[Federal Register Volume 59, Number 93 (Monday, May 16, 1994)]
[Unknown Section]
[Page 0]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 94-11601]


[[Page Unknown]]

[Federal Register: May 16, 1994]


=======================================================================
-----------------------------------------------------------------------

DEPARTMENT OF THE INTERIOR

Minerals Management Service

30 CFR Part 250

RIN 1010-AB52

 

Safety Requirements Governing Production Platforms and Pipelines

AGENCY: Minerals Management Service, Interior.

ACTION: Proposed rule.

-----------------------------------------------------------------------

SUMMARY: This rule proposes to revise various safety-related 
regulations regarding the design and operating procedures of production 
platforms and pipelines in the Outer Continental Shelf (OCS). The 
purpose of the revisions is to reduce or prevent the unintentional 
release of hydrocarbons from pipelines on or near offshore platforms 
during emergency situations and thereby reduce the potential for 
explosions or fires.

DATES: Comments must be received or postmarked no later than July 15, 
1994.

ADDRESSES: Comments should be mailed or hand-carried to the Department 
of the Interior, Minerals Management Service, Mail Stop 4700, 381 Elden 
Street, Herndon, Virginia 22070-4817; Attention: Chief, Engineering and 
Standards Branch.

FOR FURTHER INFORMATION CONTACT: Paul Schneider, Technology Assessment 
and Research Branch, telephone (703) 787-1559, or Bill Hauser, 
Engineering and Standards Branch, telephone (703) 787-1600.

SUPPLEMENTARY INFORMATION:

Background

    The MMS is proposing to revise regulations governing design, 
operation, and maintenance of oil and gas facilities in the OCS. These 
revisions were recommended by an internal task group that reviewed 
information on tow tragic offshore incidents in 1988 and 1989.

Safety Review Task Group

    A safety review task group of MMS personnel was established to 
review available information in the 1988 Piper Alpha platform fire in 
the North Sea and the circumstances related to an interactive pipeline 
and platform fire in 1989 at ARCO Oil and Gas Company's (ARCO) South 
Pass 60 Platform ``B'' facility in the Gulf of Mexico. The group was 
asked to make specific recommendations regarding regulations and 
operating practices that would reduce the risk of such incidents 
occurring in U.S. waters. Following is a capsule summary of each 
incident.

Explosion and Fire on Piper Alpha Platform, North Sea, 1988

    Piper Alpha was an oil and gas production platform in the United 
Kingdom (U.K.) sector of the North Sea that was destroyed by fire in 
1988. On July 6, 1988, a series of events and operational mistakes 
caused an explosion and fires that ultimately destroyed the platform 
and killed 167 people. Maintenance personnel mistakenly activated an 
out-of-service injection pump causing a repair flange in the pipework 
to rupture. Liquid condensate leaked into the production module for 
several minutes. The gas ignited and exploded, damaging the electrical 
power generator and the fire pumps. Eventually the fire ruptured the 
shut-in gas pipelines releasing high pressure gas on the platform. The 
fire burned for several hours until the pressure was relieved. The 
platform was completely destroyed.
    The Public Inquiry into the Piper Alpha Disaster was published by 
Her Majesty's Stationery Office, London, in November 1990. The report 
confirmed the conclusions reached in the initial investigation report 
published in September 1988. The report concluded that in all 
likelihood the scenario of the leaking blind flange in the condensate 
injector pump was the initial cause of the incident. The report lists 
106 recommendations for improving safety in the U.K. North Sea. The 
recommendations propose changes to the regulations, regulatory agency 
realignment, and a call for renewed commitment to safety by industry.

Summary of South Pass 60 Platform ``B'' Fire

    On March 19, 1989, an offshore contracting crew was ``cold-
cutting'' an 18-inch gas line riser at the platform's 10-foot level in 
preparation for the installation of a pig trap. ``Cold cutting'' is a 
method of cutting through a section of pipe with a mechanical cutting 
tool as opposed to using a blow torch. Upon penetration into the 
pipeline riser, pressurized condensate began to spray from the cut 
area. The condensate was ignited either by sparks generated on the 
compressor skid on an attendant workboat or by hot exhaust pipes on the 
above production deck. The fire raged upward from the riser, and the 
emergency shutdown (ESD) system shut down both Platform ``B'' and 
Platform ``E'' and all incoming and departing pipelines. Six of the 10 
incoming and departing pipelines, including a high pressure gas line, 
ruptured from the heat of the fire. The resulting explosions killed 
seven people and destroyed the platform.

Federal Register Notice on Subsea Pipeline Valves

    In support of the work of the task group, MMS published a Federal 
Register Notice dated July 23, 1990 (55 FR 29860), seeking information 
on subsea shutdown valve (SDV) technology and feasibility and offshore 
emergency pipeline pressure reduction techniques. Thirty companies and 
organizations representing oil- and gas-related industries responded to 
the questionnaire. Their responses are discussed later in the preamble.

Task Group Findings

    The MMS task group identified the following areas in the 
regulations that should be revised:

    1. Identification and notification procedures for out-of-service 
safety devices and systems.
    2. Location and protection of pipeline risers.
    3. Diesel and helicopter fuel storage areas and tanks.
    4. Approval of pipeline repairs.
    5. Location of ESD valves on pipelines.

Identification and Notification Procedures for Out-of-Service Safety 
Devices

    A contributing factor to both accidents was the lack of 
communication and notification to personnel of the platform production 
systems status. In the Piper Alpha incident, the production crew 
attempted to start a condensate injection pump that was partially 
dismantled for repairs during the previous shift. Leaking condensate 
from the associated pipework of the pump caused the first of a series 
of explosions and fires. The location of the pump control panel did not 
allow the operator of the control panel to view the pump or detect the 
leak. In the South Pass 60 incident, the platform operator and the 
pipeline company did not provide for adequate planning and coordination 
of the riser cutting operation. Platform personnel were apparently 
unaware of the status of the riser cutting operation or the difficulty 
the contractor was experiencing with the unexpected flow.
    Current regulations for identifying out-of-service devices are 
found at:
    30 CFR 250.123(c), General platform operations. (1) Surface or 
subsurface safety devices shall not be bypassd or blocked out of 
service unless they are temporarily out of service for startup, 
maintenance, or testing procedures. Only the minimum number of safety 
devices shall be taken out of service. Personnel shall monitor the 
bypassed or blocked-out functions until the safety devices are placed 
back in service. Any surface or subsurface safety device which is 
temporarily out of service shall be flagged.
    Requirements for out-of-service devices on pipelines are found at 
30 CFR 250.154(c). If the required safety equipment is rendered 
ineffective or removed from service on pipelines which are continued in 
operation, an equivalent degree of safety shall be provided. The safety 
equipment shall be identified by the placement of a sign on the 
equipment stating that the equipment is rendered ineffective or removed 
from service.
    The task group determined that the existing regulations do not 
provide for adequate communication or warning of out-of-service 
equipment and may not have prevented an accident similar to Piper Alpha 
if the same set of circumstances existed in the OCS. The current rule 
does not ensure that accidental flow of hydrocarbons will not be 
initiated in process components that are taken out of service, 
particularly if flow is initiated out of view of a flagged device or 
control. Flagging requirements for out-of-service equipment and valves 
need to be revised to ensure that control panels and certain equipment 
upstream of process equipment or valves are also flagged and that the 
procedure is documented. The task group recommended that the 
regulations should include requirements identifying which individuals 
have the authority to remove flags and to authorize equipment startup. 
It also recommended that subpart A be revised to include a briefing 
requirement to ensure that all workers on a production platform are 
notified of all out-of-service equipment and safety concerns at the 
beginning of each work shift or upon addition or replacement of 
personnel.

Location and Protection of Pipeline Risers

    From the evidence gathered on Piper Alpha, at least one of the 
highly pressured risers ruptured when struck by debris falling from the 
burning platform. The effect of gas escaping from the high pressure 
pipeline was catastrophic. The escaping gas boiled to the surface, 
exploded, and burned under the platform for several hours.
    Subpart J of the regulations currently requires risers to be 
protected only from contact with floating vessels. Protection is 
usually accomplished by locating risers between the jacket legs or by 
reinforcing the risers with external protection. The task group 
recommended that subpart J be revised to add a requirement to provide 
for riser protection from falling objects as well and that MMS require 
submission of piping drawings at an early stage in the platform design 
approval process.

Diesel and Helicopter Fuel Storage Areas and Tanks

    During the early stages of the Piper Alpha incident, fuel drums and 
containers of lubricants and cleaners stored throughout the platform 
exploded and burned when they were exposed to flames. These materials 
are stored in a similar manner on U.S. facilities.
    There are no current MMS regulations for fuel storage. The task 
group recommended that MMS revise the regulations to require operators 
to store diesel and other flammable liquids on platforms in accordance 
with the requirements contained in American Petroleum Institute (API) 
Recommended Practice (RP) 500, Recommended Practice for Classification 
of Locations for Electrical Installation at Petroleum Facilities. The 
task group also recommended that the revised regulations require 
operators to design fuel storage tanks in accordance with API RP 14C, 
Recommended Practice for Analysis, Design, Installation and Testing of 
Basic Surface Safety Systems for Offshore Production Platforms.

Approval of Pipeline Repairs

    Upon examination of the events leading to the fire on the ARCO 
``B'' platform, the task group found that there was a lack of 
communication and coordination between the platform operator and the 
pipeline repair company. The task group recommended that the 
regulations be strengthened by requiring MMS approval for pipeline 
repairs. The Regional Supervisor, upon being notified that the lessee 
or right-of-way holder is anticipating a pipeline repair, will consider 
the complexity of the repair procedure in deciding whether or not to 
require a written repair plan. Exceptions would be made for pipeline 
repairs necessitated by imminent harm to the environment or to human 
safety.

Location of ESD Valves on Pipelines

    The Piper Alpha fire and the Arco ``B'' fire were greatly 
intensified by released gas from pipelines associated with the 
platforms. In the United States, incoming pipelines are required to 
have emergency SDV's as a protective measure, but they are often 
located onboard the platform to allow access for maintenance and 
testing.
    Locating SDV's away from the process equipment, such as on the 
seafloor or on the riser close to the waterline, may provide a greater 
level of protection for the platform but would at the same time reduce 
accessibility for repair and maintenance. This issue has major safety 
and reliability implications; therefore, MMS published the advance 
notice of proposed rulemaking in the Federal Register requesting more 
information on this subject.
    Thirty responses to the questionnaire were received from the oil 
and gas industry, including major oil and gas production companies, 
pipeline operators, and equipment manufacturers. The first 13 questions 
dealt with locating a pipeline SDV on the seafloor or just above the 
splash zone. Approximately half of the respondents cited limited access 
to a valve, particularly those located on the seafloor, for inspection 
and maintenance purposes as a major area of concern. Nearly half of the 
commenters suggested that the reliability of subsea valves is unknown 
or nonexistent. Again, supporting data was very limited. The remaining 
four questions dealt with pipeline pressure reduction during emergency 
situations. The results of the questionnaire are discussed after this 
section.
    For applications in the United States, the task group considered 
three distinct riser locations for the placement of SDV's: On the 
platform, on the seafloor, on the vertical portion of the riser below 
the lowest production deck but above the waterline. The advantages and 
disadvantages of each location are discussed below:
    The first location considered was ``on the platform.'' Subpart J--
Pipelines and Pipeline Rights-of-Way, Sec. 250.154(b)(2) requires that,

Incoming pipelines boarding to a production platform shall be 
equipped with an automatic shutdown valve (SDV) immediately upon 
boarding the platform * * *

    This regulation allows placement of the SDV on the deck where the 
riser enters the platform. ``Immediately upon boarding'' means near the 
edge of the platform. Accessibility for testing and maintenance is the 
greatest advantage to this location since the valve is located within 
the platform structure. Also, since the valve is located in close 
proximity of the production processing equipment, there is little or no 
hydrocarbon inventory between the valve and the process equipment that 
needs to be vented in the event of an emergency. However, this location 
also presents the greatest potential safety hazard. Since the valve is 
located near the process equipment, it is vulnerable to damage from 
explosions, extreme heat from fires, and falling debris during 
emergency situations. The task group determined that the valve in this 
location does not fulfill the intended purpose of an SDV in all 
situations since failure of the SDV or pressured portion of the riser 
would likely result in the release of a significant portion of the 
pipeline inventory at the point of failure. This vulnerability was 
demonstrated in the Piper Alpha disaster and the South Pass 60 fire.
    Next, the task group considered locating SDV's on the seafloor a 
short distance from the platform. The safety advantage of this location 
is obvious. The valve is isolated from the platform and is not 
vulnerable to explosions or fire that may occur during an emergency 
situation. However, a major drawback of this location is 
inaccessibility for maintenance and testing, especially in deep water. 
At this location, the valve would isolate the majority of the pipeline 
inventory from the platform. However, there may be a significant 
hydrocarbon inventory in the riser between the valve on the seafloor 
and the process equipment. This inventory must be safely vented when 
the pipeline is depressurized during an emergency after the valve is 
closed.
    Lastly, the task group considered locating SDV's on the vertical 
portion of risers below the lowest production deck of the platform but 
above the waterline. This location offers several advantages. The valve 
is removed from and placed below the hydrocarbon process areas within 
the platform, thereby isolating it from potential explosion and fire 
damage during emergency situations. Also, it effectively isolates the 
entire inventory of the pipeline from the platform since there is a 
minimal length of riser between the valve and the process equipment 
that must be vented during emergency situations, and the valve is above 
the waterline and is accessible for maintenance and testing.
    Considering the information gathered from the Federal Register 
Notice and additional information regarding subsea valve installations 
in the U.K. North Sea, the task group concluded that locating such 
valves on risers or on the seafloor was technically feasible. Other 
aspects of the current regulation were also reviewed. The task group 
considered the current regulation which requires SDV's to be installed 
on incoming pipelines only. Based on the events that occurred on Piper 
Alpha, the task group determined that there is a significant potential 
hazard from blackflow of pressured hydrocarbons from departing 
pipelines. Therefore, the task group recommended requiring SDV's on all 
new pipelines entering and departing production platforms. This 
requirement should also apply to sulphur operations since sulphur is 
also flammable and poses a significant threat to safety. This 
requirement would cover bidirectional pipelines, crossing pipelines, 
fuel lines, and pipelines carrying flammable or hazardous fluids. 
Crossing pipelines that enter onto platforms but do not take on 
production from those platforms pose an environmental risk, if not a 
risk to human safety. Therefore, crossing pipelines should also be 
required to have SDV's installed on the incoming and departing risers.

Responses to the Questions in the July 23, 1990, Federal Register 
Notice

    The following represents a summary of the responses received and 
does not necessarily reflect the opinion of MMS.
    Question--If the SDV was located on the seafloor or just above the 
splash zone, how would the following parameters be affected?
    (a) Maintenance.
    Response--Subsea maintenance poses a major problem, especially for 
deep water which would be difficult during rough seas and winter 
months. This jeopardizes the operation of the pipeline during those 
periods. Preventative subsea maintenance would be impractical while 
maintenance by divers would pose an additional safety risk. Minor and 
major repairs of a valve would most likely require removal from the 
pipe which is dangerous in itself and would require shutting down the 
pipeline system for extended periods.
    The splash zone is the most corrosive offshore environment. The 
cyclical wetting and drying of surface materials accelerate the 
corrosion process and degrades protective coatings. At the splash zone, 
increased maintenance would be required and most platforms have limited 
access in this area. Splash zone maintenance could not be performed 
during rough seas or winter months, thus jeopardizing the operation of 
the pipeline during those periods. Control lines would also be exposed 
to the corrosive wet/dry environment. Requiring SDV's to be located 
subsea or at the splash zone increases the safety risk to personnel and 
reduces the pipeline system's reliability.
    The diving cost alone to repair a subsea SDV in 180 feet of water 
would run between $15,000 and $18,000 per day.
    (b) Inspection.
    Response--Subsea SDV inspection by a diver would be of minimal 
value. Control systems for subsea valves are more complex than for 
surface valves. The ability of divers to inspect and perform repairs 
underwater is questionable and cannot be verified. Inspection and 
repair operations would be limited by weather conditions.
    Inspection of an SDV above the splash zone is reliable since it can 
be performed by an engineer or company representative. All inspection 
information is first hand.
    A typical subsea SDV inspection in 300 feet of water could cost 
between $20,000 and $30,000 per day.
    (c) Testing.
    Response--Testing subsea valves from a remote station is not 
reliable and may indicate problems that may or may not exist.
    Dealing with a malfunction during testing could have serious 
implications due to limited accessibility.
    The higher the SDV is located above the water, the greater its 
accessibility, maintenance, and performance.
    Frequency of subsea SDV testing should be kept to a minimum in 
order to maintain valve reliability.
    Testing would be complex. Remote monitoring or divers would be 
necessary to confirm test results.
    (d) Reliability.
    Response--Reliability is dependent on the individual reliability of 
all the components that make up the SDV and control system. Subsea 
valve reliability statistics are not presently available and need to be 
established.
    It is assumed that the reliability of an SDV functioning on the 
seafloor would be less than at any other location. Access to the SDV 
and control lines would be limited and equipment and personnel would be 
exposed to adverse conditions.
    The reliability of an SDV functioning in the splash zone would be 
slightly higher. Accessibility would be improved but the valve itself 
and control lines would be exposed to more adverse conditions.
    (e) Pressure venting.
    Response--Subsurface SDV's would be limited by the static back 
pressure of the seawater, or vent lines to the surface would be 
required. This may cause a delay in response time.
    A splash zone SDV would not have back pressure, but gas exhaust 
would need to be routed to the platform vent system.
    Underwater venting of pipelines is not recommended due to 
environmental considerations.
    The volume of hydrocarbons vented through the platform flare system 
would be greater for a subsea SDV than a platform SDV. This is a 
serious safety consideration.
    The capability to vent pressure from a pipeline should never take 
the form of bypassing the SDV but should be from the respective ends of 
the pipelines.
    (f) Bidirectional operations.
    Response--Not affected.
    (g) Pigging operations.
    Response--Subsea valves should be fitted with remote position 
indicators to ensure the valve is fully open during pigging operations.
    Question--What measures could be taken to enhance performance and 
reliability--in particular, how could problems identified in response 
to question one be alleviated?
    Response--Locating the SDV above the maximum wave height would 
alleviate most problems described in question one. Control lines are 
relatively short and the valve is readily accessible for maintenance 
and repairs.
    There are designs where safety can be achieved by other methods. 
There are also ``economical'' platforms where the producer accepts more 
risk to reduce facility costs. The location of the SDV should be 
commensurate with the level of protection afforded to other high-risk 
facilities on the platform.
    The SDV's should be manufactured from materials which will avoid 
valve replacement and offer reliable performance. The valve should have 
manual actuators and quick connect ends to facilitate operation or 
removal.
    Platform operating decks should be made of plate, not grating. 
Plate acts as a fire wall. If the deck is made of plate, the SDV can be 
safely located on the deck.
    The SDV's should be self-operating and fail-safe closed.
    Valves should be routinely inspected and tested as well as 
continuously monitored.
    The SDV and control system should be protected from mechanical 
damage.
    Placement of SDV's on the platform would improve reliability but 
would also minimize their effectiveness.
    Redundant control and instrumentation systems may be desirable. 
Standards should be established for value specifications and 
certification. Quality control in manufacturing could also enhance 
their reliability.
    Valve technology has advanced to the point that reliable subsea 
operation is available. Advancement in the areas of a valve failure 
data base and check valve technology could yield further reliability 
and performance.
    Require a surface SDV as well as a subsea valve.
    Question--What types of SDV's are available that could be located 
on the seafloor?
    Response--Any valve designed for subsea service such as a quarter 
turn ball valve, check valve, or a gate valve could perform as an SDV.
    The use of hydraulically operated valves could present a pollution 
problem.
    It is the actuator that needs to be scrutinized.
    No existing SDV would likely serve the purpose when located on the 
seafloor.
    Hydraulic or pneumatic systems would be most practical. Some 
manufacturers have devised an SDV for subsea service.
    Question--What specific limitations would be encountered with 
regard to placing the SDV at the seafloor location with respect to the 
following variables?
    (a) Size of valve.
    Response--For the most part, the size of the valve is not a major 
factor. However, valves over 12 inches in diameter are cumbersome, 
heavy and difficult to maneuver, and maintain. Valves greater than 36 
inches in diameter are difficult to obtain.
    The valve and actuator may be quite large and may require 
mechanical protection.
    (b) Pressure.
    Response--For the most part, pressure is not a major consideration 
except in deep water. Very large actuators may be needed to overcome 
extreme differential pressures in deep water.
    (c) Flow rate.
    Response--For low flow rates, the reduced flow may not justify the 
placement of a seafloor SDV.
    (d) Water depth.
    Response--Water depth has a large effect on diver costs for 
installation, maintenance, repairs, testing, etc. Deep-water locations 
also require novel installation methods, additional complexity, and 
further development of components and testing methods to achieve valve 
reliability. Some SDV's may be designed for installation and 
maintenance using a drilling rig. Beyond, 1,000 feet, diverless 
maintenance and retrieval become major considerations. Common valve 
operators are limited to water depths of less than 3,000 feet.
    In shallow water, subsea valves would be subjected to potential 
damage from shipping vessels.
    (e) Types of fluids transported.
    Response--Gas lines that are pressurized contribute a higher risk 
to platform safety than nonpressurized oil lines.
    (f) Other variables identified by commenters.
    Response--Repairing and replacing subsea SDV's would increase 
pollution potential.
    Reliable valve operation is the biggest concern. Factors affecting 
operation include water pressure and severe water forces on the valve 
and operating lines, hydrate formation, wax build up, etc. Chemical 
injection may be necessary to prevent hydrate or wax build up.
    The use of seafloor SDV's would preclude the use of J-tube methods 
of riser installation since the valve could not be passed through the 
J-tube.
    Sea-bottom conditions may dictate the location of SDV's.
    Protective coverage would be necessary to prevent trawl damage.
    Heavy valves, should they become suspended, will cause additional 
stress on the pipeline.
    The SDV's located near the waterline would be vulnerable to 
collisions and wave damage.
    Question--What actuation and control system options are available 
for placement of the SDV on the seafloor (e.g., pneumatic, hydraulic, 
electrical)? Would actuation backup capability be necessary or 
desirable?
    Response--Actuators can be powered by line pressure, stored gas 
pressure, or hydraulics. Fail-safe operation would be desirable. 
Pneumatic and hydraulic systems are the most reliable for subsea 
service. Manual operation is also necessary. Electrical systems could 
be used, but a backup system would be desirable. It is also necessary 
to provide manual diver valve actuation for emergency situations.
    Question--What emergency support systems (e.g., fire loop system, 
ESD system, subsurface safety system) would activate the subsea SDV? 
Should the conditions of actuation be different than for an SDV located 
on the platform?
    Response--All ESD and fire loop systems could operate the SDV. 
There would need to be a control line between the valve actuator and 
the platform. This could pose a maintenance problem. Pressure sensors 
could also be installed for the case of a ruptured or blocked line. 
This would require a relief valve, which brings up the following 
question. Where would the relief valve relieve to, the seafloor? The 
foregoing provides yet another reason to have the SDV above water.
    Question--For seafloor placement of the SDV, what would be the 
optimum location in distance from the platform?
    Response--Distance is not very important. The closer to the 
platform, the better. This would keep the control lines the shortest. 
Placing the valve 40 feet below the water surface on the riser would 
make it accessible to divers while providing its structural protection.
    The location of an SDV relative to the platform should ideally be 
decided by a quantified risk analysis. The optimum distance for 
placement of an SDV should be determined on a case-by-case basis, 
considering water depth, anchorage areas, fishing areas, and minimizing 
the inventory between the platform and the SDV.
    Question--What effect would burial (either intentional or 
unintentional) of the valve and actuator have on maintenance and 
operational reliability?
    Response--Burial would not hurt the SDV, but it would make it 
harder for divers to find it. Burial would increase the diving costs 
associated with maintenance. Burial would preclude using a remotely 
operated vehicle for inspection and maintenance and should be avoided.
    Question--What measures would be necessary to protect a subsea 
valve and control system from the following effects?
    (a) Temperature.
    Response--The SDV and control system need to be designed to operate 
in internal and external environments by selection of suitable 
materials.
    (b) Hydrates.
    Response--Hydrate formation could prevent subsea SDV operation. 
Glycol injection lines would be required in addition to control lines 
supplemented with glycol tanks, pumps, and attendant equipment.
    (c) Permafrost.
    Response--Not feasible.
    (d) Hydrogen sulfide.
    Response--The effects of hydrogen sulfide could be controlled with 
special alloys or inhibitors.
    (e) Carbon dioxide.
    Response--The effects of carbon dioxide could be controlled with 
special alloys or inhibitors.
    (f) Stress cracking.
    Response.--The effects of stress cracking could be controlled with 
special alloys.
    (g) Other effects identified by commenters.
    Response.--Control lines and connections could be damaged by boat 
or fishing activity. Protection will be necessary to protect small 
lines from being hooked by trawl boats and anchors.
    Sand production could jeopardize the operation of a subsea valve.
    Corrosion protection will be necessary for valve operators and 
control lines.
    Question--Should SDV's be manufactured, maintained, and repaired in 
accordance with a certification process similar to the process used 
with surface and subsurface safety valves?
    Response--API Spec 6D, Specification for Pipeline Valves, is a 
sufficient standard for valves, so certification is not necessary. 
Pipeline SDV's are not critical to permanent containment of 
hydrocarbons. However, proper maintenance of subsea valves may be a 
bigger issue.
    Question--Would the use of flexible piping impose difficulties to 
subsea valve?
    Response--Not so long as the pipeline is properly anchored at the 
valve location. High seas could pose a difficult problem (keeping the 
pipe still). Also, special support may be necessary for the SDV.
    Question--If an SDV is placed at an alternate seafloor location, 
should an ADV also be placed on the platform?
    Response--An SDV installed on a platform has a different function 
than a subsea SDV. The platform SDV mitigates consequences of a 
hydrocarbon release from the process equipment by isolating the 
pipeline from those facilities. Subsea SDV's mitigate the consequences 
of a hydrocarbon release from the pipeline which may occur as a primary 
or secondary event.
    In general, redundancy is always safer. However, redundancy costs 
more for equipment and increases the chance for malfunction and 
platform downtime. Placement of a surface SDV should not be required 
but considered an option. In general, SDV's should not be placed on the 
seafloor except in unusual circumstances.
    If an SDV is installed above the splash zone, there is no need for 
another one on the seafloor.
    Question--Current regulations require SDV's on certain incoming 
pipelines. What, if any, SDV's should be required on outgoing and 
crossing pipelines?
    Response--There is no need to place SDV's on all outgoing or 
crossing pipelines. Adding more valves is not necessary; however, 
present valves may need to be relocated to safer locations.
    The SDV's should be placed on new outgoing and crossing pipelines. 
A risk assessment should be performed on existing lines before making 
such modifications.
    Flow safety valves are adequate and less likely to fail, due to 
their simplistic design.
    Unmanned platforms that contain no production facilities, no 
compression, and no power source should not require SDV's.
    Question--What options are available to allow rapid reduction of 
pipeline pressure in an emergency, and what are the benefits and 
drawbacks of the techniques?
    Response--Rapid reduction of pipeline pressure is a formidable 
problem. Flaring at the platform can be a very slow method of reducing 
pipeline pressure. Strategically located SDV's along the pipeline may 
offer an alternative to depressurization. An outlying subsea vent is 
probably safest since it distances the gas from the platform. However, 
in most cases, rapid pressure reduction is expensive and of limited 
use.
    There is the damage of the formation of hydrate plugs and liquid 
plug flow as well as the need to prevent expanding vapor explosions.
    Blowdown on the seafloor or a platform could cause considerable 
pollution due to entrained liquids and could feed a fire in some 
instances.
    Blowing down a pipeline at a platform would require a scrubber 
system to separate liquids. These liquids would need to be disposed of 
safely which may be difficult during a platform emergency.
    Question--What are the benefits and shortcomings of subsea pipeline 
diversion?
    Response--System dependability might be enhanced by subsea 
diversion but not enough to offset additional cost over platform 
diversion.
    Subsea diversion could place evacuating and rescuing personnel in 
peril and could pose a significant pollution problem.
    Question--What are the advantages and disadvantages of having the 
capability to blow down a pipeline from both ends?
    Response--It may be good engineering practice to locate blowdowns 
at each end of a pipeline. One end may be inaccessible due to fire or 
failure. If both ends are accessible, a more rapid blowdown can be 
accomplished. However, the majority of damage and injuries on a 
platform occurs during the first few minutes and before pressure could 
be reduced. Actual damage is not likely to be significantly reduced.
    It would be necessary to bypass the check valve of the outgoing 
line. The bypass would need to be maintained and tested. Facilities for 
large scrubbing, liquid handling, and flaring would also be required.
    Question--Should pipelines be required to have the capability of 
rapid reduction of pipeline pressure from either end and, if so, what 
length of time should be specified as the maximum time for pipeline 
pressure reduction in an emergency situation?
    Response--Rapid pressure reduction is impractical during 
emergencies. Larger lines and volumes must be depressurized more 
slowly.
    The pest solution is accident prevention and efficient platform 
evacuation. Gas pipeline pressure cannot be reduced fast enough to 
prevent early damage during a platform emergency.
    In an emergency, evacuation is the primary concern. Flaring large 
volumes of gas could create a dangerous situation for aircraft and 
boats.

Summary of Proposed Changes

    Based on the report of the task group and the analysis of the 
responses received following the July 23, 1990, Federal Register 
Notice, MMS proposes to:
    1. Revise Sec. 250.1, Documents incorporated by reference, to 
incorporate API's Recommended Practice for Classification of Locations 
for Electrical Installation at Petroleum Facilities, First Edition, 
June 1, 1991 (API RP 500), into the regulations. This document replaces 
API RP 500B, Recommended Practice for Classification of Areas for 
Electrical Installations at Drilling Rigs and Production Facilities on 
Land and on Marine Fixed and Mobile Platforms, Second Edition, with 
Supplement. API RP 500 combined API RP 500A, 500B, and 500C into a 
single document to provide guidelines for classifying locations at 
petroleum facilities for the selection and installation of electrical 
equipment. API RP 500 contains essentially the same information 
contained in API RP 500B. API RP 500 is referenced in Sec. 250.51(i) to 
classify fuel and other flammable liquid storage locations. Also, 
references to API RP 500 replace API RP 500B in Secs. 250.53(b), 
250.122(e)(4)(i), 250.123(b)(9)(i), 250.291(b)(3) and (d)(4)(i), and 
250.292(b)(4)(i).
    2. Add a new Sec. 250.27, Safety of operations communication, that 
requires operators of offshore production platforms to notify incoming 
or new personnel arriving on the platform of the status of repairs of 
process equipment, safety systems, or other systems that are out of 
service. The new regulation also requires operators to maintain records 
of all communications.
    3. Revise Sec. 250.51, General requirements, to include 
requirements for fuel storage on offshore facilities.
    4. Revise Sec. 250.123, Additional production system requirements, 
to be more specific on identifying and deactivating process equipment 
and controls when safety systems are out of service and maintaining 
records.
    5. Add a new paragraph, Sec. 250.153(a)(5), that requires operators 
to protect horizontal sections of pipeline risers from damage by 
falling objects.
    6. Revise Sec. 250.154 to require pipeline shutdown valves to be 
located below the lowest production deck on all new pipelines entering 
and departing OCS platforms. This rule also applies to all pipelines 
under the jurisdiction of MMS, including production flow lines, 
gathering lines, sulphur pipelines, fuel lines, bidirectional lines, 
and crossing pipelines. For existing platforms and pipelines, the rule 
requires installation or relocation of valves when significant riser 
repairs or maintenance is performed.
    7. Revise Sec. 250.158 to give the Regional Supervisor authority to 
require operators to submit written pipeline repair procedures for 
approval. The preparation and approval of written plans ensure that an 
operator adequately considers the repair activity.

Author

    The principal authors of this proposed rule are Elmer P. 
Danenberger, Chief, Engineering and Technology Division, and Paul 
Schneider, Technology Assessment and Research Branch.

Regulatory Flexibility Act

    The DOI has also determined that this proposed rule will not have a 
significant economic effect on a substantial number of small entities 
because, in general, the entities that engage in activities offshore 
are not considered small due to the technical complexities and level of 
financial resources necessary to safely conduct such activities.

Paperwork Reduction Act

    This proposed rule adds new information collection requirements to 
subparts A and J. The information collection requirements contained in 
this rule have been submitted to the Office of Management and Budget 
(OMB) for approval as required by the Paperwork Reduction Act (44 
U.S.C. 3501 et seq.). The collection of this information will not be 
required until it has been approved by OMB. Public reporting burdens 
for the new information collection requirements contained in subparts A 
and J are estimated to average 8 hours per response, including the time 
for reviewing instructions, searching existing data sources, gathering 
and maintaining the data needed, and completing and reviewing the 
collection of information. Send comments regarding these burden 
estimates or any other aspects of this collection of information, 
including suggestions for reducing the burden, to the Information 
Collection Clearance Officer; Minerals Management Service; Mail Stop 
2053, 381 Elden Street; Herndon, Virginia 22070-4817, and the Office of 
Management and Budget; Paperwork Reduction Project (1010-0030) for 
subpart A and (1010-0050) for subpart J; Washington, DC 20503, 
telephone (202) 395-7340.

Takings Implication Assessment

    The DOI certifies that the proposed rule does not represent a 
governmental action capable of interference with constitutionally 
protected property rights. Thus, a Takings Implication Assessment need 
not be prepared pursuant to E.O. 12630, Government Action and 
Interference with Constitutionally Protection Property Rights.

E.O. 12778

    The DOI has certified to OMB that this proposed regulation meets 
the applicable civil justice reform standards provided in sections 2(a) 
and 2(b)(2) of E.O. 12778.

National Environmental Policy Act

    The DOI has determined that this action does not constitute a major 
Federal action significantly affecting the quality of the human 
environment; therefore, preparation of an Environmental Impact 
Statement is not required.

E.O. 12866

    This rule was reviewed under E.O. 12866. The rule was determined to 
not be a significant rule under the criteria of E.O. 12866 and, 
therefore, was not reviewed by OMB.

List of Subjects in 30 CFR Part 250

    Continental shelf, Environmental impact statements, Environmental 
protection, Government contracts, Incorporation by reference, 
Investigations, Mineral royalties, Oil and gas development and 
production, Oil and gas exploration, Oil and gas reserves, Penalties, 
Pipelines, Public lands--mineral resources, Public lands--rights-of-
way, Reporting and recordkeeping requirements, Sulphur development and 
production, Sulphur exploration, Surety bonds.

    Dated: April 4, 1994.
Bob Armstrong,
Assistant Secretary, Land and Minerals Management.

    For the reasons set forth in the preamble, 30 CFR part 250 is 
proposed to be amended as follows:

PART 250--OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER 
CONTINENTAL SHELF

    1. The authority citation for part 250 continues to read as 
follows:

    Authority: Sec. 204, Pub. L. 95-372, 92 Stat. 629 (43 U.S.C. 
1334).

    2. In Sec. 250.1, paragraphs (d)(9) and (d)(15) are revised as 
follows:


Sec. 250.1  Documents incorporated by reference.

* * * * *
    (d) * * *

    (9) API RP 14C, Recommended Practice for Analysis, Design, 
Installation and Testing of Basic Surface Safety Systems for 
Offshore Production Platforms, Fourth Edition, September 1, 1986, 
API Stock No. 811-07180, incorporated by reference at 
Secs. 250.51(i); 250.122 (b) and (e)(2); 250.123(a), (b)(2)(i), 
(b)(4), (b)(5)(i), (b)(7), (b)(9)(v), and (c)(2); 250.124 (a) and 
(a)(5); 250.152(d); 250.154(b)(12); 250.291 (c) and (d)(2); 250.292 
(b)(2) and (b)(4)(v); and 250.293(a).

* * * * *
    (15) API RP 500, Recommended Practice for Classification of 
Locations for Electrical Installations at Petroleum Facilities, 
First Edition, June 1, 1991, API Stock No. 811-06005, incorporated 
by reference at Secs. 250.51(i), 250.53(b), 250.122(e)(4)(i), 
250.123(b)(9)(i), 250.291(b)(3) and (d)(4)(i), and 250.292(b)(4)(i).
* * * * *
    3. A new Sec. 250.27 is added to subpart A to read as follows:


Sec. 250.27  Safety of operations communication.

    At the beginning of each crew shift and upon addition or 
replacement of personnel, incoming workers shall receive safety 
information relative to activities and repairs underway on the facility 
and any process or safety equipment that is out of service. This 
information may be provided through a safety meeting, a notice provided 
to each employee, or a posted notice that must be read by each 
employee. A record of this communication shall be kept and maintained 
at the facility.
    4. In Sec. 250.51, a new paragraph (i) is added to read as follows:


Sec. 250.51  General requirements.

* * * * *
    (i) Diesel and other fuel storage tanks, drums containing 
lubricants, cleaners, and other flammable liquids shall be clearly 
labeled and located as far as practicable from ignition sources. 
Storage locations shall be classified in accordance with the American 
Petroleum Institute (API) Recommended Practice (RP) for Classification 
of Locations for Electrical Installations at Petroleum Facilities (API 
RP 500). Tanks shall be adequately vented or equipped in accordance 
with API RP for Analysis, Design, Installation and Testing of Basic 
Surface Safety Systems for Offshore Production Platforms (API RP 14C). 
Fire detection devices, such as fusible plugs, shall be installed in 
fuel and flammable liquid storage areas.
    5. In Sec. 250.53, paragraph (b) is revised to read as follows:


Sec. 250.53  Electrical equipment.

* * * * *
    (b) All areas shall be classified in accordance with API RP 500, 
Recommended Practice for Classification of Locations for Electrical 
Installations at Petroleum Facilities.
* * * * *
    6. In Sec. 250.122, the introductory text of paragraph (e)(4)(i) is 
revised to read as follows:


Sec. 250.122  Design, installation, and operation of surface 
production-safety systems.

* * * * *
    (e) * * * 
    (4) * * * 
    (i) A plan of each platform deck outlining all hazardous areas 
classified in accordance with API RP 500, Recommended Practice for 
Classification of Location for Electrical Installations at Petroleum 
Facilities, and outlining areas in which potential ignition sources, 
other than electrical, are to be installed. The area outline shall 
include the following information.
* * * * *
    7. In Sec. 250.123, paragraphs (b)(9)(i) and (c)(1) are revised to 
read as follows:


Sec. 250.123  Additional production system requirements.

* * * * *
    (b) * * *
    (9) Fire- and gas-detection system. (i) Fire (flame, heat, or 
smoke) sensors shall be installed in all enclosed classified areas. Gas 
sensors shall be installed in all inadequately ventilated, enclosed 
classified areas. Adequate ventilation is defined as ventilation that 
is sufficient to prevent accumulation of significant quantities of 
vapor-air mixture in concentrations over 25 percent of the lower 
explosive limit (LEL). One approved method of providing adequate 
ventilation is a change of air volume every 5 minutes or 1 cubic foot 
of air-volume flow per minute per square foot of solid floor area, 
whichever is greater. Enclosed areas (e.g., buildings, living quarters, 
or doghouses) are defined as those areas confined on more than four of 
their six possible sides by walls, floors, or ceilings more restrictive 
to air flow than grating or fixed open louvers and of sufficient size 
to allow entry of personnel. A classified area is any area classified 
Class I, Group D, Division 1 or 2, following the guidelines of API RP 
500.
* * * * *
    (c) General platform operations. (1) Surface or subsurface safety 
devices shall not be bypassed or blocked out of service unless they are 
temporarily out of service for startup, maintenance, or testing 
procedures. Personnel shall monitor the bypassed or blocked-out 
functions until the safety devices are placed back in service. Any 
surface or subsurface safety device that is temporarily placed out of 
service shall be flagged. When conducting repairs or maintenance that 
expose the production safety system to the atmosphere or to conditions 
that constitute a potential danger to safety of personnel or protection 
of the environment, the system shall be purged of hydrocarbons and flow 
shall be blocked from the area under repair or maintenance. Valves, 
pumps, or other equipment that could initiate flow through the 
designated area shall also be flagged and removed from service. The 
activation of such equipment from the control panel shall be 
temporarily precluded. Only the person in charge of the repair or 
maintenance may authorize the resumption of service. This authorization 
may not be given until the repair or maintenance action is completed.
* * * * *
    8. In Sec. 250.153, a new paragraph (a)(5) is added to read as 
follows:


Sec. 250.153  Installation, testing, and repair requirements for DOI 
pipelines.

    (a) * * *
    (5) Risers shall be designed to prevent damage from falling debris. 
Horizontal sections of risers shall be of minimal length and protected 
to prevent damage from falling objects.
* * * * *
    9. In Sec. 250.154, paragraphs (b) and (c) are revised to read as 
follows:


Sec. 250.154  Safety equipment requirements for DOI pipelines.

* * * * *
    (b) All new oil, gas, or sulphur pipelines approved or modified 
after the effective date of these regulations shall comply with this 
section, where applicable.
    (1)(i) Incoming pipelines to a platform shall be equipped with a 
flow safety valve (FSV).
    (ii) For sulphur operations, incoming pipelines delivering gas to 
the power plant platform may be equipped with high- and low-pressure 
sensors (PSHL), which activate audible and visual alarms in lieu of 
requirements in paragraph (b)(1)(i) of this section. The PSHL shall be 
set at 15 percent or 5 psi, whichever is greater, above and below the 
normal operating pressure range.
    (2) Incoming pipelines boarding to a production platform or 
delivering gas to a power plant platform shall be equipped with an 
automatic shutdown valve (SDV) below the lowest production deck of the 
platform. The SDV shall be connected to the automatic- and remote-
emergency shut-in systems.
    (3) Departing pipelines receiving production from production 
platforms shall be protected by PSHL to directly or indirectly shut in 
all production facilities. The PSHL shall be set not to exceed 15 
percent above and below the normal operating pressure range. However, 
high pilots shall not be set above the pipeline's maximum allowable 
operating pressure.
    (4) Departing pipelines from a production platform shall be 
equipped with an SDV below the lowest production deck of the platform. 
The SDV shall be connected to the automatic- and remote-emergency shut-
in systems in a manner that allows the safe shut in of the platform 
prior to SDV closure.
    (5)(i) Crossing pipelines on production or manned nonproduction 
platforms shall be equipped with an SDV on both the incoming and 
departing lines below the lowest production deck. These SDVs shall be 
connected to the automatic- and remote-emergency shut-in systems.
    (ii) Crossing pipelines on unmanned nonproduction platforms shall 
be equipped with an FSV.
    (6) Bidirectional pipelines servicing production or manned 
nonproduction platforms shall be equipped with a PSHL and an SDV on all 
risers.
    (7) All SDV's shall be operable locally and connected to the 
automatic- and remote-emergency shut-in systems. The SDV shall be 
protected from fire, explosion, and impacts from falling objects and 
marine vessels. The SDV shall be accessible for inspections, 
maintenance, repairs, and testing. The SDV shall be inspected and 
tested at least once each calendar month, but the interval shall not 
exceed 6 weeks.
    (8) For facilities and pipelines installed prior to the effective 
date of these regulations, an SDV shall be installed when riser 
maintenance or repair is performed.
    (9) The Regional Supervisor may require that oil pipelines be 
equipped with a metering system to provide a continuous volumetric 
comparison between the input to the line at the structure(s) and the 
deliveries onshore. The system shall include an alarm system and shall 
be of adequate sensitivity to detect variations between input and 
discharge volumes. In lieu of the foregoing, a system capable of 
detecting leaks in the pipeline may be substituted with the approval of 
the Regional Supervisor.
    (10) Pipelines incoming to a subsea tie-in shall be equipped with a 
block valve and a FSV. Bidirectional pipelines connected to a subsea 
tie-in shall be equipped with only a block valve.
    (11) Gas-lift or water-injection pipelines on unmanned platforms 
need only be equipped with an FSV installed immediately upstream of 
each casing annulus or the first inlet valve on the wellhead.
    (12) Pipeline pumps shall comply with Section A7 of API RP 14C. The 
setting levels for the PSHL devices are specified in paragraph (b)(5) 
of this section.
    (c)(1) If the SDV or other required safety equipment is rendered 
ineffective or removed from service on pipelines that are continued in 
operation, an equivalent degree of safety shall be provided. The 
affected safety equipment shall be identified by the placement of a 
sign on the equipment stating that the equipment is rendered 
ineffective or removed from service.
    (2) When conducting repairs or maintenance to the pipeline system 
components that expose the pipeline to the atmosphere or to conditions 
that constitute a potential danger to safety of personnel or protection 
to the environment, the system shall be purged of hydrocarbons and flow 
shall be blocked from the area under repair or maintenance. Valves, 
pumps, or other equipment that could allow or initiate flow through the 
designated area shall also be flagged and removed from service. 
Activation of this equipment from the control panel shall be 
temporarily precluded. Only the person in charge of the repair or 
maintenance may authorize the resumption of service. This authorization 
may not be given until the repair or maintenance action is completed.
    10. In Sec. 250.158, paragraph (e) is revised to read as follows:


Sec. 250.158  Reports.

* * * * *
    (e)(1) Except for emergency repairs necessary to prevent or 
minimize pollution or the loss of human life, the lessee or right-of-
way holder shall notify the Regional Supervisor prior to the repair of 
any pipeline or pipeline component. Based on the nature of the repair, 
the Regional Supervisor may require the lessee or right-of-way holder 
to submit detailed pipeline repair procedures for approval before 
conducting repairs. The repair procedures shall include the types of 
equipment and specifications of components used in the repair.
    (2) A detailed report of the pipeline repair shall be submitted to 
the Regional Supervisor within 30 days after completion of the repair. 
The report shall include the following:
    (i) Type of damage sustained and cause:
    (ii) Type and volume of hydrocarbons lost due to damage;
    (iii) Specifications of components utilized in the repair and a 
detailed repair procedure;
    (iv) Results of pressure and other verification tests; and
    (v) Date pipeline or component returned to service.
* * * * *
    11. In Sec. 250.291, paragraphs (b)(3) and (d)(4)(i) are revised to 
read as follows:


Sec. 250.291  Design, installation, and operation of production 
systems.

* * * * *
    (b) * * *
    (3) Electrical system information, including a plan of each 
platform deck that shows:
    (i) All hazardous areas classified in accordance with API RP 500, 
Recommended Practice for Classification of Locations for Electrical 
Installations at Petroleum Facilities; and
    (ii) All areas in which potential ignition sources are to be 
installed;
* * * * *
    (d) * * *
    (4) * * *
    (i) A plan of each platform deck, outlining all hazardous areas 
classified in accordance with API RP 500 and outlining areas in which 
potential ignition sources are to be installed;
* * * * *
    12. In Sec. 250.292, paragraph (b)(4)(i) is revised to read as 
follows:


Sec. 250.292  Additional production and fuel gas system requirements.

* * * * *
    (b) * * *
    (4) Fire- and gas-detection system. (i) Fire (flame, heat, or 
smoke) sensors shall be installed in all enclosed classified areas. Gas 
sensors shall be installed in all inadequately ventilated, enclosed 
classified areas. Adequate ventilation is defined as ventilation that 
is sufficient to prevent accumulation of significant quantities of 
vapor-air mixture in concentrations over 25 percent of the LEL. One 
approved method of providing adequate ventilation is a change of air 
volume every 5 minutes or 1 cubic foot of air-volume flow per minute 
per square foot of solid floor area, whichever is greater. Enclosed 
areas (e.g., buildings, living quarters, or doghouses) are defined as 
those areas confined on more than four of their six possible sides by 
walls, floors, or ceilings more restrictive to air flow than grating or 
fixed open louvers and of sufficient size to allow entry of personnel. 
A classified area is any area classified Class I, Group D, Division 1 
or 2, following the guidelines of API RP 500.
* * * * *
[FR Doc. 94-11601 Filed 5-13-94; 8:45 am]
BILLING CODE 4310-MR-M