available, the operator may provide any other
information or perform any other measures deemed necessary by the
authorized officer to assure that the cementing will isolate and
protect usable water zones. Operators planning to conduct hydraulic
fracturing on existing wells will also need to demonstrate that there
is at least 200 feet of adequately bonded cement between the zone to be
hydraulically fractured and the deepest usable water zone. Operators
will be able to run a CEL on the production casing, as is consistent
with prudent operating practice, without an additional cost burden.
Environmental Impacts
Certain commenters expressed concern stating that the environmental
assessment (EA) did not consider a reasonable range of alternatives to
the proposed action. Commenters claimed that, other than the No Action
alternative, all alternatives looked too similar to be considered
different alternatives. Commenters further suggested that the BLM
consider alternatives that: (1) Do not impose cement evaluation log
(CEL) requirements; (2) Defer to states with hydraulic fracturing rules
regardless of whether they meet or exceed the requirements of the BLM's
rule; (3) Ban hydraulic fracturing entirely or in sensitive areas; (4)
Regulate air emissions from hydraulic fracturing operations; (5) Ban
the use of diesel in hydraulic fracturing fluid; or (6) Ban the use of
harmful chemicals in hydraulic fracturing fluid.
To help inform the development of the hydraulic fracturing rule,
the Secretary and the BLM hosted forums in Washington, DC and various
parts of the country to receive input from the public regarding their
concerns about hydraulic fracturing activities on onshore Federal and
Indian lands. A majority of the concerns raised during the sessions
relate to the risks hydraulic fracturing activities pose to surface and
subsurface sources of water, the constituents of the fluids injected
into the ground as part of the hydraulic fracturing process, and
concerns over the management of the fluids used during and recovered
after a well is fractured.
The information gathered from these sessions, coupled with the
BLM's authority to regulate all oil and gas operations on Federal and
Indian lands, helped guide the development of the BLM's Purpose and
Need statement in the environmental assessment (EA).
The Purpose and Need section of the EA states that ``The BLM's
existing limited regulations pertaining to hydraulic fracturing
operations need strengthening to provide adequate protection of water
resources.'' The Purpose and Need section of the EA further states
that, ``Pursuant to the FLPMA, the Indian mineral leasing acts, and
other statutes, the BLM administers oil and gas operations in a manner
that protects Federal and Indian lands, while providing for
opportunities to develop oil and gas resources on those lands.''
The BLM's obligation under NEPA is to analyze a reasonable range of
alternatives (not every conceivable alternative) that would meet the
bureau's purpose and need for Federal action and allow for a reasoned
choice among alternatives to be made. The Council on Environmental
Quality (CEQ) has determined that ``Reasonable alternatives include
those that are practical or feasible from the technical and economic
standpoint and using common sense, rather than simply desirable from
the standpoint of the applicant.'' \10\
---------------------------------------------------------------------------

\10\ CEQ, Forty Most Asked Questions Concerning CEQ's National
Environmental Policy Act Regulations, 46 FR 18026, 18027 (1981) (Q
2a-).
---------------------------------------------------------------------------

The BLM analyzed six alternatives that respond to the BLM's purpose
and need for Federal action. These alternatives consider a broad range
of prescriptions for how hydraulic fracturing operations should be
regulated, including the option of not promulgating a rule--the No
Action alternative. Regarding the action alternatives, Alternative B
seeks to regulate all forms of well stimulation, including hydraulic
fracturing, and prescribes a particular way to confirm wellbore
integrity and zonal isolation of usable water-bearing zones, i.e.,
through the use of cement bond logs for all wells that are to be
stimulated. In contrast, Alternative E seeks to regulate hydraulic
fracturing operations specifically, and broadens the set of cement
evaluation tools that may be used (not just a cement bond log) to
confirm wellbore integrity and zonal isolation of usable water-bearing
zones. Alternative E also evaluates the concept of a type well, which
would serve as a model well for hydraulic fracturing in a field where
geologic characteristics are similar. A cement evaluation log would not
be required for all wells that would replicate the successful type well
in the same field. The BLM also looked at alternatives that were less
and more restrictive in the way recovered fluids should be handled. The
following table outlines the alternatives that the BLM considered as
part of its NEPA analysis.

[[Page 16190]]

------------------------------------------------------------------------
Name of alternative Description of alternative
------------------------------------------------------------------------
Alternative A--No Action............... Under this alternative, the BLM
would neither promulgate a
rule to amend existing
regulations nor add any new
regulation.
Alternative B--Initial Proposed Well Under this alternative, the BLM
Stimulation Rule. would promulgate the well
stimulation rule entitled Oil
and Gas; Well Stimulation,
Including Hydraulic
Fracturing, on Federal and
Indian Lands, which was
published in the Federal
Register on May 11, 2012 (77
FR 27691)
Alternative C--Unlined Pits............ This alternative is identical
to Alternative A except oil
and gas operators would not be
required to line the pits that
store the fluids flowed back
from a well after well
stimulation operations are
complete.
Alternative D--Storage Tank Requirement This alternative is identical
to Alternative B except that
it requires oil and gas
operators to use storage tanks
to manage flowback.
Alternative E--Proposed Action-- Under this alternative, the BLM
Supplemental Proposed Hydraulic would promulgate the
Fracturing Rule. supplemental proposed
hydraulic fracturing rule
entitled Oil and Gas;
Hydraulic Fracturing on
Federal and Indian Lands,
which was published in the
Federal Register on May 24,
2013 (78 FR 31636). This
alternative is similar to
Alternative B, the Initial
Proposed Rule, except it
contains sufficient changes
that publication of a revised
proposed rule was necessary.
Alternative F--BLM Preferred Under this alternative, the BLM
Alternative, Final Hydraulic would promulgate the final
Fracturing Rule. rule entitled: Oil and Gas;
Hydraulic Fracturing on
Federal and Indian Lands. This
alternative is similar to
Alternative E, but with
certain modifications based on
comments received during the
public comment period for the
Supplemental Proposed Rule on
Oil and Gas; Hydraulic
Fracturing, on Federal and
Indian Lands.
------------------------------------------------------------------------

Alternative C evaluated the option of not requiring operators to
line their pits to temporarily store recovered fluids. Alternative D
evaluated the option of requiring operators to use only storage tanks
to store recovered fluids. Under Alternative F, the BLM requires the
use of rigid enclosed, covered, or netted and screened above-ground
tanks with a 500 bbl capacity, but will consider the use of a lined pit
so long as the risk of adversely affecting sensitive water resources,
such as surface water and shallow groundwater, was low and use of
storage tanks was infeasible for environmental, public health, or
safety reasons. However, Alternative F does not include a requirement
to perform a cement evaluation log on all casing strings. Rather, it
requires operators to circulate cement to the surface for the surface
casing and either circulate cement to the surface or run a CEL on the
intermediate and production casing, in addition to performing specific
well integrity tests, to confirm wellbore integrity and zonal
isolation. These alternatives meet the BLM's purpose and need for
Federal action and comply with CEQ's requirement to also consider the
No Action alternative, which is Alternative A.
In addition to the six alternatives analyzed in the environmental
assessment, the BLM also considered additional alternatives that were
eliminated from detailed analysis. The BLM considered an alternative to
defer to the states' and tribes' hydraulic fracturing rules regardless
of whether those rules meet or exceed the agency's hydraulic fracturing
requirement. However, those governments are regulating hydraulic
fracturing operations in varying ways. For example, the state
regulations range from not regulating the activity at all in some
states to fairly comprehensive regulation in other states. The BLM
administers oil and gas operations in many states and on various Indian
reservations, and the agency needs a baseline set of standards that
would apply to Federal and Indian oil and gas leases in all states.
These standards must meet the agency's unique responsibilities under
the FLPMA, the Indian mineral leasing acts, and other statutes to
administer oil and gas operations in a manner that protects Federal and
Indian lands. The BLM's regulations are necessary because the BLM is
unable to delegate its responsibilities to the states and tribes. An
alternative that would defer to state and tribal hydraulic fracturing
rules, even in circumstances where those rules do not meet or exceed
the requirements of the BLM's rule, would not meet the purpose and need
for the BLM's action. Moreover, an alternative deferring only to more
stringent regulations would be unnecessary. None of the alternatives
considered by the BLM for this rulemaking would preempt a more
stringent state or tribal law. Unless a specific variance is granted by
the BLM, operators on Federal leases must comply both with this rule
and any applicable state requirements, just as they already must comply
with both BLM rules and state rules on a variety of drilling and
completion issues. This alternative was therefore not carried forward
for further analysis.
The BLM considered an alternative that would ban hydraulic
fracturing activities in all areas. However, such an alternative may
render most oil and gas development projects on Federal and Indian land
infeasible, as indicated by the fact that the BLM estimates that 90
percent of the wells drilled on Federal and Indian land are
hydraulically fractured. The BLM has a responsibility under the FLPMA
to act as a steward for the development, conservation, and protection
of Federal lands, by implementing multiple use principles and
recognizing, among other values, the Nation's need for domestic sources
of minerals from the public lands. The Secretary of the Interior has
responsibilities under the Indian mineral leasing acts to assist tribes
and individual Indians in obtaining the benefits of mineral development
while protecting other resources. A ban or moratorium would not satisfy
the BLM's development responsibility under the FLPMA, or the
Secretary's responsibilities under other statutes, when regulations can
adequately reduce the risks associated with hydraulic fracturing
operations. In addition, a part of the BLM's purpose and need for this
action is to administer oil and gas operations in a manner that
protects Federal and Indian lands while providing for opportunities to
develop oil and gas resources on those lands. An alternative that would
ban or place a moratorium on hydraulic fracturing operations would not
meet the purpose

[[Page 16191]]

and need for the BLM's action, and was not carried forward for further
analysis.
Similarly, the BLM considered an alternative that would ban
hydraulic fracturing activities in sensitive areas. However, the BLM
has other tools and processes in place to ensure protection of
sensitive areas. For example, the BLM has rules at 43 CFR 3100.0-
3(a)(2)(iii) that prohibit the leasing of Federal minerals beneath
incorporated cities, towns, and villages. Also, during development of a
Resource Management Plan (RMP), the BLM identifies areas needing
protection as areas closed to leasing or areas open to leasing, but
with stipulations that limit or prohibit surface occupancy. Further,
specific setbacks from sensitive areas are more effective when they are
determined at a level where the information associated with a given
sensitive area is available. That information is gathered and
maintained at the field office level where specific drilling and
hydraulic fracturing operations are permitted. At the permitting stage,
the BLM conducts additional analysis as required by NEPA, when
drilling/hydraulic fracturing proposals are received. The analysis
includes onsite inspections, which identify any additional sensitive
areas. Using that information, the BLM then develops proper mitigation
to protect these areas. Mitigation could include moving the well
location or including site-specific conditions of approval (COAs). In
addition, if unnecessary or undue degradation impacts are identified on
public land, or unacceptable impacts are identified on Indian land,
which cannot be mitigated, the BLM may deny the proposal. Through
existing regulations, the RMP process, and the subsequent site-specific
analyses, the BLM has or can specify measures to ensure protection of
sensitive areas. Furthermore, state set-back requirements would
normally apply on Federal lands, and tribal set-back requirements would
apply on tribal lands (see also existing section 3162.3-1(b)). Since
setback requirements are already addressed in existing regulations,
land use planning, and internal processes and policy, minimum setback
distances are not necessary in this rule. For these reasons, an
alternative that entails setbacks from sensitive areas would not be a
reasonable alternative, and was not carried forward for further
analysis.
The BLM considered an alternative that would regulate emissions
associated with the hydraulic fracturing process. However, this
alternative is not within the scope of this rulemaking. The purpose and
need for the BLM's action is, among other things, to improve its
regulatory framework to account for hydraulic fracturing activities and
establish procedures that would provide adequate protection of water
resources on Federal and Indian lands. Please note that the EPA issued
final rules to reduce air pollution from the oil and natural gas
industry. The final rules were issued in 2012 and include air standards
for natural gas wells that are hydraulically fractured. For these
reasons, the alternative was not carried forward for analysis.
The BLM considered an alternative that would ban the use of harmful
chemicals in the fluids used to hydraulically fracture a well.
Chemicals used during the hydraulic fracturing process are tailored to
the downhole conditions of a given well. In this rule, to be
conservative, the BLM treats all chemicals used in hydraulic fracturing
as if they were hazardous. Thus, the rule is written to ensure that all
hydraulic fracturing fluids are confined to the intended zone and do
not contaminate usable water zones, and that recovered fluids do not
contaminate surface or groundwater. For these reasons, an alternative
to ban hazardous chemicals was not carried forward for analysis.
Similarly, the BLM considered an alternative that bans the use of
diesel fuel in hydraulic fracturing fluids. Diesel fuel is used as a
base fluid instead of water where the hydrocarbon-bearing formation
would swell when coming into contact with water, limiting or preventing
the flow of oil and gas into the wellbore. The regulation of diesel
fuel in hydraulic fracturing fluids is committed to EPA under the SDWA
and the Energy Policy Act of 2005. The action alternatives would
prevent hydraulic fracturing fluids, recovered fluids, and hydrocarbons
from contaminating usable water sources. Banning the use of diesel fuel
on Federal and Indian lands could prevent some oil and gas resources
from being developed, even though such operations would be allowed by
the EPA's regulations and guidance. That would not serve the purpose
and need for the regulation. Accordingly, an alternative to ban the use
of diesel fuel was not carried forward for analysis.
Certain commenters recommended that the BLM not only analyze the
impacts from the proposed rule, but rather all impacts associated with
hydraulic fracturing operations in order to determine the effectiveness
of the rule. Those commenters wanted an analysis of impacts to
landscapes, air, wildlife, etc., as well as increased greenhouse gas
emissions released as a result of increased production from
unconventional sources made available only because of hydraulic
fracturing technologies.
An expanded description of hydraulic fracturing operations is
provided in the Environmental Impacts section of the EA, and in the
discussion of the No Action Alternative. Analyzing impacts associated
with actual site-specific hydraulic fracturing activities is outside
the scope of the EA for this rule. The BLM's Preferred Alternative is
not to consider the approval of a specific hydraulic fracturing
operation, but rather to consider how its existing rules should be
revised to respond to changes in technologies for hydraulic fracturing
and the public's concern regarding the practice. Approvals to develop
Federal and Indian oil and gas resources (including proposals to
hydraulically fracture wells) are made at different levels of the
agency's organization and during various decision-making processes--
land use planning, oil and gas leasing, and permitting. It is at those
decision points where the BLM would analyze, through the NEPA process,
impacts to landscapes, air, wildlife, etc., as well as greenhouse gas
emissions released from oil and gas development.
The BLM has analyzed the action alternatives in comparison to the
No Action Alternative. The CEQ requires that a No Action Alternative be
considered. The No Action Alternative would not amend the BLM's oil and
gas regulations. Instead oil and gas activities on Federal and Indian
lands would continue under existing regulations. The No Action
Alternative provides a useful basis for comparison, enabling decision-
makers to compare the magnitude of environmental effects of the action
alternatives against the No Action Alternative. The No Action
alternative also demonstrates the consequences of not meeting the need
for the action.
The BLM has evaluated the effectiveness of the rule when evaluating
the effects of the No Action Alternative in Chapter IV of the EA. The
BLM determined that if none of the action alternatives were to be
implemented, operators or their contractors would still perform
hydraulic fracturing operations on Federal and Indian lands, usually
without the BLM's prior approval, and without performance standards
specific for wells to be fractured. The BLM and the public would not
have an adequate assurance that hydraulic fracturing operations
performed on Federal and Indian lands are conducted in a safe and
environmentally sound manner, particularly because there would not be a
regulation that provides: (1) For the disclosure of chemicals used in
the stimulation process; (2) A means to

[[Page 16192]]

confirm that all hydraulically fractured wells would be able to
withstand the pressures of an anticipated hydraulic fracturing event
and that all chemicals injected would be contained within the well and
targeted producing formations; or (3) An assurance that the fluids
recovered from the hydraulic fracturing process are handled and
disposed of properly.
Some commenters believe that the scope of the rule requires the
preparation of an EIS. The comments in favor of an EIS make one or more
of three different positions. First, some commenters believe that an
EIS is required because of the trade secrets provision within the rule.
Although the rule contains requirements for disclosure, there are
provisions that allow operators to withhold trade secrets. Those
commenters said that the BLM cannot claim that the rule's chemical
disclosure requirement will help the agency and other agencies make an
accurate determination of whether hydraulically fractured fluids could
be the source of any future reports of groundwater contamination.
Without the information about trade secrets, the commenters said,
future approvals of hydraulic fracturing operations could not
accurately predict environmental impacts, and thus the BLM should
prepare an EIS for the final rule.
Second, some commenters believe that an EIS is required because
multiple significance factors are present under the regulations which
would govern widespread hydraulic fracturing on public lands throughout
the country. The alleged significance factors include adverse
environmental effects, significant impacts to public health and safety,
unique characteristics of the geographic area, controversial effects,
uncertain risks, cumulatively significant impacts, adverse effects to
threatened and endangered species, and potential violations of
environmental laws. Commenters said that the significant impacts of
widespread hydraulic fracturing on public lands that would take place
under the regulations contradict BLM's ultimate conclusion in the EA
that the proposed regulations would have no significant impacts on the
environment.
Third, some commenters have expressed concern with the EA's
analysis of socioeconomic impacts. Commenters said a nationwide rule
that has economic and employment impacts is a major Federal action
requiring the preparation of an EIS, therefore, the NEPA analysis
performed for the proposed rule is inadequate. The commenter said that
the BLM is in error in determining that an EA is sufficient to analyze
the impacts associated with the rule. The commenter said that a
nationwide rule of this magnitude and its coinciding economic and
employment impacts certainly rise to the level of ``Major Federal
Action,'' and therefore questioned the BLM's determination that an EA
is sufficient.
The BLM has not prepared an EIS in response to those comments.
First, the comments based on the trade secrets provisions miss the
point that BLM's evaluation of the impacts associated with promulgation
of the rule, and with the BLM's later evaluation of site specific
impacts, does not require operators to disclose trade secrets. The BLM
will make its decisions on proposals to conduct hydraulic fracturing
operations on the assumption that the operations will use hazardous
chemicals. The BLM will not approve proposals unless the operator
demonstrates that the well was cased, cemented, and tested to show that
it will isolate and protect usable water, and that recovered fluids
will be isolated from surface and groundwater. The precise chemical
constituents are not necessary for the BLM to assure that the operation
will protect surface and groundwater. Exemptions from public disclosure
for trade secrets or confidential business information will not prevent
the BLM from assessing the environmental impacts of future hydraulic
fracturing operations, and thus do not require an EIS for this rule.
Second, the comments that advocate an EIS because of multiple
significance factors which would govern widespread hydraulic fracturing
on public lands throughout the country misunderstand the effect and
impact of this rule. Federal agencies are required to prepare an EIS
when they will take a major Federal action that will potentially have a
significant effect (direct, indirect, or cumulatively) on the human
environment. The BLM's action is to update its existing regulations
that pertain to hydraulic fracturing operations on Federal and Indian
leases. Analyzing impacts associated with actual site-specific
hydraulic fracturing activities is outside the scope of the EA for this
rule. The BLM's proposed action is not to consider the approval of a
specific hydraulic fracturing operation, but rather to consider how its
existing rules should be revised to respond to changes in technologies
for hydraulic fracturing and the public's concern regarding the
practice. Approvals to develop Federal and Indian oil and gas resources
(including proposals to hydraulically fracture wells) are made at
different levels of the agency's organization and during various
decision-making processes--land use planning, oil and gas leasing, and
permitting. It is at those decision points where the BLM would conduct
further analysis under NEPA to evaluate impacts to landscapes, air,
wildlife, etc., as well as increased greenhouse gas emissions released
from oil and gas development.
In the EA prepared for this rule, the BLM evaluated a range of
reasonable alternatives, including the final rule, to determine whether
its promulgation of the final rule would result in a significant effect
on the human environment. In making its Finding of No Significant
Impact (FONSI), the BLM considered the significance factors set out in
40 CFR 1508.27, which include the significance factors identified by
commenters. For the reasons discussed in more detail in the EA and
FONSI, the BLM concluded that the final rule would not have a
significant impact on the environment and that no EIS was required.
Furthermore, the rule is not connected to other actions that may
require an EIS because it does not automatically trigger land use
planning decisions, oil and gas leasing, or hydraulic fracturing
operations. The rule will be in effect regardless of any previous
leasing or development. The rule is not an interdependent part of a
larger action and it does not depend on any larger action for its
justification.
The rule will govern future hydraulic fracturing operations, as
will stipulations in oil and gas leases, and COAs in permits to drill.
The lease stipulations and COAs can address local conditions and
resources. Thus, the rule does not foreclose reasonable mitigation for
site-specific direct, indirect, or cumulative impacts.
Under the CEQ's regulations, an EIS is required only if the
issuance of a rule or regulation may significantly affect the quality
of the human environment. 40 CFR 1508.18. The human environment
includes the natural and physical environment and the relationship of
people with that environment, but economic or social effects do not by
themselves require preparation of an EIS. 40 CFR 1508.14. The EA refers
to and analyzes the socioeconomic impacts of the rule that are provided
in the separate economic analysis. The economic analysis shows that the
rule will increase compliance costs of operators, but also discloses
that those increased costs would be only a small percentage of the
costs of drilling and hydraulically fracturing an oil and gas well.
Thus, only marginally prospective lands could even theoretically become
less attractive to the oil industry, and

[[Page 16193]]

the employment and revenue impacts of the rule, if any, will be
impossible to separate from the greater influences of geologic
conditions, technological innovations, and market forces. The BLM's EA
thus appropriately determined that there would be no significant
impacts to the quality of the human environment, and it is not
necessary for the BLM to prepare an EIS.
Certain commenters stated that the BLM did not inform the public
that it was preparing a NEPA analysis, nor did it circulate a draft EA.
Other commenters expressed similar concern saying the BLM did not
provide a public comment period and therefore, the public was not able
to provide meaningful input at a time when the environmental analysis
could have been altered and improved.
Unlike the procedures for issuing an EIS, which includes specific
formal notification requirements through the Federal Register and
minimum requirements for inviting public comments, the CEQ's and the
DOI's NEPA implementing regulations require Federal agencies to involve
the public when preparing an EA, but gives discretion to each agency to
determine whether it is appropriate to make the EA available for public
comment and review.
On May 11, 2012, the BLM issued the notice of proposed rulemaking
and then issued a supplemental notice of proposed rulemaking on May 24,
2013. The 2012 proposal was available for public comment for 120 days
and the 2013 notice was available for 90 days. Both rules put the
public on notice that the EA was available for review and comment along
with the other documents in the administrative record. The BLM, in
fact, received several comments concerning the substance of the EA, and
those comments have been considered. Thus, comments suggesting that the
EA was unavailable, or not properly made available for comment, are
incorrect.

III. Procedural Matters

Federal and Indian Oil and Gas Leasing Activity

To understand the context of the costs and benefits of this rule,
the BLM includes background information concerning the BLM's leasing of
Federal oil and gas, and management of Federal and Indian leases. This
analysis explains the basis for the conclusions related to the
procedural matters sections that follow. The BLM Oil and Gas Management
program is one of the largest mineral leasing programs in the Federal
Government. At the end of fiscal year (FY) 2013, there were 47,427
Federal oil and gas leases covering 36,092,482 acres, 93,598 producible
and service drill holes, and 99,975 producible and service completions
on Federal leases. Table 1 shows the sales volume, sales value, and
royalty generated from Federal and Indian oil and gas production in
2013. For FY 2013, onshore Federal oil and gas leases produced about
133 million bbl of oil, 2.67 trillion cubic feet (Tcf) of natural gas,
and 2.5 billion gallons (Gal) of natural gas liquids, with a sales
value of almost $24 billion and generating royalties of almost $2.7
billion. Oil and gas production from Indian leases was almost 46
million bbl of oil, 238 billion cubic feet (Bcf) of natural gas, and
155 million gallons of natural gas liquids, with a sales value of over
$5 billion and generating royalties of $860 million for the Indian
mineral owners.

Table 1--Federal and Indian Oil and Gas Production and Royalties, Fiscal Year 2013
----------------------------------------------------------------------------------------------------------------
Jurisdiction Commodity Sales volume Sales value Revenue
----------------------------------------------------------------------------------------------------------------
Federal Leases................... Oil (bbl)........... 133,364,128 $11,927,069,991 $1,444,886,822
Gas (Mcf)........... 2,662,577,254 9,905,897,816 1,051,198,875
NGL (Gal)........... 2,477,721,602 2,076,639,138 195,789,932
--------------------------------------------------------
Subtotal..................... .................... ................. 23,909,606,945 2,691,875,629
Indian Leases.................... Oil (bbl)........... 45,966,597 4,137,453,205 721,089,106
Gas (Mcf)........... 238,717,918 813,440,706 124,217,560
NGL (Gal)........... 155,399,916 135,369,266 15,192,781
--------------------------------------------------------
Subtotal..................... .................... ................. 5,086,263,176 860,499,447
----------------------------------------------------------------------------------------------------------------
Source: Office of Natural Resources Revenue (ONRR), Federal Onshore Reported Royalty Revenue, FY 2013 and
American Indian Reported Royalty Revenue, FY 2013.

Need for Policy Action

To summarize the need for policy action, the National Academy of
Science has identified three potential pathways for hydraulic
fracturing fluids or oil and gas from hydraulic fracturing operations
to contaminate usable water resources. The BLM agrees that the most
likely pathway would be a leak in the wellbore casing, and that
assurances of the strength of the casing are appropriate. The BLM also
believes that it is important to consider known faults or natural
fissures that could serve as pathways between the fractured zone and
usable water before approving a hydraulic fracturing operation. A
related issue is prevention of ``frack hits,'' which are unplanned
surges of pressurized fluids from one wellbore into another wellbore.
Frack hits have resulted in surface spills on Federal and non-federal
lands and have caused the loss of recoverable oil and gas, but they
have not yet been shown to be a source of contamination of usable
water. Furthermore, proper management of recovered fluids on the
surface is necessary to prevent leaks and spills that could contaminate
surface waters and shallow aquifers; the BLM needs to fill the existing
regulatory gap between completion of a hydraulic fracturing operation
and the implementation of an approved plan for permanent disposal of
produced water. Finally, the BLM, the public, and tribes should have
access to information about the chemicals injected into Federal or
Indian lands, consistent with statutory protections for proprietary
information. The following discusses those needs for policy action in
more detail.
Much of the debate about hydraulic fracturing has centered on fluid
or gas migration; that is, the potential that hydraulic fracturing
fluids pumped into deep geologic formations, or oil or gas liberated by
hydraulic fracturing will migrate into shallower drinking water sources
with potential contamination made more likely if the wellbore integrity
is compromised. Most reports suggesting that hydraulic fracturing
operations contributed to contamination of water supplies involve
instances of abnormally high concentrations of methane in water wells
or monitoring wells in or near areas with active oil and gas drilling.

[[Page 16194]]

For example, the National Academy of Sciences issued reports in
2011 \11\ and in 2012 \12\ finding that there are at least three
possible mechanisms for fluid migration into shallow drinking-water
aquifers that could help explain the increased methane concentrations
observed in water wells that existed around shale gas wells in
Pennsylvania:
---------------------------------------------------------------------------

\11\ Osborn, S., et al. (2011). Methane contamination of
drinking water accompanying gas-well drilling and hydraulic
fracturing. Proceedings of the National Academy of Sciences.
\12\ Warner, N., et al. (2012). Geochemical evidence for
possible natural migration of Marcellus Formation brine to shallow
aquifers in Pennsylvania. Proceedings of the National Academy of
Sciences, Vol. 109, July 24, 2012.
---------------------------------------------------------------------------

1. The movement of gas-rich solutions within the shale formations
up into shallow drinking-water aquifers;
2. The movement of gas through inadequately constructed, or leaky
gas-well casings; and
3. The creation of new or enlarging of existing fractures above the
shale formation as a result of hydraulic fracturing, which increases
the connectivity of the entire fracture system, thus allowing the gas
to absolve out of solution and migrate through the fracture systems and
into shallow aquifers.
These reports have indicated that the movement of gas-rich
solutions within the shale formations up into shallow drinking-water
aquifers is the least likely possibility. This is due primarily to the
extensive distance between the shale formations and the shallow
aquifers as well as high underground pressures exerted against the deep
shale formations. The most likely possibility for gas contamination
would be from leaky gas-well casings. These leaks could occur at
hundreds of feet underground, with methane passing laterally through
the well casing and vertically through fracture systems. There is also
a possibility for gases to migrate through fractures above the shale
formation that is created or enlarged as a result of hydraulic
fracturing and thus expanding the overall underground fracture system.
These new fractures could potentially relieve the pressures exerted
against these gas-rich solutions, which would allow the gas to come out
of solution and migrate through the fracture system and potentially
into shallow aquifers or improperly plugged wells. However, these
researchers have stated that the possibility of such occurrence is
unlikely, but still unknown.
The focus on fluid or gas migration is only one aspect of potential
damage. According to the EPA, there are other potential impacts,
including stress on surface water and groundwater supplies from the
withdrawal of large volumes of water used in drilling and hydraulic
fracturing, contamination of underground sources of drinking water and
surface waters resulting from spills, faulty well construction, or by
other means, and adverse impacts from discharges into surface waters or
from disposal into underground injection wells.\13\
---------------------------------------------------------------------------

\13\ U.S. Environmental Protection Agency (May 20, 2014).
Natural Gas Extraction--Hydraulic Fracturing: Providing Regulatory
Clarity and Protections against Known Risks. Retrieved from http://www2.epa.gov/hydraulicfracturing#providing.
---------------------------------------------------------------------------

The BLM is aware that a small number of hydraulic fracturing
operations on Federal lands have communicated with other wells in their
vicinity. Those hydraulic fracturing operations created fractures that
connected with existing fissures or fractures in the shale, allowing
pressurized fluids to flow into nearby wellbores. During these
instances of downhole inter-well communication, known as ``frack
hits,'' the pumped-in hydraulic fracturing fluid may flow into and up
through a nearby well, causing a blow out and spill.
The Secretary of Energy's Advisory Board
At the President's direction, the Secretary of Energy's Advisory
Board convened a Natural Gas Subcommittee to evaluate hydraulic
fracturing issues. The subcommittee met with industry, service
providers, state and Federal regulators, academics, environmental
groups, and many other stakeholders. Initial recommendations were
issued by the subcommittee on August 18, 2011. Among other things, the
report recommended that more information be provided to the public,
including disclosure of the chemicals used in fracturing fluids. The
subcommittee also recommended the adoption of progressive standards for
wellbore construction and testing.
The final report, issued on November 18, 2011, recommended, among
other things, that operators and regulating agencies ``adopt best
practices in well development and construction, especially casing,
cementing, and pressure management. Pressure testing of cemented casing
and state-of-the-art cement bond logs should be used to confirm
formation isolation. Regulations and inspections are needed to confirm
that operators have taken prompt action to repair defective cementing
jobs. The regulation of shale gas development should include
inspections at safety-critical stages of well construction and
hydraulic fracturing.'' \14\
---------------------------------------------------------------------------

\14\ Secretary of Energy Advisory Board (2011). Shale Gas
Production Subcommittee Second Ninety Day Report. November 18, 2011.
Retrieved from http://www.shalegas.energy.gov/resources/111811_final_report.pdf.
---------------------------------------------------------------------------

Public Concern

The public and various groups have expressed strong concerns about
the prevalence of hydraulic fracturing and the chemical content of the
fluids used in the process. Some of the comments frequently heard
during the public forums previously discussed included concerns about
water quality, water consumption, and a desire for improved
environmental safeguards for surface operations. Commenters also
strongly encouraged the agency to require public disclosure of the
chemicals used in hydraulic fracturing operations on Federal and tribal
lands.

Improving Governmental Processes

The BLM has existing regulations for hydraulic fracturing, found in
43 CFR 3162.3-2. Under that regulatory provision, an operator must seek
approval from the BLM before performing ``non-routine'' fracturing
operations. Conversely, an operator performing ``routine'' fracturing
operations does not currently need the BLM's approval. The regulation
makes a distinction between ``routine'' and ``non-routine'' fracturing
operations, but it does not define them. This omission makes the
distinction functionally difficult to apply and confusing for both the
agency and the regulated public.
Also, hydraulic fracturing operations conducted now are vastly
different than the operations conducted decades ago. For decades,
hydraulic fracturing was a completion or re-completion technology that
used relatively small quantities of fluid to improve the flow of
hydrocarbons around the bottom of conventional wells. Due to advances
in horizontal drilling, hydraulic fracturing operations are now
conducted on wells with longer lateral legs (often 1 to 2 miles) and
require far larger volumes of water. The chemical content of the
hydraulic fracturing fluids is also a growing concern to the public,
such that many state regulatory authorities now require the chemical
disclosure of fracturing fluids. The information that the BLM currently
requires before and after fracturing operations is inadequate and does
not reflect the complex nature of the operations.
From a resource management perspective, the current regulation
results in incomplete information being provided to the BLM. That lack
of

[[Page 16195]]

information restricts the BLM's ability as the resource manager to make
informed resource decisions about hydraulic fracturing operations or to
respond effectively to incidents that may occur. Knowledge of the
hydraulic fracturing operations will help the BLM better manage and
protect public and tribal resources.

Potential for Externalities

Generally, there is greater potential for undesirable events or
incidents to occur when operations are conducted in wells that are
constructed improperly, where the plans are inadequate, or when the
fluids are not properly managed. This potential extends to hydraulic
fracturing operations, where the well may extend laterally and for
longer distances, greater pressures are placed on the well, and larger
volumes of fluids are used and recovered. As with all drilling and
production activities, there is a potential that they may pose a
negative externality to society, considering limitations in
understanding the extent of potential damage or determining a causal
relationship between the operation and the damage.
Relative to wells constructed with sufficient and demonstrated
integrity, wells that are inadequately constructed may not sufficiently
isolate formation gas or fluids from water resources or may be more
likely to fail during fracturing operations. Although wellbore
integrity provisions exist in current BLM regulations, this rule would
enhance those provisions to account for advances in technology and
hydraulic fracturing operations. In addition, the recovered fluid from
hydraulic fracturing operations may pose additional risk to the surface
and subsurface environments if not managed and disposed of properly.

Estimating Benefits and Costs

After reviewing the requirements of the final rule, we have
determined that it will not have an annual effect on the economy of
$100 million or more or adversely affect in a material way the economy,
a sector of the economy, productivity, competition, jobs, the
environment, public health or safety, or state, local, or tribal
governments or communities. Additionally, we have determined that it
would not have a significant economic impact on a substantial number of
small entities.
Many of the requirements are currently met by operators as a matter
of standard industry practice or in compliance with existing state
regulations or other BLM regulations (including Onshore Oil and Gas
Orders No. 1 and No. 2). We measure the incremental burden to operators
against that baseline. While some requirements do not pose an
additional burden, other requirements will pose an additional burden.
We estimate that the rule will impact about 2,800 hydraulic
fracturing operations per year, but that it could impact up to 3,800
operations per year based on previous levels of activity on Federal
lands and growing activity on Indian lands. We estimate that the
compliance cost could reach about $11,400 per operation or $32 million
per year. The estimated per-operation compliance costs represent about
0.13 to 0.21 percent of the cost of drilling a well. Given the
potential to impact 3,800 operations per year, the compliance costs
might reach $45 million per year.
The BLM estimated or described the potential costs and benefits
that would occur as a result of the rule. As such, it analyzes the
impacts in relation to the current operating environment (or the
baseline). In analyzing costs and benefits, it is important to
differentiate between the activities that an operator conducts (either
voluntarily or in compliance with state or Federal requirements) and
those new activities that the rule would compel.
Office of Management and Budget (OMB) Circular A-4 recognizes that
not all benefits and costs can be described in monetary or even in
quantitative terms. In those cases, it directs agencies to present any
relevant quantitative information along with a description of the
unquantified effects.
We use a bottom-up approach to measure the incremental impacts
rather than a top-down approach. In doing so, the BLM estimates the
number of hydraulic fracturing operations per year for future years,
determines the applicability of the requirements on the operations,
determines the unit cost of compliance per requirement, and then
calculates the total costs across all requirements and operations. Due
to the uncertainty of the hydraulic fracturing activity in future
years, the BLM presents a range of costs based on the range of
potential activity. We chose to use a bottom-up approach because a
requirement may not pose an incremental compliance cost, depending on
the operators' voluntary compliance (generally determined as whether
the requirement is consistent with industry guidance or best practice)
or the regulatory requirements in the jurisdiction within which the
operation will occur.
The BLM's approach to estimating the number of hydraulic fracturing
operations is described in the Economic Analysis for this rule, which
is available from the BLM at the address listed in the ADDRESSES
section of this rule. The BLM took the number of well completions on
Federal and Indian lands for FY 2010 to FY 2013, and assumed that 90
percent of wells were completed using hydraulic fracturing and that 3
percent of those wells would be recompleted. The BLM then used the
results from that 4-year period to forecast 3 future years of
implementation over a 3-year period in the future, resulting in an
estimate of about 2,815 hydraulic fracturing operations on Federal and
Indian lands per year.
For the annual estimate of completions using hydraulic fracturing,
the BLM uses the 3-year average of the implementation years within each
state and reservation. Recognizing the dip in well completions on
Federal lands in FY 2013, and recognizing that previous levels of
activity were higher, the BLM also calculated costs using the FY 2012
level of activity on Federal lands, prior to the FY 2013 decrease, and
presents that estimate as an upper bound of potential costs.
The BLM expects that operators are already in compliance with many
of the rule's requirements as a matter of company practice or standard
industry practice (described in the Economic Analysis), or to meet
state regulations (described in the Economic Analysis) or Federal
regulations (described in the Economic Analysis). Where the rule's
requirements are consistent with industry guidance, state regulations,
or Federal regulations, the BLM considered the applicability of the
requirement to be 0 percent and the incremental impact to be zero. We
consider partial applicability in areas and in situations where the
operator is expected to comply voluntarily, for example, when a
requirement costs less than the alternative.

Measuring the Incremental Costs

Application Requirement: The operator must submit an application to
conduct a hydraulic fracturing operation with the APD or an NOI when it
plans to hydraulically fracture a well for which it has:
Not yet submitted an APD as of the effective date of this
rule;
Submitted an APD, but the APD has yet to be approved as of
the effective date of this rule;
An approved APD or APD extension on the effective date of
this rule, drilling did not begin until after the effective date, and
does not conduct

[[Page 16196]]

hydraulic fracturing within 90 days after the effective date;
Started (but does not complete) drilling before the
effective date and does not conduct hydraulic fracturing within 90 days
after the effective date;
Completed drilling 180 days prior to the effective date,
and does not conduct hydraulic fracturing within 90 days after the
effective date; or
Completed drilling 180 or more days prior to the effective
date.
The operator may also submit an application for a group of wells as
part of an MHFP, thus reducing the number of potential applications.
This is a new requirement and poses an incremental burden to the
operator and the BLM. The information required in the application
should be readily available or known to the operator. The information
should not require any additional information gathering. An MHFP will
allow for efficiencies in submission and review.
The BLM expects there to be fewer applications than there are
hydraulic fracturing operations, because of the option to make one
submission for a group of wells, a process which is designed to achieve
additional efficiencies.
The BLM estimates the applicability of this requirement based on
the number of well completions using hydraulic fracturing that we
expect to occur. Since the BLM assumes that every hydraulic fracturing
operation will require an application, our estimate is inclusive of all
instances described in the first paragraph of this section (and
particularly in bullets 3 through 6) where an operator would be
required to submit an application to conduct hydraulic fracturing.
The data are as follows:
(a) Applicability of requirement = 100 percent of operations.
Although the BLM allows for the operator to submit a single NOI
covering a group of wells, it is uncertain whether the operator will
prefer that method over submitting an application with the APD. For the
purpose of this analysis, the BLM assumes that the operator will submit
an application for a single well, especially in the near-term future.
(b) Cost per application = $643. The cost per application includes
the operator burden and the BLM burden. For both burdens, the BLM
estimates the compliance or review hours and the respective wage. The
compliance cost for the operator is estimated to be about $496 per
application (calculated as 8 hours at about $61.99 per hour). The
review cost for the BLM is estimated to be about $147 per application
(calculated as 4 hours at about $36.66 per hour).\15\ Some commenters
stated that the additional informational requirements would cause
additional delays in the processing of APDs and thus constitute an
opportunity cost on the operator. This argument is not supported. The
supporting statement for the Paperwork Reduction Act estimates only 4
hours of additional review time for the BLM to review this information.
This does not present a measureable delay in processing time, and no
revisions were made to the cost estimate on that basis.
---------------------------------------------------------------------------

\15\ The cost formulation for administrative requirements is
detailed in the supporting statement for the Paperwork Reduction
Act.
---------------------------------------------------------------------------

Usable Water Requirement: The operator must isolate all usable
water and other mineral-bearing formations and protect them from
contamination. Usable water means generally those waters containing up
to 10,000 ppm of TDS. Usable water includes, but is not limited to: (i)
Underground water that meets the definition of ``underground source of
drinking water'' as defined at 40 CFR 144.3; (ii) Underground sources
of drinking water under the law of the state (for Federal lands) or
tribe (for Indian lands); and (iii) Water in zones designated by the
state (for Federal lands) or tribe (for Indian lands) as requiring
isolation or protection from hydraulic fracturing operations.
The following geologic zones are deemed not to contain usable
water:
(i) Zones from which an operator is authorized to produce
hydrocarbons provided that the operator has obtained all other
authorizations required by the EPA, the State (for Federal lands), or
the tribe (for Indian lands) to conduct hydraulic fracturing operations
in the specific zone;
(ii) Zones designated as exempted aquifers under 40 CFR 144.7; and
(iii) Zones that do not meet the definition of underground source
of drinking water at 40 CFR 144.3 which the state (for Federal lands)
or the tribe (for Indian lands) has designated as exempt from any
requirement to be isolated or protected from hydraulic fracturing
operations.
This requirement does not pose an incremental cost. The term usable
water is defined in a manner consistent with existing BLM requirements
in Onshore Oil and Gas Order No. 2, Drilling Operations on Federal and
Indian Oil and gas leases (53 FR 46798) (Onshore Order 2). Onshore
Order 2 section III.B. requires casing and cement to ``protect and/or
isolate all usable water zones.'' Onshore Order 2 defines ``isolate''
as ``using cement to protect, separate, or segregate usable water and
mineral resources'' (section II.I.) and ``usable water'' as ``generally
those waters containing up to 10,000 ppm of total dissolved solids''
(section II.Y.). Onshore Order 2 has been in effect since 1988;
therefore, the requirement to protect and/or isolate usable water
generally containing up to 10,000 ppm of TDS has been in effect since
that time. This rule corrects the inconsistency between the definition
in Onshore Order 2 (the definition in effect) and the definition in the
existing 43 CFR 3162.5-2(d). The definition in the CFR, of a 5,000 ppm
standard, was superseded by the Onshore Order 2 definition in 1998.

(a) Applicability of requirement = 0 percent of operations
(b) Incremental cost per requirement = $0

Cement Monitoring Requirement: During cementing operations on any
casing used to isolate usable water zones, the operator must monitor
and record the flow rate, density, and pump pressure and submit a
cement operation monitoring report, including this information, to the
authorized officer prior to commencing hydraulic fracturing operations.
For wells drilled prior to the effective date of the rule, the operator
is required to provide documentation that demonstrates that the well is
adequately cemented.
This requirement does not pose an incremental cost. API Guidance
Document HF1 stresses the importance of using data from reports, logs,
and tests to evaluate the quality of a cement job, including drilling
reports, drilling fluid reports, cement design and related laboratory
reports, etc. Based on this information and our observations of field
operations, the BLM believes that operators monitor cementing
operations as a matter of practice and can easily provide this
information to the authorized officer prior to conducting hydraulic
fracturing. The administrative burden of providing this information to
the BLM is contained in the application requirement.

(a) Applicability of requirement = 0 percent of operations
(b) Incremental cost per requirement = $0

Surface Casing Requirements: The operator must observe cement
returns to the surface and document any indications of inadequate
cement (such as, but not limited to, lost returns, cement channeling,
gas cut mud, failure of equipment, or fallback from the surface
exceeding 10 percent of surface casing setting depth, or 200 feet,
whichever is less). If there are indications of inadequate cement, then

[[Page 16197]]

the operator must determine the top of the cement with a CEL,
temperature log, or other method or device approved by the authorized
officer.
This requirement does not pose an incremental cost. Onshore Order 2
requires the operator to return cement to the surface (section
II.B.1.c.). Documenting indications of adequate cement and taking
corrective action are necessary responses when such issues arise.

(a) Applicability of requirement = 0 percent of operations
(b) Incremental cost per requirement = $0

CEL on Intermediate Casing that Protects Usable Water: If the
operator does not cement the intermediate casing string to surface and
the intermediate casing is used to isolate usable water, then the
operator must run a CEL to demonstrate that there is at least 200 feet
of adequately bonded cement between the zone to be hydraulically
fractured and the deepest usable water zone.
This requirement might pose an additional burden to the operator.
API Guidance Document HF1 stresses the importance of using data from
reports, logs, and tests to evaluate the quality of a cement job.
According to the guidance, well logging is a common practice of
operators and may be conducted multiple times while drilling a well.
``Well logs are critical data gathering tools used in formation
evaluation, well design, and construction.'' \16\ A cement bond log
``measures the presence of cement and the quality of the cement bond or
seal between the casing and the formation.'' \17\ Logs are important in
``determining that the well drilling construction is adequate and
achieves the desired design objectives.'' \18\ It is industry practice
to run logs on the production casing of wells. For the intermediate
casing, if cement is not circulated to the surface, operators may run a
CEL or other diagnostic tools to determine the adequacy of the cement
integrity and that the cement reached the desired height (above any
exposed USDW or any hydrocarbon bearing zone). State requirements of
conditions of the drilling permit may also necessitate the running of
logs on the intermediate casing.
---------------------------------------------------------------------------

\16\ Ibid, p. 8.
\17\ Ibid, p. 9.
\18\ Ibid, p. 10.
---------------------------------------------------------------------------

Generally, the BLM expects that the operator would log the
intermediate casing to ensure that the well was constructed according
to design. Logging the casing may also be warranted if the operator
plans to hang a production liner off of the intermediate casing, if the
proposed fracturing is through the intermediate casing, for hole
stability, for isolation through salt zones, or for isolation through
disposal zones.
Some states require logging of the intermediate casing through
regulation in a manner that is consistent with this rule. North Dakota
requires a CBL on the intermediate casing; Colorado requires a CBL if
the operator uses a production liner; and Texas specifies that the
operator must identify the top of cement (with a CBL or temperature
log) if it does not cement to the surface. California and Wyoming may
require it in certain circumstances. Additionally, the BLM and states
may require operators to log the intermediate casing as a condition of
approval if, for example, any of the conditions in the previous
paragraph apply. Industry guidance states that operators may run a CBL
and/or other diagnostic tools to determine the adequacy of the cement
integrity and that the cement reached the desired height.
The rule requires that the operator demonstrate that there is at
least 200 feet of adequately bonded cement between the zone to be
hydraulically fractured and the deepest usable water zone. When the
operator does not circulate cement to the surface, it will most often
comply with this requirement by running a CEL on the production casing
(when the operator is conducting hydraulic fracturing through the
production string). That process is described later. However, if the
operator plans to conduct the fracturing operation through a production
liner that is hung from the intermediate casing, then it must either
circulate the cement behind the intermediate string to surface or run a
CEL on the intermediate casing string. Although we believe that this
requirement is consistent with prudent operations, the intent of the
industry guidance, other state regulations, and conditions of approval
that the BLM generally places on APDs where the operator uses a
production liner hung from the intermediate casing, we recognize that,
in some cases, the rule would compel the operator to run a CEL when it
would not have done so otherwise.
The BLM does not have credible data on the prevalence of voluntary
compliance or the prevalence of CEL requirements as conditions of
approval. The BLM assumes that the rule will compel new action for all
operations in states without existing regulations requiring a CEL of
the intermediate casing. The BLM also recognizes that, as a result of
this assumption, the cost estimates will be overstated.
(a) Applicability of requirement = 0 percent of operations in ND
and CO; 2.5 percent in TX ; and 5 percent in other states. Based on
field experience, the BLM anticipates that only about 5 percent of
wells have intermediate casing to protect usable water.
(b) Incremental cost per requirement = $111,200. After the operator
cements the intermediate casing, it must wait a number of hours for the
cement to harden before commencing drilling operations. After that
time, the operator will pressure test the casing, drill out, and
perform a leak-off test. The BLM received some comments indicating that
a CEL test necessitates that the cement harden for 72 hours. These
comments do not take into consideration the time that the operator must
wait to perform other well tests. The BLM also notes that operators
generally use additives to speed up the hardening of cement behind
intermediate casing. For the purpose of our analysis, the BLM considers
only the additional wait time required for the CEL, accounting for 48
hours of additional time at a cost of $1,900 per hour. The cost for a
CEL on the intermediate casing includes the test ($20,000) and the cost
of maintaining idle drilling equipment on-site ($91,200). The BLM
believes that 48 hours is the upper bound of the potential cost. In
addition, the operator could potentially avoid delays in part or
entirely by running the CEL at some point while drilling the production
casing.
CEL on Production Casing that Protects Usable Water: If the
operator does not cement the production casing string to the surface,
then the operator must run a cement evaluation log to demonstrate that
there is at least 200 feet of adequately-bonded cement between the zone
to be hydraulically fractured and the deepest usable water zone.
This requirement does not pose an incremental cost. API Guidance
Document HF1 indicates that operators run a log to evaluate the quality
of the cement bond on the production casing as a matter of industry
practice. This is consistent with observations of field operations.
Colorado and North Dakota require a CBL in their regulations. Texas
specifies that the operator must identify the top of cement (with a CBL
or temperature log) if it does not cement to the surface. California
and Wyoming may require it under certain circumstances. In states that
do not specify a requirement in their regulations, the BLM still
expects that

[[Page 16198]]

the operator to run a CEL as a matter of practice.

(a) Applicability of requirement = 0 percent of operations
(b) Incremental cost per requirement = $0

Corrective Action Requirement: On all casing strings where the
operator cements to the surface, the operator must document any
indications of inadequate cement (such as, but not limited to, lost
returns, cement channeling, gas cut mud, failure of equipment, or
fallback from the surface exceeding 10 percent of surface casing
setting depth or 200 feet, whichever is less). If there are indications
of inadequate cement, then the operator must:
Notify the authorized officer within 24 hours of
discovering the inadequate cement;
Submit an NOI to the authorized officer requesting
approval of a plan to perform remedial action to achieve adequate
cement. In emergencies or in situations of an immediate nature that may
result in unnecessary delays, the operator may request oral approval
from the authorized officer for actions to be undertaken to remediate
the cement and follow-up with a written notice afterwards;
Verify that the remedial action was successful with a CEL
or other method approved in advance by the authorized officer; and
Submit a subsequent report for the remedial action
including a signed certification that the operator corrected the
inadequate cement job in accordance with the approved plan with the
results from the CEL or other approved test.
This requirement poses an administrative burden, but not an
operational burden. The BLM and many state regulations and requirements
have established protocol for remedial actions in the event of
inadequate cementing, which require operators to remediate and/or take
action as directed by the regulatory authority. For example, Onshore
Order 2 requires that operators perform remedial cementing if cement is
not circulated back to the surface for the surface casing (section
III.B.1.c.). Onshore Order 2 also requires an additional pressure test
and/or remedial action as specified by the authorized officer if a
pressure test indicates that casing strings do not meet minimum
standards (section III.B.1.h.). The BLM believes that this requirement
will impose an administrative burden on the operator who observes
indications of inadequate cementing, but not an operational burden. In
the supplemental proposed rule, the BLM had specified that the operator
would have to run a CEL to demonstrate that the remedial action was
successful, but the final rule's requirement is that the operator may
use a CEL or other approved test, presumably a temperature log, that
would not result in delays.
(a) Applicability of requirement = 3 percent of operations. The
number of wells where there is an indication that the initial cement
jobs require repairs is generally believed to be between 1 percent and
5 percent.\19\ The BLM uses the midpoint of the range, or 3 percent,
and applies it to the number of newly drilled wells for the activity
data.
---------------------------------------------------------------------------

\19\ Percent range cited by George King, a petroleum engineer
for Apache Corporation (Behr, P. (October 1, 2012). Safety of shale
gas wells is up to the states--and the `cement job'. EnergyWire).
That range is consistent with a survey of enforcement actions
conducted by the Energy Institute (Groat, C. & Grimshaw, T.
(February 2012). Fact-based regulation for environmental protection
in shale gas development. The Energy Institute, p. 16).
---------------------------------------------------------------------------

(b) Cost per response = $643. Burden includes the operator burden
and the BLM burden. The compliance cost for the operator is estimated
to be about $496 per application (calculated as 8 hours at about $61.99
per hour). The review cost for the BLM is estimated to be about $147
per application (calculated as 4 hours at about $36.66 per hour).
Mechanical Integrity Test Requirement: If hydraulic fracturing
through the casing is proposed, the operator must test the casing to
not less than the maximum anticipated surface pressure that will be
applied during the hydraulic fracturing process. If hydraulic
fracturing through a fracturing string is proposed, then the operator
must test the fracturing string to not less than the maximum
anticipated surface pressure minus the annulus pressure applied between
the fracturing string and the production or intermediate casing.
This requirement does not pose an incremental cost. Industry
guidance and state regulations are consistent with this requirement.
Industry guidance on hydraulic fracturing states that the production
casing of a well should be pressure tested prior to completion. The BLM
also reviewed state regulations in California, Colorado, Montana, New
Mexico, North Dakota, Oklahoma, Texas, Utah, and Wyoming. From FY 2010
to FY 2013, the number of well completions on Federal and Indian lands
in those states accounted for 99.3 percent of the total well
completions on Federal and Indian lands nationwide. The state
regulations in those states either require pressure tests on all casing
strings or on the casing strings through which the completion operation
will occur.

(a) Applicability of requirement = 0 percent of operations
(b) Incremental cost per requirement = $0

Monitor Annulus Pressures and Reporting Requirement: During the
operation, the operator must continuously monitor and record the
annulus pressures at the bradenhead and between any intermediate
casings and the production casing. The operator must submit a
continuous record of all annuli pressure during the fracturing
operation in the subsequent report. If during any hydraulic fracturing
operation any annulus pressure increases by more than 500 psi as
compared to the pressure immediately preceding the stimulation, the
operator must take immediate corrective action and orally notify the
authorized officer as soon as practical, but no later than 24 hours
following the incident. Within 30 days after the hydraulic fracturing
operations are completed, the operator must submit a report containing
all details pertaining to the incident, including corrective actions
taken, as part of a subsequent report.
This requirement does not pose an incremental cost. API Guidance
Document HF1 says that if the annular space is not cemented to the
surface, then operators should monitor pressures in the annulus between
the production casing and the intermediate casing. ``Pressure is
normally measured at the pump and in the pipe that connects the pump to
the wellhead. If the annulus between the production casing and the
intermediate casing has not been cemented to the surface, the pressure
in the annular space should be monitored and controlled. Pressure
behavior throughout the hydraulic fracture treatment should be
monitored so that any unexplained deviation from the pretreatment
design can be immediately detected and analyzed before operations
continue . . . Unexpected or unusual pressure behavior during the
hydraulic fracturing process could indicate some type of problem.''
\20\ Based on this information and our observations of field
operations, we believe that operators monitor annulus pressures during
hydraulic fracturing operations as a matter of practice and can easily
provide this information to the authorized officer after conducting
hydraulic fracturing. The administrative burden of providing this
information to

[[Page 16199]]

the BLM is contained in the post-fracturing reporting requirements.
---------------------------------------------------------------------------

\20\ API Guidance Document HF1, p. 21.

(a) Applicability of requirement = 0 percent of operations
(b) Incremental cost per requirement = $0

Storage Tank Requirement: The operator must manage recovered fluid
in ``rigid enclosed, covered or netted and screened above-ground
tanks.'' The tanks may be vented, unless Federal law, or state
regulations (on Federal lands) or tribal regulations (on Indian lands)
require vapor recovery or closed-loop systems. The tanks are also
limited in size to 500 bbl of capacity or less. Under certain limited
circumstances, the operator may seek approval to use a lined pit with a
leak detection system.
This is a new requirement and could pose an incremental burden to
the operator depending on the size and specifics of the operation, and
whether the management of recovered fluids in tanks is already required
by the state or tribe. Although API Guidance Document HF2 does not
specify the use of rigid above-ground tanks to manage recovered fluids
from hydraulic fracturing operations, our observations of field
operations indicate that the use of rigid above-ground tanks for
receiving recovered fluids is very common, regardless of the state's
requirements. These tanks are commonly referred to as ``frac tanks,''
constructed of steel, and have a holding capacity of up to 21,000
gallons, or 500 bbl, of fluid. The tanks are generally limited to that
capacity or size due to their transportability on surface roads to and
from a well site. Enclosed tanks are generally provided with anti-burst
air vents to vent pressurized gas to prevent safety hazards or they may
be connected to a system that collects the pressurized gas for sale or
combustion. Some tanks of the same size specifications, steel
construction, and rigidity, may have open tops that allow the operator
to more easily inspect the flowback visually, pump out fluids, and
vacuum out the proppants.
The rule prohibits the use of other larger-volume above-ground
semi-rigid tanks (with a capacity of up to 40,000 bbl) for managing
recovered fluids. These tanks are ``semi-rigid,'' because they are
constructed of steel sections and assembled on-site. These tanks are
rarely used for managing flowback directly and are more often used for
holding fresh water before the hydraulic fracturing operation and
sometimes for holding water after it has been separated and treated
after hydraulic fracturing operations.
The use of rigid steel tanks to manage recovered fluids tends to
vary by operator and the regions in which they operate. These tanks are
particularly prevalent in the Eastern U.S. and are being incorporated
into model standards for shale development.\21\ Among Western states,
where development on Federal and Indian lands is most prevalent, New
Mexico and Texas generally require storage tanks, but allow operators
to apply for permits to use pits. Colorado requires storage tanks in
Surface Water Supply Areas.\22\
---------------------------------------------------------------------------

\21\ Center for Sustainable Shale Development Web site. Accessed
on March 29, 2013, http://037186e.netsolhost.com/site/performance-standards/.
\22\ A map of designated Surface Water Supply Areas, accessed on
May 27, 2014, is available at http://cogcc.state.co.us/rulemaking/FinalDraftRules/CDPHE317B_Map.pdf.
---------------------------------------------------------------------------

Our observations of field operations in the Western states lend
evidence to the widespread use of steel rigid tanks to manage recovered
fluids from hydraulic fracturing operations in those states. Further,
by examining the expected volume of recovered fluids, and the relative
costs of using storage tanks versus a pit for these volumes, the BLM
believes that the use of storage tanks often will cost less than pits
for operations on Federal and Indian lands as discussed in more detail
below.
In the supplemental proposed rule, the BLM solicited comment
concerning the incremental costs of a requirement to manage recovered
fluids with tanks instead of lined pits.
One commenter supported the broad use of steel tanks, but
recommended that the BLM not require closed-loop systems, citing
concerns about costs, the pressurization of gas, and ability to make
visual inspections of the fluid, the advantage of maintaining
flexibility depending on the operations or conditions, and the EPA's
regulations covering emissions from storage tanks. It also supported
the option of potentially using larger volume atmospheric tanks and
lined impoundments (or pits), both with secondary containment and leak
detection systems, for large volume hydraulic fracturing
operations.\23\
---------------------------------------------------------------------------

\23\ The comment letter from ConocoPhillips, dated August 22,
2013, is available in the rulemaking docket at www.regulations.gov.
---------------------------------------------------------------------------

The commenter estimated the costs of steel tanks, semi-rigid tanks,
and pits over a 5-year period (using a present discounted value
approach and a 10 percent discount rate) for multiple operations, with
a cumulative total capacity of about 250,000 bbl. It estimated the
costs of an engineered impoundment to be $2.3 million, semi-rigid tanks
to be $2.42 million, and steel tanks to be $23 million, all over a 5-
year period (see Table 5).

Table 5--Commenter Cost Estimates for Managing Recovered Fluids
----------------------------------------------------------------------------------------------------------------
Engineered
impoundment Semi-rigid steel tanks Steel tanks
----------------------------------------------------------------------------------------------------------------
Number of impoundments or tanks......... 1 6......................... 500
Impoundment or tank capacity (bbl)...... 250,000 40,000.................... 500
Total capacity (bbl).................... 250,000 240,000................... 250,000
Initial construction or set up-take down $2,970,000 $51,000 x 6 = $306,000.... n/a
cost.
Annual operating or Rental Cost......... $20,000 $132,000 x 6 = $792,000 $16,425 x 500 = $8,212,500
(assumes $11,000 monthly (assumes $45 daily rental
rental fee). fee)
5-Year net present value (NPV) (at 10%). $2,300,000 $2,420,000................ $23,000,000
----------------------------------------------------------------------------------------------------------------

In reviewing these data, it would be inappropriate to conclude
simply that using steel tanks would cost 10 times more than a pit. The
commenter did not specify the number of hydraulic fracturing operations
that a pit, or deployment of semi-rigid tanks or rigid steel tanks,
might service over the 5-year period. The BLM expects that while each
method could service the same number of hydraulic fracturing operations
at the same general location, pits are limited to a single geographic
location, but tanks are portable and can be deployed at different
geographic locations over the 5-year period, thereby servicing a larger
number of operations

[[Page 16200]]

and reducing the per-operation cost of using tanks over that time
period.
We also note that the transportability and severability of 500
steel tanks allow an operator to service multiple operations in
different locations at the same time. For example, 500 steel tanks
could service 5 large operations (of 100 steel tanks each) concurrently
in different geographic locations.
The BLM received other comments about the incremental costs of
requiring storage tanks. A commenter's analysis suggested a tank
requirement would pose an incremental cost of $5,500 per operation or
$19.6 million for the industry per year. Another commenter suggested
that an open pit costs $447,000 and a closed-loop system costs $267,000
(an $180,000 cost advantage).
The BLM did not receive comments on the prevalence of voluntary
compliance among operations or across operations, though the first
commenter supported the broad use of storage tanks and the potential
option to use larger tanks or pits. The BLM would generally expect that
an operator would choose to use steel tanks voluntarily (when otherwise
not compelled to do so by regulation, condition of approval,
environmental consideration, or company practice) in situations where
tanks would cost the same as or less than pits, and this may be largely
dependent on the volume of recovered fluids expected.
The amount of water used to hydraulically fracture a well and the
amount of fluid recovered from the operations vary depending on the
formation and the operation itself. The BLM examined data extracted
from FracFocus \24\ for wells completed in 2013, shown in Figure 3. The
data show that the average volume of water used for the hydraulic
fracturing operations was 60,279 bbl (or more than 2.5 million
gallons). The BLM used the number of well completions on Federal and
Indian lands from FY 2010-FY 2013 to develop a weighted average for
hydraulic fracturing operations on Federal and Indian lands. Shown in
Figure 3, the BLM would expect the average volume of water used for
hydraulic fracturing operations on Federal and Indian lands to be
24,385 bbl (or more than 1 million gallons).
---------------------------------------------------------------------------

\24\ Skytruth.org, ``2013 Reports Data,'' accessed on November
20, 2014.

Figure 3--Average Water Used in Hydraulic Fracturing Operations, 2013, and Estimated Recovered Fluids
----------------------------------------------------------------------------------------------------------------
Average Range of recovered fluids
volume of (bbl)
water used -------------------------------
State (bbl) (data
extracted from Low (15%) High (40%)
FracFocus)
----------------------------------------------------------------------------------------------------------------
Alaska.......................................................... 2,343 351 937
Arkansas........................................................ 203,648 30,547 81,459
California...................................................... 2,375 356 950
Colorado........................................................ 52,013 7,802 20,805
Kansas.......................................................... 35,373 5,306 14,149
Louisiana....................................................... 89,333 13,400 35,733
Mississippi..................................................... 111,500 16,725 44,600
Montana......................................................... 50,058 7,509 20,023
New Mexico...................................................... 19,110 2,866 7,644
North Dakota.................................................... 56,535 8,480 22,614
Ohio............................................................ 107,855 16,178 43,142
Oklahoma........................................................ 78,600 11,790 31,440
Pennsylvania.................................................... 128,122 19,218 51,249
South Dakota.................................................... 61,227 9,184 24,491
Texas........................................................... 61,412 9,212 24,565
Utah............................................................ 8,885 1,333 3,554
Virginia........................................................ 706 106 282
Washington...................................................... 23,264 3,490 9,306
West Virginia................................................... 143,873 21,581 57,549
Wyoming......................................................... 17,397 2,610 6,959
Weighted Average (based on the operations in the dataset)....... 60,278 9,042 24,111
Weighted Average (based on average volume of the operations by 24,385 3,658 9,754
state and the distribution of operations on Federal and Indian
lands).........................................................
----------------------------------------------------------------------------------------------------------------
Note: There were no data in the FracFocus extraction for Alabama and Nevada, which had a total of only seven
well completions from FY 2010-FY 2013.

The data extracted from FracFocus do not show the amount of fluid
recovered from the operations. The EPA indicates that this amount may
range widely from 15 percent to 80 percent of the original amount
injected, depending on the site.\25\ Halliburton lists ranges for fluid
recovery for popular producing areas that are more modest, as follows:
\26\
---------------------------------------------------------------------------

\25\ EPA Web site, ``Hydraulic Fracturing Research Study,''
accessed on November 20, 2014 at http://www.epa.gov/ogwdw000/uic/pdfs/hfresearchstudyfs.pdf.
\26\ Halliburton, ``Produced and Flowback Water Recycling and
Reuse: Economics, Limitations, and Technology,'' accessed on
November 25, 2014 at http://www.halliburton.com/public/multichem/contents/Papers_and_Articles/web/Feb-2014-Oil-Gas-Facilities-Article.pdf.

Bakken: 15-40 percent
Eagle Ford: < 15 percent
Permian Basin: 20-40 percent
Marcellus: 10-40 percent
Denver-Julesburg: 15-30 percent

Figure 3 also provides the range of volumes expected to be
recovered from hydraulic fracturing operations, which is estimated to
range from 3,658 bbl (10 percent) to 9,754 bbl (40 percent) on average
based on the data.
The BLM contacted service providers of tanks used for the
management of fluids from hydraulic fracturing operations to better
examine the per-operation incremental costs of using rigid steel tanks
instead of a pit. We estimated the baseline cost of

[[Page 16201]]

constructing and operating a pit based on the first commenter's data.
We estimated the 5-year NPV (using a discounted rate of 7 percent) of a
pit to be about $2,460,000, generating an annualized cost of about
$92,000 and, finally, a per-operation cost of about $98,400, assuming a
pit could service 5 operations per year and 25 operations over a 5-year
period.\27\ Using the BLM's Automated Fluid Minerals Support System
(AFMSS) well-completion data from January 2008 to December 2012, we
found that operators completed an average of 5.067 wells in a case.
---------------------------------------------------------------------------

\27\ We attempted to replicate the commenter's derivation of the
5-Year NPV (at 10%) for the engineered impoundment in order to
estimate an annualized value for a pit with a 7% discount rate. We
roughly generated the commenter's value by assigning one-third of
the capital costs to initial construction (year 0) and two-thirds of
the capital costs to the take down costs (year 5).
---------------------------------------------------------------------------

In Table 2, we provide the general engineering costs for rigid
steel tanks provided by service companies and then we calculate per-
operation job costs based on the capacity number of potential job
capacities. In addition, for each job capacity, we estimate the cost of
the tank deployment for that operation and the incremental cost per
operation when employed instead of a pit. Other assumptions include
that the transportation to and from the site for steel tanks will take
4 hours, and that the rental period is either 14 or 21 days.

Table 2--General Engineering Costs for Steel Rigid Tanks per Operation
and Incremental Costs, by Job Capacity
------------------------------------------------------------------------

------------------------------------------------------------------------
Engineering Costs
------------------------------------------------------------------------
Job duration (days)..................... 14 21
Tank capacity (bbl)..................... .............. 500
Transportation to site ($/hr/tank)...... .............. $120
Rental ($/day/tank)..................... .............. $40
Transportation from site ($/hr/tank).... .............. $120
------------------------------------------------------------------------
Job Capacity (10,000 bbl)
------------------------------------------------------------------------
Tanks required.......................... 20 20
Costs per operation..................... $30,400 $36,000
Incremental cost instead of a pit....... -$68,000 -$62,400
------------------------------------------------------------------------
Job Capacity (30,000 bbl)
------------------------------------------------------------------------
Tanks required.......................... 60 60
Costs per operation..................... $91,200 $108,000
Incremental cost instead of a pit....... -$7,200 $9,600
------------------------------------------------------------------------
Job Capacity (50,000 bbl)
------------------------------------------------------------------------
Tanks required.......................... 100 100
Costs per operation..................... $152,000 $180,000
Incremental cost instead of a pit....... $53,600 $81,600
------------------------------------------------------------------------

According to the available information, rigid steel tanks are less
costly than pits on smaller and medium volume jobs lasting 14 days
(e.g., $68,000 and $7,200 advantage for jobs with capacities of 10,000
and 30,000 bbl, respectively) and likely to be more costly than pits
for higher-volume jobs (e.g., $53,600 disadvantage for jobs with a
capacity of 50,000 bbl). For jobs lasting 21 days, rigid steel tanks
are likely to be less costly than pits on jobs up to the job capacity
threshold described above.
Given the assumptions, and for a job lasting 14 days, the point at
which the cost of using tanks and the cost of using a pit are roughly
equal is when the job capacity is 32,368 bbl. This means that steel
tanks would cost less for jobs where the volume of recovered fluids is
less than 32,368 bbl and pits would cost less for jobs where the volume
of recovered fluids is greater than 32,368 bbl. For a job lasting 21
days, the point at which the cost of using tanks and the cost of using
a pit are roughly equal is when the job capacity is 27,333 bbl.
The BLM derived these thresholds using the following progression:

(1) Per-operation cost of pit = Cost of steel tanks for an operation
(2) Per-operation cost of pit = [Cost of tank transport to and from
site + Cost of tank rental ]
(3) Per-operation cost of pit =
2 * [(Cost of tank transport $/hr/tank) * (hours) * (Job capacity/tank
capacity)]
+ [(Cost of rental $/day/tank) * (days) * (Job capacity/tank capacity)]
(4) [Per-operation cost of pit/3.04 ] = Job capacity bbl; when the job
duration is 14 days; or
[Per-operation cost of pit/3.60 ] = Job capacity bbl; when the job
duration is 21 days
(5) Job capacity bbl = 32,368; when the job duration is 14 days; or
Job capacity bbl = 27,333; when the job duration is 21 days

To estimate voluntary compliance, we looked at the percent of
operations (in the data extracted from FracFocus) where the job
capacity (measured as the 40 percent of the water used) was less than
the thresholds of 32,368 bbl and 27,333 bbl.
Where the job capacity exceeded the threshold, the BLM assumed that
the operators would not have voluntarily used storage tanks. We then
calculated the average job capacity for operations above this threshold
based on the distribution of operations on Federal and Indian lands. We
estimate that the average job capacity for operations exceeding the
thresholds is either 47,575 or 55,631 bbl. See Table 5C. We note again
that operators may choose to use steel tanks irrespective of costs, for
example in adherence to condition of approvals, environmental
considerations, company practice, etc.
Based on that average job capacity, we then calculated an average
incremental cost of using tanks instead of a pit for only those
operations where we do not estimate that the operator will

[[Page 16202]]

voluntarily comply. Assuming job durations lasting 14 days, we estimate
the average incremental cost to be $71,840 per operation that exceeds
the threshold of 32,368 bbl. Assuming job durations last 21 days, we
estimate the average incremental cost to be $74,400 per operation that
exceeds the threshold of 27,333 bbl. Due to the variability of job
durations across the U.S., we use the average incremental cost to be
$74,400 per operation as a basis for the cost estimates, recognizing
that this is likely to both overestimate and constrain the potential
costs.

Table 5C--Estimated Voluntary Compliance of a Steel Tank Requirement and the Average Volume of Recovered Fluids
for Operations Where the Operator Is Not Expected to Voluntarily Comply
----------------------------------------------------------------------------------------------------------------
Job duration of 14 days Job duration of 21 days
---------------------------------------------------------------
Average Average
volume of volume of
recovered recovered
State Estimated fluids for Estimated fluids for
voluntary operations voluntary operations
compliance exceeding the compliance exceeding the
(%) threshold (%) threshold
(40% recovery (40% recovery
rate) rate)
----------------------------------------------------------------------------------------------------------------
Alaska.......................................... 100.0 0 100.0 0
Arkansas........................................ 2.9 83,926 2.9 83,926
California...................................... 100.0 0 100.0 0
Colorado........................................ 84.7 58,980 71.7 45,616
Kansas.......................................... 100.0 0 95.6 27,597
Louisiana....................................... 49.3 53,781 30.4 47,650
Mississippi..................................... 66.7 130,775 66.7 130,775
Montana......................................... 91.8 37,257 79.6 32,260
New Mexico...................................... 96.7 79,352 96.1 72,616
North Dakota.................................... 86.8 50,455 75.1 40,842
Ohio............................................ 0.0 43,142 0.0 43,142
Oklahoma........................................ 68.5 63,084 61.9 57,248
Pennsylvania.................................... 12.4 55,208 7.1 53,780
South Dakota.................................... 100.0 0 100.0 0
Texas........................................... 68.2 57,699 64.3 54,663
Utah............................................ 100.0 0 100.0 0
Virginia........................................ 100.0 0 100.0 0
Washington...................................... 100.0 0 100.0 0
West Virginia................................... 3.3 58,566 0.0 57,549
Wyoming......................................... 93.3 39,880 92.3 38,629
Weighted Average (based on distribution of 70.3 57,283 65.4 53,398
operations in FracFocus).......................
Weighted Average (based on distribution of 93.5 55,631 90.6 47,757
operations on Federal and Indian lands)........
----------------------------------------------------------------------------------------------------------------

With respect to the applicability of the requirement, we estimate
that the rule will have no impact in states with existing requirements
for use of tanks. We also assume that the rule will have no impact
where operators are expected to voluntarily comply with the use of
tanks regardless of the rule (the rates of assumed voluntary compliance
are in Table 5C). We assume that for all other states, the rule will
compel action on 100 percent of the operations, even though we expect
that operators are already in compliance with the rule as a matter of
voluntary practice.
(a) Applicability of requirement = 0 percent of operations in NM
and TX based on state regulations; 0 percent in AK, CA, SD, UT, based
on estimated voluntary compliance; 97.1 percent in AR, 28.3 percent in
CO, 4.4 percent in KS, 69.6 percent in LA, 33.3 percent in MS, 20.4
percent in MT, 24.9 percent in ND, 100 percent in OH, 38.1 percent in
OK, 92.9 percent in PA, and 7.7 percent in WY, based on estimated
voluntary compliance; 100 percent in AL and NV, based on lack of
validating data. We attribute the appropriate percentages to each tribe
based on geographic location.
(b) Incremental cost per operation = $74,400. This incremental cost
is only for those operations where the use of storage tanks is not
required by state regulations and where the operator is not expected to
use storage tanks voluntarily. Operations that are most likely to incur
this cost are in states where 0.8% of all oil and gas activity on
public lands occurs. Incremental average costs across all operations on
public and Indian lands are $5,544 (see Table 6A). Under the rule, the
operator may request approval to use a lined pit that is equipped with
a leak detection system. While Onshore Order 7 requires leak detection
systems for produced water disposal pits, which may be used on a long-
term basis, there has been no requirement for leak detection systems on
temporary pits until now. According to BLM engineers citing analogous
EPA data, the cost of equipping a pit with a leak detection system
might range from $2 to $9 per square foot, depending on the
sophistication of the system (EPA 2012, Field Demonstration of
Innovative Condition Assessment Technologies for Water Mains: Leak
Detection and Location). Assuming 2,000 feet of piping and that a
centralized pit might service 5 operations, the per-operation cost of
equipping a centralized pit with a leak detection system might be
between $800 and $3,600. Additional cost information for leak detection
systems is available in the EPA Notice of Proposed Rulemaking for
Liners and Leak Detection for Hazardous Waste and Land Disposal Units.
The notice suggests that costs of a leak detection system would be
about $6,100 for a half-acre pit and $6,520 for an acre pit. Again,
that cost could be spread across multiple hydraulic fracturing
operations and, assuming a pit services 5 completions, the per-
operation cost might be $1,200 to $1,300. However, according to the

[[Page 16203]]

specifications listed in Onshore Order 7, the BLM engineers also
believe that the costs of including a leak detection system could be
higher and generally comparable to using storage tanks.
The BLM examined an alternative approach to the final rule. That
alternative would have required the operator to manage recovered fluids
in a lined pit, at a minimum. The requirement to manage recovered
fluids in lined pits or storage tanks is consistent with almost all
existing state regulations in states where new oil and gas activity is
occurring on BLM-managed lands. The BLM examined regulations in nine
states where new drilling activity is most prevalent on Federal lands
and found that those states either have existing minimum requirements
for lined pits or storage tanks or that operators use lined pits or
tanks to ensure the protection of groundwater. One exception,
California, does not appear to have a statewide minimum requirement for
lined pits, but such requirements may be contained within rules
specific to particular fields within the state. Further, according to
Resources for the Future (RFF), Alabama, Arkansas, Kansas, Louisiana,
Mississippi, Pennsylvania, and South Dakota also have existing pit
liner requirements.\28\ Considering the low level of oil and gas
development on Federal lands in these states where lined pits are
permitted, the impact of this provision is likely to be very small. The
BLM does not have data on the pit-liner requirements on Indian lands or
the voluntary use of lined pits in general, as is recommended as a
minimum standard by industry guidance.\29\ The BLM estimated the unit
cost of lining a pit to be $6,000, using prices quoted by suppliers of
about $0.24 per square foot of lining. The amount of lining required
varies by well and the cost of lining depends on the thickness and
other properties that vary by the use of the pit.
---------------------------------------------------------------------------

\28\ The RFF findings cited are available on its Web site under
flowback/wastewater storage and disposal, accessed on May 27, 2014:
http://www.rff.org/centers/energy_economics_and_policy/Pages/Shale_Maps.aspx.
\29\ API, HF2.
---------------------------------------------------------------------------

(a) Applicability of requirement (alternative) = 0 percent of
operations in AL, AR, CO, KS, LA, MS, MT, ND, NM, OK, PA, SD, TX, UT,
WY; 20 percent in CA; 50 percent in AK, NV, OH, and Indian lands.
(b) Incremental cost per operation (alternative) = $6,000.
Post-Fracturing Reporting Requirement: The operator must submit
information to the BLM after the hydraulic fracturing operation in a
subsequent report. The operator must disclose the chemicals used to the
BLM, and may use FracFocus for that disclosure. The operator may
withhold formulations that are deemed to be a trade secret.
This is a new requirement and poses an incremental burden to the
operator and the BLM to review. The information required in the
application should be all readily available or known to the operator.
The information should not require any additional information
gathering. Unlike the application, which may be an MHFP for a group of
wells, the operator will submit a unique subsequent report for each
operation. The disclosure requirement is included in the post-fracture
report. The operator may post to FracFocus or submit the chemical
information directly to the BLM, and it may withhold trade secret
information by submitting an affidavit. The disclosure requirement only
poses an incremental burden to the operator in states that do not
already require disclosure to FracFocus. The BLM notes that Colorado,
Montana, North Dakota, Oklahoma, Texas, and Utah, require disclosure to
FracFocus already and so the Federal requirement would not pose an
incremental burden to those operations.
(a) Applicability of requirement = 100 percent of operations.
(b) Cost per requirement = $723. Burden includes the operator
burden ($558 per Subsequent Report (SR) Sundry) and the BLM burden
($165 per SR Sundry). We estimate that the operator will require 9
hours at about $61.99 per hour to comply with the SR Sundry and that
the BLM will require 4.5 hours at about $36.66 per hour to review the
SR Sundry. The bases for these estimates are explained in the
supporting statement for the Paperwork Reduction Act.
Variance Requests: The operator may submit a variance for BLM
approval.
Operators taking advantage of this provision will incur an
incremental cost. Previously, the BLM estimated that it might receive
variance requests on 10 percent of the applications, primarily because
of previously proposed requirement to run a CEL on the surface casing
and the type well provision. Since the final rule does not contain
those provisions, the BLM believes that it might receive fewer variance
requests. However, there is still the potential that operators will
request a variance (or approval) for the storage tank requirement or
for a CEL on the intermediate casing (e.g., the operator may request to
use a temperature log or other test).
(a) Applicability of requirement = 10 percent of operations.
(b) Cost per request = $643. Burden includes the operator burden
and the BLM burden. The compliance cost for the operator is estimated
to be about $496 per application (calculated as 8 hours at about $61.99
per hour). The review cost for the BLM is estimated to be about $147
per application (calculated as 4 hours at about $36.66 per hour).

Benefits Framework

The potential benefits of the rule are significant, but are more
challenging to monetize than the costs; however, the rule will
significantly reduce the risks associated with hydraulic fracturing
operations on Federal and Indian lands, particularly risks to surface
waters and usable groundwater. The operational requirements of the
final rule generally conform to industry guidance on hydraulic
fracturing and state regulations. The operational requirements should
ensure that hydraulic fracturing is conducted in a manner than
minimizes any environmental and health risks.
The use of storage tanks in lieu of pits reduces the potential risk
to surface and groundwater resources. The BLM expects that through this
rule, since it incorporates many of the best practices currently used
by companies to manage recovered fluid, will provide environmental
benefit and provide the best possible avoidance of surface and
groundwater spills and contamination. Pits require careful design,
construction (including fencing and netting), monitoring and
reclamation. Rigid steel tanks used for recovered fluids are typically
mounted on truck trailers or are transportable by truck. They require
space on a well pad. However, any leaks are readily detectable without
special equipment. As compared with pits, tanks better isolate
recovered fluids from contamination by surface sediments that might
increase the costs of recycling the fluids.
The tank requirement also specifies that where an operator uses an
``enclosed'' tank, the tank may be vented unless another Federal,
state, or tribal law or requirement requires a closed-loop system or
vapor recovery. Tanks that are not enclosed will need to be covered,
netted or screened to exclude wildlife. That is not a new requirement.
BLM has issued an instructional memorandum for authorized officers to
assure that pits, tanks, and similar structures are fully enclosed in
netting or screens to exclude wildlife. This requirement helps prevent
accidental

[[Page 16204]]

deaths of species protected under the Migratory Bird Treaty Act or
other laws.
The primary challenge in monetizing benefits lies in the
quantification of a baseline risk associated with specific operating
practices and in the measurement of the change in that risk that the
BLM can attribute to the rule's requirements. For example, the risk of
spills associated with the use of pits versus the risk of spills
associated with the use of storage tanks is unknown, though it is
generally recognized that tanks carry less risk onsite. In an initial
analysis for the proposed rule, we attempted to value the reduction in
risk, but we do not believe that the available information represented
modern hydraulic fracturing operations nor were we able to distinguish
between the risks posed by wells that were hydraulically fractured and
wells with conventional completion techniques.
Operators are required to notify the BLM when undesirable events
occur, but there are limitations in using the BLM data on undesirable
events for this analysis. Undesirable events may include accidents, or
accidental spills or releases of hydrocarbon fluids, produced water,
hydraulic fracturing flowback fluids, or other substances. Undesirable
events also include ``frack hits,'' which are unplanned surges of
pressurized fluids into other wells. These events have the potential to
adversely affect public lands, Indian lands, and other important
resources.
There are several limitations in using these data. First, the data
do not specify whether the undesirable events occur in conjunction with
or as a result of hydraulic fracturing operations. In addition, the
available data cannot be readily matched with particular provisions in
the rule. The data provide figures for the incidence of spills,
accidents, injuries, and other impacts on a well, but the pit liner
information is generally not specified in the incident reports for
spills or leaks. As such, there is difficulty in quantifying the level
of risk reduction that would be attributed to the regulations, even
though the regulations would most certainly reduce risk.
Although operators are required to remediate damage when it occurs,
there may be uncertainty about the true value or extent of any
potential damage or limitations in connecting an incident to an
operation. Even if the damage is internalized, and as long as the
compliance costs are less than the damage costs, the net benefit to
society would be less than if the incident was avoided, since resources
would have been unnecessarily dedicated to the remediation.
Damage, in general, is unknown, particularly when attempting to
generalize damage costs which may vary by expected magnitude and
reversibility of effects. Also, the valuation of the damage may also
take many and highly variable forms. For example, an undesirable
incident occurring during hydraulic fracturing might require the
remediation of surface or subsurface areas. The incident might also
require that the operator shut-in temporarily or plug the well before
it may produce all of the mineral resources. In this case, the operator
would lose revenue and society would not benefit from the produced
resources. Such would be the same for spills.
The following is an example of an event that occurred in 2012 when
a hydraulic fracturing operation on one Federal well affected another
Federal well. The incident occurred on November 20, 2012, in Lea
County, New Mexico.\30\ The fracture path of the first well intercepted
the fracture path of the second well, pushing produced fluids through
the second well and its associated equipment such as the separator and
an open top fiberglass tank. The open-top fiberglass tank overflowed
into an unlined firewall. The firewall was over-topped and fluids ran
into a pasture. The fluids also entered a second facility via flow
lines and over-topped an open fiberglass tank to overflow into an
unlined containment berm. The majority of fluids, 1,220 bbl consisting
primarily of fracturing fluids, were contained within unlined firewalls
and inside two 210-barrel open-topped fiberglass tanks. About 60 bbl of
oil ran into a pasture near the second well.
---------------------------------------------------------------------------

\30\ The Carlsbad Field Office submitted an Initial Report for
the major undesirable event, occurring on lease NMNM0631.
---------------------------------------------------------------------------

In order to control the event, the fracturing job had to be shut
in. The active wells in the area were also shut in. The surface damage
included less than 0.1 acre of pasture land, and the removal and
disposal of the material inside the two firewalls. Vacuum trucks picked
up all of the standing fluids. The impacted surface material was
removed for sampling, site delineation, and remediation.
This ``frack hit'' incident illustrates the difficulty in
estimating benefits. The environmental damage included potential
surface contamination and subsequent remediation efforts, and most of
the environmental damage appears to have been remediated by the
operator. Aside from the environmental damage, there were several
economic impacts, including the shutting-in of the impacted wells for a
period of time, wellbore damage to the second wells, potentially lost
fracturing stages, and unrecovered resources.
Since relative risk is unknown, the BLM provides a qualitative
discussion of benefits. Field experience tells us that the remediation
of a minor incident, such as the surface remediation after a minor
spill, might cost about $15,000 and range upwards. Remediation efforts
of larger spills are much more complicated and can reach the hundreds
of thousands of dollars. The remediation of a major incident will
likely be more complex. As with the example incident, there were
surface, possible subsurface impacts to multiple wells, and potentially
stranded resources (from lost fracturing stages of permanent plugging
of wells). The Federal Remediation Technologies Roundtable makes a
number of case studies available on its Web site (though none are
hydraulic fracturing incidents) concerning contamination to aquifers
where the remediation costs may be $1 million.

Discounted Present Value

There is a time dimension to estimates of potential costs and
benefits. While the incremental costs of the rule are likely to occur
within a comparatively short period of time, the incremental benefits
may continue into the future. The further in the future that the
benefits and costs are expected to occur, the smaller the present value
associated with the stream of costs and benefits.
For this analysis, we expect that the potential incremental costs
posed to an operation will occur within a short timeframe, starting
generally with the APD submission and ending with the subsequent
report. As such, we generally use undiscounted costs for the
requirements. However, in order to determine the incremental cost of
the storage tank requirement, we adjusted the 5-year data provided by a
commenter to annualize the costs of constructing and operating a pit
based on the net present value of costs using a 7 percent discount
rate.

Uncertainty

The costs and benefits provided in this analysis are estimates and
come with uncertainty. Generally, the primary sources of uncertainty
are:
Number of hydraulic fracturing operations on Federal and
Indian lands occurring in the future. The economic analysis describes
the method the BLM used to estimate operations that will occur in the
future. The BLM also considers an upper bound estimate which should
constrain the costs.

[[Page 16205]]

Delays and costs associated with the CEL on the
intermediate casing. Sources of uncertainty are: (1) The prevalence by
which the operator will run a log on the intermediate casing as a
matter of practice; and (2) The ways in which operators may run logs on
the intermediate casing while avoiding delays.
Storage tank costs. The BLM estimated voluntary compliance
based on the average volume of recovered fluids and a number of cost
assumptions, including the per-operation cost of a pit. In some areas,
field observations indicate that the use of storage tanks is higher
than the estimated voluntary compliance. As such, we believe the
compliance costs of this requirement are still likely to be
overestimated.
Benefits of specific provisions. The BLM is unable to
estimate the incremental benefits of the rule because the BLM is unable
to ascribe incremental benefits to the particular provisions of the
rule. Nonetheless, the rule's provisions are generally consistent with
best management practices of the industry at large and of several firms
within the industry.

Results: Total Costs of the Rule

The BLM estimates that the rule will impact 2,814 hydraulic
fracturing operations per year in the near-term on Federal and Indian
lands. The BLM estimates that the incremental cost of the rule on
Federal and Indian lands will be about $26 million per year. These
estimates are based on expectations about the future well completions
on Federal and Indian lands. In order to meet a $100 million per year
threshold, we estimate that the number of hydraulic fracturing
operations on Federal and Indian lands would have to be about 3.83
times higher than we anticipate, or over 10,775 operations per year.
The estimated per-operation compliance costs of about $11,400
represent about 0.13 to 0.21 percent of the cost of drilling a well.
The compliance costs, shown in Table 6A, were developed by dividing the
total costs of the rule by the number of hydraulic fracturing
operations expected to occur, per year. Because we believe that
operators would have undertaken some of the rule's requirements
voluntarily or as a result of state requirements, we expect that some
of the compliance costs will be borne by a relatively small number of
operations. This is particularly the case with respect to the
requirement to use rigid above-ground tanks, which we estimate to be
less costly than lined pits for operations with recovered fluids below
a certain volume. In those cases where fluid volumes exceed a certain
threshold, we estimate that the compliance with the storage tank
requirement could cost an operator $74,400 (representing approximately
0.8 to 1.4 percent of the cost of drilling a well) Through our analysis
we estimate that this is only a small subset of total operations. These
operations are those where the volumes of recovered fluids are expected
to be very high and typically occur in states (Arkansas, Louisiana,
Mississippi, Ohio, Oklahoma, and Pennsylvania) which represent only
about 0.8% of estimated hydraulic fracturing activities on Federal and
Indian land (from FY 2010 to FY 2013).
The costs of drilling a well may vary by reservoir or formation,
depth, and length, site-specific characteristics, as well as operator
efficiencies. The Energy Information Administration suggests costs of
about $5.4 million which we believe may be a lower bound estimate of
the costs for drilling a well to be completed with hydraulic
fracturing. The EIA figures were last updated in 2007, were not
specific to horizontal wells or hydraulically fractured wells, and
included costs of drilling exploratory or development wells. We
adjusted the EIA figures to 2015 dollars. Meanwhile, horizontal wells
drilled in the Bakken formation have been reported to cost $5.6 million
(cited by Investopedia from Continental Resources in 2010) and, most
recently, between $7-9 million per well (cited from various companies
in industry trade journal Oil Patch Hotline 2015).

Small Number of Operations

As discussed in the Economic Analysis, well completions decreased
on Federal lands from FY 2012 to FY 2013, but increased steadily on
Indian lands on an annual basis since FY 2010. If the FY 2012 level of
activity on Federal lands is used as a basis for the estimate, the rule
could potentially impact up to 3,775 hydraulic fracturing operations
per year on Federal and Indian lands at an incremental cost of about
$45 million per year.
Many of the rule's requirements are consistent with industry
guidance and some are required by existing BLM regulations and state
regulations. Accordingly, to the extent that industry is already in
voluntary compliance, the cost of several provisions may be
overestimated. Where the rule's requirements are consistent with
industry practice or state regulations, there will not be an
incremental cost. There are two requirements in particular that are
likely to pose the bulk of the estimated costs.
First, the rule requires the operator to run a CEL on the
intermediate casing if that casing string protects usable water and if
the operator chooses not to cement the casing to the surface. Industry
guidance suggests that an operator may run a cement bond log on the
intermediate casing to show that the casing was cemented to the design.
The BLM believes that operators will generally run logs on the
intermediate casing, particularly if they plan to conduct hydraulic
fracturing through a production liner that is hung from the
intermediate casing, and that states or the BLM may specify this as a
condition of approval, even if it is not in regulation. Since the BLM
does not have validating data, the analysis assumes that the rule would
compel CELs in all areas, except those states that require them in
regulation. As such, the costs associated with this requirement are
likely overstated.
Second, the rule requires the operator to manage recovered fluids
in storage tanks. Industry guidance suggests that operators may use
storage tanks or pits to manage recovered fluids. Some states require
the use of tanks by regulation and some states have adopted the
practice as a policy through guidance or as a standard condition of
approval for drilling operations. Our observations of field operations
indicate that operators almost always use storage tanks, which
indicates that they may be doing so voluntarily. The BLM estimated the
voluntary use of storage tanks in states that do not have regulations
requiring their use. Still, in some areas, our field observations
indicate that the use of storage tanks is higher than the estimated
voluntary compliance. As such, the costs associated with this
requirement are also likely overstated.

Cost Breakout According to Federal and Tribal Lands

On Federal lands only, the BLM estimates that the final rule would
impact 2,144 hydraulic fracturing operations per year in the near-term
future and that the rule poses an incremental cost of about $22 million
per year. The rule could potentially impact up to 3,105 operations per
year on Federal lands at an incremental cost of about $35 million per
year.
Tables 3A and 3B depict the annual incremental costs associated
with the rule's requirements, attributed to operations on Federal lands
within a state. It accounts for consistencies between a state's
requirements and the rule's requirements.

[[Page 16206]]

On Indian lands, the BLM estimates that the final rule would impact
670 hydraulic fracturing operations per year in the near-term future
and that the rule poses an incremental cost of about $10 million per
year. The estimate accounts for the steady increase in activity on
Indian lands over the past few years.
Table 4 depicts the annual incremental costs associated with the
rule's requirements, attributed to operations on Indian lands within a
reservation. The highest total costs are associated with operations in
the Fort Berthold, Uintah and Ouray, and Jicarilla Apache reservations,
due to the volume of activity within those reservations.

Table 3A--Estimated Annual Incremental Costs Associated With Activity on Federal Lands
--------------------------------------------------------------------------------------------------------------------------------------------------------
Remedial
Number of Application action CEL on Storage Post-fracture Variance
Federal lands, by state operations (sundry) reporting intermediate tank reporting requests Total costs
per year (sundry) casing (sundry) (sundry)
--------------------------------------------------------------------------------------------------------------------------------------------------------
ALASKA.................................. 9 $5,787 $174 $50,040 $0 $6,507 $579 $63,086
ALABAMA................................. 1 643 19 5,560 74,400 723 64 81,410
ARKANSAS................................ 3 1,929 58 16,680 216,727 2,169 193 237,756
CALIFORNIA.............................. 188 120,884 3,627 1,045,280 0 135,924 12,088 1,317,803
COLORADO................................ 59 37,937 1,138 0 1,242,257 42,657 3,794 1,327,783
KANSAS.................................. 0 0 0 0 0 0 0 0
LOUISIANA............................... 2 1,286 39 11,120 103,565 1,446 129 117,584
MISSISSIPPI............................. 6 3,858 116 33,360 148,651 4,338 386 190,709
MONTANA................................. 1 643 19 5,560 15,178 723 64 22,187
NORTH DAKOTA............................ 173 111,239 3,337 0 3,204,929 125,079 11,124 3,455,708
NEW MEXICO.............................. 732 470,676 14,120 4,069,920 0 529,236 47,068 5,131,020
NEVADA.................................. 0 0 0 0 0 0 0 0
OHIO.................................... 2 1,286 39 11,120 148,800 1,446 129 162,819
OKLAHOMA................................ 15 9,645 289 83,400 425,196 10,845 965 530,340
PENNSYLVANIA............................ 12 7,716 231 66,720 829,411 8,676 772 913,526
SOUTH DAKOTA............................ 4 2,572 77 22,240 0 2,892 257 28,038
TEXAS................................... 23 14,789 444 63,940 0 16,629 1,479 97,281
UTAH.................................... 579 372,297 11,169 3,219,240 0 418,617 37,230 4,058,553
WYOMING................................. 335 215,405 6,462 1,862,600 1,919,148 242,205 21,541 4,267,361
TOTAL............................... 2,144 1,378,592 41,358 10,566,780 8,328,262 1,550,112 137,859 22,002,963
--------------------------------------------------------------------------------------------------------------------------------------------------------

Table 3B--Potential Upper Bound Estimate (Using FY 2012 Level of Activity)--Estimated Annual Incremental Costs Associated With Activity on Federal Lands
--------------------------------------------------------------------------------------------------------------------------------------------------------
Remedial
Number of Application action CEL on Storage Post-fracture Variance
Federal lands, by state operations (sundry) reporting intermediate tank reporting requests Total costs
per year (sundry) casing (sundry) (sundry)
--------------------------------------------------------------------------------------------------------------------------------------------------------
ALASKA.................................. 1 $643 $19 $5,560 $0 $723 $64 $7,010
ALABAMA................................. 1 643 19 5,560 74,400 723 64 81,410
ARKANSAS................................ 7 4,501 135 38,920 505,697 5,061 450 554,764
CALIFORNIA.............................. 222 142,746 4,282 1,234,320 0 160,506 14,275 1,556,129
COLORADO................................ 365 234,695 7,041 0 7,685,148 263,895 23,470 8,214,248
KANSAS.................................. 1 643 19 5,560 3,274 723 64 10,283
LOUISIANA............................... 4 2,572 77 22,240 207,130 2,892 257 235,168
MISSISSIPPI............................. 0 0 0 0 0 0 0 0
MONTANA................................. 15 9,645 289 83,400 227,664 10,845 965 332,808
NORTH DAKOTA............................ 127 81,661 2,450 0 2,352,751 91,821 8,166 2,536,849
NEW MEXICO.............................. 956 614,708 18,441 5,315,360 0 691,188 61,471 6,701,168
NEVADA.................................. 0 0 0 0 0 0 0 0
OHIO.................................... 3 1,929 58 16,680 223,200 2,169 193 244,229
OKLAHOMA................................ 15 9,645 289 83,400 425,196 10,845 965 530,340
PENNSYLVANIA............................ 0 0 0 0 0 0 0 0
SOUTH DAKOTA............................ 5 3,215 96 27,800 0 3,615 322 35,048
TEXAS................................... 39 25,077 752 108,420 0 28,197 2,508 164,954
UTAH.................................... 517 332,431 9,973 2,874,520 0 373,791 33,243 3,623,958
WYOMING................................. 827 531,761 15,953 4,598,120 4,737,718 597,921 53,176 10,534,649
TOTAL............................... 3,105 1,996,515 59,895 14,419,860 16,442,177 2,244,915 199,652 35,363,014
--------------------------------------------------------------------------------------------------------------------------------------------------------

Table 4--Estimated Annual Incremental Costs Associated With Activity on Tribal Lands
--------------------------------------------------------------------------------------------------------------------------------------------------------
Remedial
Number of Application action CEL on Storage Post-fracture Variance
Reservation or BIA agency operations (sundry) reporting intermediate tank reporting requests Total costs
per year (sundry) casing (sundry) (sundry)
--------------------------------------------------------------------------------------------------------------------------------------------------------
ANADARKO................................ 6 $3,858 $116 $33,360 $170,078 $4,338 $386 $212,136
ARDMORE................................. 0 0 0 0 0 0 0 0
BLACKFEET............................... 4 2,572 77 22,240 60,710 2,892 257 88,749

[[Page 16207]]

CHEYENNE & ARAPAHO...................... 1 643 19 5,560 28,346 723 64 35,356
CONCHO.................................. 14 9,002 270 77,840 396,850 10,122 900 494,984
CROW.................................... 0 0 0 0 0 0 0 0
EASTERN NAVAJO.......................... 19 12,217 367 105,640 0 13,737 1,222 133,182
FIVE CIVILIZED TRIBES................... 0 0 0 0 0 0 0 0
FORT BELKNAP............................ 0 0 0 0 0 0 0 0
FORT BERTHOLD........................... 334 214,762 6,443 0 6,187,550 241,482 21,476 6,671,713
FORT PECK............................... 0 0 0 0 0 0 0 0
JICARILLA APACHE........................ 93 59,799 1,794 517,080 0 67,239 5,980 651,892
MUSKUGEE................................ 0 0 0 0 0 0 0 0
OKMULGEE................................ 2 1,286 39 11,120 56,693 1,446 129 70,712
PAWNEE.................................. 9 5,787 174 50,040 255,118 6,507 579 318,204
SHAWNEE................................. 0 0 0 0 0 0 0 0
SHIPROCK................................ 4 2,572 77 22,240 0 2,892 257 28,038
SOUTHERN UTE, BIA....................... 0 0 0 0 0 0 0 0
TAHLAQUAH............................... 1 643 19 5,560 28,346 723 64 35,356
TALIHINA................................ 1 643 19 5,560 28,346 723 64 35,356
TURTLE MOUNTAIN......................... 2 1,286 39 0 37,051 1,446 129 39,950
UINTAH AND QURAY........................ 176 113,168 3,395 978,560 0 127,248 11,317 1,233,688
UTE MOUNTAIN UTE........................ 0 0 0 0 0 0 0 0
WIND RIVER.............................. 4 2,572 77 22,240 22,915 2,892 257 50,954
TOTAL............................... 670 430,810 12,924 1,857,040 7,272,005 484,410 43,081 10,100,270
--------------------------------------------------------------------------------------------------------------------------------------------------------

Cost Breakout by Activity

Tables 5A and 5B show the incremental costs by requirement for
operations on Federal and Indian lands. The BLM estimates that the
largest incremental costs are associated with the operational
requirements for a CEL on certain intermediate casing and storage tanks
to manage recovered fluids. As mentioned previously, the BLM does not
have specific data about the prevalence of voluntary compliance with
these requirements irrespective of the rule. Accordingly, these
estimates are may be overstated. The BLM estimates that the CEL
requirement will impact a fraction of the operations, but could cost
operators $12.4 million annually (and potentially up to $16.3 million).
The BLM also estimates that the incremental annual cost of requiring
storage tanks (instead of allowing pits) could cost operators about
$15.6 million (and potentially up to $23.7 million).

Compliance Costs Per-Operation

The rule would result in compliance costs of about $11,400 per
hydraulic fracturing operation. Average compliance costs to meet the
requirements for a CEL on certain intermediate casing and for storage
tanks represent the bulk of the per-operation compliance costs. The
results are in Tables 6A and 6B.
Of the estimated per-operation compliance costs, the administrative
burden represents about $1,450. The BLM estimates that the operator
will assume about $1,118 and the BLM will assume $331 of that amount.
The administrative burden figures are in Tables 7A and 7B.
The review of information associated with the application,
subsequent report, remedial action report (when applicable), and
variance request (when applicable) will pose an additional workload to
the BLM of about 25,400 hours per year. That additional burden
represents about 12.20 full-time equivalent (FTE) of workload or, as a
practical matter, about 13.80 staffed positions (takes into account
leave and holidays).

Table 5A--Estimated Annual Incremental Costs, by Requirement
--------------------------------------------------------------------------------------------------------------------------------------------------------
Remedial
Number of Application action CEL on Storage Post-fracture Variance
Jurisdiction operations (sundry) reporting intermediate tank reporting requests Total costs
per year (sundry) casing (sundry) (sundry)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Federal lands........................... 2,144 $1,378,592 $41,358 $10,566,780 $8,328,262 $1,550,112 $137,859 $22,002,963
Indian lands............................ 670 430,810 12,924 1,857,040 7,272,005 484,410 43,081 10,100,270
Total............................... 2,814 1,809,402 54,282 12,423,820 15,600,266 2,034,522 180,940 32,103,233
--------------------------------------------------------------------------------------------------------------------------------------------------------

[[Page 16208]]

Table 5B--Potential Upper Bound Estimate (Using FY 2012 Level of Activity)--Estimated Annual Incremental Costs, by Requirement
--------------------------------------------------------------------------------------------------------------------------------------------------------
Remedial
Number of Application action CEL on Storage Post-fracture Variance
Jurisdiction operations (sundry) reporting intermediate tank reporting requests Total costs
per year (sundry) casing (sundry) (sundry)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Federal lands........................... 3,105 $1,996,515 $59,895 $14,419,860 $16,442,177 $2,244,915 $199,652 $35,363,014
Indian lands............................ 670 430,810 12,924 1,857,040 7,272,005 484,410 43,081 10,100,270
Total............................... 3,775 2,427,325 72,820 16,276,900 23,714,182 2,729,325 242,733 45,463,284
--------------------------------------------------------------------------------------------------------------------------------------------------------

Table 6A--Average Per-Operation Compliance Costs, by Requirement
--------------------------------------------------------------------------------------------------------------------------------------------------------
Remedial
Number of Application action CEL on Storage Post-fracture Variance
Jurisdiction operations (sundry) reporting intermediate tank reporting requests Total costs
per year (sundry) casing (sundry) (sundry)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Federal lands........................... 2,144 $643 $19 $4,929 $3,884 $723 $64 $10,263
Indian lands............................ 670 643 19 2,772 10,854 723 64 15,075
Total............................... 2,814 643 19 4,415 5,544 723 64 11,408
--------------------------------------------------------------------------------------------------------------------------------------------------------

Table 7A--Annual Administrative Burden, by Requirement
----------------------------------------------------------------------------------------------------------------
Remedial
Application action Post-fracture Variance
Party assuming burden (sundry) reporting reporting requests Total costs
(sundry) (sundry) (sundry)
----------------------------------------------------------------------------------------------------------------
Operators....................... $1,395,744 $41,872 $1,570,212 $139,574 $3,147,403
BLM............................. 413,658 12,410 464,310 41,366 931,744
Total....................... 1,809,402 54,282 2,034,522 180,940 4,079,146
----------------------------------------------------------------------------------------------------------------

Table 7B--Average Per-Operation Administrative Burden, by Requirement
----------------------------------------------------------------------------------------------------------------
Remedial
Application action Post-fracture Variance
Party assuming burden (sundry) reporting reporting requests Total costs
(sundry) (sundry) (sundry)
----------------------------------------------------------------------------------------------------------------
Operators....................... $496 $15 $558 $50 $1,118
BLM............................. 147 4 165 15 331
Total....................... 643 19 723 64 1,450
----------------------------------------------------------------------------------------------------------------

Economic Impact Analysis and Distributional Assessments

Energy System Impact Analysis
Executive Order 13211 requires that agencies prepare and submit to
the Administrator of the Office of Information and Regulatory Affairs
(OIRA), OMB, a Statement of Energy Effects for certain actions
identified as significant energy actions. Section 4(b) of Executive
Order 13211 defines a ``significant energy action'' as ``any action by
an agency (normally published in the Federal Register) that promulgates
or is expected to lead to the promulgation of a final rule or
regulation, including notices of inquiry, advance notices of proposed
rulemaking, and notices of proposed rulemaking: (1)(i) That is a
significant regulatory action under Executive Order 12866 or any
successor order; and (ii) Is likely to have a significant adverse
effect on the supply, distribution, or use of energy; or (2) That is
designated by the Administrator of OIRA as a significant energy action.
A key consideration is the extent to which the costs of the
requirements might impact investment, production, employment, and a
number of other factors. That is, to what extent, if any, would an
operator choose to invest in other areas, non-Federal and non-Indian
lands, when faced with the cost requirements of the rule. Since the
bulk of the costs of this rule would apply to hydraulic fracturing
operations on wells that are yet to be drilled (and not on existing
wells and to refracturing operations), operators will be able to
account for any cost increases up front when making investment
decisions.
The BLM believes that the additional cost per hydraulic fracturing
operation is insignificant when compared with the drilling costs in
recent years, the production gains from hydraulically fractured well
operations, and the net incomes of entities within the oil and natural
gas industries.
For the average hydraulic fracturing operation, the compliance
costs represent about 0.13 to 0.21 percent of the cost of drilling a
well. Since the estimated compliance costs are not substantial when
compared with the total costs of drilling a well, the BLM believes that
the rule is unlikely to have an effect on the investment decisions of
firms, and the rule is unlikely to affect the supply, distribution, or
use of energy.
Employment Impact Analysis
Executive Order 13563 reaffirms the principles established in
Executive Order 12866, but calls for additional consideration of the
regulatory impact on employment. It states, ``Our regulatory system
must protect public health, welfare, safety, and our environment while
promoting economic growth, innovation, competitiveness,

[[Page 16209]]

and job creation.'' An analysis of employment impacts is a standalone
analysis and the impacts should not be included in the estimation of
benefits and costs.
This final rule requires operators, who have not already done so,
to conduct one-time tests on a well or make a one-time installation of
a mitigation feature. In addition, operators are required to perform
administrative tasks related to a one-time event.
Compliance with a few of the operational requirements is expected
to pose an additional cost to the operator and is likely to shift
resources from firms in the crude oil and natural gas extraction
industries (NAICS codes: 211111--Crude Petroleum and Natural Gas
Extraction, 211112--Natural Gas Liquid Extraction) to firms providing
support services for drilling oil and gas wells (NAICS code: 213111--
Drilling Oil and Gas Wells).
Of principal interest is the extent to which the financial burden
is expected to change operators' investment decisions. If the financial
burden is not significant and all other factors are equal, then one
would expect operators to maintain existing levels of investment and
employment. The BLM believes that the rule would result in an
additional cost per well hydraulic fracturing operation that is small
and will not alter the investment or employment decisions of firms.
Small Business Impact Analysis
The Regulatory Flexibility Act as amended by the Small Business
Regulatory Enforcement Fairness Act (SBREFA) generally requires an
agency to prepare a regulatory flexibility analysis of any rule subject
to notice and comment rulemaking requirements under the Administrative
Procedure Act if a rule would have a significant economic impact,
either detrimental or beneficial, on a substantial number of small
entities. See 5 U.S.C. 601-612. Congress enacted the RFA to ensure that
Government regulations do not unnecessarily or disproportionately
burden small entities. Small entities include small businesses, small
governmental jurisdictions, and small not-for-profit enterprises.
The BLM reviewed the Small Business Administration (SBA) size
standards for small businesses and the number of entities fitting those
size standards as reported by the U.S. Census Bureau in the 2007
Economic Census. Using the Economic Census data, the BLM concludes that
about 99 percent of the entities operating in the relevant sectors \31\
are small businesses in that they employ fewer than 500 employees.
Also, within these relevant sectors, small firms account for 74 percent
of the total value of shipments and receipts for services, 86 percent
of the total cost of supplies, 78 percent of the total capital
expenditures (excluding land and mineral rights), and 67 percent of the
paid employees (see the Economic Analysis).
---------------------------------------------------------------------------

\31\ NAICS codes: 211111--Crude Petroleum and Natural Gas
Extraction, 211112--Natural Gas Liquid Extraction, and 213111--
Drilling Oil and Gas Wells.
---------------------------------------------------------------------------

Small entities represent the overwhelming majority of entities
operating in the onshore crude oil and natural gas extraction industry.
As such, the rule is likely to affect a significant number of small
entities. To examine the economic impact of the rule on small entities,
the BLM performed a screening analysis for impacts on a sample of
expected affected small entities by comparing compliance costs to
entity net incomes.
The firms most likely to be affected by the rule are those
conducting hydraulic fracturing activities on Federal and Indian lands.
More specifically, the firms most impacted are expected to be those
drilling new wells for hydraulic fracture completions. The BLM compiled
a list of firms that completed wells according to AFMSS. The BLM
expects that these firms are most likely to be impacted by the rule.
From that list, the BLM researched for company annual report filings
with the Securities and Exchange Commission (SEC) to determine annual
company net incomes and employment figures. From the original list, the
BLM found 55 company filings. Of those, 33 were small businesses. For
the purposes of this analysis, the BLM assumes that all entities (all
lessees and operators) that may be affected by this rule are small
entities, even though that is not actually the case.
Using the net income data for the small businesses that filed SEC
Form 10-K, the BLM used the estimated compliance costs per hydraulic
fracturing operation to calculate the percent of compliance costs as a
portion of annual company net incomes for 2011. The BLM used the
absolute values of the percentages in the average, so that the negative
net incomes would not negate the positive net incomes, and vice versa.
Averaging results for the small businesses that the BLM examined, the
average costs of the rule are expected to represent about 0.15 percent
of the company net incomes. The results of those findings are in Table
8.

Table 8--Small Business' Company Net Income and Compliance Costs as a Share of Net Income
----------------------------------------------------------------------------------------------------------------
Hydraulic
Hydraulic Hydraulic fracturing
Company net fracturing fracturing operation
Descriptive statistic income operation on operation on (without
federal lands Indian lands distinction)
(%) (%) (%)
----------------------------------------------------------------------------------------------------------------
Average of absolute values...................... 67,288,696 0.132 0.195 0.147
Average......................................... 27,566,704 0.005 0.008 0.006
Minimum value................................... -228,063,000 -0.858 -1.260 -0.954
Maximum value................................... 392,678,000 0.731 1.074 0.813
----------------------------------------------------------------------------------------------------------------

The rule deals with hydraulic fracturing on all Federal and Indian
lands (except those excluded by statute). Please see the discussion
earlier in this preamble for the discussion of the need for, and
objectives of the rule and a discussion of the impacts of the rule. The
BLM received many comments on the economic impacts of the supplemental
proposed rule, as discussed elsewhere in this preamble.
There would be some increased costs associated with the enhanced
recordkeeping requirements and some new operational requirements.
Specifically, there will be increased costs for operators to manage
recovered

[[Page 16210]]

fluids in above-ground tanks until they have approved plans for
disposal of produced water pursuant to Onshore Order No. 7. Operators
that do not routinely run a CEL to ensure that the producing zone is
isolated from usable water or that do not routinely run an MIT prior to
hydraulic fracturing operations will face increased costs. Submission
of hydraulic fracturing plans for prior approval, and submission of
detailed reports after hydraulic fracturing operations will be new
costs, as will the costs of submitting chemical information or of
submitting an affidavit. Maintaining access to information on chemicals
that was withheld from submission may also pose a cost. The
application, reporting and data retention requirements are not overly
burdensome because they are for information readily available to the
operator or its service contractors. The reasons for those requirements
and responses to comments on each requirement are discussed previously
in this preamble. As shown on Tables 5A, 5B, 6A, 6B, 7A, 7B, and 8, the
BLM expects that the costs of compliance with this rule would be minor
in comparison to overall operations costs.
The BLM has taken steps to reduce costs on small entities by not
promulgating a general requirement to run a CEL on surface casings, by
allowing submission of chemical data through FracFocus, by providing
for submission of a request for approval for hydraulic fracturing in a
master hydraulic fracturing plan, by clarifying that isolating and
protecting usable water means 200 feet of competent cement between the
fractured zone and the usable water zone, by clarifying that modeling
of fissure propagation is not required, and by allowing for both
operation-specific and state or tribal variances. Therefore, the BLM
has determined that the rule would not have a significant economic
impact on a substantial number of small entities.
Also, based on the available information, the BLM estimates the
annual effect on the economy of the regulatory changes will be less
than $100 million. This rule will not create a major increase in costs
or prices for consumers, individual industries, Federal, state, or
local government agencies, or geographic regions. In addition, this
regulation will not have any significant adverse effects on
competition, employment, investment, productivity, innovation, or on
the ability of United States-based enterprises to compete with foreign-
based enterprises in domestic and export markets.

Executive Order 12866, Regulatory Planning and Review

In accordance with the criteria in Executive Order 12866, the
Office of Management and Budget has determined that this rule is a
significant regulatory action.
The rule will not have an annual effect on the economy of $100
million or more or adversely affect in a material way the economy, a
sector of the economy, productivity, competition, jobs, the
environment, public health or safety, or state, local, or tribal
governments or communities. However, the rule may raise novel policy
issues because of the requirement that operators provide to the BLM
information regarding hydraulic fracturing operations that they are not
currently providing to the BLM.
This rule would not create inconsistencies or otherwise interfere
with an action taken or planned by another agency. This rule would not
change the relationships of oil and gas operations with other agencies.
These relationships are included in agreements and memoranda of
understanding that would not change with this rule. In addition, this
rule would not materially affect the budgetary impact of entitlements,
grants, loan programs, or the rights and obligations of their
recipients. Please see the discussion of the impacts of the rule
described earlier in this section of the preamble.

Unfunded Mandates Reform Act

Under the Unfunded Mandates Act, agencies must prepare a written
statement about benefits and costs prior to issuing a proposed or final
rule that may result in aggregate expenditure by state, local, and
tribal governments, or by the private sector, of $100 million or more
in any one year.
This rule does not contain a Federal mandate that may result in
expenditures of $100 million or more for state, local, and tribal
governments, in the aggregate, or to the private sector in any one
year. Thus, the rule is also not subject to the requirements of
Sections 202 or 205 of the Unfunded Mandates Reform Act (UMRA).
This rule is also not subject to the requirements of Section 203 of
UMRA because it contains no regulatory requirements that might
significantly or uniquely affect small governments; it contains no
requirements that apply to such governments nor does it impose
obligations upon them.

Executive Order 12630, Governmental Actions and Interference With
Constitutionally Protected Property Rights (Takings)

Under Executive Order 12630, the rule will not have significant
takings implications. A takings implication assessment is not required.
This rule establishes recordkeeping requirements for hydraulic
fracturing operations and some additional operational requirements on
Federal and Indian lands. All such operations are subject to lease
terms which expressly require that subsequent lease activities be
conducted in compliance with subsequently adopted Federal laws and
regulations. The rule conforms to the terms of those Federal leases and
applicable statutes and as such the rule is not a governmental action
capable of interfering with constitutionally protected property rights.
Therefore, the rule will not cause a taking of private property or
require further discussion of takings implications under this Executive
Order.

Executive Order 13352, Facilitation of Cooperative Conservation

Under Executive Order 13352, the BLM has determined that this rule
will not impede facilitating cooperative conservation and takes
appropriate account of and consider the interests of persons with
ownership or other legally recognized interests in land or other
natural resources. The rulemaking process involved Federal, state,
local, and tribal governments, private for-profit and nonprofit
institutions, other nongovernmental entities and individuals in the
decision-making. The process provides that the programs, projects, and
activities are consistent with protecting public health and safety.

Executive Order 13132, Federalism

Under Executive Order 13132, this rule will not have significant
Federalism effects. A Federalism assessment is not required because the
rule will not have a substantial direct effect on the states, on the
relationship between the national government and the states, or on the
distribution of power and responsibilities among the various levels of
government. The rule will not have any effect on any of the items
listed. The rule affects the relationship between operators, lessees,
and the BLM, but it does not impact states. Therefore, under Executive
Order 13132, the BLM has determined that this rule will not have
sufficient Federalism implications to warrant preparation of a
Federalism Assessment.

[[Page 16211]]

Executive Order 13175, Consultation and Coordination With Indian Tribal
Governments

Under Executive Order 13175, the President's memorandum of April
29, 1994, ``Government-to-Government Relations with Native American
Tribal Governments'' (59 FR 22951), The Department of the Interior
Policy on Consultation with Indian Tribes (Dec. 1, 2011), and 512
Departmental Manual 2, the BLM evaluated possible effects of the rule
on federally recognized Indian tribes. The BLM approves proposed
operations on all Indian onshore oil and gas leases (except those
excluded by statute). Therefore, the rule has the potential to affect
Indian tribes. In conformance with the Department's policy on tribal
consultation, the Bureau of Land Management held four tribal
consultation meetings to which over 175 tribal entities were invited.
The consultations were held in four cities in January 2012.
The purpose of those meetings was to solicit initial feedback and
preliminary comments from the tribes. To date, the tribes have
expressed concerns about the BLM's Inspection and Enforcement program's
ability to enforce the terms of this rule; previously plugged and
abandoned wells being potential conduits for contamination of
groundwater; and the operator having to provide documentation that the
water used for the fracturing operation was legally acquired. The BLM
considered these concerns during the drafting of the final rule.
After publication of the proposed rule, the BLM held another series
of meetings to obtain comments and recommendations from tribes and
tribal organizations. Those meetings were held in June 2012 in Utah,
New Mexico, Oklahoma, and Montana. The BLM also engaged in one-on-one
consultations as requested by several tribes. Some tribal
representatives were concerned about risks to the quality of their
vital water supplies. Others, though, were more concerned with the risk
that increased compliance costs would drive the industry off of Indian
lands, and deprive the tribes of much-needed revenues and economic
development.
After publication of the supplemental proposed rule, the BLM again
held regional meetings with tribes in Farmington, New Mexico, and
Dickinson, North Dakota, in June 2013. Representatives from six tribes
attended. The discussions included a variety of tribal-specific and
general issues. The BLM again offered to follow up with one-on-one
consultations, and several such meetings were held with individual
tribes. Several tribes, tribal members, and associations of tribes
provided comments on the supplemental proposed rule.
In March 2014, the BLM invited tribes to participate in another
meeting in Denver, Colorado. Representatives from seven tribes
attended. There was significant discussion of issues raised in the
comments on the supplemental proposed rule. The BLM subsequently held
several consultations with individual tribes.
The BLM understands the importance of tribal sovereignty and self-
determination, and seeks to continuously improve its communications and
government-to-government relations with tribes.
The BLM has considered and responded to the concerns expressed by
the tribal representatives both orally and in written comments, as
described previously. In particular, it has made changes that will
reduce economic burdens of compliance for many operators.
Several tribes provided written and oral comments critical of the
proposed rule. Other tribes said that the rules violated tribal
sovereignty. The final rule, however, is not unique. Regulations
promulgated by the Bureau of Indian Affairs render the BLM's operating
regulations in 43 CFR part 3160 applicable to oil and gas leases of
trust and restricted Indian lands, both tribal and individually owned.
See 25 CFR 211.4, 212.4, and 225.4.
Some tribes insist that those BIA regulations are in violation of
the FLPMA, which they said restricts the BLM's authority to Federal
lands. Section 301 of the FLPMA, however, charges the Director of the
BLM to carry out functions and duties as the Secretary may prescribe
with respect to the lands and the resources under the Secretary's
jurisdiction according to the applicable provisions of the FLPMA and
any other applicable law. 43 U.S.C. 1731(a). See also 43 U.S.C.
1731(b). The Act of March 3,1909 (1909 Act) (at 25 U.S.C. 396), the
Indian Minerals Leasing Act (IMLA) (at 25 U.S.C. 396d) and the Indian
Mineral Development Act (IMDA) (at 25 U.S.C. 2107) provide the
Secretary of the Interior with authority to promulgate regulations
governing oil and gas operations and mineral agreements on certain
Indian lands. As previously cited, the Secretary, through delegations
in the Departmental Manual as reflected in the regulations promulgated
by the BIA, has assigned to the BLM part of the Secretary's trust
responsibilities to regulate oil and gas operations on those Indian
lands. This rule concerning Indian lands is promulgated pursuant to the
1909 Act, the IMLA, and the IMDA, and will be implemented by the BLM
under those authorities, consistent with Section 301 of the FLPMA.
Some tribes have asked that the final rule exempt Indian lands from
its scope. Such an exemption would require the Secretary of the
Interior to conclude, among other things, that usable waters in Indian
lands, and the persons who use such waters, are less deserving of
protection than waters and water users on Federal land. The Department
of the Interior declines to reach that conclusion.
Some tribes have advocated that the rule should allow Indian tribes
to decide individually whether the hydraulic fracturing regulations
would apply on their lands. The BIA's regulations, however, apply to
all of the BLM's oil and gas operating regulations on Indian lands, and
do not allow the tribes to pick and select which of the BLM's
regulations apply on their lands.
The tribes, however, report that industry representatives have
threatened not to bid on Indian leases if the proposed rules were
promulgated. The tribes are concerned that a major source of revenue
and of economic development might leave Indian lands because of the
costs of compliance with the rule. The BLM has carefully considered the
tribes' comments, along with those of the oil and gas industry and of
concerned citizens and governments. The final rule includes several
changes from the initial proposed rules to reduce the costs and other
burdens of compliance. Examples include not requiring a CEL on surface
casings absent an indication of a cementing problem, allowing operators
to use any one of a class of CELs to verify the adequacy of cement
casings and not requiring the CEL to be approved before fracturing
operations if there is no indication of problems with the cementing.
The final rule also explicitly states that the BLM will require
isolation of zones that the tribes designate for protection from oil
and gas operations, and will not require isolation of zones that tribes
have exempted from protection. (Note, though, that the final rule would
not exempt an operator from the provisions of the SDWA.) Furthermore,
the BLM could approve a variance from certain provisions of the rule
applicable to all or parts of Indian lands, provided the relevant
tribal rule meets or exceeds the effectiveness of BLM's rule. Such a
variance could allow an operator's compliance with a tribe's standard
or procedure to be accepted as compliance with the revised proposed
rule, thus

[[Page 16212]]

reducing the compliance burdens for operators. Such changes should
significantly reduce compliance costs for operators while still
assuring protection of usable water resources.
The BLM is aware that the final rule could nonetheless result in
some higher costs for operators on Federal and Indian lands, compared
with compliance costs for hydraulic fracturing on non-Federal, non-
Indian lands in some states with no regulations or less protective
regulations. Regulatory compliance costs, however, are only one
category in a long list of costs that operators compare to anticipated
revenues when deciding whether and how much to bid on a Federal or
Indian lease. The costs of this rule are estimated to be only 0.13 to
0.21 percent of the cost of drilling a well. It has not been the BLM's
experience that regulatory compliance costs have caused the industry to
avoid valuable oil and gas resources on Federal and Indian lands.

Executive Order 12988, Civil Justice Reform

Under Executive Order 12988, the Office of the Solicitor has
determined that this rule will not unduly burden the judicial system
and meets the requirements of Sections 3(a) and 3(b)(2) of the Order.
The Office of the Solicitor has reviewed the rule to eliminate drafting
errors and ambiguity. It has been written to minimize litigation, to
provide clear legal standards for affected conduct rather than general
standards, and to promote simplification and avoid unnecessary burdens.

Paperwork Reduction Act

The Paperwork Reduction Act (44 U.S.C. 3501-3521) provides that an
agency may not conduct or sponsor, and a person is not required to
respond to, a ``collection of information,'' unless it displays a
currently valid OMB control number. Collections of information include
requests and requirements that an individual, partnership, or
corporation obtain information, and report it to a Federal agency (44
U.S.C. 3502(3); 5 CFR 1320.3(c) and (k).
The BLM included a request for approval of a collection of
information in both the proposed rule and the supplemental proposed
rule. OMB approved the collection for the final rule under control
number 1004-0203.
Compliance with this collection of information will be required to
obtain or retain a benefit for the operators of Federal and Indian
(except on the Osage Reservation, the Crow Reservation, and certain
other areas) onshore oil and gas leases, units, or communitization
agreements that include Federal leases. After the effective date of the
final rule, the BLM plans to request that OMB merge control number
1004-0203 with control number 1004-0137, ``Onshore Oil and Gas
Operations,'' (expiration date: January 31, 2018).
The following activities comprise the information collection for
the final rule.
Request for Prior Approval
The final rule removes the distinction in existing 43 CFR
3162.3-2 between ``routine'' and ``non-routine'' fracturing jobs, and
requires in section 3162.3-3(a) that operators propose and seek prior
BLM approval for all hydraulic fracturing jobs except for three
instances in which a well is drilled shortly before or after the
effective date of the rule, and is hydraulically fractured within 90
days after the effective date of the rule. However, all other
applicable provisions of the rule must be adhered to, including 3162.3-
3(e), relating to monitoring and verification of cementing operations
prior to hydraulic fracturing.
Section 3162.3-3(c) provides that a request to commence hydraulic
fracturing may be submitted either on Form 3160-5 as a ``Notice of
Intent (NOI) Sundry'' or as part of Form 3160-3, Application for Permit
to Drill (APD), both of which are authorized by control number 1004-
0137. The BLM will use the following-described information to determine
whether or not to grant prior approval for hydraulic fracturing jobs.
Section 3162.3-3(d)(6) lists two requirements that apply only if an
operator requests prior approval for hydraulic fracturing in an NOI
after drilling and completing a well. The first requirement (at
paragraph (d)(6)(i)) is a surface use plan of operations if the
hydraulic fracturing operation would include surface disturbance. The
second requirement (at paragraph (d)(6)(ii)) is documentation that
adequate cementing was achieved for all casing strings designed to
isolate usable water zones. These requirements are included in the
collection activity labeled ``Request for Prior Approval of Hydraulic
Fracturing Job Using a Notice of Intent Sundry Plus a Surface Use Plan
of Operations Plus Documentation of Adequate Cementing.''
While the well completion report (Form 3160-4) that is approved
under control number 1004-0137 requires some information about
cementing, the second requirement in paragraph (d)(6)(ii) is not
duplicative. The well-completion report requires the operator to
disclose the number of sacks and type of cement, the slurry volume, the
cement trop, and any cement squeeze information. The information we are
requiring in paragraph (d)(6)(ii) is actual monitoring information from
when the cementing operations took place, for example, pump pressures,
cement density, and observations during the cement job. We anticipate
that typically, an operator will comply with paragraph (d)(6)(ii) by
providing us with information recorded on a service company's ``job
ticket.''
Section 3162.3-3(e)(1) lists two requirements that apply only if an
operator requests prior approval for hydraulic fracturing in an
Application for Permit to Drill before drilling and completing a well.
This provision requires operators to submit a cement operation
monitoring report to the BLM before commencing hydraulic fracturing
operations. The required elements of a cement operation monitoring
report are (1) The flow rate, density, and pump pressure during pre-
fracturing cementing operations on any casing used to isolate usable
water zones; and (2) A determination of adequate cement for all casing
strings that are used to isolate usable water zones. These requirements
are included in the collection activity labeled, ``Request for Prior
Approval of Hydraulic Fracturing Job Using an Application for Permit to
Drill Plus a Cement Operation Monitoring Report.''
Unlike the supplemental proposed rule, the final rule does not
require the operator to identify a ``type well'' as part of a request
for prior approval for a group of wells. Instead, section 3162.3-
3(c)(3) of the final rule provides for the submission of an MHFP. The
differences between the ``type well'' requirement and the requirement
for an MHFP are described in the preamble discussion of 43 CFR 3160.0-5
(``Definitions''). This discussion clarifies that the MHFP for a group
of wells is only for initial planning purposes and that operators must
submit all required information for each well and get approval for each
well before drilling.
Remedial Action Plan
Section 3162.3-3(e)(3) requires an operator to notify the BLM
within 24 hours of discovering inadequate cement on any casing used to
isolate usable water and submit an NOI to the BLM requesting approval
of a plan to perform remedial action. The BLM will use this collection
activity to determine the adequacy of the proposed remedial action. At
least 72 hours before starting hydraulic fracturing operations,
operators must submit a subsequent report for the remedial action,
which would include a signed certification that

[[Page 16213]]

the operator corrected the inadequate cement job along with the results
from the CEL or other method showing that there is adequate cement.
Subsequent Report
Section 3162.3-3(i) lists information that must be provided to the
BLM within 30 days after the completion of the last stage of hydraulic
fracturing operations. We have revised the information that is
required. The information is required for each well, even if the
authorized officer approved fracturing of a group of wells.
The final rule lists the following requirements for a subsequent
report:
(1) The true vertical depth of the well, total water volume used,
and a description of the base fluid and each additive in the hydraulic
fracturing fluid, including the trade name, supplier, purpose,
ingredients, Chemical Abstract Service Number (CAS), maximum ingredient
concentration in additive (percent by mass), and maximum ingredient
concentration in hydraulic fracturing fluid (percent by mass). This
information must be submitted to the authorized officer through
FracFocus, another BLM-designated database, or in a subsequent report.
If information is submitted through FracFocus or another BLM-designated
database, the operator must specify that the information is for a
Federal or an Indian well, certify that the information is correct, and
certify compliance with applicable law;
(2) The actual source(s) and location(s) of the water used in the
hydraulic fracturing fluid;
(3) The maximum surface pressure and rate at the end of each stage
of the hydraulic fracturing operation and the actual flush volume;
(4) The actual, estimated, or calculated fracture length, height
and direction;
(5) The actual measured depth of perforations or the open-hole
interval;
(6) The total volume of fluid recovered between the completion of
the last stage of hydraulic fracturing operations and when the operator
starts to report water produced from the well to ONRR. If the operator
has not begun to report produced water to ONRR when the subsequent
report is submitted, the operator must submit a supplemental subsequent
report to the authorized officer documenting the total volume of
recovered fluid;
(7) The following information concerning the handling of fluids
recovered covering the period between the commencement of hydraulic
fracturing and the implementation of the approved plan for the disposal
of produced water under BLM regulations (currently in Onshore Order 7):
(i) The methods of handling the recovered fluids, including, but
not limited to, transfer pipes and tankers, holding pond use, re-use
for other stimulation activities, or injection; and
(ii) The disposal method of the recovered fluids, including, but
not limited to, the percent injected, the percent stored at an off-
lease disposal facility, and the percent recycled;
(8) A certification signed by the operator that:
(i) The operator complied with the requirements in 43 CFR 3162.3-
3(b), (e), (f), (g), and (h);
(ii) For Federal lands, the hydraulic fracturing fluid
constituents, once they arrived on the lease, complied with all
applicable permitting and notice requirements as well as all applicable
Federal, state, and local laws, rules, and regulations; and
(iii) For Indian lands, the hydraulic fracturing fluid
constituents, once they arrived on the lease, complied with all
applicable permitting and notice requirements as well as all applicable
Federal and tribal laws, rules, and regulations;
(9) The operator must submit the result of the mechanical integrity
test as required by 43 CFR 3162.3-3(f); and
(10) The BLM may require the operator to provide documentation
substantiating any of the information listed previously.
The information required in paragraphs (2) though (10), previously,
must be submitted to the authorized officer in a subsequent report.
This information will enable the BLM to have a complete record of the
hydraulic fracturing job.
Affidavit in Support of Claim of Confidentiality
Section 3162.3-3(j) describes how an operator, or the operator and
the owner of the information, may support a claim to be exempt from
public disclosure of information otherwise required in the subsequent
report. If required information is withheld, the regulation requires
submission with the subsequent report of an affidavit that:
Identifies the owner of the withheld information and
provides the name, address and contact information for an authorized
representative of the owner;
Identifies the Federal statute or regulation that would
prohibit the BLM from publicly disclosing the information if it were in
the BLM's possession;
Affirms that the operator has been provided the withheld
information from the owner of the information and is maintaining
records of the withheld information, or that the operator has access
and will maintain access to the information held by the owner of the
information;
Affirms that the information is not publicly available;
Affirms that the information is not required to be
publicly disclosed under any applicable local, state, or Federal law
(on Federal lands), or tribal or Federal law (on Indian lands);
Affirms that the owner of the information is in actual
competition and identifies competitors or others that could use the
withheld information to cause the owner substantial competitive harm;
Affirms that the release of the information would likely
cause substantial competitive harm to the owner and provides the
factual basis for that affirmation; and
Affirms that the information is not readily apparent
through reverse engineering with publicly available information.
In addition, if the operator relies upon information from third
parties, such as the owner of the withheld information, to make the
previous affirmations, the operator must provide a written affidavit
from the third party that sets forth the relied-upon information. The
BLM will use the information to determine whether to grant an exemption
from public disclosure of information that otherwise would be required
in a subsequent report.
Section 3162.3-3(j)(5) requires the operator to maintain records of
any withheld information until the later of the BLM's approval of a
final abandonment notice, or 6 years from the completion of hydraulic
fracturing operations on Indian lands, or 7 years from the completion
of hydraulic fracturing operations on Federal lands, consistent with
applicable law. Any subsequent operator will be responsible for
maintaining access to records of any withheld information during its
operation of the well. The operator will be deemed to be maintaining
the records if it can promptly provide the complete and accurate
information to the BLM, even if the information is in the custody of
its owner. This provision enables the BLM to have access to records of
injected chemicals during the life of the well, while protecting trade
secrets.
Section 3162.3-3(j)(6) provides that if any of the chemical
identity information is withheld, the operator must provide the generic
chemical name in the subsequent report.
Variance Request
Section 3162.3-3(k) provides that a decision on a variance request
is not

[[Page 16214]]

subject to administrative appeal either to the State Director or under
43 CFR part 4.
Necessity/Avoidance of Unnecessary Duplication
The Paperwork Reduction Act requires each Federal agency to certify
that its collections of information are necessary for the proper
performance of agency functions, and are not unnecessarily duplicative
of information otherwise reasonably accessible to the agency. 43 U.S.C.
3506(c)(3)(A) and (B). We received many comments on the proposed rule
with respect to this standard, and we responded to them in the
supplemental proposed rule. In addition, we received the following
comments on the supplemental proposed rule with respect to this
standard.
Comments: Numerous commenters said that in states where there is
already a regulatory process for hydraulic fracturing, an operator
should be allowed to submit the same information to the BLM as it does
to the state.
Response: We made no changes as a result of these comments because
the rule already addresses the expressed concerns. Section 3162.3-3(d)
allows information submitted in accordance with state or tribal law to
be submitted to the BLM if the information meets the standards of this
rule. Section 3162.3-3(k)) allows the BLM to issue a statewide or
regional variance to use state or tribal regulations and processes for
permitting hydraulic fracturing operations if they meet or exceed the
objectives of this rule.
Comment: One commenter requested that the BLM clarify the following
statement in section 3162.3-3(d): If information submitted in
accordance with states (on Federal lands) or tribal (on Indian lands)
laws or regulations meets the standards prescribed by the BLM, such
information may be submitted to the BLM as part of the Sundry Notice.
Response: We did not revise the rule in response to this comment.
The statement in section 3162.3-3(d) provides clearly that if the
information submitted to states or tribes meets the standards in this
section, the operator does not need to generate any information.
Operators may submit the information that was generated to meet the
state or tribal requirements to the BLM.
Comments: Some commenters on the supplemental proposed rule
questioned the necessity of collecting information in a subsequent
report within 30 days after the completion of the last stage of
hydraulic fracturing operations under section 3162.3-3(i). They stated
that much of the information is required either in the NOI or in the
well completion report (Form 3160-4) that is required by 43 CFR 3162.4-
1(b).
Response: We disagree with comments claiming duplication between
the NOI and the subsequent report. The information in the NOI allows
the BLM to analyze the proposed operations to ensure that there will
not be any unnecessary or undue degradation of public lands or breach
of trust on Indian lands. The information also enables the BLM to
develop any necessary mitigation to protect resources. In contrast, the
information in the subsequent report allows the BLM to determine
whether or not operations were conducted as designed and authorized.
Some information, such as the results of the MIT and the cement
operations monitoring report, are not included in the NOI, and can only
be submitted after the operations are complete.
We did revise section 3162.3-3(i)(9) (paragraph (i)(8) of the
supplemental proposed rule) in response to comments saying that the
proposed requirement to submit well logs and records of adequate cement
duplicates a requirement in the well completion report. However, we
made no changes to section 3162.3-3(i) in response to other comments
saying that the information required in the subsequent report
duplicates information that is required in the well completion report.
Examples of data that are required in the subsequent report, but not in
the well completion report, include the cement operations monitoring
report, the results of the MIT, and the operator certification that it
complied with the paragraphs in the rule that assure wellbore integrity
was maintained prior to and throughout the hydraulic fracturing
operation.
Comment: A commenter recommended that all cementing requirements be
eliminated from the rule because cementing operations are part of
drilling operations and information is already submitted to state
regulatory agencies for such operations. The commenter also asserted
that cementing operations have little to do with hydraulic fracturing.
Response: We did not revise any provision in response to this
comment. While cementing information is already submitted to state
regulatory agencies and the BLM, this rule expands on the requirements
by including cement monitoring, cement remediation, and cement
evaluation. Moreover, the cementing information that is required is
related to protection of usable water from hydraulic fracturing
operations.
Comments: Some commenters stated that information regarding the
water source that is required in section 3162.3-3(d)(3) would have
already been provided as part of an APD.
Response: We did not revise the rule in response to this comment.
While section III.D.4.e of Onshore Order 1 requires the operator to
identify the location and type of water supply to be used during the
drilling operations in the APD, this may or may not be the same as the
water supply for hydraulic fracturing operations. Since the water
supply may be different, this information must be included in the
application for hydraulic fracturing.
Practical Utility
The Paperwork Reduction Act requires that each Federal agency
certify that each collection of information has practical utility. The
term ``practical utility'' means the ability of an agency to use
information, particularly the capability to process such information in
a timely and useful fashion. 44 U.S.C 3502(11) and 3506(c)(3)(A).
Comments: Commenters expressed various concerns with the
requirement in section 3162.3-3(d)(3) to provide information concerning
the water source and location of water supply. Some stated that they
were unsure how we would use the information. Others stated that the
water source could change and filing a Sundry Notice for the BLM to
approve the change is burdensome.
Response: We did not revise the final rule in response to these
comments. We require information about the proposed source of the water
in order to conduct and document an environmental effects analysis that
takes a hard look at the impacts of its Federal action and meets the
requirements of NEPA. The BLM has always required operators to file a
Sundry Notice for changes to the approved permit--whether it is an APD
or an NOI for hydraulic fracturing.
Clarity
The Paperwork Reduction Act requires each Federal agency to certify
that each collection of information is written using plain, coherent,
and unambiguous terminology and is understandable to those who are to
respond. 44 U.S.C. 3506(c)(3)(D).
Comments: Some commenters recommended restructuring of sections
3162.3-3(d)(3) and 3162.3-3(d)(4) of the supplemental proposed rule
(pertaining to the NOI). They stated that restructuring these
provisions would add clarity to the requirements.

[[Page 16215]]

Response: We revised sections 3162.3-3(d)(3) and 3162.3-3(d)(4) as
suggested in these comments. Section 3162.3-3(d)(3) now requires
information concerning the source and location of the water supply. The
requirement for the measured depth of the proposed perforated or open-
hole interval is moved to section 3162.3-3(d)(4)(v). The information
regarding the proposed perforated interval is now a distinct
requirement, and this information relates more closely with the other
information required by section 3162.3-3(d)(4).
Consistency With Existing Reporting and Recordkeeping Practices
The Paperwork Reduction Act requires each Federal agency to certify
that its collections of information are to be implemented in ways
consistent and compatible, to the maximum extent practicable, with the
existing reporting and recordkeeping practices of those who are to
respond. 44 U.S.C. 3506(c)(3)(E). We received comments on the proposal
to allow some of the information in a subsequent report to be submitted
through FracFocus or another BLM-designated database.
Comments: Some commenters supported the provision (section 3162.3-
3(i)) that allows some of the information in a subsequent report to be
submitted through FracFocus or another BLM-designated database. They
stated that provision would reduce duplication of efforts for the
operators. They also supported the provision that allows operators in
states that require disclosure on FracFocus to meet both the state and
the BLM requirements through a single submission to FracFocus.
Some commenters suggested that additional information, such as the
APD, status, compliance, volume of fluid recovered, and complaint
process, should be reported through the FracFocus submission.
Other commenters were critical of FracFocus as not being user-
friendly and for not allowing re-publication or linking with other
databases. Some commenters were critical of FracFocus because of the
unknown future condition and long-term reliability of this organization
in hosting and retaining the data. A few commenters expressed concern
about future funding, access, and data backup issues of FracFocus.
Other commenters suggested that the disclosure registry should be
searchable across forms and allow for meaningful cross-tabulation of
search results. One of the commenters specified that each of the
disclosure submissions should have a date stamp showing the actual date
of submission to the database and validate/reject the correct/incorrect
CAS Registry Numbers of the disclosed chemicals/ingredients when
submitted. Another commenter suggested that the BLM should develop a
public disclosure platform tailored to the agency's needs.
Some commenters expressed concern that the ownership of the data on
FracFocus and the applicability of public disclosure laws, such as FOIA
are unknown. A commenter suggested that the BLM adopt a procedure used
in Texas that requires operators to submit to the state commission a
copy of the information that they upload to FracFocus.
Some commenters argued that using FracFocus would violate an
executive order requiring government information to be available to the
public in open, machine-readable formats, and the implementing guidance
from the Office of Management and Budget. See Executive Order 13642, 78
FR 93 (2013), and Memorandum for the Heads of Executive Departments and
Agencies, M-13-13 (OMB 2013). That order provides, in pertinent part
that the policy of the Executive Branch is that modernized Government
information resources must be open and machine readable. The order is
subject to several conditions, including available appropriations.
A commenter was concerned that using FracFocus could cause a
conflict of interest because the GWPC is a trade association for oil
and gas.
A commenter argued that using FracFocus would fail to meet minimum
standards for managing government records.
A commenter raised an issue of implementation and enforcement--that
because FracFocus does not show the date that information is uploaded,
it will be difficult for the BLM to know if the information was
submitted within the time required by the rule.
Response: The BLM did not make any changes to the rule in response
to these comments. The responses that are summarized here are discussed
in detail earlier in the preamble discussion of section 3162.3-3(i).
Under this final rule, submission of the required information
through FracFocus is optional; an operator may instead submit it
directly to BLM. The BLM's intent, however, is to reduce the paperwork
burden on operators by allowing them to submit information through
FracFocus, if they so choose. Thus, in states that require submission
on FracFocus, there would be no additional burden of complying with
this requirement of the rule. If an operator submits the information
directly to the BLM, the BLM will upload the information to FracFocus,
and retain a copy in its files.
The BLM did not adopt suggestions to allow additional information
to be reported through the FracFocus submission because FracFocus is
limited to chemical disclosures.
The GWPC has upgraded the FracFocus database to enhance its
functionality for the public, state regulatory agencies and industry
users. As mentioned earlier under New Requirements, GWPC and IOGCC,
joint venture partners in the FracFocus initiative, announced the
release of several improvements to FracFocus' system functionality. The
new features are designed to reduce the number of human errors in
disclosures, expand the public's ability to search records, provide
public extraction of data in a ``machine readable'' format, update
educational information on chemical use, environmental impacts from oil
and gas production, and potential environmental impacts. The new self-
checking features in the system will help companies detect and correct
possible errors before disclosures are submitted. This feature will
detect errors verifying that CAS numbers meet the proper format. GWPC
recently met with the BLM and confirmed the following updates to
FracFocus:
(a) Validation of the CAS number;
(b) Reduction of errors by taking measures, such as a water volume
alert if the operators input exceedingly high numbers (>15 million
gallons) in error, multiple disclosures with the same API numbers,
etc.;
(c) Validation checks of the maximum ingredient concentration,
using two checks/alerts when the sum exceeds 3% and 10%;
(d) Improved public search capabilities with faster response times
when filtering search results;
(e) Updated record retention and amendment aspects to keep a backup
copy of every disclosure submitted to FracFocus;
(f) Adopted established record management standards to meet proper
data quality objectives;
(g) Notify the BLM through a group email box when an operator
uploads the chemical disclosure data for a well;
(h) Include a link to a downloadable file containing the data in a
machine-readable format; and
(i) Provide a date stamp when chemical disclosure data is uploaded
from the BLM operations.
These updates are addressed in the most recent iteration of
FracFocus.

[[Page 16216]]

The agreement would also require GWPC to include the BLM as a
member of the Full and Technical Committees to engage in updates and
developments to FracFocus.
The BLM expects that these requirements will yield further progress
and improvement of the FracFocus site to meet the requirements of the
rule by providing an effective chemical disclosure registry for the
hydraulic fracture fluids.
The Federal FOIA does not apply to FracFocus, because it is
operated by the GWPC, which is not an agency of the Federal Government.
However, information on FracFocus concerning Federal or tribal wells is
public information because FracFocus is a public Web site and there
would be no need for the costs of delays associated with awaiting a
response to a FOIA request. The public can access that information for
themselves.
Executive Order 13642 does not prohibit the BLM from allowing
operators to submit information through FracFocus. We believe that
FracFocus is the quickest, most cost-effective way to make the
information public. Working with FracFocus to meet the policy goals of
the Executive Order, including machine-readable formats, will be more
prompt and will use taxpayer dollars more efficiently than would the
BLM creating and managing its own database solely for chemical
disclosures.
The use of FracFocus does not constitute a conflict of interest.
The members of GWPC are the states agencies (www.gwpc.org/state-agencies) that protect and regulate groundwater resources. They do not
have a conflict of interest in operating FracFocus to serve as a way
for operators to submit data to the BLM, or in making that information
available to the public.
The use of FracFocus does not conflict with requirements for
records management. FracFocus will not be the official repository of
the chemical information required by the rule. Whether an operator
submits information to the BLM directly or through FracFocus, the BLM
will maintain access to all the relevant information. The information
will also be available on FracFocus for the benefit of the public and
state and tribal agencies.
The BLM will closely monitor FracFocus to ensure that operators
submit information in a timely manner consistent with these
regulations. Operators also have an incentive to assure that the BLM
has received the required information within the deadlines. The BLM
will be working with the GWPC to improve the ability of FracFocus to
meet the BLM's needs and of operators on Federal or tribal lands.
Estimates of Burdens
The following table shows the estimated annual paperwork burdens
associated with this rule.

Estimates of Hour Burdens
----------------------------------------------------------------------------------------------------------------
D. (column B x
A. B. C. column C)
Total hours Type of Number of Hours per
response responses response
----------------------------------------------------------------------------------------------------------------
Request for Prior Approval of Hydraulic Fracturing Job Using an 2,614 8 20,912
Application for Permit to Drill Plus a Cement Operation
Monitoring Report 43 CFR 3162.3-3(c)(1), (d), (e)(1), and
(e)(2) Form 3160-3.............................................
Request for Prior Approval of Hydraulic Fracturing Job Using a 200 8 1,600
Notice of Intent Sundry Plus a Surface Use Plan of Operations
Plus Documentation of Adequate Cementing 43 CFR 3162.3-3(c)(2),
(c)(3), (d), and (e). Form 3160-5..............................
Sundry Notices and Reports on Wells/Hydraulic Fracturing/Request 84 8 672
for Approval of Remedial Plan 43 CFR 3162.3-3(e)(3) Form 3160-5
Sundry Notices and Reports on Wells/Hydraulic Fracturing/ 2,814 8 22,512
Subsequent Report Sundry Notice 43 CFR 3162.3-3(g) and (i) Form
3160-5.........................................................
Affidavit in Support of Claim of Confidentiality 43 CFR 3162.3- 2,814 1 2,814
3(j)...........................................................
Sundry Notices and Reports on Wells/Hydraulic Fracturing/ 281 8 2,248
Variance Request 43 CFR 3162.3-3 Form 3160-5...................
-----------------------------------------------
Totals...................................................... 8,807 .............. 50,758
----------------------------------------------------------------------------------------------------------------

No capital and start-up costs are involved with this information
collection--respondents are not required to purchase additional
computer hardware or software to comply with these information
collection requirements. The Fiscal Year 2015 appropriations law (Pub.
L. 113-203) directs the BLM to charge a $6,500 processing fee for Form
3160-3, Application for Permit to Drill or Re-Enter. We estimate that
5,000 of these applications are filed annually under control number
1004-0137, and another 2,614 will be filed under control number 1004-
0203. The estimated non-hour cost burden is $32,500,000 under control
number 1004-0137, and $16,991,000 under 1004-0203. The total estimated
non-hour cost burden is $49,491,000.

National Environmental Policy Act

The BLM has prepared an environmental assessment (EA) that
concludes that this rule will not constitute a major Federal action
that may result in a significant effect on the human environment under
section 102(2)(C) of the National Environmental Policy Act (NEPA), 42
U.S.C. 4332(2)(C). The EA, the Finding of No Significant Impact, and
the Decision Record are available for review and on file in the BLM
Administrative Record at the address specified in the ADDRESSES
section.

Data Quality Act

In developing this rule, the BLM did not conduct or use a study,
experiment, or survey requiring peer review under the Data Quality Act
(Pub. L. 106-554).

Executive Order 13211, Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use

Under Executive Order 13211, agencies are required to prepare and
submit to OMB a Statement of Energy Effects for significant energy
actions. This Statement is to include a detailed

[[Page 16217]]

statement of ``any adverse effects of energy supply, distribution, or
use (including a shortfall in supply, price increases, and increase use
of foreign supplies)'' for the action and reasonable alternatives and
their effects.
Section 4(b) of Executive Order 13211 defines a ``significant
energy action'' as ``any action by an agency (normally published in the
Federal Register) that promulgates or is expected to lead to the
promulgation of a final rule or regulation, including notices of
inquiry, advance notices of proposed rulemaking, and notices of
proposed rulemaking: (1)(i) That is a significant regulatory action
under Executive Order 12866 or any successor order, and (ii) is likely
to have a significant adverse effect on the supply, distribution, or
use of energy; or 2) That is designated by the Administrator of OIRA as
a significant energy action.''
The BLM believes that the additional cost per hydraulic fracturing
operation is insignificant when compared with the drilling costs in
recent years, the production gains from hydraulically fractured well
operations, and the net incomes of entities within the oil and natural
gas industries. For the average hydraulic fracturing operation, the
compliance costs represent about 0.13 to 0.21 percent of the cost of
drilling a well.
Since the estimated compliance costs are not substantial when
compared with the total costs of drilling a well, the BLM believes that
the rule is unlikely to have an effect on the investment decisions of
firms, and the rule is unlikely to affect the supply, distribution, or
use of energy. As such, the rule is not a ``significant energy action''
as defined in Executive Order 13211.

Authors

The principal authors of this rule are: Bryce Barlan, Program
Analysis Officer, BLM Washington Office; James Tichenor, Economist, BLM
Washington Office; Gerald Dickinson, Petroleum Engineer, BLM Rawlins
Field Office; John Ajak, Petroleum Engineer, Washington Office; John
Pecor, Petroleum Engineer, BLM Tre Rios Field Office; Rich Estabrook,
Petroleum Engineer, BLM Washington Office; Rosemary Herrell, Senior
Policy Analyst, BLM Washington Office; Steven Wells, Division Chief,
Fluid Minerals, BLM Washington Office; Subijoy Dutta, Senior Petroleum
Engineer, BLM Washington Office; Will Lambert, Petroleum Engineer, BLM
Washington Office; Allen McKee, Petroleum Engineer, BLM Utah State
Office; Don Judice, Field Manager, BLM Great Falls Field Office; Bev
Winston, Public Affairs Specialist, BLM Washington Office; assisted by
the BLM's Division of Regulatory Affairs and the Department of the
Interior's Office of the Solicitor.

List of Subjects 43 CFR Part 3160

Administrative practice and procedure, Government contracts,
Indians-lands, Mineral royalties, Oil and gas exploration, Penalties,
Public lands-mineral resources, Reporting and recordkeeping
requirements.

For the reasons stated in the preamble, and under the authorities
stated below, the Bureau of Land Management amends 43 CFR part 3160 as
follows:

PART 3160--ONSHORE OIL AND GAS OPERATIONS

0
1. The authority citation for part 3160 is revised to read as follows:

Authority: 25 U.S.C. 396d and 2107; 30 U.S.C. 189, 306, 359,
and 1751; and 43 U.S.C. 1732(b), 1733, and 1740.

Subpart 3160--Onshore Oil and Gas Operations: General

Sec. 3160.0-3 [Amended]

0
2. In Sec. 3160.0-3 add ``the Federal Land Policy and Management Act
(43 U.S.C. 1701 et seq.),'' after ``the Mineral Leasing Act for
Acquired lands, as amended (30 U.S.C. 351-359),''.

0
3. Amend Sec. 3160.0-5 by adding definitions of ``annulus,''
``bradenhead,'' ``Cement Evaluation Log (CEL),'' ``confining zone,''
``hydraulic fracturing,'' ``hydraulic fracturing fluid,'' ``isolating
or to isolate,'' ``master hydraulic fracturing plan,'' ``proppant,''
and ``usable water,'' in alphabetical order and by removing the
definition of ``fresh water'' to read as follows:

Sec. 3160.0-5 Definitions.

* * * * *
Annulus means the space around a pipe in a wellbore, the outer wall
of which may be the wall of either the borehole or casing; sometimes
also called annular space.
* * * * *
Bradenhead means a heavy, flanged steel fitting connected to the
first string of casing that allows the suspension of intermediate and
production strings of casing and supplies the means for the annulus to
be sealed.
Cement Evaluation Log (CEL) means any one of a class of tools that
verify the integrity of annular cement bonding, such as, but not
limited to, a cement bond log (CBL), ultrasonic imaging log, variable
density logs, CBLs with directional receiver array, ultrasonic pulse
echo log, or isolation scanner.
Confining zone means a geological formation, group of formations,
or part of a formation that is capable of preventing fluid movement
from any formation that will be hydraulically fractured into a usable
water zone.
* * * * *
Hydraulic fracturing means those operations conducted in an
individual wellbore designed to increase the flow of hydrocarbons from
the rock formation to the wellbore through modifying the permeability
of reservoir rock by applying fluids under pressure to fracture it.
Hydraulic fracturing does not include enhanced secondary recovery such
as water flooding, tertiary recovery, recovery through steam injection,
or other types of well stimulation operations such as acidizing.
Hydraulic fracturing fluid means the liquid or gas, and any
associated solids, used in hydraulic fracturing, including constituents
such as water, chemicals, and proppants.
Isolating or to isolate means using cement to protect, separate, or
segregate usable water and mineral resources.
* * * * *
Master hydraulic fracturing plan means a plan containing the
information required in section 3162.3-3(d) of this part for a group of
wells where the geologic characteristics for each well are
substantially similar.
* * * * *
Proppant means a granular substance (most commonly sand, sintered
bauxite, or ceramic) that is carried in suspension by the fracturing
fluid that serves to keep the cracks in the geologic formation open
when fracturing fluid is withdrawn after a hydraulic fracture
operation.
* * * * *
Usable water means
(1) Generally those waters containing up to 10,000 parts per
million (ppm) of total dissolved solids. Usable water includes, but is
not limited to:
(i) Underground water that meets the definition of ``underground
source of drinking water'' as defined at 40 CFR 144.3;
(ii) Underground sources of drinking water under the law of the
State (for Federal lands) or tribe (for Indian lands); and
(iii) Water in zones designated by the State (for Federal lands) or
tribe (for Indian lands) as requiring isolation or protection from
hydraulic fracturing operations.
(2) The following geologic zones are deemed not to contain usable
water:

[[Page 16218]]

(i) Zones from which the BLM has authorized an operator to produce
oil and gas, provided that the operator has obtained all other
authorizations required by the Environmental Protection Agency, the
State (for Federal lands), or the tribe (for Indian lands) to conduct
hydraulic fracturing operations in the specific zone;
(ii) Zones designated as exempted aquifers pursuant to 40 CFR
144.7; and
(iii) Zones that do not meet the definition of underground source
of drinking water at 40 CFR 144.3 which the State (for Federal lands)
or the tribe (for Indian lands) has designated as exempt from any
requirement to be isolated or protected from hydraulic fracturing
operations.
* * * * *

Subpart 3162--Requirements for Operating Rights Owners and
Operators

0
4. Amend Sec. 3162.3-2 by revising the first sentence of paragraph (a)
and revising paragraph (b) to read as follows:

Sec. 3162.3-2 Subsequent well operations.

(a) A proposal for further well operations must be submitted by the
operator on a Sundry Notice and Report on Wells (Form 3160-5) as a
Notice of Intent for approval by the authorized officer prior to
commencing operations to redrill, deepen, perform casing repairs, plug-
back, alter casing, recomplete in a different interval, perform water
shut off, combine production between zones, and/or convert to
injection. * * *
(b) Unless additional surface disturbance is involved and if the
operations conform to the standard of prudent operating practice, prior
approval is not required for acidizing jobs or recompletion in the same
interval; however, a subsequent report on these operations must be
filed using a Sundry Notice and Report on Wells (Form 3160-5).
* * * * *

0
5. Revise Sec. 3162.3-3 to read as follows:

Sec. 3162.3-3 Subsequent well operations; Hydraulic fracturing.

(a) Activities to which this section applies. This section, or
portions of this section, apply to hydraulic fracturing as shown in the
following table:

------------------------------------------------------------------------
If . . . Then
------------------------------------------------------------------------
(1) No APD was submitted as of June 24, The operator must comply
2015. with all paragraphs of this
section.
(2) An APD was submitted but not approved
as of June 24, 2015.
(3) An APD or APD extension was approved To conduct hydraulic
before June 24, 2015, but the authorized fracturing within 90 days
drilling operations did not begin until after the effective date of
after June 24, 2015. this rule, the operator
must comply with all
paragraphs of this section,
except (c) and (d).
(4) Authorized drilling operations began, ............................
but were not completed before June 24,
2015.
(5) Authorized drilling operations were
completed after September 22, 2015.
(6) Authorized drilling activities were The operator must comply
completed before September 22, 2015. with all paragraphs of this
section.
------------------------------------------------------------------------

(b) Isolation of usable water to prevent contamination. All
hydraulic fracturing operations must meet the performance standard in
section 3162.5-2(d) of this title.
(c) How an operator must submit a request for approval of hydraulic
fracturing. A request for approval of hydraulic fracturing must be
submitted by the operator and approved by the authorized officer before
commencement of operations. The operator may submit the request in one
of the following ways:
(1) With an application for permit to drill; or
(2) With a Sundry Notice and Report on Wells (Form 3160-5) as a
notice of intent (NOI).
(3) For approval of a group of wells submitted under either
paragraph (c)(1) or (2) of this section, the operator may submit a
master hydraulic fracturing plan. Submission of a master hydraulic
fracturing plan does not obviate the need to obtain an approved APD
from the BLM for each individual well.
(4) If an operator has received approval from the authorized
officer for hydraulic fracturing operations, and the operator has
significant new information about the geology of the area, the
stimulation operation or technology to be used, or the anticipated
impacts of the hydraulic fracturing operation to any resource, then the
operator must submit a new NOI (Form 3160-5). Significant new
information includes, but is not limited to, information that changes
the proposed drilling or completion of the well, the hydraulic
fracturing operation, or indicates increased risk of contamination of
zones containing usable water or other minerals.
(d) What a request for approval of hydraulic fracturing must
include. The request for approval of hydraulic fracturing must include
the information in this paragraph. If the information required by this
paragraph has been assembled to comply with State law (on Federal
lands) or tribal law (on Indian lands), such information may be
submitted to the BLM authorized officer as provided to the State or
tribal officials as part of the APD or NOI (Form 3160-5).
(1) The following information regarding wellbore geology:
(i) The geologic names, a geologic description, and the estimated
depths (measured and true vertical) to the top and bottom of the
formation into which hydraulic fracturing fluids are to be injected;
(ii) The estimated depths (measured and true vertical) to the top
and bottom of the confining zone(s); and
(iii) The estimated depths (measured and true vertical) to the top
and bottom of all occurrences of usable water based on the best
available information.
(2) A map showing the location, orientation, and extent of any
known or suspected faults or fractures within one-half mile (horizontal
distance) of the wellbore trajectory that may transect the confining
zone(s). The map must be of a scale no smaller than 1:24,000.
(3) Information concerning the source and location of water supply,
such as reused or recycled water, rivers, creeks, springs, lakes,
ponds, and water supply wells, which may be shown by quarter-quarter
section on a map or plat, or which may be described in writing. It must
also identify the anticipated access route and transportation method
for all water planned for use in hydraulically fracturing the well;
(4) A plan for the proposed hydraulic fracturing design that
includes, but is not limited to, the following:
(i) The estimated total volume of fluid to be used;
(ii) The maximum anticipated surface pressure that will be applied
during the hydraulic fracturing process;

[[Page 16219]]

(iii) A map at a scale no smaller than 1:24,000 showing:
(A) The trajectory of the wellbore into which hydraulic fracturing
fluids are to be injected;
(B) The estimated direction and length of the fractures that will
be propagated and a notation indicating the true vertical depth of the
top and bottom of the fractures; and
(C) All existing wellbore trajectories, regardless of type, within
one-half mile (horizontal distance) of any portion of the wellbore into
which hydraulic fracturing fluids are to be injected. The true vertical
depth of each wellbore identified on the map must be indicated.
(iv) The estimated minimum vertical distance between the top of the
fracture zone and the nearest usable water zone; and
(v) The measured depth of the proposed perforated or open-hole
interval.
(5) The following information concerning the handling of fluids
recovered between the commencement of hydraulic fracturing operations
and the approval of a plan for the disposal of produced fluid under BLM
requirements:
(i) The estimated volume of fluid to be recovered;
(ii) The proposed methods of handling the recovered fluids as
required under paragraph (h) of this section; and
(iii) The proposed disposal method of the recovered fluids,
including, but not limited to, injection, storage, and recycling.
(6) If the operator submits a request for approval of hydraulic
fracturing with an NOI (Form 3160-5), the following information must
also be submitted:
(i) A surface use plan of operations, if the hydraulic fracturing
operation would cause additional surface disturbance; and
(ii) Documentation required in paragraph (e) or other documentation
demonstrating to the authorized officer that the casing and cement have
isolated usable water zones, if the proposal is to hydraulically
fracture a well that was completed without hydraulic fracturing.
(7) The authorized officer may request additional information prior
to the approval of the NOI (Form 3160-5) or APD.
(e) Monitoring and verification of cementing operations prior to
hydraulic fracturing. (1)(i) During cementing operations on any casing
used to isolate and protect usable water zones, the operator must
monitor and record the flow rate, density, and pump pressure, and
submit a cement operation monitoring report for each casing string used
to isolate and protect usable water to the authorized officer prior to
commencing hydraulic fracturing operations. The cement operation
monitoring report must be provided at least 48 hours prior to
commencing hydraulic fracturing operations unless the authorized
officer approves a shorter time.
(ii) For any well completed pursuant to an APD that did not
authorize hydraulic fracturing operations, the operator must submit
documentation to demonstrate that adequate cementing was achieved for
all casing strings designed to isolate and protect usable water. The
operator must submit the documentation with its request for approval of
hydraulic fracturing operations, or no less than 48 hours prior to
conducting hydraulic fracturing operations if no prior approval is
required, pursuant to paragraph (a) of this section. The authorized
officer may approve the hydraulic fracturing of the well only if the
documentation provides assurance that the cementing was sufficient to
isolate and to protect usable water, and may require such additional
tests, verifications, cementing or other protection or isolation
operations, as the authorized officer deems necessary.
(2) Prior to starting hydraulic fracturing operations, the operator
must determine and document that there is adequate cement for all
casing strings used to isolate and protect usable water zones as
follows:
(i) Surface casing. The operator must observe cement returns to
surface and document any indications of inadequate cement (such as, but
not limited to, lost returns, cement channeling, gas cut mud, failure
of equipment, or fallback from the surface exceeding 10 percent of
surface casing setting depth or 200 feet, whichever is less). If there
are indications of inadequate cement, then the operator must determine
the top of cement with a CEL, temperature log, or other method or
device approved in advance by the authorized officer.
(ii) Intermediate and production casing. (A) If the casing is not
cemented to surface, then the operator must run a CEL to demonstrate
that there is at least 200 feet of adequately bonded cement between the
zone to be hydraulically fractured and the deepest usable water zone.
(B) If the casing is cemented to surface, then the operator must
follow the requirements of paragraph (e)(2)(i) of this section.
(3) For any well, if there is an indication of inadequate cement on
any casing used to isolate usable water, then the operator must:
(i) Notify the authorized officer within 24 hours of discovering
the inadequate cement;
(ii) Submit an NOI (Form 3160-5) to the authorized officer
requesting approval of a plan to perform remedial action to achieve
adequate cement. The plan must include the supporting documentation and
logs required under paragraph (e)(2) of this section. In emergency
situations, an operator may request oral approval from the authorized
officer for actions to be undertaken to remediate the cement. However,
such requests must be followed by a written notice filed not later than
the fifth business day following oral approval;
(iii) Verify that the remedial action was successful with a CEL or
other method approved in advance by the authorized officer;
(iv) Submit a Sundry Notice and Report on Wells (Form 3160-5) as a
subsequent report for the remedial action including:
(A) A signed certification that the operator corrected the
inadequate cement job in accordance with the approved plan; and
(B) The results from the CEL or other method approved by the
authorized officer showing that there is adequate cement.
(v) The operator must submit the results from the CEL or other
method approved by the authorized officer (see paragraph (e)(3)(iv)(B)
of this section) at least 72 hours before starting hydraulic fracturing
operations.
(f) Mechanical integrity testing prior to hydraulic fracturing.
Prior to hydraulic fracturing, the operator must perform a successful
mechanical integrity test, as follows:
(1) If hydraulic fracturing through the casing is proposed, the
casing must be tested to not less than the maximum anticipated surface
pressure that will be applied during the hydraulic fracturing process.
(2) If hydraulic fracturing through a fracturing string is
proposed, the fracturing string must be inserted into a liner or run on
a packer-set not less than 100 feet below the cement top of the
production or intermediate casing. The fracturing string must be tested
to not less than the maximum anticipated surface pressure minus the
annulus pressure applied between the fracturing string and the
production or intermediate casing.
(3) The mechanical integrity test will be considered successful if
the pressure applied holds for 30 minutes with no more than a 10
percent pressure loss.
(g) Monitoring and recording during hydraulic fracturing.

[[Page 16220]]

(1) During any hydraulic fracturing operation, the operator must
continuously monitor and record the annulus pressure at the bradenhead.
The pressure in the annulus between any intermediate casings and the
production casing must also be continuously monitored and recorded. A
continuous record of all annuli pressure during the fracturing
operation must be submitted with the required Subsequent Report Sundry
Notice (Form 3160-5) identified in paragraph (i) of this section.
(2) If during any hydraulic fracturing operation any annulus
pressure increases by more than 500 pounds per square inch as compared
to the pressure immediately preceding the stimulation, the operator
must stop the hydraulic fracturing operation, take immediate corrective
action to control the situation, orally notify the authorized officer
as soon as practicable, but no later than 24 hours following the
incident, and determine the reasons for the pressure increase. Prior to
recommencing hydraulic fracturing operations, the operator must perform
any remedial action required by the authorized officer, and
successfully perform a mechanical integrity test under paragraph (f) of
this section. Within 30 days after the hydraulic fracturing operations
are completed, the operator must submit a report containing all details
pertaining to the incident, including corrective actions taken, as part
of a Subsequent Report Sundry Notice (Form 3160-5).
(h) Management of Recovered Fluids. Except as provided in
paragraphs (h)(1) and ((2) of this section, all fluids recovered
between the commencement of hydraulic fracturing operations and the
authorized officer's approval of a produced water disposal plan under
BLM requirements must be stored in rigid enclosed, covered, or netted
and screened above-ground tanks. The tanks may be vented, unless
Federal law, or State regulations (on Federal lands) or tribal
regulations (on Indian lands) require vapor recovery or closed-loop
systems. The tanks must not exceed a 500 barrel (bbl) capacity unless
approved in advance by the authorized officer.
(1) The authorized officer may approve an application to use lined
pits only if the applicant demonstrates that use of a tank as described
in this paragraph (h) is infeasible for environmental, public health or
safety reasons and only if, at a minimum, all of the following
conditions apply:
(i) The distance from the pit to intermittent or ephemeral streams
or water sources would be at least 300 feet;
(ii) The distance from the pit to perennial streams, springs, fresh
water sources, or wetlands would be at least 500 feet;
(iii) There is no usable groundwater within 50 feet of the surface
in the area where the pit would be located;
(iv) The distance from the pit to any occupied residence, school,
park, school bus stop, place of business, or other areas where the
public could reasonably be expected to frequent would be greater than
300 feet;
(v) The pit would not be constructed in fill or unstable areas;
(vi) The construction of the pit would not adversely impact the
hydrologic functions of a 100-year floodplain; and
(vii) Pit use and location complies with applicable local, State
(on Federal lands), tribal (on Indian lands) and other Federal statutes
and regulations including those that are more stringent than these
regulations.
(2) Pits approved by the authorized officer must be:
(i) Lined with a durable, leak-proof synthetic material and
equipped with a leak detection system; and
(ii) Routinely inspected and maintained, as required by the
authorized officer, to ensure that there is no fluid leakage into the
environment. The operator must document all inspections.
(i) Information that must be provided to the authorized officer
after hydraulic fracturing is completed. The information required in
paragraphs (i)(1) through (10) of this section must be submitted to the
authorized officer within 30 days after the completion of the last
stage of hydraulic fracturing operations for each well. The information
is required for each well, even if the authorized officer approved
fracturing of a group of wells (see Sec. 3162.3-3(c)). The information
required in paragraph (i)(1) of this section must be submitted to the
authorized officer through FracFocus or another BLM-designated
database, or in a Subsequent Report Sundry Notice (Form 3160-5). If
information is submitted through FracFocus or another BLM-designated
database, the operator must specify that the information is for a
Federal or an Indian well, certify that the information is both timely
filed and correct, and certify compliance with applicable law as
required by paragraph (i)(8)(ii) or (iii) of this section using
FracFocus or another BLM-designated database. The information required
in paragraphs (i)(2) though (10) of this section must be submitted to
the authorized officer in a Subsequent Report Sundry Notice (Form 3160-
5). The operator is responsible for the information submitted by a
contractor or agent, and the information will be considered to have
been submitted directly from the operator to the BLM. The operator must
submit the following information:
(1) The true vertical depth of the well, total water volume used,
and a description of the base fluid and each additive in the hydraulic
fracturing fluid, including the trade name, supplier, purpose,
ingredients, Chemical Abstract Service Number (CAS), maximum ingredient
concentration in additive (percent by mass), and maximum ingredient
concentration in hydraulic fracturing fluid (percent by mass).
(2) The actual source(s) and location(s) of the water used in the
hydraulic fracturing fluid;
(3) The maximum surface pressure and rate at the end of each stage
of the hydraulic fracturing operation and the actual flush volume.
(4) The actual, estimated, or calculated fracture length, height
and direction.
(5) The actual measured depth of perforations or the open-hole
interval.
(6) The total volume of fluid recovered between the completion of
the last stage of hydraulic fracturing operations and when the operator
starts to report water produced from the well to the Office of Natural
Resources Revenue. If the operator has not begun to report produced
water to the Office of Natural Resources Revenue when the Subsequent
Report Sundry Notice is submitted, the operator must submit a
supplemental Subsequent Report Sundry Notice (Form 3160-5) to the
authorized officer documenting the total volume of recovered fluid.
(7) The following information concerning the handling of fluids
recovered, covering the period between the commencement of hydraulic
fracturing and the implementation of the approved plan for the disposal
of produced water under BLM requirements:
(i) The methods of handling the recovered fluids, including, but
not limited to, transfer pipes and tankers, holding pond use, re-use
for other stimulation activities, or injection; and
(ii) The disposal method of the recovered fluids, including, but
not limited to, the percent injected, the percent stored at an off-
lease disposal facility, and the percent recycled.
(8) A certification signed by the operator that:
(i) The operator complied with the requirements in paragraphs (b),
(e), (f), (g), and (h) of this section;
(ii) For Federal lands, the hydraulic fracturing fluid
constituents, once they

[[Page 16221]]

arrived on the lease, complied with all applicable permitting and
notice requirements as well as all applicable Federal, State, and local
laws, rules, and regulations; and
(iii) For Indian lands, the hydraulic fracturing fluid
constituents, once they arrived on the lease, complied with all
applicable permitting and notice requirements as well as all applicable
Federal and tribal laws, rules, and regulations.
(9) The operator must submit the result of the mechanical integrity
test as required by paragraph (f) of this section.
(10) The authorized officer may require the operator to provide
documentation substantiating any information submitted under paragraph
(i) of this section.
(j) Identifying information claimed to be exempt from public
disclosure.
(1) For the information required in paragraph (i) of this section,
the operator and the owner of the information will be deemed to have
waived any right to protect from public disclosure information
submitted with a Subsequent Report Sundry Notice (Form 3160-5) or
through FracFocus or another BLM-designated database. For information
required in paragraph (i) of this section that the owner of the
information claims to be exempt from public disclosure and is withheld
from the BLM, a corporate officer, managing partner, or sole proprietor
of the operator must sign and the operator must submit to the
authorized officer with the Subsequent Report Sundry Notice (Form 3160-
5) required in paragraph (i) of this section an affidavit that:
(i) Identifies the owner of the withheld information and provides
the name, address and contact information for a corporate officer,
managing partner, or sole proprietor of the owner of the information;
(ii) Identifies the Federal statute or regulation that would
prohibit the BLM from publicly disclosing the information if it were in
the BLM's possession;
(iii) Affirms that the operator has been provided the withheld
information from the owner of the information and is maintaining
records of the withheld information, or that the operator has access
and will maintain access to the withheld information held by the owner
of the information;
(iv) Affirms that the information is not publicly available;
(v) Affirms that the information is not required to be publicly
disclosed under any applicable local, State or Federal law (on Federal
lands), or tribal or Federal law (on Indian lands);
(vi) Affirms that the owner of the information is in actual
competition and identifies competitors or others that could use the
withheld information to cause the owner of the information substantial
competitive harm;
(vii) Affirms that the release of the information would likely
cause substantial competitive harm to the owner of the information and
provides the factual basis for that affirmation; and
(viii) Affirms that the information is not readily apparent through
reverse engineering with publicly available information.
(2) If the operator relies upon information from third parties,
such as the owner of the withheld information, to make the affirmations
in paragraphs (j)(1)(vi) through (viii) of this section, the operator
must provide a written affidavit from the third party that sets forth
the relied-upon information.
(3) The BLM may require any operator to submit to the BLM any
withheld information, and any information relevant to a claim that
withheld information is exempt from public disclosure.
(4) If the BLM determines that the information submitted under
paragraph (j)(3) of this section is not exempt from disclosure, the BLM
will make the information available to the public after providing the
operator and owner of the information with no fewer than 10 business
days' notice of the BLM's determination.
(5) The operator must maintain records of the withheld information
until the later of the BLM's approval of a final abandonment notice, or
6 years after completion of hydraulic fracturing operations on Indian
lands, or 7 years after completion of hydraulic fracturing operations
on Federal lands. Any subsequent operator will be responsible for
maintaining access to records required by this paragraph during its
operation of the well. The operator will be deemed to be maintaining
the records if it can promptly provide the complete and accurate
information to BLM, even if the information is in the custody of its
owner.
(6) If any of the chemical identity information required in
paragraph (i)(1) of this section is withheld, the operator must provide
the generic chemical name in the submission required by paragraph
(i)(1) of this section. The generic chemical name must be only as
nonspecific as is necessary to protect the confidential chemical
identity, and should be the same as or no less descriptive than the
generic chemical name provided to the Environmental Protection Agency.
(k) Requesting a variance from the requirements of this section.
(1) Individual variance: The operator may make a written request to
the authorized officer for a variance from the requirements under this
section. A request for an individual variance must specifically
identify the regulatory provision of this section for which the
variance is being requested, explain the reason the variance is needed,
and demonstrate how the operator will satisfy the objectives of the
regulation for which the variance is being requested.
(2) State or tribal variance: In cooperation with a State (for
Federal lands) or a tribe (for Indian lands), the appropriate BLM State
Director may issue a variance that would apply to all wells within a
State or within Indian lands, or to specific fields or basins within
the State or the Indian lands, if the BLM finds that the variance meets
the criteria in paragraph (k)(3) of this section. A State or tribal
variance request or decision must specifically identify the regulatory
provision(s) of this section for which the variance is being requested,
explain the reason the variance is needed, and demonstrate how the
operator will satisfy the objectives of the regulation for which the
variance is being requested. A State or tribal variance may be
initiated by the State, tribe, or the BLM.
(3) The authorized officer (for an individual variance), or the
State Director (for a State or tribal variance), after considering all
relevant factors, may approve the variance, or approve it with one or
more conditions of approval, only if the BLM determines that the
proposed alternative meets or exceeds the objectives of the regulation
for which the variance is being requested. The decision whether to
grant or deny the variance request must be in writing and is entirely
within the BLM's discretion. The decision on a variance request is not
subject to administrative appeals either to the State Director (for an
individual variance) or under 43 CFR part 4.
(4) A variance under this section does not constitute a variance to
provisions of other regulations, laws, or orders.
(5) Due to changes in Federal law, technology, regulation, BLM
policy, field operations, noncompliance, or other reasons, the BLM
reserves the right to rescind a variance or modify any conditions of
approval. The authorized officer must provide a written justification
before a variance is rescinded or a condition of approval is modified.

[[Page 16222]]

0
6. Amend Sec. 3162.5-2 by revising the first sentence of paragraph (d)
to read as follows:

Sec. 3162.5-2 Control of wells.

* * * * *
(d) Protection of usable water and other minerals. The operator
must isolate all usable water and other mineral-bearing formations and
protect them from contamination. * * *

Janice M. Schneider,
Assistant Secretary, Land and Minerals Management.
[FR Doc. 2015-06658 Filed 3-20-15; 4:15 pm]
BILLING CODE 4310-84-P