[Senate Hearing 112-30]
[From the U.S. Government Publishing Office]


                                                         S. Hrg. 112-30

         NEW DEVELOPMENTS IN UPSTREAM OIL AND GAS TECHNOLOGIES

=======================================================================

                                HEARING

                               before the

                              COMMITTEE ON
                      ENERGY AND NATURAL RESOURCES
                          UNITED STATES SENATE

                      ONE HUNDRED TWELFTH CONGRESS

                             FIRST SESSION

                                   TO

     RECEIVE TESTIMONY ON NEW DEVELOPMENTS IN UPSTREAM OIL AND GAS 
                              TECHNOLOGIES

                               __________

                              MAY 10, 2011


                       Printed for the use of the
               Committee on Energy and Natural Resources
               COMMITTEE ON ENERGY AND NATURAL RESOURCES

                  JEFF BINGAMAN, New Mexico, Chairman

RON WYDEN, Oregon                    LISA MURKOWSKI, Alaska
TIM JOHNSON, South Dakota            RICHARD BURR, North Carolina
MARY L. LANDRIEU, Louisiana          JOHN BARRASSO, Wyoming
MARIA CANTWELL, Washington           JAMES E. RISCH, Idaho
BERNARD SANDERS, Vermont             MIKE LEE, Utah
DEBBIE STABENOW, Michigan            RAND PAUL, Kentucky
MARK UDALL, Colorado                 DANIEL COATS, Indiana
JEANNE SHAHEEN, New Hampshire        ROB PORTMAN, Ohio
AL FRANKEN, Minnesota                JOHN HOEVEN, North Dakota
JOE MANCHIN, III, West Virginia      BOB CORKER, Tennessee
CHRISTOPHER A. COONS, Delaware

                    Robert M. Simon, Staff Director
                      Sam E. Fowler, Chief Counsel
               McKie Campbell, Republican Staff Director
               Karen K. Billups, Republican Chief Counsel
                            C O N T E N T S

                              ----------                              

                               STATEMENTS

                                                                   Page

Banks, Kevin R., Director, Division of Oil and Gas, Alaska 
  Department of Natural Resources, Anchorage, AK.................    15
Bingaman, Hon. Jeff, U.S. Senator From New Mexico................     1
Davis, Thomas, Director, Reservoir Characterization Project, 
  Colorado School of Mines, Golden, CO...........................     3
Epstein, Lois, P.E., Director, Arctic Program, The Wilderness 
  Society, Anchorage, AK.........................................    21
Hendricks, Andy, President, Drilling and Measurements, 
  Schlumberger Limited, Sugarland, TX............................     5
Melzer, L. Stephen, CO2 Consultant and Annual 
  CO2 Flooding Conference Director....................     9
Murkowski, Hon. Lisa, U.S. Senator From Alaska...................     2

                               APPENDIXES
                               Appendix I

Responses to additional questions................................    43

                              Appendix II

Additional material submitted for the record.....................    57

 
         NEW DEVELOPMENTS IN UPSTREAM OIL AND GAS TECHNOLOGIES

                              ----------                              


                         TUESDAY, MAY 10, 2011

                                       U.S. Senate,
                 Committee on Energy and Natural Resources,
                                                    Washington, DC.
     The committee met, pursuant to notice, at 10:02 a.m. in 
room SD-366, Dirksen Senate Office Building, Hon. Jeff 
Bingaman, chairman, presiding.

OPENING STATEMENT OF HON. JEFF BINGAMAN, U.S. SENATOR FROM NEW 
                             MEXICO

    The Chairman. OK. Why don't we get started on the hearing? 
This morning's hearing focuses on new developments in 
technologies for the exploration and production of oil and 
natural gas. It's a continuation of a series of hearings the 
Committee has held on oil and gas this Congress beginning with 
our first hearing on overall trends in oil and gas markets 
including our hearing with the leaders of the National 
Commission on the BP Deep Water Horizon oil spill.
    Senator Murkowski suggested we have a technology focused 
hearing to understand better the new exploration and production 
activities that the industry is undertaking. I appreciate her 
suggestion. I think it is timely. Given the broader interest in 
these activities, particularly, so we have invited a group of 
highly qualified technical experts to come and give us 
testimony on this subject today.
    This hearing will help inform our coming deliberations on 
legislation related to oil and natural gas. Yesterday I 
introduced 2 bills related to these topics. The Oil and Gas 
Facilitation Act of 2011 and the Outer Continental Shelf Reform 
Act of 2011.
    Both bills are comprised of provisions that were introduced 
and passed out of our Committee in the last Congress with 
strong bipartisan support. Along with this hearing these bills 
are a good starting point for what I hope will be a 
constructive bipartisan dialog on the topic as the rest of this 
month unfolds. We hope to have a hearing on the bills and 
related legislation next week. I hope we can mark up 
legislation related to oil and natural gas as part of our 
overall Committee agenda during this work period.
    Today we will be hearing from experts on the topic of 
recent events as in seismic data acquisition, processing and 
its new applications, advanced drilling technologies. How 
enhanced oil recovery is allowing operators to get more 
production in their fields without drilling additional wells.
    Before we start hearing from our witnesses let me defer to 
Senator Murkowski for her opening comments.

        STATEMENT OF HON. LISA MURKOWSKI, U.S. SENATOR 
                          FROM ALASKA

    Senator Murkowski. Thank you, Mr. Chairman. I appreciate 
the hearing this morning. To the witnesses, thank you all for 
being here.
    I think we all recognize that it's worth our time to learn 
more about technological advances in the production of oil and 
gas as we endeavor to legislate on the subject. Whether we're 
debating access or safety or simply trying to understand how 
our energy needs will be met in the years ahead it helps if we 
know what truly is and is not possible with technology. Many 
examples throughout history of technology changing our nation's 
behavior, our energy portfolio and really the overall economy.
    A century and a half ago the steam engine brought America 
to the West. A half century ago, nuclear power began to 
revolutionize the way that we generate electricity and even 
power our submarines and our aircraft carriers. Then just more 
recently in the past few years, we've seen natural gas evolve 
from a dangerously scarce commodity to a secure, long term 
source of energy.
    These are all American success stories. I hope that we hear 
this morning perhaps some more success stories. Recognizing, of 
course, that with new territory comes the need to understand 
new risks and the impacts.
    As this hearing's joint background memo indicates we've got 
incredible advances in seismic technology that have 
substantially reduced the cost of exploration, the risks 
associated with exploration and the environmental impacts 
associated with drilling.
    Directional drilling has enabled operators to shrink their 
environmental footprint, maximize efficiency and lower costs. 
Advances in directional drilling can now facilitate access to 
20 or more deposits and reach as far as seven or eight miles 
away from a rig. This translates to less surface area being 
occupied, fewer emissions and a lesser impact on humans as well 
as the flora and the fauna.
    Enhanced oil recovery also provides many of those same 
effects. Its increased production from existing wells and helps 
ensure that American taxpayers receive the fullest return 
possible on resource development.
    New technologies present new opportunities for the 
responsible development of our nation's tremendous energy 
resources. That's true whether the operation is out of 
Bakersfield or whether it's out of Barrow. I would suggest that 
it's through a combination of economics, geology and policy 
that these technologies have come about.
    But because this committee can really only control and 
influence the third factor which is the policy, I hope that we 
can work to reward and encourage developments like those that 
we're hearing about today. On balance these demonstrate 
significant benefits for the environment, for energy security 
and for the American people.
    Again, Mr. Chairman, I'm pleased that you have worked with 
us to schedule a hearing this morning. I look forward to the 
comments from the witnesses.
    The Chairman. Thank you very much.
    Let me introduce our witnesses.
    Professor Thomas L. Davis, who is Director of the Reservoir 
Characterization Project at the Colorado School of Mines in 
Golden, Colorado. Thank you for being here.
    Mr. Andy Hendricks, who is President of Drilling and 
Measurements with Schlumberger in Sugarland, Texas. Thank you 
for being here.
    Mr. Steve Melzer, who is Engineer and Founder of Melzer 
Consulting in Midland, Texas. Thank you for being here.
    Mr. Kevin Banks, who is Director of the Division of Oil and 
Gas in the Alaska Department of Natural Resources in Anchorage. 
Thank you for being here.
    Ms. Lois Epstein, who is the Director of the Arctic Program 
for the Wilderness Society. Thank you for coming.
    Why don't we just take you in that order? If you'll just 
give us about 5 minutes to make the main points that you think 
we need to try to understand. We will include your entire 
statement in the record as if read.
    Dr. Davis.

STATEMENT OF THOMAS DAVIS, DIRECTOR, RESERVOIR CHARACTERIZATION 
         PROJECT, COLORADO SCHOOL OF MINES, GOLDEN, CO

    Mr. Davis. Good morning. Thank you very much, Chairman 
Bingaman and Ranking Member Murkowski. I'm here to talk to you 
about seismic technologies. The technologies I'm going to focus 
on are related to data acquisition systems.
    These--before I jump into that framework of acquisition 
systems let me just tell you a little bit about seismic data 
itself. How it's acquired. What it is.
    In this particular regard, the fact that I'm talking to you 
in here relates to seismic waves. These are acoustic waves that 
we transmit. So our ears are sensors. In the same vein in the 
framework of the seismic industry we developed sensors that 
record ground motion. So the ground motion allows us to hear 
and see into the subsurface.
    Now the kinds of sensors that we use today have transformed 
or changed. We have different mechanical sensors, acoustic 
sensors. We put sensors in the water which we call hydrophones. 
So there's a whole variety of sensors. They record different 
types of waves.
    So as I've indicated there's acoustic waves. But there are 
also other types of waves we call elastic waves. Now with these 
multiple sensors and the ability to be able to look at 
recording all these different forms, we can better characterize 
the subsurface. This gives us a huge uplift in terms of our 
ability to see the unseen, what's underneath us.
    In this regard then the kinds of sensors that we've been 
going toward now have been matched up with new recording 
systems. The kinds of recording systems that we're now looking 
at you can hold in your hand, much like a cell phone. In this 
regard then they're easy to put out, to place in different 
places. They're also environmentally friendly in the sense that 
we can walk in and place them in different places.
    We're not locked in grid lock anymore. The grid lock used 
to be the framework of cables. Like a land phone lines these 
cables would go for miles and miles and were really hampering a 
lot of our ability to record with very sensitive measurements 
in the subsurface. So in this regard then the fact that we're 
now using cable less or wireless systems helps us tremendously.
    So we can place these on the surface of the Earth in 
different locations, many, many of these sensors, up to 
hundreds of thousands actually now. We can leave them there and 
let them record. So in that regard we can use natural 
seismicity of the Earth to be able to sense what's underneath. 
We can also use active recording where we vibrate the Earth 
itself in low vibration intensity levels and record.
    So in that regard we develop better images. The better 
images right now are akin to your high definition television. 
Not only is it high definition but it's also 3D. So that's 
where the television industry has been going. Hollywood is into 
3D. We've been there for many years now.
    Moreover, it's not just 3D. We operate in what we call 4D. 
This is a framework of looking at monitoring and sensing 
changes in the subsurface.
    The changes could be induced by some operational change, 
some drilling change, some completion change, the introduction 
of fluids into the reservoir. We can know sense that and see 
that. We call this 4D. Others would call it time lapse.
    So we do time lapse imaging much like a medical doctor will 
do in recording different images. In that sense then it gives 
us the huge benefit of being able to see where the fluids are 
going. Even to characterize those fluids over time and their 
time changes.
    Reservoirs change. So in this regard better reservoir 
characterization helps us increase the recovery efficiency, the 
recovery factor, in a lot of our reservoirs. Conventional 
reservoirs, unconventional reservoirs, you name it.
    In that regard, the technology here has been developing 
over the last several decades here to allow us to do this. It's 
very exciting technology. It's also going to cause a greater 
alignment with the environmental framework. That is, the 
environmental areas that were off limits before we can now go 
into. Look at very, very, I guess we'll just say, with new 
technology we can then advance into those areas, other areas 
that we haven't been into for a long, long time.
    Thank you.
    [The prepared statement of Mr. Davis follows:]

        Prepared Statement of Thomas Davis, Director, Reservoir 
     Characterization Project, Colorado School of Mines, Golden CO
Seismic Technology--A Transformation
    Good Morning and Thank you Chairman Bingaman and Ranking Member 
Murkowski for this opportunity to come and speak to you today in this 
hearing about recent advances to upstream oilfield technologies. I will 
be speaking to you today about new developments in the area of seismic 
technologies and its importance to finding, developing, and eventually 
producing oil and gas.
    Let me begin with a brief explanation of what seismic data is. 
Seismic data are acquired by ``listening'' to motion related to seismic 
waves. Seismic waves are vibrations within the Earth induced naturally 
or artificially. The devices used to listen are seismic sensors that 
transform Earth motion into impulses that are recorded by seismic 
recording systems. After the data is recorded, the data is processed 
and used to get a better understanding, or a ``picture'', in two or 
three dimensions of what the rock below the Earth's surface looks like, 
as well as any potential oil and gas that might be contained within 
those rocks.
    There are exciting new developments in seismic technology that will 
create greater efficiency in oil and gas exploration with an increased 
emphasis on the environment with a greater transparency in the upstream 
petroleum industry going forward. The main development has been in new 
seismic acquisition systems creating higher definition and greater 
productivity. The transformation involves new wireless recording 
systems. The systems can record actively as well as passively, meaning 
that they can record with an active source or they can ``listen'' to 
the natural seismicity of the Earth. It is equivalent to putting ``cell 
phones'' as monitoring stations on the ground.
    These devices can record various kinds of seismic waves. The most 
widely used waves are acoustic waves, or sound waves, but other waves 
propagate within the Earth. Detecting different types of waves gives us 
additional information about the subsurface including: the strength or 
integrity of the substrate, stresses within the subsurface, fluid 
pressures and even the fluids themselves. Combined recording of 
different seismic waves enables us to characterize the subsurface to 
optimally target wells, provide guidance on well drilling, and to 
monitor well completions and to monitor well and completion integrity. 
As a result, the petroleum industry is being transformed and the 
seismic industry is leading the transformation of the upstream oil and 
gas sector as we know it.
    New seismic recording systems are being used to conduct monitoring 
of enhanced oil recovery projects in the US and Canada including carbon 
dioxide flooding and sequestration. The results have enabled scientists 
and regulators to work together to assess environmental safety 
associated with these projects. They have been used recently in 
resource plays in the US and Canada to determine ``sweet spots'' that 
are more economical to develop through horizontal drilling and 
hydraulic fracturing. The combined use of new seismic, drilling and 
completions technology is changing the landscape of the petroleum 
industry to lessen the environmental footprint and to create greater 
transparency.
    Seismic technology is traditionally used for oil and gas 
exploration, but is capable of being used for much more. Recent uses 
include advanced reservoir characterization to increase the recovery 
factor of oil and gas reservoirs. Reservoir characterization is 
basically the methodology to document the heterogeneity, or 
complexities, naturally associated with reservoirs. Geology is complex 
and reservoirs are too. In the past about 25% to 33% of a resource has 
been recoverable. Through improved integrated reservoir 
characterization technology we have been able to increase recovery to 
50 %, but we are not done. Enhanced recovery methods will enable us to 
improve the recovery factor even further. In resources, or 
unconventional plays where the oil and gas is generated and contained 
in-situ, recovery factors are generally low (10%), but the potential to 
increase recoveries through integrated reservoir characterization 
technologies is substantial.
    Technology is the single most important factor in finding and 
developing energy resources to fuel our economy in an environmentally 
responsible manner. New seismic technologies will enable us to find new 
resources, to develop old ones more efficiently, and to open up 
exciting new growth opportunities here in the US for current and future 
generations.
    I have provided some examples of sensors and recording devices that 
are shown in the attached figures. The equipment is getting smaller and 
more sophisticated to the point that high definition images of the 
subsurface can be made with relatively little intrusion on the 
environment. The instruments can be left in place to monitor the 
subsurface over relatively long periods of time-like motion sensors 
that are used for in-home security systems. These systems allow us to 
listen to our reservoirs and to take proactive rather than reactive in 
the management of our reservoirs.

    The Chairman. Thank you very much.
    Mr. Hendricks.

     STATEMENT OF ANDY HENDRICKS, PRESIDENT, DRILLING AND 
       MEASUREMENTS, SCHLUMBERGER LIMITED, SUGARLAND, TX

    Mr. Hendricks. Mr. Chairman and members of the committee, 
thank you. First I'd like to say I consider it a privilege to 
have been invited to speak to you today. I brought my son, Drew 
with me so he could see the government process and work as 
well. So thank you for that.
    My name is Andy Hendricks. I'm from the Drilling division 
of Schlumberger. I have a degree in Petroleum Engineering from 
Texas A and M. My industry expertise is in horizontal drilling 
and extended reach drilling of oil and gas wells.
    Schlumberger is the leading oilfield services provider. My 
division is responsible for supplying the oil companies with 
technology and services in order to control and navigate the 
direction of the oil and gas wells. To improve drilling 
performance to reduce the overall costs. To maximize the 
contact of the wellbore with the oil or gas bearing rock, or 
what we call, the reservoir.
    So I'm here today to talk to you about today's high-tech 
drilling technology. Our industry is about high-tech tools and 
equipment these days, and the skilled engineers and 
geoscientists who run them. Drilling has become a sophisticated 
science as it has evolved over the years.
    Back in 1858, the Drake well in Pennsylvania was the first 
U.S. oil well. This well was drilled with what we call a cable 
tool drilling rig, which compared to today's standards is a 
rudimentary concept that utilizes gravity and heavy steel bars 
that are suspended from a cable to pound and crush the rock. 
The result back then was a simple, vertical well with the 
drilling operation making progress in the ground at about 3 
feet every day. Drake's well finished up at 69 1/2 feet of 
depth.
    In 1901 rotary drilling rigs were the next big step change 
for the industry. Where pipe is lowered into the well and 
rotated from the surface in order to turn a drill bit at the 
bottom of the well. Fluid is circulated down the pipe in order 
to cool the drill bit as it rotates and crushes the rock and 
then to lift the drill cuttings from the well.
    Again these wells were drilled vertical or straight down. 
But the early advancements allowed engineers to control the 
direction of the well with a technique that was based on 
placing a simple, triangular shaped deflection device down into 
the well and aligning this with a compass heading. At the time 
the technology was in its infancy and the progress was slow. 
Today we have full navigational and guidance instrumentation 
built into the drilling assemblies that we use at the bottom of 
the well. Much more advanced and precise than the navigation 
system in your car and with high speed communications through 
the drill pipe that allows us to direct the path of the well 
using robotic steering devices.
    One of our state-of-the-art pieces of equipment, which we 
refer to as a Measurements While Drilling tool, contains an 
electronics package consisting of 2 high speed computer 
processors, memory boards collecting data from navigational 
instrumentation and sensors. It's powered by its own turbine 
driven generator. All of which is packaged and ruggedized to 
withstand 30,000 pounds per square inch of wellbore pressure, 
temperatures up to 400 degrees Fahrenheit and shock and 
vibration exceeding 150 Gs. So imagine baking your iPhone or 
your Blackberry in the oven. Then driving over it with your car 
and expecting it to continue to function.
    An oil well drilled today will start off going straight 
down from the surface. But then it may gradually turn through a 
smooth curve until it is going horizontal or parallel with the 
surface. Then progress sideways, moving up and down or left and 
right in order to either maximize the reservoir contact or link 
together smaller reservoir pockets in a chain along this 3 
dimensional wellbore path. When it comes to drilling 
performance, where the drilling of a well used to progress at 3 
feet each day, today we drill the wells at hundreds of feet 
each hour. We finish after the drill bit has travelled several 
miles into the Earth.
    With today's technology we can drill multiple wells from a 
single location at the surface. This is a process called pad 
drilling or template drilling. It's used in places like the 
Rockies on land or offshore on platforms. This reduces the 
footprint of the drilling operation on the surface by 
eliminating the need for multiple single well locations.
    Another complex operation used more and more is extended 
reach drilling. In recent years the oil and gas industry has 
been increasing its ability to drill longer and longer wells 
with more complex, 3 dimensional paths. The horizontal lengths 
of these extended reach wells are measured in miles.
    In Prudhoe Bay, Alaska, and in other parts of the world, 
extended reach drilling is used to access off shore reservoirs 
using drilling rigs from land. The drilling of these long 
horizontal sections requires expert engineering, planning and 
high tech equipment to steer the miles of pipe drilling 
underground. We currently hold the record for directional 
drilling in this type of well at 7.6 miles.
    Now when it comes to placing the well in the productive 
zone, imagine that this room is a reservoir. It's miles down. 
It's dark. You're not even sure exactly what's in here. The 
walls, ceiling and floors are the borders and we want to drill 
within these to get as much reservoir contact as possible.
    The steering is directed from 5 miles away. To do this we 
use a complex device called a rotary steerable system to steer 
the well path. We will also have a variety of high tech sensors 
collecting data in order to identify the reservoir boundaries 
and analyze the type of rock we are in and whether or not we 
have oil and gas.
    Schlumberger is the leader in drilling services. We hire 
the best from the most prestigious universities in the U.S. and 
other countries. Our latest advancement further integrate 
technologies to improve drilling performance and to provide 
advanced techniques to allow the oil companies to reduce their 
costs.
    In 2010, we invested $919 million in research in 
engineering. We worked with oil companies to drill more than 
7,000 miles.
    I'd like to thank you for your time and attention today.
    [The prepared statement of Mr. Hendricks follows:]

     Prepared Statement of Andy Hendricks, President, Drilling and 
           Measurements, Schlumberger Limited, Sugarland, TX
    I have a degree in Petroleum Engineering, and my industry expertise 
is in the area of horizontal and extended-reach drilling of oil and gas 
wells. Schlumberger is the leading oilfield services provider, and my 
division is responsible for supplying oil companies with technology and 
services in order to control and navigate the direction of oil and gas 
wells, improve drilling performance to reduce overall costs, and to 
maximize the contact of the wellbore with the oil or gas bearing rock, 
or what we call--the reservoir.
    I'm here today to talk to you about today's high-tech drilling 
technology. Our industry is about high-tech tools and equipment, and 
the skilled engineers who run them. Drilling has become a sophisticated 
science as it evolved over the years. In 1858, the Drake well in 
Pennsylvania was the first US oil well. This well was drilled with a 
cable tool drilling rig, which compared to today's standards, is a 
rudimentary concept that utilizes gravity and heavy steel bars 
suspended at the end of a cable to pound and crush the rock. The result 
then was a simple, vertical well, with the drilling operation making 
progress in the ground at 3 feet each day. Drake's well was 69 1/2 ft 
deep.
    In 1901, rotary drilling rigs were the next big step change for the 
industry, where pipe is lowered into the well and rotated at the 
surface in order to turn a drill bit at the bottom of the well. Fluid 
is circulated down the pipe in order to cool the drill bit as it 
rotates and crushes the rock, and then to lift the drill cuttings from 
the well. Again, these wells were drilled vertical, or straight down, 
but early advancements allowed engineers to control the direction of 
the well, with a technique based on placing a simple, triangular-shaped 
deflection device down into the well and aligning this with a compass 
heading. At the time, the technology was in its infancy and progress 
was slow.
    Today, we have full navigational and guidance instrumentation built 
into the drilling assembly at the bottom of the well-much more advanced 
and precise than the navigation system in your car-with high-speed 
communications through the drill pipe that allows us to direct the path 
of the well using robotic steering devices. One of our state-of-the-art 
pieces of equipment, which we refer to as a Measurements While Drilling 
tool, contains an electronics package consisting of two high-speed 
computer processors and memory boards, collecting data from 
navigational instrumentation and sensors, powered by its own turbine 
driven generator, and all of which is packaged and ruggedized to 
withstand 30,000 psi of wellbore pressure, temperatures to 400 degrees, 
and shock and vibration exceeding 150 Gs. Imagine baking your iPhone or 
Blackberry in the oven, then driving over it, and expecting it to 
continue to function.
    An oil well drilled today will start off going straight down from 
the surface, but then it may gradually turn upwards through a smooth 
curve until it is going horizontal, or parallel with the surface, and 
then progress sideways, moving up and down or left and right in order 
to either maximize the reservoir contact, or link together smaller 
reservoir pockets in a chain along this 3-dimensional wellbore path. 
And when it comes to drilling performance, where the drilling of a well 
used to progress at 3 feet each day, today we drill wells at hundreds 
of feet each hour, and finish after the drill bit has travelled several 
miles into the earth.
    With today's technology, we can drill multiple wells from a single 
location at the surface. This is a process called pad drilling or 
template drilling, and it is used in places like the Rockies on land or 
offshore from platforms. This reduces the footprint of the drilling 
operation on the surface by eliminating the need for multiple single-
well locations. The challenge in this process is to navigate a dense 
cluster of well bores close to the surface, and we accomplish this 
through the use of the navigational technology mentioned previously.
    Another complex operation used more and more is extended-reach 
drilling. In recent years, the oil and gas industry has been increasing 
its ability to drill longer and longer wells with more complex 3-
dimensional paths. The horizontal lengths of these extended-reach wells 
are measured in miles. In Prudhoe Bay, Alaska, and in other parts of 
the world, extendedreach drilling is used to access offshore reservoirs 
using drilling rigs on land. The drilling of these long horizontal 
sections requires expert engineering, planning, and high-tech equipment 
to steer the miles of pipe drilling underground. We currently hold the 
world record for directionally drilling this type of well at 7.6 miles.
    Now when it comes to placing the well in the productive zone, 
imagine that this room is a reservoir. It's miles down, and you're not 
even sure exactly what is in here. The walls, ceiling and floor are the 
borders, and we want to drill within these to get as much reservoir 
contact as possible-the steering is directed from 5 miles away. To do 
this, we will use a complex device called a rotary steerable system to 
steer the well path, and we will also have a variety of high-tech 
sensors collecting data in order to identify the reservoir boundaries, 
and analyze the type of rock we are in, and whether or not we have oil 
and gas.
    The sensors include multi-frequency acoustic sound waves, 
electromagnetic radio waves, and magnetic resonance imaging that 
illuminate the reservoir, or in our case this room, so we can see where 
we are and steer the well to the most productive zones. All of this is 
done while we drill the well, by highly skilled engineers and 
geoscientists.
    Schlumberger is the leader in drilling services and we hire the 
best from the most prestigious universities in the US and other 
countries. Our latest advancements further integrate technologies to 
improve drilling performance and to provide advanced techniques that 
allow the oil companies to reduce their costs. In 2010, we invested 
$919 million in research and engineering and worked with oil companies 
to drill more than 7,000 miles.
    With our 2010 acquisition of Smith, we have complemented our 
existing technologies with drill bits, specialty drilling tools, 
drilling fluids and more, to provide a complete and integrated downhole 
drilling system. The next few years will be very exciting and see even 
more advancements.
    I thank you for your time and attention.

    The Chairman. Thank you very much.
    Mr. Melzer.

 STATEMENT OF L. STEPHEN MELZER, CO2 CONSULTANT AND 
           ANNUAL CO2 CONFERENCE DIRECTOR

    Mr. Melzer. Mr. Chairman and members of the Committee, my 
name is Steve Melzer. I come to you from the Permian Basin 
region of West Texas and Southeastern New Mexico, one of the 
largest petroleum basins in the world. I'd like to thank you 
for allowing me to bring our exciting advanced--enhanced oil 
recovery or EOR, technology to Washington.
    We've been producing oil from West Texas and Southeastern 
New Mexico for more than 70 years. The region is known 
throughout the world as a leader in oil recovery. What I wish 
to talk about today, especially, CO2 EOR.
    The U.S. and our area, in particular, have some very new 
developments occurring not only for enhancing oil production 
but also a solution to finding a home for CO2 
emissions that are otherwise problematic. But before examining 
the new technology for CO2 EOR, let's review 
together the stages of producing an oil reservoir.
    When you drill into a subsurface formation and counter 
fluids within the rock pore spaces the fluids are under 
pressure. The wellbore being a low pressure sink allows the 
fluids to flow to it and then on up into the surface. We call 
this the primary phase of production. Hydrofracking 
technologies and extended reach drilling allow us to reach into 
more of the formation to produce oil or gas that way.
    Eventually the fluid pressures are dissipated. The fluids 
cease to flow at a commercial rate. At this point the producing 
wells will be plugged and abandoned or we look for a method to 
re-pressure the formation and sweep fluids from what we call 
injector wells to producer wells.
    This is the second phase of production and we call it 
secondary recovery. We generally use water as a pressuring 
fluid. The water is typically sourced from deep depths, a 
brackish or more saline formation water.
    The water and oil don't mix. Much oil is swept, but a lot 
of oil is bypassed. After a good water flood is finished most 
projects will still have more than 50 percent of the oil left 
in place.
    So what comes next? To get more oil we must somehow change 
the fluid properties. We can thin it. We can move it and even 
get the oil that is clinging to the rock surfaces. This would 
be our tertiary stage.
    We do this with heat and heavy oils like in California or 
we can do it with CO2 in deeper areas. We begin the 
process--we began this process in the field in 1970s thanks to 
some oiling entrepreneurial companies, some byproduct 
CO2 from natural gas plants and a clever incentive 
from our Texas Railroad Commission to encourage the first move 
of projects. Today the process of CO2 EOR has spread 
to many places besides the Permian Basin. We make 100 million 
barrels per year or about 5 percent of our needs in the U.S. 
from CO2 EOR. We get our CO2 from what is 
typically called anthropogenic sources which might include 
natural gas processing facilities, fertilizer or even a coal 
gasification plant like in North Dakota.
    Our growth of the industry has been hampered of late as we 
are out of CO2. We envision the new CO2 
coming from more anthropogenic sources. Many are in stages of 
planning today. Several of these are first in kind facilities 
that are being aided with DOE assistance.
    CO2 purchased is valuable. What we buy gets 
stored in a formation. We don't like to lose it.
    You might be asking how much CO2 can be utilized 
or stored in or its corollary question. How much oil can be 
produced? The answer resources international corporation has 
looked at these questions in considerable detail. Their 
projections can fall into 3 categories.
    One using conventional technology and existing reservoirs.
    Two, using next generation technologies.
    Three, moving into residual oil zones.
    These last 2 categories are what I really would like to 
speak to and since this is a technology hearing. Next 
generation CO2 includes CO--things like 
viscosifiers, adding thickeners to the CO2 to 
enhance the spread of CO2 into the formation thereby 
contacting and sweeping more of the oil.
    The last category is what I've spent a great deal of my 
time on in recent years. It is residual oil zones or intervals 
that lie below the oil water contact in a reservoir, below 
where you can produce oil normally. This--the mobile phase of 
the fluids in these zones are water and the immobile phase is 
oil.
    The primary and secondary phases of production can produce 
only water from these intervals. It takes an injected such as 
CO2 to mobilize the oil. We have nine projects in 
our part of the world and several more planned later this year 
to look at the specific technology.
    Hess Corporation has one field that is just an hour north 
of my hometown where they have expanded the residual oil zone 
project 3 times and are planning a fourth for later this year. 
They are currently producing over 5,000 barrels of oil per day 
from an interval that would have produced only water in primary 
or secondary phases. Effectively they are working on what we 
call the fourth stage or quaternary oil and it will extend the 
production in the field for another 20 years.
    This process requires CO2 and deepening of the 
wells. Produce from an oil in place target of over a billion 
barrels. The ROZ resource is not present in just--in only the 
Permian Basin. We believe there are very large reservoirs of 
these type present in Wyoming and South Dakota, just to name 2, 
also many other places.
    We've seen--we have a proposed study to address these 
matters awaiting formal notification to begin. It's somewhere 
stuck up here, somewhere in Washington. We haven't quite 
figured out where yet.
    But I should say we also welcome public funding. The value 
of public money in this space is to regionally examine these 
ROZs and to make the industry results public. Heretofore the 
results have been very limited to very private studies and 
investigations.
    In summary, CO2 technology is clearly exciting 
and advancing rapidly. It addresses both energy security and 
environmental concerns. Thank you for the opportunity to speak 
to this. I would welcome any questions.
    [The prepared statement of Mr. Melzer follows:]

Prepared Statement of L. Stephen Melzer, CO2 Consultant and 
               Annual CO2 Conference Director
principles of co2 flooding, new technologies and new targets 
                for energy security and the environment
BACKGROUND ON THE U.S. AND PERMIAN BASIN OIL INDUSTRY AND THE NEW 
        EXCITEMENT IN THE CO2 FLOODING SUBINDUSTRY
    The oil and gas industry is generally portrayed as dominated by 
drilling for new oil and gas fields. And, in fact, most companies could 
be called exploration companies and make their entire living doing 
exactly that. However, there is a sub-industry concentrating on getting 
more oil from a given discovery (field). We tend to brand them as 
production companies where engineering skills are put to test in trying 
to recover more and more oil from a ``reluctant'' reservoir. The 
rewards come to these companies slower and, in a fast paced world 
seeking immediate gratification; most companies opt for the exploration 
path to provide more immediate returns for their shareholders.
    It is useful background to examine oil and gas production in a 
framework the industry has come to call the phases of production.
            A. Primary Production
    The first is the primary phase where a new field discovery is found 
and well penetrations are drilled into the formation. Oil or gas is 
produced using the pent-up energy of the fluids in the sandstone or 
carbonate (limestone, dolomite) reservoir. As long as you are good at 
finding new oil or gas and avoiding the ``dry holes,'' the returns come 
quickly while the reservoir fluid pressures are high. Eventually, 
however, the energy (usually thought of as reservoir pressure) is 
expended and the wells cease to flow their fluids. At this point, in 
the case of oil reservoirs, considerable amounts of the oil are left in 
place.
            B. Secondary Phase of Production
    The field may be abandoned after depleting the pressures or it can 
be converted to what we like to call a secondary phase of production 
wherein a substance (usually water) is injected to repressure the 
formation. New injection wells are drilled or converted from producing 
wells and the injected fluid sweeps oil to the remaining producing 
wells. This secondary phase is often very efficient and can produce an 
equal or greater volume of oil that was produced in the primary phase 
of production.
    As mentioned, water is the common injectant in the secondary phase 
of production since water is relatively inexpensive. Normally fresh 
water is not used during the waterflood and this is especially true 
today. The water produced from the formation is recycled back into the 
ground again and again. Ultimately, in most reservoirs, more than half 
of the oil that was present in the field at discovery remains in the 
reservoir since it was bypassed by the water that does not mix with the 
oil.
            C. Tertiary Phase
    If there is a third phase of production, it will require some 
injectant that reacts with the oil to change its properties and allow 
it to flow more freely within the reservoir. Hot water can do that; 
chemicals can accomplish that as well. These techniques are commonly 
lumped into a category called enhanced oil recovery or EOR. One of the 
best of these methods is carbon dioxide (CO2) flooding. 
CO2 has the property of mixing with the oil to make it 
lighter, detach it from the rock surfaces, and causing the oil to flow 
more freely within the reservoir so that it can be ``swept up'' in the 
flow from injector to producer well. Compared to the other methods of 
production, this technique is relatively new and was first tested at 
large scale in the Permian Basin of West Texas and southeastern New 
Mexico. The first two projects consisted of the SACROC flood in Scurry 
County, Tx, implemented in January of 1972, and the North Crossett 
flood in Crane and Upton Counties, Tx initiated in April, 1972. It is 
interesting to note that installation of these two floods was 
encouraged by daily production allowable\1\ relief offered by the Texas 
Railroad Commission and special tax treatment of oil income from 
experimental procedures.
---------------------------------------------------------------------------
    \1\ During the 1930s through 1972, the Texas Railroad Commission 
limited statewide oil production by granting production permits to well 
operators for a certain number of days per month.
---------------------------------------------------------------------------
    Over the next five to ten years, the petroleum industry was able to 
observe that incremental oil could indeed be produced by the injection 
of CO2 into the reservoir and the numbers of CO2 
flood projects began to grow. Figure 1 illustrates the growth of new 
projects and production from 1984 through the present day.
    The carbon dioxide for the first projects came from CO2 
separated from produced natural gas processed and sold in the south 
region of the Permian Basin. Later, however, companies became aware 
that source fields with relatively pure CO2 could offer 
large quantities of CO2 and three source fields were 
developed--Sheep Mountain in south central Colorado, Bravo Dome in 
northeastern New Mexico, and McElmo Dome in southwestern Colorado. 
Pipelines were constructed in the early 1980s to connect the 
CO2 source fields with the Permian Basin fields (Figure 2). 
The new supply of CO2 led to a growth of projects through 
the early 1980s and expansion to other regions of the U.S.
    The oil price crash of 1986 resulted in a drop of oil prices into 
single digits in many regions. The economics of flooding for oil was 
crippled; capital for new projects was nonexistent. But curiously, as 
demonstrated in Figure 1, the industry survived the crash with fairly 
minor long term effects and resumed its growth curve until the next 
price crash in 1998.
CURRENT AND PROJECTED FLOODING ACTIVITY IN THE U.S. & PERMIAN BASIN
    The recent decade has once again seen a flourish of new 
CO2 floods. Today, 111 floods are underway in the U.S. with 
64 of those in the Permian Basin. The numbers have doubled since the 
economically stressful days of 1998 (see Figure 1*). New CO2 
pipelines are being constructed in the Gulf Coastal region and in the 
Rockies promising to grow the flooding activity in both of those 
regions dramatically. The Permian Basin is effectively sold out of 
their daily CO2 volumes and, as a result, growth there has 
slowed to a crawl.
---------------------------------------------------------------------------
    * All figures have been retained in committee files.
---------------------------------------------------------------------------
    The aggregate production from CO2 EOR has grown to about 
18% of the Permian Basin's 180,000 (see Figure 3) out of the 900,000 
barrels of oil per day (bpd) or approximately 5% of the daily U.S. oil 
production. The oil industry rightfully brags about finding a billion 
barrel oil field. Such discoveries are very rare and non-existent today 
in the U.S. It is interesting to note that the billionth CO2 
EOR barrel was produced in 2005. The CO2 bought and sold in 
the U.S. every day now totals 3.1 billion cubic feet or about 65,000 
tons per year.
LONG TERM NATURE OF THE INDUSTRY
    What may be evident is that the CO2 flood industry is a 
long-lived industry. While fluctuation of oil prices have a de-
accelerating effect, the steady baseline growth represents a refreshing 
exception to the otherwise frustrating cyclicity of gas and oil 
drilling/production. Both of the first two floods (SACROC and Crossett) 
are still in operation today and are producing nearly one million 
barrels per year today. After almost 40 years of operation under 
CO2 injection, these floods are still purchasing 
approximately 300 million cubic feet per day (over six million tons per 
year) of CO2. The long term nature of the floods continues 
to generate enormous economic power, provide local, state and federal 
taxes as well as employment and energy production for the area and 
nation. These barrels will be produced from reservoirs already 
developed and should represent about 15% of the original oil in place 
within the reservoirs. Without the advent of CO2 flooding, 
the barrels would have been lost, i.e. left in the reservoir upon 
abandonment of the waterfloods.
PROJECT PLANNING UNDERWAY WITHIN THE PERMIAN BASIN
    Many Permian Basin companies are currently planning new 
CO2 projects. Denbury Resources has averaged two new 
startups per year in the Gulf Coast region for the last decade. Wyoming 
is another area with intense CO2 activity. My ``backlog'' of 
projects in planning is estimated at more than 20.
    Much of the impetus for planning new CO2 floods results 
from a broader recognition of the technical success and economic 
viability of the CO2 EOR process. The current oil price is a 
huge factor as well. The last factor relates to the maturity of the 
oilfields and secondary waterfloods of which many began in the 1950s.
    Technological advancements are another major reason for the 
development of CO2 flooding. Three-D seismic techniques have 
had a large impact on delineating heretofore unknown features of the 
reservoir. The ability to characterize and model the reservoir and in 
simulating the effects of CO2 injection have clearly reduced 
the risk of a flood (economic) failure.
    To date, the development of carbon dioxide flooding has clearly 
favored the Permian Basin. In addition to the extensive pipeline 
infrastructure and the nearby CO2 source fields, it has a 
large number of large and mature fields which have been shown to be 
amenable to CO2 injection
CO2 SUPPLY AND DEMAND WITHIN THE PERMIAN BASIN
            A. Demand for CO2
    Demand for CO2 stems from the oilfield opportunities and 
the ability to reap financial rewards from the oil produced. Many 
believe that the long term demand for oil has never been greater except 
in times of imminent war. Additionally, technology has paved the path 
for moving a field into a new phase of production; such undertakings 
are considered both viable and desirable. But matching demand with a 
supply of CO2 can be expensive and challenging. Historically 
it was done within an integrated oil company who recognized the 
oilfield upsides and was willing and able to develop the CO2 
source and connect the two with a pipeline. Today, with the departure 
of the oil majors, this connection must be accomplished between several 
corporate entities, each of which knows very little about the business 
of the others. This is especially true for the industrial sources of 
CO2 where we think the large CO2 supplies for 
tomorrow must come.
            B. New Supplies of CO2
    A new report in preparation by the MIT Energy Institute\2\ has 
examined the economics of CO2 supplies coming from the 
fossil fuel power plants and concludes that a ``gap'' exists between 
the value of the CO2 and the costs of capture. Perhaps 
technology can close that gap but the first few demonstration plants 
are multi-billion dollar investments and appear to be outside the risk 
portfolios of companies capable of making those investments.
---------------------------------------------------------------------------
    \2\ MIT Energy Institute, July 23, 2010, Role of Enhanced Oil 
Recovery in Accelerating the Deployment of Carbon Capture and 
Sequestration, 196 pgs.
---------------------------------------------------------------------------
    Alternative sources are smaller but their economics are better. 
CO2 value is a function of purity and pressure; some 
industrial sources can capture CO2 for the value received. 
But what is more apparent every day, this all takes time and the 
cultures of the surface and subsurface industries are so different that 
barriers constantly impede the progress.
            C. Supply/Demand Balance
    For the first 25 years of the CO2 EOR business, the 
underground natural CO2 source fields were of ample size to 
provide the CO2 needed for EOR. Pipelines had also been 
built of sufficient throughput capacity to supply the needs. Today the 
situation has changed. Either depletion of the source fields or 
limitations of the pipeline are now constricting EOR growth. Cost of 
capture of industrial CO2 has not advanced to close the gap 
between the value of the CO2 and the cost of capture.
NEW U.S. DEVELOPMENTS OUTSIDE OF THE PERMIAN BASIN
    While the Permian Basin clearly dominates the CO2 EOR 
development picture today, it is important to note that the Gulf Coast 
and Wyoming are ``exploding'' with new growth In fact, the Mississippi 
growth is a classic example of production growth where CO2 
supply was not a limiting factor. The Jackson Dome natural source field 
near Jackson, MS has been developed in very rapid fashion to provide 
the necessary new CO2 to fuel the expansion of EOR. Wyoming 
has a similar story with their LaBarge field and Shute Creek plant.
RESIDUAL OIL ZONES DEVELOPMENTS WITHIN THE PERMIAN BASIN
    A new revolution is underway in the CO2 EOR industry. 
The oil industry is undergoing a significant shift in the way it 
calculates resources. New sources of oil are being recovered today 
using techniques such as CO2 EOR in intervals known as 
Residual Oil Zones (ROZs). Furthermore, these intervals appear to be 
very abundant.
    The traditional phases of production, or Ternary view of oil 
extraction, have often been characterized by three phases. As shown in 
Figure 4, the bottom of the resource triangle (primary) represents 
production coming from conventional reservoirs where pent-up energy 
within the pore fluids is used to produce the oil (or gas). As 
mentioned earlier, the pressures in these conventional reservoirs 
eventually are depleted as the fluids are produced and the fluids no 
longer flow to the producing wells at a commercial rate. Some 
formations (a subset of the primary produced ones) are amenable to 
injection of a fluid to re-pressurize and sweep the oil from newly 
drilled injection wells to the producer wells. This is the second tier 
shown in Figure 4. Water is usually the chosen fluid for injection 
since it is relatively cheap and widely available. The oil and gas 
industry has had a long history developing best practices for 
optimizing waterflood oil recovery.
    A lot of oil will remain in a reservoir even after the 
waterflooding phase. A common metric for the Permian Basin of West 
Texas, the largest oil and gas reserve in the US, is that primary 
processes will get about 15 percent of the original oil in place (OOIP) 
in the reservoir and secondary processes will get another 20-30 
percent. Astonishingly, more than half of the original OOIP is left 
behind.
    The next phase of resource recovery (tertiary) goes after the oil 
left in place and this is where the aforementioned EOR techniques are 
used. It is a more expensive process than waterflooding so fewer 
reservoirs make it to this stage and oil production here has been 
important but relatively small when compared to both primary and 
waterflood applications.
    EOR typically aims for the oil bypassed during waterflooding. When 
CO2 contacts the oil, it enters into solution with the oil. 
This alters the density and viscosity of the oil, expanding it, and 
changes the oil's surface tension with the rock. EOR using 
CO2 is so effective at loosening and displacing oil that the 
process often leaves less than 10 percent of the OOIP behind. The 
engineering challenge to EOR using CO2 revolves around the 
ability to contact large portions of the oil reservoir. To gauge 
success, engineers use a metric called ``volumetric sweep efficiency.'' 
In the Permian Basin, where the techniques have been polished, 
CO2 has been used in EOR processes to obtain an additional 
15-20 percent of the OOIP.
            A. ROZ Targets
    Residual Oil Zones that are not man-made, but created by natural 
waterfloods in reservoirs, are being looked at as possible commercial 
targets for oil production today. Natural causes, such as ancient 
tectonic activity, can cause oil to move around in basins and water can 
encroach into a former trap. Industry is now looking at how much oil is 
left behind in naturally swept reservoirs and finding that these 
natural waterfloods can leave behind levels of residual oil similar to 
those left behind by manmade waterfloods. These ROZ targets can be very 
large and open a whole new resource for development.
    Today, nine CO2 EOR projects have targeted ROZs in the 
Permian Basin. Most notable among these are three projects being 
developed by Hess Corporation. The first two were Hess pilot projects 
designed to deepen wells into the ROZ to evaluate the technical and 
commercial feasibility of a 250-foot thick ROZ. The ROZ resource at the 
field is given nearly one billion barrels of oil in place and the 
results from the two pilots have led to a phased and full field project 
designed to recover 200+ million barrels of oil. Stage 1 of the full 
field deployment is two years old and budget approvals are being put in 
place to expand into Stage 2. Time will tell what the total recovery 
figures will be, but the current 29 patterns (injection wells) are 
already responsible for over 5,000 barrels of oil per day with rapidly 
upward trending production. The oil being produced in these wells could 
not have been produced except by EOR techniques since the target oil is 
the residual oil left behind when a natural waterflood swept out the 
originally entrapped oil sometime in the geological past.
            B. Quaternary View
    The new (``quaternary'') view of oil production (Figures 4 and 5) 
are the new ways to visualize the ROZ opportunity. It can be called the 
fourth phase of oil resource production as in the Hess project or, 
alternatively, can offer production possibilities in swept reservoirs 
where primary or secondary production could not be obtained. How much 
oil is there to recover via EOR that would not otherwise be part of the 
recoverable reserves of a Nation? On-going Permian Basin studies 
suggest that these quaternary phase producible resources are enormous-
perhaps as large a future production figure as the cumulative 
production of oil from this basin to date (30 billion barrels). A 
proposal to more closely examine the sizes of this resource in the 
Permian Basin and extend the methodology to two other U.S. Basins is 
awaiting approvals at DOE.
SUMMARY
    The technological innovations sweeping the world are also evident 
in the oil and gas industry. One of these developments is carbon 
dioxide flooding where oil that would be abandoned in existing fields 
is being produced. CO2 EOR was shown to grow during times of 
$20 per barrel oil and is clearly demonstrating all the symptoms of 
rapid growth and expansion. Formerly led by the Permian Basin, new 
CO2 floods are becoming commonplace. In the U.S. and Permian 
Basin today, the percentage of production attributable to 
CO2 injection is 5% and 18% of total production, 
respectively. The numbers are capable of growing rapidly.
    CO2 EOR utilizes an injectant that is considered by many 
to be an air emissions issue. When pressured and purified, it becomes a 
valuable commodity that can produce oil and, when its work is done, 
effectively all of it can remain stored in the subsurface. 
CO2 EOR becomes both a mechanism for oil production and an 
environmental tool for emission reductions.
    Historically, CO2 EOR has been cast in a framework where 
it is insignificant in terms of the emission streams that are to be 
captured. However, the truth is that it can provide an enormous 
``demand pull'' for the needed CO2 supplies. Additionally, 
the emergence of residual oil zones as viable EOR targets changes the 
dialogue. And, maybe best of all, it pushes the public discussion from 
waste disposal (sequestration) to resource extraction and energy 
security.

    The Chairman. Thank you very much.
    Mr. Banks.

STATEMENT OF KEVIN R. BANKS, DIRECTOR, DIVISION OF OIL AND GAS, 
         DEPARTMENT OF NATURAL RESOURCES, ANCHORAGE, AK

    Mr. Banks. Thank you, Senator Bingaman and Senator 
Murkowski for inviting me to speak to the committee today. I 
feel privileged to be here. I've submitted written testimony to 
the committee but for my oral testimony I'd like to provide you 
with a brief summary.
    I'm Kevin Banks, the Director of the Division of Oil and 
Gas as part of the Department of Natural Resources in Alaska. 
Our agency manages over a million acres of State land and most 
all of the oil production in Alaska comes from these lands. We 
are here today to discuss these improvements of seismic data 
technologies, advances in drilling techniques and enhanced oil 
recovery.
    I want to talk about how these and other improvements in 
exploration and production operations have been deployed in the 
Arctic. My emphasis will be to describe the evolution of these 
technologies through time and how that has minimized the impact 
of industry operations on the Arctic environment.
    Since the discovery of Prudhoe Bay in the 1970s the oil 
industry has had to invent engineering and scientific solutions 
to match the cold and remoteness and extraordinary values of 
the land and animals in the Arctic. It is a process where the 
industry has come up with new and unique ideas. Where industry 
has imported into the north, advances in technologies tested 
elsewhere every tool and concept that has been modified and 
specialized from the ordinary civil construction of man camps 
and roads and pipelines to the high tech science of oil 
exploration production.
    Much of the exploration on the North Slope always occurs in 
the winter. Frozen tundra makes it possible to move across the 
land with minimal impact and to position very heavy drilling 
rigs. Winter operations means that impacts on wildlife can be 
minimized. Polar bears have moved offshore. Most birds and 
caribou have migrated south.
    Geophysical surveys represent the first step in exploration 
that contacts the land. As we've heard, 3D seismic surveys now 
differ from the old 2D seismic in the number of seismic lines 
laid out, the number of geophones and the number and placement 
of the energy sources used. The evolution of seismic technology 
in the field is in the intensity of data acquisition, the 
sensitivity of the instrumentation and precision that the 
equipment can be located using global positioning satellite 
system.
    The biggest leap in seismic technology has been in the 
digital processing of the data and the result and the 
resolution of the subsurface stratigraphy. The current state-
of-the-art seismic interpretation on the North Slope means that 
wild cat exploration has become much more successful. Better 
success rates for exploration wells means that fewer intrusions 
from these operations on the environment.
    Exploration wells on the North Slope are drilled from ice 
pads and logistical support is conveyed over ice roads. In my 
submitted written testimony I have included photos of drilling 
in the Alpine field on page 5. When the well illustrated in 
these photos was completed the only visible sign of prior 
activity is the well house that was left because the well was 
going to be a part of a further Alpine field development. Most 
exploration wells are secured, cutoff below grade and buried, 
leaving no visible footprint.
    While extended reach drilling is suitable for the 
production phase of oil development, vertical wells are still 
the best way to drill an exploration well. Even with the best 
3D seismic information available there's still some uncertainty 
of the target depth for a wild cat objective. A highly deviated 
well can over shoot or under shoot the oil/gas zone. On the 
North Slope when the time to drill is constrained by the winter 
season an explorer can drill a vertical well faster and with 
better results. In the production phase it is the extended 
reach drilling that is so important.
    The first drill sites drilled in Prudhoe Bay used well 
spacing to distance between the well heads of 160 acres. The 
drill site No. 1 there had a 65 acre impact on the ground and 
wells deviated from that particular site would only deviate 
about a mile or so. If you were to place DS-1 over the Capitol 
Building the drill site itself would cover the Capitol and all 
of its environs around here, the neighborhood around here. The 
reach of the wells would be no further than the Washington 
Monument.
    By 2000 extended reach drilling was combined with 
horizontal drilling techniques so that the CD-2 site at Alpine 
field is just now 13 acres. 54 wells drilled on it with a well 
spacing of just 10 feet. The extended reach of these wells can 
intercept an area 8 miles across and penetrate 50 square miles 
of the field.
    On a map of a Washington DC, if you're to drill those wells 
from here, the wells could reach south of the Anacostia freeway 
on the south and Adams Morgan on the north. The Liberty Project 
which is proposed by BP and the OCS is going to extend the 
drilling concept even further. If these wells were drilled from 
here the extent of those wells would reach out to Andrews Air 
Force Base in the south, Silver Springs in the north and well 
into Fairfax County in the West.
    I will close with just a final comment about enhanced oil 
recovery. When applied to fields in the lower 48 people usually 
think of EOR as intended to simulate oil fields. On the North 
Slope every field was developed with EOR plans already in place 
before the field began production. This is the kind of 
secondary recovery that you heard about from the water flooding 
and gas injection.
    Optimization of reservoir production is monitored using 
intensive surveillance tools and modeled using sophisticated 
dynamic simulations. These programs, in turn, have led to the 
use of missile injection, water alternating with gas, polymer 
treatments and the low salinity water injection project. In the 
Prudhoe Bay field, a truly ingenious gas cap water injection 
project that sweeps relic oil out of the gas cap and into the 
oil leg. These techniques have together achieved recovery rates 
that the North Slope developers could not have dreamed of when 
Prudhoe Bay was first brought online in 1977.
    This concludes my oral testimony. I certainly appreciate 
having the opportunity to speak to you today.
    [The prepared statement of Mr. Banks follows:]

  Prepared Statement of Kevin R. Banks, Director, Division of Oil and 
          Gas, Department of Natural Resources, Anchorage, AK
    The indigenous people of the Arctic have demonstrated a unique 
skill in adapting to new technologies to survive over 10,000 years. The 
extremes of the climate and the terrain demand only the best 
performance of man to succeed. Ironically, the oil and gas industry has 
also learned that it must bring its best tools and brightest people to 
the Arctic to meet the challenges of the environment.
    Since the construction of the Trans-Alaska Pipeline System and the 
development of the Prudhoe Bay oil field in the late 1970s, the oil 
industry has had to invent engineering and scientific solutions to 
match cold, the remoteness, and the extraordinary values of the land 
and animals in this place. This has been a process where industry has 
come up with new and unique solutions applicable to only the Arctic and 
where industry has brought north advances in technology tested 
elsewhere and adapted to the special conditions of the North Slope. 
Everything from the civil construction of man-camps, treatment and 
handling of the by-products of oil development, and the installation of 
roads and pipelines to the hightech science of oil exploration and 
development has been modified and specialized for the conditions found 
only in the Arctic. Even as the Inupiaq people of Alaska's North Slope 
have incorporated modern tools to sustain their subsistence lifestyle, 
so too has the oil industry adapted.
    The North Slope represents America's toehold in the Arctic. Though 
Americans don't often think about it, Alaskans know that the US is an 
Arctic Nation with the same rights and concerns and aspirations as 
Russia, Norway, Greenland, or Canada. The North Slope of Alaska-the 
onshore region north of the Brooks Range-is truly vast; at nearly 
150,000 square miles, an area larger than 39 states in the ``Lower 
48.'' (See Figure 1*) Offshore in the Chukchi Sea north of the Bering 
Straits and the Beaufort Sea on Alaska's northern coast are another 
65,000 square miles in just the area of the outer continental shelf 
(OCS) managed by the Bureau of Oceans and Energy Management, 
Regulation, and Enforcement (BOEMRE). Onshore the State of Alaska owns 
only a small share of the total acreage; the Figure 1 2 federal 
government is, by far, the largest landowner in the region controlling 
20 million acres in the Arctic National Wildlife Refuge, 23 million 
acres in the National Petroleum Reserve-Alaska (NPR-A), and all of the 
OCS.
---------------------------------------------------------------------------
    * Figures 1-26 have been retained in committee files.
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    This region holds incredible potential for oil and gas. According 
to the US Geological Survey, America's Arctic ranks as number one for 
undiscovered oil potential and number three for gas potential for the 
world's conventional petroleum resources north of the Arctic Circle. 
Nearly 50 billion barrels of conventional undiscovered, technically 
recoverable oil resources and 223 trillion feet of conventional 
undiscovered, technically recoverable gas resources may be found in the 
North Slope and the Arctic OCS off Alaska's northern coast. This 
represents 43 percent of the nation's total oil potential and 25 
percent of its gas potential.\1\ Figure 2 shows that these estimates 
fall within a range of wide uncertainty. This range is indicated in the 
size of the distribution between the 5 percent and 95 percent 
probabilities that oil or gas resources may exceed the amounts shown. 
For an area like Alaska's Arctic this uncertainty should be expected. 
Figure 3 explains why this is so.
---------------------------------------------------------------------------
    \1\ These estimates do not include the potential for undiscovered, 
technically recoverable unconventional resources: coalbed methane, 
deep-basin gas, gas hydrates (USGS mean estimate is 85 trillion cubic 
feet), or shale oil and gas.
---------------------------------------------------------------------------
    The North Slope has barely been explored when compared to the 
intensity of exploration that has already occurred throughout out the 
rest of the United States. If we were to place a map of Wyoming over a 
map of the North Slope the discovery well at Prudhoe Bay-the largest 
oil field in the US-would lie at the eastern boundary of Wyoming. The 
Burger well in the Chukchi Sea that discovered hydrocarbons there in 
the early 1990s would lie at Wyoming's western boundary. For reference, 
the 150,000 square miles of onshore area of the North Slope is twice 
the prospective area of Wyoming. Wyoming has seen over 19,000 wells 
drilled over the years or about 250 wells per 250 square miles. Only 
500 exploration wells have been drilled on the North Slope; just three 
wells per 250 square miles. Exploration activity in America's Arctic 
has just begun. Over the years, as exploration has continued in places 
like Wyoming the assessment of undiscovered resources often continues 
to grow. Today's estimate of remaining oil and gas reserves in Wyoming 
far exceeds the amount of undiscovered resources predicted years ago in 
spite of substantial actual production during the same time period. As 
exploration matures in the US Arctic the same history may be written.
    We are here today to discuss advances in oil and gas exploration 
and production technologies, specifically improvements of seismic data 
acquisition and processing, advances in drilling techniques, and 
enhanced oil recovery. I want to describe how these and other 
improvements in oil and gas exploration and production operations have 
been deployed in the Arctic. My emphasis will be how the evolution of 
these technologies has through time minimized the impact of exploration 
and production operations on the Arctic environment.
    Onshore exploration on the North Slope always occurs in the winter. 
The frozen tundra makes it possible to move across the land and to 
position drilling rigs. Winter operations have almost no impact on 
wildlife: polar bears move offshore, most birds and caribou have 
migrated south. Geophysical surveys represent the first step in 
exploration that contacts the land-and it is a relatively light touch. 
Tracked vehicles are used to spread the weight of the vehicles on the 
ground to avoid compaction and any scouring. Even conventional trucks 
can be modified with rubber track kits. Heavier loads are carried on 
roligons, special trucks with huge, soft tires. For those of us who 
remember typewriters, the wheels of a roligon look like a typewriter 
roller. The physical acquisition of seismic data is a labor-intensive 
process so the main impact on the land is the boots-on-the-ground of 
crews carrying geophones across the tundra. Vibroseis equipment is used 
whenever possible further reducing any impact to ground. The frozen 
tundra also provides a better medium to transmit energy into the earth.
    From the perspective of land use, three-dimensional seismic surveys 
differ from 2D seismic in the number of seismic lines laid out, the 
number of geophones used, and the number and placement of energy 
sources used. The evolution of seismic technology in the field is in 
the intensity of data acquisition, the sensitivity of the equipment and 
improvements in positioning the equipment using global positioning 
satellite (GPS) system. The biggest leap of seismic technology has been 
in the digital processing of all of the data acquired and the resultant 
resolution of the subsurface stratigraphy. Not more than 15 years ago, 
super-computers were used to manipulate seismic data. Now desktop 
workstations are used at a cost that many more oil companies can 
afford.
    I've include three images to illustrate an example of the state of 
the art for seismic interpretation in use on the North Slope. (These 
are from paper written by a geoscientist from the Bureau of Land 
Management, US Department of the Interior. He presented this paper at 
joint session of the American Association of Petroleum Geologists and 
the Society of Petroleum Engineers held yesterday in Anchorage, Alaska. 
Figure 7 shows just how dramatic the resolution of 3D seismic 
interpretation can reveal the characteristics of the subsurface. The 
vertical dimension is exaggerated and what you can see in this figure 
is the deposition of layers of sandstones and siltstone in an 
underwater delta system as it crests over the continental shelf of an 
ancient shallow sea. Figure 8 shows more detail of how these 
depositions occurred in channels and at the edges of delta fans. As 
material flowed through these systems, the sands were transported and 
sorted by turbidity washing out the fines in channels and at the distal 
edges of the fans. In these areas are found the best reservoir rock 
characteristics, the more porous and permeable sandstones.
    Figure 9 shows what the geophysicist is looking for: anomalies in 
the seismic reflections that can be correlated to similar anomalies 
detected in surveys done an area nearby where extensive drilling has 
already occurred. In this case, within the Alpine oil field just east 
of the Colville River and just outside of the NPR-A. The ``Class III 
anomalies'' shown in the bottom of this graphic are filtered out of the 
data and provide information of not only the rock characteristics but 
also the fluid properties. These same anomalies are the ``bright 
spots'' highlighted back in Figure 8.
    This kind of seismic interpretation is only possible because of the 
resolution and detail afforded from 3D. In this particular case 
drilling at Alpine provides the information from well logs and the 
fluids produced from the wells to identify anomalies in the seismic 
data where exploration drilling should occur. Because of this 
interpretation, the exploration program conducted in the northeast of 
the NPR-A was very successful in finding hydrocarbons. It also means 
that fewer ``wildcat'' exploration wells were needed to find oil and 
gas. Over the last twenty years, improvements in seismic technology and 
the application of better geological interpretation has meant that the 
dry hole risk has substantially declined. Better success rates for 
exploration wells means fewer intrusions from exploration operations on 
the environment.
    Seismic surveys are not a replacement for actual exploration 
drilling. While 3D seismic surveys have fundamentally changed the 
exploration business, ``The truth is in the drilling!'' On the North 
Slope, onshore exploration drilling occurs only in the winter. Heavy 
equipment is brought out to remote sites on ice roads (Figure 10) and 
the drilling rigs are assembled on ice pads. Ice roads are built by 
hauling crushed ice to the road location to provide a substrate for 
trucks that spray water over the crushed ice to form a smooth hard 
surface. The flat terrain of the North Slope and the usually abundant 
water sources located there make it possible to build ice roads in most 
places. They are nonetheless expensive when considering that they 
disappear with the spring thaw. Ice roads have been used on the North 
Slope for decades.
    Figure 11 shows a drill rig erected on a remote ice pad in the 
Alpine field. The rig itself weighs several million pounds, the large 
structure on the left is a 100 person camp, and adjacent to the ice pad 
is an ice airstrip. The pad itself is at least 12 inches thick and in 
many cases insulation and rig mats are placed on top of the ice to 
protect it and distribute the heavy loads. All drilling wastes and 
other discharges, e.g., domestic water from the camp, are trucked away 
for disposal in approved injection wells. At the end of the winter 
season, a front-end loader will scrape the pad down to pure ice to 
allow the ice to melt more quickly. When the ice melts, there is no 
trace left of the pad.
    The only visible sign of prior activity is an eight-by-eight foot 
well house that will remain on location only because this well is part 
of a field under development and will one day produce oil. If the well 
were to be plugged and abandoned, which would be the case for most 
exploration wells, the well would be cemented-in to prevent any 
communication among any formations penetrated by the well and the 
surface. The well would be cut off below grade, marked with a plaque 
welded on the top, and buried. Note the recovery of the vegetation 
around the well house illustrated in Figure 13. It is possible to 
explore for oil on the North Slope and leave no visible footprint.
    Figures 14 and 15 are photos of the ``Hot Ice'' platform erected at 
the edge of the foothills of the Brooks Range. This is also a temporary 
structure and actual drilling activity only occurred during the winter. 
This structure was tested because it afforded a way to store the 
drilling rig and to stage other equipment through the summer months. 
This exploration concept is intended to be used in very remote sites. 
The length of the ice road and the time needed to build it means that 
the drilling season is shorter for these sites. With the rig already in 
place, winter drilling can begin earlier and continue longer than could 
be accomplished by building an ice pad.
    Extended reach drilling techniques have advanced tremendously in 
recent years and, as the technology has evolved, drillers have 
extensively used these techniques on the North Slope. While suitable 
for the production phase, vertical wells are still the best way to 
explore for hydrocarbons especially on the North Slope. The main 
advantage of a vertical exploration well can be seen in Figure 16. Even 
with the best 3D seismic information available, there is some 
uncertainty of the target depth for a wildcat objective. A highly 
deviated well can overshoot or undershoot the oil or gas zone whether 
the zone is a structural or stratigraphic trap. On the North Slope when 
the time to drill is constrained by the winter season, the explorer can 
drill a vertical well faster and with better control. A deviated well 
is more difficult to drill, more difficult to log successfully, and is 
more expensive. Once measurements are taken, e.g., true depth 
established and correlated to the seismic information, delineation 
wells drilled to assess the areal extent of the prospect can be drilled 
using horizontal drilling techniques. In some instances delineation 
wells can be drilled laterally from the same borehole of the first 
exploration well.
    As extended-reach drilling technology has evolved so has the 
deployment of the technology on the North Slope. From a land use 
perspective and as a way to minimize environmental conflicts, extended 
reach drilling combined with improvements in well design that allows 
for closer well spacing-the distance between the wellheads at the 
surface-has been incredibly successful. The evolution of drilling on 
the North Slope is another example of how industry has brought to the 
region technologies developed elsewhere and then improved upon for the 
unique conditions in the Arctic. These improved technologies are then 
exported from the North Slope to other regions where new improvements 
are made and new tools are developed. Then the resulting new technology 
is brought back to the North Slope. Figures 17 and 18 show the twin 
impacts of well spacing and extended reach drilling.
    The first drill sites in the Prudhoe Bay field were built in the 
1970s and used well spacing of about 160 feet and covered 65 acres of 
land to accommodate the footprint of the drilling rigs of the day. As 
many as 25 or 30 wells drilled in three rows from these sites could 
deviate to approximately one-mile from the vertical. By the time the 
first production wells were drilled in the Kuparuk River field in the 
early 1980s, improvements in rig design and drilling techniques and the 
materials used in the wells meant that the area of the drill sites 
could be reduced by more than one-half. The first drill sites in the 
Kuparuk River field had a well spacing of 60 feet and a 16 well drill 
site was just 24 acres. Wells from these first drill sites could 
deviate more than one-and-a-half miles from the vertical.
    By the mid 1980's the technology employed in the Kuparuk River 
field had advance significantly. A 16 well drill site was reduced to 
just 11 acres and the wells could deviate by more than 2.5 miles from 
vertical and penetrate over 12,560 acres of the reservoir.
    The Alpine field in the Colville River Delta represents the next 
stage in drilling advancement. From a drill site of only 13 acres, 54 
wells have been drilled at a spacing of just 10 feet. The rig 
cantilevers over the well to avoid the wellhead of the neighboring 
well. The extended reach of these wells can intercept an area 8 miles 
across and penetrate 50 square miles of the field.
    In just 30 years, surface footprint requirements have been reduced 
from over 2 acres per well at Prudhoe Bay, to one quarter (0.24) acre 
per well at Alpine.
    The pairs of maps shown in Figures 19-24 show what this evolution 
means in terms of the areal extent achieved by the changes in extended-
reach drilling capabilities over the years. Wells drilled from DS-1 in 
Prudhoe Bay could reach only a part of the field. In Figure 19 the 
spider diagrams represent the areal extent of the wells and their 
underground trajectory. The surface footprint of the drill site is much 
smaller, as was shown in Figure 18. Now superimpose the extent of the 
spider diagram from DS-1 on the US Capitol Building (See Figure 20). 
Some of these wells can't reach the Washington Monument and the drill 
site itself would dominate the area of the Capitol Building and the 
surrounding neighborhood.
    Improvements in drilling technology during the 1980s and early 
1990s extended well reach to about 3 miles. Modular rig construction 
reduced the space needed between wellheads and elimination of reserve 
pits further reduced surface impact. Figure 21 is the spider diagram of 
the DM-2 drill site in the Kuparuk River field. Again the spider image 
shows well trajectories and how far the wells can reach. The surface 
impact is only a very small part of the spider diagram. Wells from DM-2 
produce oil from nearly 6,400 acres (10 square miles) and the drill 
site has a footprint of just 12 acres. Superimpose this diagram on the 
US Capitol Building (Figure 22) and the wells will reach beyond Reagan 
National Airport and up towards Washington Hospital.
    By 2000 extended reach drilling technology was combined with 
horizontal drilling techniques that had become commonplace for most all 
production wells on the North Slope. The Alpine field is the latest 
excellent example of minimizing surface impact while maximizing 
resource development. The spider diagram in Figure 23 shows that 
extended reach/horizontal wells drilled from the 11-acre CD-2 drill 
site in the Alpine Field can produce from about 14,200 acres (22 square 
miles). Some of the wells in the Alpine field can reach out 4 miles 
from the drill site. On a map of Washington, DC with the drill site at 
the Capitol Building, the wells can reach well south of the Anacostia 
Freeway all the way to Adams-Morgan (Figure 24).
    The Liberty project represents the next and latest phase: ultra-
extended-reach drilling. Although these wells have not yet been 
drilled, the rig is up and undergoing final engineering and design 
assessments. It is likely be the largest land rig in the world. Figure 
25 is a map of the proposed Liberty project. Green areas denote 
underground oil reservoirs. Yellow dots denote proposed drilling 
targets. Liberty will be developed from the existing Satellite Drilling 
Island (SDI) drill site originally constructed for the Endicott field. 
Six wells are planned that will reach up to 8 miles from the island. If 
successfully implemented, these wells will be the longest reach wells 
ever drilled.
    Figure 26 shows the area that could be reached by the Liberty wells 
if the rig was set on the site of the Capitol Building. The wells could 
extend out to Andrews Air Force Base in the southeast, Silver Spring in 
the North, and well into Fairfax County in the west. If the Prudhoe Bay 
field were developed today using Liberty-type drilling technology, 
surface impact would be greatly reduced to possibly as few as two drill 
pads.
    The climate, the remoteness, government regulation, and undoubtedly 
the cost all contribute to the industry's ability to drill in the 
Arctic with as little impact to the land as possible. The evolution and 
deployment of technological improvements over the years tell a story of 
innovation and adaptation that is demanded of the Arctic on all who 
live and work there.
    Epilogue: A final comment about enhanced oil recovery (EOR). 
Testimony by others at this hearing will provide the committee with a 
description of incredible and fantastic applications of physics, 
chemistry, and engineering to squeeze every drop of hydrocarbons out of 
US oil and gas fields. When applied to fields in the Lower 48, people 
usually think that EOR is intended to stimulate old oil and gas fields 
and reverse their production declines. Note that every field developed 
on the North Slope, including Prudhoe Bay, had an EOR plan in place 
before the first drop of oil was produced. Water flooding and gas 
injection, miscible injection, water-alternating-with-gas (WAG) were 
designed into the facilities as they were installed and upgraded. The 
optimization of these EOR projects are continually monitored using 
intensive surveillance tools and modeled using sophisticated dynamic 
simulations of the reservoirs. The Saddlerochit reservoir in the 
Prudhoe Bay field maybe the most well understood reservoir in the 
world.
    The Alaska oil and gas Industry is also implementing amazing new 
EOR ideas. The Gas Cap Water Injection Project at the Prudhoe Bay field 
is such an idea. By flooding water through the gas cap, relic oil will 
be swept into the oil leg of the reservoir where it can be produced. 
Monitoring the progress of the success of this project is achieved by 
employing the first of its kind micro-gravity 4D survey that can 
remotely detect the movement of fluids through the gas cap. Pilot 
projects are also underway including the low salinity water injection 
project and polymer treatments.
    A variety of artificial lift mechanisms are employed throughout the 
fields on the North Slope including gas lift, jet pumps, electric 
submersible pumps, and progressive cavity pumps. The industry has also 
implemented many surface gathering and processing advancements, 
corrosion monitoring, and equipment condition based monitoring 
programs.

    The Chairman. Thank you.
    Ms. Epstein.

STATEMENT OF LOIS N. EPSTEIN, P.E., ENGINEER AND ARCTIC PROGRAM 
        DIRECTOR, THE WILDERNESS SOCIETY, ANCHORAGE, AK

    Ms. Epstein. Good morning. Thank you for inviting me here 
to testify today. My name is Lois Epstein and I am an Alaska 
licensed engineer and the Arctic Program Director for The 
Wilderness Society or TWS, a national public interest 
organization with over 500,000 members and supporters.
    My background in oil and gas issues includes membership 
from 1995 to 2007 on the U.S. DOT Oil Pipeline Federal Advisory 
Committee.
    Appointment to the Bureau of Ocean Energy Management 
Regulation Enforcement or BOEMRE's newly formed Ocean Energy 
Safety Committee.
    Testifying before Congress on numerous occasions 
previously.
    Analyzing in detail the environmental performance of 
Alaska's Cook Inlet oil and gas infrastructure.
    The purpose of this hearing is to discuss new developments 
in upstream oil and gas technologies. I will provide an Alaskan 
perspective. I will discuss several key issues.
    One ensuring that upstream oil and gas operations do not 
result in spills.
    Two, keeping the Trans-Alaska pipeline system or TAPS, 
operating.
    Three, realistically assessing the impacts of directional 
drilling.
    On the first topic both onshore and offshore oil and gas 
wells and their associated pipelines have unfortunately a 
troubling spill record and a highly inadequate oversight 
framework which needs to be addressed by Congress and the Obama 
Administration. Just last week the Administration and BP agreed 
to a proposed civil settlement for 2006 oil pipeline spills of 
$25 million. Plus, and this is what's important, a set of 
required safety measures for BP's Federal unregulated North 
Slope pipelines which are all upstream of transmission lines. 
That's part of oil gas field operations. While the settlement 
is certainly welcome and an important precedent, Congress and 
U.S. DOT need to require such measures for federally 
unregulated upstream lines operated by other companies in 
Alaska and the lower 48.
    Lack of adequate preventive maintenance in North Slope 
operations is not a new issue. However, as corrosion problems 
in Prudhoe Bay's and other oil fields pipelines have been 
raised previously by regulators and others including as early 
as 1999 by the Alaska Department of Environmental Conservation. 
As additional evidence of the problems with upstream 
infrastructure, the State of Alaska recently completed a report 
in November 2010 which showed that there is a spill of over 
1,000 gallons nearly once every 2 months. Of the spills 
included in the report, which I do have with me, a substantial 
portion or 39 percent were from federally unregulated upstream 
pipelines. Thus, there's great opportunities to make sure that 
those don't happen with the proper oversight, those spills.
    Turning to offshore operations. Since the BP Deep Water 
Horizon tragedy is now well known at the Minerals Management 
Service and its successor agency BOEMRE need to upgrade 
regulatory standards and enforcement capabilities for offshore 
drilling. As I discuss in more detail in my written testimony.
    Congress also needs to upgrade Federal legislation since 
the spill. I welcome this committee's work on that issue. 
Including in areas widely considered problematic. As just one 
example, current Federal law still has a low liability cap of 
$75 million.
    On the second topic of the Trans-Alaska pipeline system, 
Alaska's North Slope oil producers and indeed, all Alaskans 
have a financial interest in keeping TAPS operating. There are 
several different ways of ensuring that TAPS continues to 
operate including technical upgrades to the pipeline such as 
heaters or liners and/or increases in conventional including 
heavy oil and/or unconventional including shale oil drilling on 
State lands. Though drilling in State waters may be 
problematic.
    I want to, from the perspective of The Wilderness Society, 
I want to emphasize that despite in State and DC based 
rhetoric, drilling on Federal lands or waters is not necessary 
to ensure that TAPS remains viable for decades to come. There's 
been quite a bit of testimony along those lines in the State 
legislature recently. From an Alaskan perspective drilling on 
State lands generally provides far more revenue for the State 
than from Federal lands including outer continental shelf 
drilling beyond 6 miles where the State receives no revenue 
from leases.
    On the third topic directional drilling for oil which is 
not a new technology has impacts in an area that are no 
different than conventional vertical oil drilling. Directional 
drilling requires surface occupancy for drill rigs and well 
pads as well as runways, roads, pipelines and other 
transportation and supply infrastructure. Because of its higher 
costs and the improved likelihood of accessing a reservoir 
using a vertical well, directional drilling may not be used for 
exploratory drilling. It might be, but it might not.
    Additionally regardless of the type of drilling used there 
would be adverse impacts from seismic exploration which occurs 
directly above the subsurface being explored. In the Arctic 
seismic exploration typically involves heavy vehicles driving 
across the tundra in a great pattern impressing sensitive soil 
and plants. Tundra recovery from seismic activities can take 
decades.
    Those familiar with directional drilling know that for 
technical reasons directional drilling only has a range of a 
few miles. As a result any bill proposing to use directional 
drilling to access federally protected areas may be said to 
potentially mislead decisionmakers by ignoring the need for 
repeated surface use across extensive areas for seismic 
exploration including 3D surveys and exploratory and 
delineation drilling. It may also cause decisionmakers to think 
that an area's full oil development potential could be realized 
through directional drilling.
    It might also be perceived to mislead the public by 
implying that oil drilling in an area will be forever limited 
to the distance accessible via directional drilling. When oil 
production precedes using directional drilling there will be 
calls to expand the drilling to reach portions of the 
reservoirs not accessible via that approach. The bottom line 
with directional drilling is that it allows a region to become 
industrialized and adversely impacted to essentially the same 
extent as conventional drilling including surface exploratory 
activities which can have long term consequences.
    Wildlife including marine mammals, caribou, migratory birds 
using federally protected areas do not recognize political 
boundaries. There's no question that conducting drilling 
activities immediately adjacent to federally protected areas, 
like the Arctic National Wildlife Refuge would have harmful 
ecological impacts.
    Thank you very much for your attention to these important 
issues. I look forward to answering your questions.
    [The prepared statement of Ms. Epstein follows:]

   Prepared Statement of Lois N. Epstein, P.E., Engineer and Arctic 
         Program Director, The Wilderness Society Anchorage, AK
    Good morning and thank you for inviting me to testify today. My 
name is Lois Epstein and I am an Alaska-licensed engineer and the 
Arctic Program Director for The Wilderness Society. The Wilderness 
Society, or TWS, is a national public interest conservation 
organization with over 500,000 members and supporters. TWS' mission is 
to protect wilderness and inspire Americans to care for our wild 
places. My background in oil and gas issues includes membership from 
1995-2007 on the U.S. Department of Transportation's Technical 
Hazardous Liquid Pipeline Safety Standards Committee which oversees oil 
pipeline regulatory and other agency activities, appointment to the 
Bureau of Ocean Energy Management, Regulation and Enforcement's 
(BOEMRE's) newly-formed Ocean Energy Safety Committee, testifying 
before Congress on numerous occasions, and analyzing in detail the 
environmental performance of Alaska's Cook Inlet oil and gas 
infrastructure. I have worked on oil and gas environmental and safety 
issues for over 25 years for three private consultants and for national 
and regional conservation organizations in both DC and Anchorage.
    The purpose of this hearing is to discuss new developments in 
upstream oil and gas technologies, and I will provide an Alaskan 
perspective. I will discuss several key issues:

          1. Ensuring that upstream oil and gas operations do not 
        result in spills and pollution,
          2. Keeping the Trans-Alaska Pipeline System, or TAPS, 
        operating, and
          3. Realistically assessing the impacts of directional 
        drilling. Last, I will present The Wilderness Society's 
        position on oil drilling in the Arctic National Wildlife 
        Refuge.

Ensuring Upstream Operations Do Not Result in Spills and Pollution
    Both onshore and offshore, oil and gas wells and their associated 
pipelines have a troubling spill record and a highly inadequate 
oversight framework which needs to be addressed by Congress and the 
Obama Administration. Just last week, the Administration and BP agreed 
to a proposed civil settlement for 2006 pipeline spills of $25 million 
plus a set of required safety measures on BP's federally-unregulated 
North Slope pipelines which are all upstream of transmission lines.\1\ 
Under the requirements of the settlement, BP's federally-unregulated 
oil field pipelines, i.e., three-phase flowlines (gas, crude, produced 
water mixture), produced water lines, and well lines, now will be 
subject to integrity management requirements largely similar to those 
that must be met by transmission pipelines in 49 CFR 195. While this 
settlement certainly is a welcome step for BP's lines and an important 
precedent, Congress in its pipeline safety act reauthorization and the 
U.S. Department of Transportation need to move forward expeditiously on 
requiring such measures for lines operated by other companies in Alaska 
and the Lower 48.
---------------------------------------------------------------------------
    \1\ Proposed settlement posted at http://media.adn.com/smedia/2011/
05/03/1029-1%20consent%20decree.112830.source.prod__affiliate.7.pdf 
(downloaded May 8, 2011).
---------------------------------------------------------------------------
    BP's March 2006 spill of over 200,000 gallons was the largest crude 
oil spill to occur in the North Slope oil fields and it brought 
national attention to the chronic problem of such spills. Another 
pipeline spill in August 2006 resulted in shutdown of BP's production 
in Prudhoe Bay and brought to light major concerns about systemic 
neglect of key infrastructure. Lack of adequate preventive maintenance 
was not a new issue, however, as corrosion problems in Prudhoe Bay's 
and other oil field pipelines have been raised previously by regulators 
and others, including as early as 1999 by the Alaska Department of 
Environmental Conservation.\2\
---------------------------------------------------------------------------
    \2\ Charter for the Development of the Alaskan North Slope, 
December 2, 1999, (BP ARCO Merger Agreement), http://
www.dec.state.ak.us/spar/ipp/docs/Charter%20Agreement.pdf.
---------------------------------------------------------------------------
    As additional evidence of the problems with upstream 
infrastructure, the State of Alaska completed a report\3\ in November 
2010 which reviewed a set of over 6,000 North Slope spills from 1995-
2009. This report showed that there were 44 loss-of-integrity spills/
year\4\ with 4.8 of those greater than 1,000 gallons/year.\5\ Of the 
640 spills included in the report, a significant proportion, 39%, were 
from federally-unregulated pipelines.\6\
---------------------------------------------------------------------------
    \3\ North Slope Spills Analysis: Final Report on North Slope Spills 
Analysis and Expert Panel Recommendations on Mitigation Measures, Nuka 
Research & Planning Group, LLC for the Alaska Department of 
Environmental Conservation, November 2010, 244 pp., http://
www.dec.state.ak.us/spar/ipp/ara/documents/101123NSSAReportvSCREEN.pdf.
    \4\ Ibid., p. 21.
    \5\ Ibid., p. 23.
    \6\ Certain types of spills were not included. See p. 14 of the 
North Slope Spills Analysis report.
---------------------------------------------------------------------------
    In 2009, TWS issued its own report on North Slope spills entitled 
Broken Promises,\7\ which I have with me here today. Broken Promises 
should be used in conjunction with the state's spill report. The TWS 
report shows a spill frequency on the North Slope of 450 spills/year 
during 1996-2008, with the difference being that the state included 
only ``production-related'' spills in its analysis and excluded North 
Slope toxic chemical (e.g., antifreeze) and refined product (e.g., 
diesel) spills--many of which are related to oil development--as well 
as spills indirectly related to oil production infrastructure, such as 
those from drilling or workover operations and from vehicles.
---------------------------------------------------------------------------
    \7\ Broken Promises: The Reality of Oil Development in America's 
Arctic (2nd Edition), The Wilderness Society, 2009.
---------------------------------------------------------------------------
    Turning to offshore operations, since the BP Deepwater Horizon 
tragedy, it is now well-known that the Minerals Management Service and 
its successor agency, BOEMRE, need to upgrade regulatory standards and 
enforcement capabilities for offshore drilling. Since the BP spill, 
BOEMRE has issued several new drilling safety regulations and is in the 
process of developing new policies regarding the environmental analyses 
required for offshore drilling. The conservation community is most 
concerned with the following currently-inadequate BOEMRE practices: 
lack of transparency in permitting, the limited nature of its 
enforcement, the need for real-time electronic monitoring of offshore 
operations by regulators, the insufficiency of key regulations (e.g., 
covering blowout preventers), and the problematic implementation of 
National Environmental Policy Act and oil spill response requirements. 
Additionally, Congress has not upgraded federal legislation since the 
spill including in areas widely considered problematic; as examples, 
current federal law has a low liability cap of $75 million, inadequate 
financial responsibility requirements, and there are no whistleblower 
protections for the offshore drilling industry.
    Notably, BOEMRE recently released a technical memo\8\ showing that 
a hypothetical blowout in the Chukchi Sea lease sale 193 area could 
result in a spill of 58-90 million gallons, meaning that there could be 
a spill of approximately the same scale as that from the BP Deepwater 
Horizon in the Arctic where cleanup would be extraordinarily more 
difficult. This information sends a strong message that the legislative 
and regulatory failures which in part led to the BP upstream spill--as 
discussed in the National Commission on the BP Deepwater Horizon Oil 
Spill and Offshore Drilling report\9\--need to be remedied 
expeditiously.
---------------------------------------------------------------------------
    \8\ Memorandum on Estimate for Very Large Discharge (VLD) of Oil 
from an Exploration Well in the Chukchi Sea OCS Planning Area, NW 
Alaska, March 4, 2011.
    \9\ DeepWater: The Gulf Oil disaster and the Future of Offshore 
Drilling, Report to the President, National Commission on the BP 
Deepwater Horizon Oil Spill and Offshore Drilling, January 2011, see 
http://www.oilspillcommission.gov/final-report.
---------------------------------------------------------------------------
Keeping TAPS Operating
    Alaska's North Slope oil producers and, indeed, all Alaskans have a 
financial interest in keeping TAPS operating. There are several 
different ways of ensuring that TAPS continues to operate including 
technical upgrades to the pipeline such as heaters\10\ or liners and/or 
increases in conventional (including heavy oil) and/or unconventional 
oil drilling on state lands. I want to emphasize that--despite in-state 
and DC-based rhetoric--drilling on federal lands or waters is not 
necessary to ensure that TAPS remains viable for decades to come.
---------------------------------------------------------------------------
    \10\ Which could, according to TAPS owners, ensure TAPS viability 
using current proven reserves through 2042 (BP Pipelines (Alaska) Inc., 
et al. v. State of Alaska, et al., Case No. 3AN-06-8446 C1, Superior 
Court for the State of Alaska, October 26, 2010 p. 129).
---------------------------------------------------------------------------
    Oil industry's plans to operate TAPS for many decades to come were 
highlighted recently in the Alaska legislature by Senator Joe Paskvan:

          There is reliable information that the likely operation of 
        TAPS is at least until 2047. This is likely without any 
        potential contribution to throughput from heavy oil or shale 
        oil or ANWR oil or NPRA oil or OCS oil. Based on the available 
        evidence, Mr. President, I am confident saying that TAPS will 
        continue to operate for decades. There are billions of barrels 
        of conventional crude remaining in Alaska's Central North 
        Slope.\11\
---------------------------------------------------------------------------
    \11\ A Math Problem and Alaska's Production Tax System, Senator Joe 
Paskvan, Alaska Legislature, Senate Floor Session, Special Orders, May 
3, 2011. Also listen at http://gavelalaska.org/media/
?media_id=SFLS110503A&type=audio; see also Comments on Judge Gleason's 
Decision: BP Pipelines, et al. v. State of Alaska, et al. op. cit., 
Alaska Legislature Senator Joe Paskvan, April 27, 2011, 4 pp.

    Over 5 billion barrels in conventional oil reserves remain on 
Alaska's North Slope according to the Alaska Department of Natural 
Resources.\12\ Additionally, viscous and heavy oil reserves of 30 
billion barrels, largely in strata above the existing Prudhoe Bay oil 
fields, have begun to be produced.\13\ At West Sak, viscous oil has 
been produced for the past few years.
---------------------------------------------------------------------------
    \12\ 2009 Annual Report Updated, Alaska Department of Natural 
Resources, May 2010, p. 8, see http://www.dog.dnr.state.ak.us/oil/
products/publications/annual/2009_annual_report/
updated_2009annual_report/Annual%20Report%202009%20Updated%205-18-
10.pdf.
    \13\ BP puts test horizontal well into operation in the Ugnu at 
Milne Point, Petroleum News, May 1, 2011, see http://
www.petroleumnews.com/pnads/40812990.shtml.
---------------------------------------------------------------------------
    From an Alaskan perspective, drilling on state lands provides far 
more revenue for the state than from federal lands, including Outer 
Continental Shelf drilling where the state receives no revenue from 
leases. Today the oil industry holds roughly 3.9 million acres in 
active State of Alaska leases on the North Slope. Millions of acres of 
existing leases on state lands have not yet been developed. Each year, 
the state holds area-wide lease sales covering 11 million acres between 
the Canning and Colville Rivers on the North Slope.
    I'd like to speak for a moment about the potential for shale oil 
fracking in Alaska on state lands. Underlying lands close to TAPS 
infrastructure are three shale oil formations with high potential for 
unconventional oil production. The geology in this area is similar to 
North Dakota's prolific Bakken Shale and the South Texas Eagle Ford 
Shale. Great Bear Petroleum LLC recently leased over 500,000 acres of 
state land near TAPS south and southwest of Prudhoe Bay to pursue shale 
oil fracking. This relatively new technique to produce oil from shale 
rock could result in substantial volumes of additional oil entering 
TAPS from state, rather than federal, lands. Shale oil production needs 
to be well-regulated by both the federal and state governments to 
protect the Arctic's waters and wildlife habitat--lack of adequate 
state regulation always is a concern in a state seeking to attract oil 
producers.
    The following graphic\14\ from Great Bear Petroleum taken from its 
presentation to the state legislature in 2011 shows projected oil 
production over 150,000 barrels/day beginning in 2015 with nearly 
300,000 barrels/day in 2029 and sustainable long-term production of 
450,000 barrels/day beginning in 2044. Note that Phase 1 would include 
drilling 200 wells per year for 15 years beginning in 2013, a 
substantial additional economic boost to Alaska.
---------------------------------------------------------------------------
    \14\ Title changed for purposes of this testimony.
---------------------------------------------------------------------------
    Importantly, Great Bear Petroleum is not asking the state for any 
changes in the state's oil tax rates.
    Increased conventional oil production on state lands also is 
possible as the extensive discussion on how to encourage such 
production during the 2011 state legislative session made clear.
Realistically Assessing Directional Drilling
    Oil and gas drilling and production is an inherently complicated 
and messy business. Even the best and most well-financed operators 
cannot ensure they will not have oil or other spills because they may 
encounter unexpected or changing conditions which have not been 
adequately addressed. Additionally, there is always a tension between 
reducing operating costs while still maintaining safety and 
environmental protection.
    Directional drilling for oil, which is not a new technology, has 
impacts that are no different than conventional oil drilling. It 
requires surface occupancy for drill rigs and well pads as well as 
runways, roads, pipelines and other transportation and supply 
infrastructure, albeit at a location near but not immediately above oil 
and gas reservoirs. Because of its higher cost, directional drilling 
may or may not be used for exploratory drilling. Additionally, 
regardless of whether directional or conventional drilling is used, 
there would be extensive adverse impacts from seismic exploration which 
does occur directly above the subsurface being explored. In the Arctic, 
seismic exploration typically involves heavy vehicles driving across 
the tundra in a grid pattern, compressing sensitive soil and plants. 
Tundra recovery from seismic activities can take decades.
    Those familiar with directional drilling know that for technical 
reasons directional drilling only has a range of a few miles. As a 
result, any bill proposing to use directional drilling to access 
federally-protected areas:

          1. Misleads decision-makers by ignoring the need for repeated 
        surface use across extensive areas for seismic exploration, 
        including 3-D surveys and exploratory and delineation drilling,
          2. Misleads decision-makers by having them think that an 
        area's full oil development potential could be realized through 
        directional drilling, and
          3. Misleads the public by implying that oil drilling in an 
        area will be forever limited to the distance accessible via 
        directional drilling. When oil production proceeds, there will 
        be calls to expand drilling to reach portions of reservoirs not 
        accessible via directional drilling.

    The bottom line with directional drilling is that it allows a 
region to become industrialized and adversely impacted to essentially 
the same extent as conventional drilling. Wildlife including marine 
mammals and ungulates using federally-protected areas do not recognize 
political boundaries. Moreover, wildlife movements are not always 
predictable from year to year, particularly with the advent of climate 
change. There's no question that conducting drilling activities 
immediately adjacent to federally-protected areas like the Arctic 
National Wildlife Refuge would have harmful ecological impacts.
The Wilderness Society's Position on Oil Drilling in the Arctic 
        National Wildlife Refuge
    Opening the Arctic National Wildlife Refuge to oil leasing, 
exploration, and production unacceptably threatens the Refuge's 
globally significant wilderness and wildlife values. Oil drilling 
activities--even with directional drilling as one component--would 
undermine the Refuge's fundamental purposes: to protect wilderness, 
wildlife, and subsistence.
    Thank you very much for your attention to these important issues.

    The Chairman. Thank all of you for your excellent 
testimony. Let me start with a few questions.
    You know one of the impressions I get is that the new 
technologies that have been developed have had 2 big--they've 
obviously had a lot of impacts, but 2 of those are that it's 
much less likely that you're going to be drilling dry holes 
because of the new information that the industry has from all 
the seismic technology Dr. Davis spoke about. That once you do 
drill a well, your ability to actually access more of the 
resource, whether it's oil or gas, is substantially improved. 
Is that a fair characterization of what has changed in the 
industry,
    Dr. Davis.
    Mr. Davis. Yes. I'd like to speak to that with a few 
statistics. Historically in the past we've averaged for wild 
cat drilling in one in 8 successful wells. Now we're well below 
one in 4 using 3D seismic technologies. But with the advent of 
the new recording systems, the new technologies, we're down to 
less than that.
    I haven't seen any recent----
    The Chairman. You mean out of every 4 wells that are 
drilled, 3 of them will be dry holes still?
    Mr. Davis. That is correct for wild cat drilling. That's in 
areas that are, you know, that haven't been drilled in before. 
Most of our drilling though is in areas where we already have 
reserves. In those areas we have also accelerated our success 
ratios to generally the other way around that is 3 out of 4 
wells would be successful.
    So in this regard then our success has certainly 
accelerated. Also as you've already indicated we've also, you 
know, found additional reserves in areas that we didn't 
necessarily think were there. In other words there are 
satellite fields proximal to the main fields that we've now 
been able to find.
    So as a result we've increased the recovery of those 
general fields substantially. So before we basically booked 
reserves on the framework of the geometry of the reservoir and 
that and we found out that the reservoir is much more extensive 
than before we thought. We now are also using enhanced oil 
recovery methods like Mr. Melzer indicated to even recover oil 
below the oil water contact.
    So again, what has been astonishing is the accelerated, I 
guess we'll say, intake of the recovery here that's occurred in 
these fields.
    The Chairman. Am I right that these new gas findings that 
in the deep shale that are being drilled in Pennsylvania and 
all around these days. Those are--you don't get dry holes with 
those. I mean, you pretty much know the gas is there. It's a 
question of making the investment to access it.
    Is that a fair statement?
    Mr. Davis. It is a fair statement. We know that we're going 
to not have a dry hole. But whether we have an economic well or 
not is the issue.
    The Chairman. Right.
    Mr. Davis. So another use of the new technology is to 
optimize the drilling for what we call ``sweet spots,'' those 
areas that will be economically attractive.
    The Chairman. Let me ask Mr. Melzer. Your comment that 
you're out of CO2 at this point. Could you elaborate 
on that a little bit? I mean, how much enhanced oil recovery 
activity currently uses CO2 and how much could use 
CO2 if the CO2 were available?
    Mr. Melzer. The question is an excellent one. I get this 
asked of me quite often. The answer is a bit subjective to 
match supply and demand.
    It regards--I'm pretty well connected to the industry so I 
understand where pent up projects are. Many of them, I don't 
know them all. But what I see in our basin is that we could 
probably double our CO2 utilization today if we had 
double the supply in a matter of 5 years we could probably find 
the projects to implement.
    Some of that is due to enhanced pricing, oil pricing today, 
where it is. We were growing this business at $20 oil. 
CO2 EOR was growing at 1990s which averaged $19 a 
barrel in that decade. So maybe that's a $40 barrel today.
    The Chairman. What does----
    Mr. Melzer. Certainly.
    The Chairman. What does the CO2 cost?
    Mr. Melzer. The old contracts that were around back in the 
1980s and 1990s, many of those are still there. I just heard of 
a new contract which was a record setting price. I think in 
terms of MCF, thousands of cubic feet, $2 a thousand is 
probably a current price that's going around.
    The average price because of the old contracts is closer to 
a dollar on that order. That's $20 a ton for the latter and $40 
a ton for the former.
    The Chairman. Thank you.
    Senator Murkowski.
    Senator Murkowski. Thank you, Mr. Chairman.
    Gentlemen, thank you for speaking to some of the advances 
in the technology that have really taken us to where we are.
    Ms. Epstein, I had hoped--I understand where you're coming 
from on oil. But I had hoped that you too would recognize, we 
really have made some transformational, transformational 
movement in how we access our resources and reducing that 
footprint and reducing our emissions and really trying to do a 
much, much better job.
    Mr. Hendricks, I wanted to ask you about the extended reach 
drilling. You mention that Schlumberger, the furthest you've 
gone out is 7.6 miles. Mr. Banks has indicated that in Alaska 
we're up to about 8 miles in all different directions.
    Is there any physical limitation in terms of your ability 
to go further, to push it out or are the limitations more from 
an economical? Is it technical? What's keeping us from going 
further than the 7.6 or the 8 miles?
    Mr. Hendricks. Thank you for the question, Senator. So as 
engineers we like to take on these types of challenges. We like 
to solve these types of technical problems. But yes, there is 
an economic factor as well that comes into play.
    There are limits eventually as to how far out we can drill. 
I don't think we've met those limits yet. We're at a little 
over 7 miles now and some of our records.
    Senator Murkowski. Has anybody gone further?
    Mr. Hendricks. No, not yet. We've done that so far. But, 
you know, soon we'll see 8, 9, 10 and maybe 15 or 20 someday in 
the future. We'll take this step by step.
    As engineers we like to take these a little bit at a time 
and make sure that we've done the calculations so that 
everything works out like it's supposed to.
    Senator Murkowski. Appreciate that.
    Mr. Davis and Mr. Melzer, you both talked about the--well, 
and Mr. Banks as well, the EOR and kind of what the 
technologies are now allowing us to do. One of the discussions 
that we have around here we're always arguing over how much 
resource is really out there. If you believe what the President 
says, you know, you've got 2 percent of the reserves out there.
    In fairness, do we really know? It seems like the more our 
technology advances us, the more we are able to not only 
access, but really it seems like it's unlimited. Am I being too 
``pie in the sky'' about this or are there really more for us 
in terms of the opportunities?
    Either one of you, I mean, any of you?
    Mr. Melzer.
    Mr. Melzer. It's a great topic, Senator. It's--we are kind 
of on the verge of trying to understand the resource that would 
be in these residual oil zones. I can really say that the 
commercial resource that's in those zones at $100 a barrel it's 
enormously higher than it would be at $40 a barrel.
    We did a real quick calculation. Admittedly it was back in 
the envelope in one county in West Texas, it's a large county, 
but it's one county. We had $30 billion barrels of oil in 
place. We could calculate from that residual oil zone in that 
county.
    I suspect that parts of Wyoming, maybe some of Utah have 
the same resource that we just are, just now understanding that 
we ought to go study. South Dakota, I mentioned, southern 
Williston Basin and into Canada as well. So, now it becomes a 
question of where you going to get the CO2 to do 
that?
    I like to think in terms of the gap between the cost of 
capture and the value of the CO2 for EOR. We have 
shrunk that because the price of oil is up and because 
technology is advancing thanks to a lot of the work that DOE is 
doing. So it's not closed for coal plants today. But it's 
getting closer.
    It is close for some industrial processes like ammonia and 
natural gas byproducts CO2. So it's a complicated 
answer because it depends on the supply of CO2 as 
well as the total resource in the ground.
    Senator Murkowski. But isn't it more than just, I mean, the 
CO2 is what has enabled us to really gain the 
advantage with the enhanced oil recovery.
    Mr. Davis, is there more out there that, I mean, you 
mentioned that the time lapse imaging and better understanding 
where it is. Are we just now beginning to understand in being 
able to identify what the true resource might actually be?
    Mr. Davis. We truly are. We've been involved with 
monitoring these enhanced oil recovery projects since 1995. To 
give you an indication of the amount of recovery that is 
incremental recovery that's occurred, generally the enhanced 
oil recovery framework involves about a 15 percent incremental.
    In other words if you have oil, original oil in place of 
say, 3 billion barrels, you can escalate that by additional, 
well normally you'd recover about a quarter of that with 
secondary and primary. But going with enhanced oil recovery 
you'd have an incremental recovery of 15 percent. But we found 
out through monitoring that we can escalate that even farther 
to 17 to 20 percent.
    We don't know what the limits are. You're quite right in 
your observations. So in some fields, for example we've gone 
from 12,000 barrels to 35,000 barrels a day incremental 
recovery. That's on a day basis. There's a field in Oklahoma 
that we've worked that we've taken from 10 barrels to over 
3,000 barrels a day. Many, many examples like that exist.
    We now want to focus on the so-called unconventional 
reservoirs and push those. Where we've had incremental, you 
know, recoveries of 3, 4, 5 percent. We think we can double or 
even perhaps triple the recoveries in places like the Bakken in 
North Dakota, for example, with the introduction of carbon 
dioxide.
    So we have similarities of the residual oil zone there. But 
we're pushing into areas where we have up dip water in that 
system. Now by introducing carbon dioxide in that system we can 
push the boundaries of these fields out and recover a lot more 
resource.
    Senator Murkowski. Thank you. I'm over my time.
    The Chairman. Senator Udall.
    Senator Udall. Thank you, Mr. Chairman. Good morning to the 
panel, particularly I want to welcome Dr. Davis. It's always 
wonderful to have a faculty member of the esteemed Colorado 
School of Mines. We're very proud of the work you do. Thank you 
for making the trip to Washington.
    Let me turn to you first, Dr. Davis, if I might. You talked 
about the fact that new seismic technology can be used to 
monitor well in completion integrity. I believe those are the 
terms you used.
    Does that mean you can use seismic data to test the 
integrity of cementing and casing and could this technology 
perhaps be also used to monitor older abandoned wells?
    Mr. Davis. Absolutely. We actually lower detectors down 
into the wellbores and do that monitoring. We can also put 
them, these sensors, on the outside of casing if we want. We 
can also do some kind of integrity measurements by just surface 
measurements or in what we call water holes or water wells 
nearby. In other words drill shallow holes and put these 
sensors nearby and just monitor.
    So in this regard, yes. Even completion technologies right 
now. We're just talking about it with Mr. Hendricks here and 
that is that generally only 5 percent of these wells that are 
completed in hydrolytic fracturing are monitored. I'm 
forecasting that we're going to see more and more of this in 
terms of monitoring going forward. We have to, from an 
environmental point of view.
    Senator Udall. So you're saying in the context of the story 
even today about wells being contaminated with methane in the 
Marcellus area that those water wells could be monitored with 
these sensors as well.
    Mr. Davis. Absolutely.
    Senator Udall. Perhaps we can get a more pinpoint accurate 
idea of where this methane is coming from.
    Mr. Davis. That is correct.
    Senator Udall. Thank you. WThank you for that.
    Let me turn to Mr. Banks and Ms. Epstein to talk about the 
Arctic National Wildlife Refuge.
    I understand that in order to potentially develop oil 
production through directional drilling, seismic testing and 
the like, exploratory drilling would be necessary first. In the 
refuge what would this look like? How would the seismic testing 
and the exploratory drilling be conducted? What equipment and 
infrastructure would it require?
    Maybe in turn you could each give your point of view to the 
committee?
    Mr. Banks. I thank you for the question, Senator.
    Senator Udall. If you turn on your mic that'd be great.
    Mr. Banks. Thank you. I'll try to touch on that. The--I 
would expect seismic activity would have to be done, of course, 
on the surface, just as has been described.
    I also spoke about the preference of drilling vertical 
wells for exploration because of the timing and also the 
precision that we can achieve in doing so. It helps us to 
describe what the layer cake looks like, so to speak, to help 
us interpret better what the seismic is telling us. Exploration 
and development of ANWR, if it were to proceed, would likely 
occur in a step wise fashion.
    There are some resources that we know of on the west side 
of the Canning River on State land that may extend, in fact, 
into the ANWR land. We don't know for sure. But that would be a 
likely spot to begin looking.
    Senator Udall. Miss Epstein.
    Ms. Epstein. I would agree with Mr. Banks about the fact 
that there would be surface impacts. I would like to emphasize 
that depending on how the seismic exploration is done those 
impacts could last quite a long time, decades in fact. That it 
does pose a concern.
    I would like to follow up just briefly on Senator 
Murkowski's comment a moment ago about appreciation for the 
technological advances. As an engineer I am absolutely 
respectful and appreciative of technological changes that have 
been made over the years. Ones that have in fact, reduced 
environmental impact.
    I would also add and I think we're all aware it's a very 
complex industry. There are lots of things that are going on. 
As essentially a watchdog on some of the nitty gritty 
regulatory matters involving pipeline safety in particular, and 
now involving offshore issues. You know, there's a lot of 
details in a lot of areas where we can make additional 
improvements. That was, sort of, the main emphasis of my 
testimony.
    Senator Udall. Let me ask a follow on question more broadly 
to both of you. I understand that extended reach drilling is 
being utilized on the North Slope which is, as you know, a vast 
area. What kind of access do the oil and gas companies have to 
Alaska's North Slope?
    Ms. Epstein, maybe start with you and then turn to Mr. 
Banks?
    Ms. Epstein. Actually along the coast about 90 percent is 
available to be drilled right now. There's a mere 10 percent 
that's off limits. So I think that's a pretty significant 
statistic.
    Senator Udall. Mr. Banks.
    Mr. Banks. Senator Udall, I think the issue of how much you 
can reach with extended reach drilling from State lands and a 
figure like 90 percent. I'm not exactly sure 90 percent of what 
that is. Speaking to the kinds of extended reach drilling that 
has been extended so far.
    There's still a need for manmade islands in the very near 
shore. Two more--most of our recent developments on the North 
Slope have occurred from manmade islands. In part because 
extended reach drilling is possible when the--and the reach 
that you can achieve is possible as long as the objective is 
deep. But in some of the most recent discoveries on the North 
Slope, some of those reservoirs have been rather shallow. So 
there is some need for access on to State lands, State 
submerged lands in order to develop our resources.
    With respect to the activities in a place like the National 
Wildlife Refuge, I'm a bit--I think it's fair to say. I think 
the photos in my written testimony indicate that it is possible 
to move a drilling rig onto the surface from an ice road and an 
ice pad and leave the area relatively untouched when the 
operations are completed.
    Ms. Epstein has talked about the heavy trucks that are used 
for seismic surveys. In fact the equipment used is designed to 
be able to be used in the winter time when there's sufficient 
snow cover and the ground is hard enough. So that in fact there 
is not much of an impact from those kinds of operations.
    Now that has evolved over time. Early on equipment was 
different. But now the equipment has transformed and evolved to 
limit that kind of damage.
    Senator Udall. These are important questions. The committee 
wants to seriously consider these. I'd welcome and I know the 
committee would, and the leaders of the committee, additional 
comment before the record is closed.
    Thank you for being here today.
    The Chairman. Senator Portman.
    Senator Portman. Thank you, Mr. Chairman. I thank the 
panelists today. Very interesting testimony.
    I come from the Midwest, from Ohio. Unlike my western and 
Alaskan colleagues here on the panel we're looking now with the 
new finds in Marcellus and Utica particularly at the 
possibility of drilling in some pretty densely populated areas. 
It creates additional challenges, as you know.
    Mr. Davis or Dr. Davis, I was interested in your testimony 
and talking a little about some of the seismic technologies 
that can be used with regard to drilling. How can those 
technologies be used to reduce some of the footprint and some 
of the potential intrusion on private landowners in a place 
like Eastern Ohio where we have these potentially huge new 
finds with Marcellus and Utica?
    Mr. Davis. One of the things that we've studied along the 
way are where are these ``sweet spots'' in these types of 
plays, these unconventional gas plays. We've been working in 
Western Colorado in the area of the Piceance Basin. There the 
technology, as of a few years ago, was drilling wells at ten 
acre spacing, 660 feet apart, vertical wells to access the 
resource.
    Now, once we've identified the ``sweet spot'' with seismic 
techniques. We define a ``sweet spot'' as an area of increased 
productivity, higher productivity, which translates to the 
higher permeability in the rock, the ability of the rock to 
flow hydrocarbons. So we've been able to analyze that from 
surface seismic techniques.
    Sensing those areas and then locating pads on which to 
drill these extended reach deviated wells, now fairly highly 
deviated wells, off of one particular pad. Then we'll look at 
now pad locations which are environmentally permitted, working 
with landowners and that framework and working with State 
regulatory agencies. That's allowed the industry to move 
forward in that particular area. I see that happening in areas 
like your homeland.
    Senator Portman. So instead of 660 feet what is the spacing 
or distance typically?
    Mr. Davis. They are extending now over distances of a mile, 
for example.
    Senator Portman. We talked about horizontal drilling.
    Mr. Davis Yes.
    Senator Portman. Being up to 7 or 8 miles.
    Mr. Davis. Yes, so, you know, maybe, we'll see further 
separation in these pads.
    Senator Portman. As the Marcellus production is ramped up 
in Pennsylvania and Upstate New York. Both of those States have 
raised some environmental concerns. Ohio is starting to develop 
more Marcellus in Eastern Ohio and then Utica because of the 
incredible new technologies and therefore the new finds it 
looks like it could be even broader into Central Ohio, 
potentially and certainly up in Northeast Ohio.
    What advice and maybe, Mr. Hendricks, you might have some 
thoughts on this or any of the panelists? But what advice would 
you have for Ohio as we begin our natural gas production which 
by the way we're very much looking forward to because it's very 
much tied to jobs in Ohio. We produce a lot of things that go 
into the drilling, the pumps, the pipes and so on. So this is 
something we want to be sure is successful.
    What lessons can we learn in Ohio from what's happened in 
Pennsylvania and certainly in Upstate New York where there have 
been some environmental concerns raised? Can you comment on 
that?
    Mr. Hendricks. So thank you, Senator. When it comes to, per 
say, the drilling operations and let's say the footprint of the 
drilling unit, you know, certainly it's up to the people of the 
municipality and of the State to determine how they would like 
this to happen. You know, we certainly encourage open dialog in 
this process.
    We do have experience where we've drilled in suburban 
neighborhoods whether it's in Southern California, North Texas, 
Oklahoma, different places. It is possible to set up certain 
types of specific drilling units that are quiet. It will work 
daylight hours that don't take up much space.
    These are all possibilities and, you know, verses what we 
might traditionally do in West Texas where your nearest 
neighbor is 50 miles away. In some places your nearest neighbor 
is 15 feet away. All these things have to be taken into 
account.
    Senator Portman. How about specifically? Senator Udall 
talked about Marcellus and some of the technology to determine 
where methane might be coming from. I guess there was a recent 
report on that.
    What are your thoughts on the CO2 emissions from 
particularly the natural gas drilling that might be done in 
connection with Marcellus or Utica?
    Mr. Hendricks. For me specifically I'm directly involved in 
the drilling operations. We prepare the wellbores for what 
needs to be done in the completion phase. Then we take our 
operations and our expertise and we move on to the next well.
    So by the time the well comes on production my team is 
usually working on drilling the next well. So I'm not directly 
involved in the production.
    Senator Portman. Mr. Banks, do you have thoughts on that? I 
know you're from an Alaska perspective, but you've gone through 
some of these same issues.
    Mr. Banks. I think some of the issues--sorry. Some of the 
issues that we may be dealing with will--some of the issues we 
may be dealing with are similar with respect to concerns about 
produced fluids and that sort of thing. But in Alaska these 
drilling fluids are ejected into approved Class Four wells. 
There's nothing that remains on the surface.
    Like Texas there's not too many neighbors nearby and with 
respect to managing the kind of drill works and equipment 
that's used on the surface. Extended reach drilling, as I've 
mentioned, is extremely important for us in terms of minimizing 
the impact of surface access. Such that even the most recent, 
or one of the most recent developments of the large alpine 
field is not even road connected to the rest of the system in 
the North Slope, it sits out by itself on a fairly small 150 
acre pad in an airstrip.
    Senator Portman. Thank you. My time is up. But I appreciate 
the testimony today and the technological advances, not just 
the horizontal drilling and not just the fracking which has 
been around for 50 years, I guess. But some of the refinements 
are really important to us in Ohio.
    We're excited about the prospects of being able to develop 
these resources and we look forward to your continued input.
    The Chairman. Thank you.
    Senator Hoeven.
    Senator Hoeven. Thank you, Mr. Chairman. I guess I'd start 
with a question that each of you could maybe touch on. Your 
thoughts on how should EPA handle regulation of hydraulic 
fracturing. They're doing a study now.
    What's the right role in terms of EPA and how should they 
approach hydraulic fracturing? Obviously States have primary 
responsibility for regulation. What's EPA's role?
    Mr. Davis, do you want to start? I'm very interested in 
responses from Mr. Hendricks and Mr. Melzer from a private 
industry standpoint.
    Mr. Davis. I'll start but to what extent I can actually 
comment on remains to be seen. I'm on the Science Advisory 
Board or panel that is evaluating the proposed plan/study of 
the EPA on hydraulic fracturing. Generally the framework is 
that, since I'm on that panel that I shouldn't comment on this 
while this study is underway.
    So I'm going to dodge that question.
    Senator Hoeven. Ok. Mr. Hendricks.
    Mr. Hendricks. Thank you for the question, Senator.
    Senator Hoeven. This is your chance to advise Dr. Davis.
    [Laughter.]
    Mr. Hendricks. So, you know, it's true that the hydro 
fracking has assisted greatly in enhancing the production of 
gas and oil wells in the United States. As an industry we 
continue to learn these lessons of what works best and the 
safest and best methods of doing this. We encourage open dialog 
and discussion.
    I, per say, am not a policymaker. But we certainly, as an 
industry, would like to encourage, you know, the open dialog 
and discussion with the policymakers and the people that live 
in the area to continue this effort.
    Senator Hoeven. Mr. Melzer.
    Mr. Melzer. Yes, sir. Thanks for the question, sir.
    I am a very strong advocate of State involvement in these 
regulatory regimes. For reasons of balance perhaps in State 
employment verses the environment and there is a role for EPA I 
think in a regional sense. One of the factors that I tend to 
think doesn't get evaluated as much as it should is the 
specific case by cases.
    When you get shallow and you get shale underlying the 
aquifer, that's one alarm bell that goes off. When the shale is 
underneath tens or hundreds of feet of salt, that alarm bell 
should not even be present. So I'm a very strong advocate of 
some criteria to establish the level of monitoring, for 
example, we've discussed this morning being very much site 
based. Perhaps EPA could play a role in that.
    USGS could play a role in that. Certainly the States need 
to have a role in that.
    Senator Hoeven. So you are specifically commenting on the 
difference between perhaps the shallow gas play and a deep oil 
and gas play?
    Mr. Melzer. Correct. Yes, sir.
    Senator Hoeven. Mr. Banks.
    Mr. Banks. Senator, thank you for the question. If I may 
just as an aside, I may be from Alaska but my son graduated 
from UND just a couple of years ago.
    Senator Hoeven. Outstanding.
    [Laughter.]
    Mr. Banks. I think that the States have a particularly 
important role to play. I have a lot of confidence in my sister 
agency, the Alaska Oil and Gas Conservation Commission in whose 
wheelhouse the management of oil well drilling and integrity 
and management falls. I think there's been a fairly long 
history demonstrated by that particular agency on the success 
of well drilling in the North Slope and elsewhere in the State. 
As Mr. Melzer has mentioned there are a lot of differences. 
Different States, different site issues that each State, I 
think, has a better opportunity to examine and strike the right 
balance.
    Now I will go a little bit out on a limb. I think that one 
of the issues that has arisen because of say, oil shale--shale 
oil development, gas shale development, around the issues of 
produced fluids has to do with some of the fears based on lack 
of information. I certainly would advocate that the States, or 
even in Alaska, that as we move forward into a shale 
development, should that occur soon, that we have a better 
reporting for what kinds of fluids are being put into the 
ground so as to alleviate some of those concerns.
    Senator Hoeven. Ms. Epstein, I noticed that you'd raised 
your hand. So I'd better give you an opportunity to comment.
    Ms. Epstein. Thank you, Senator.
    Just briefly, as someone who lives in Alaska and has been 
there for 10 years having moved there from DC. I just wanted to 
raise a concern of mine which is that when you have an 
important industry in a State there can be the possibility of 
conflict of interest at the State level in terms of some 
regulatory decisionmaking enforcement, etcetera. So I do 
believe that this is an important enough issue that EPA could 
play a strong, analytical role in terms of providing 
information to States.
    Like Mr. Banks, I do think our Alaska Oil and Gas 
Conservation Commission does a good job. But they are only able 
to do what they have the staff and resources to do. This is--we 
don't have any sort of large scale gas or oil fracking going on 
in Alaska at this point. But it's possible we may in a very 
short time.
    So information coming from the Federal Government and the 
scientists there who are putting together the report could be 
enormously helpful to the State.
    Senator Hoeven. You see a differentiation in the plays 
throughout the United States and Alaska as, I think it was Mr. 
Melzer pointed out, is that correct? Do you see a 
differentiation in how hydraulic fracturing should be handled 
from a regulatory standpoint based on the nature of the play or 
not? Do you think it's generic, a one size fits all?
    Ms. Epstein. There are some important similarities. I've 
been studying what's going on up north in terms of the 
potential for shale oil fracking. I've been talking to 
counterparts in North Dakota and trying to understand the 
differences and the similarities. I think there's no easy 
answer to that question. No black or white.
    Senator Hoeven. OK. Thank you.
    The Chairman. Thank you very much. Let me ask a couple more 
questions.
    Mr. Melzer, I asked you before about the fact that you're 
out of CO2. Is the problem there that's there no 
production of--not adequate production of CO2 or 
availability of natural CO2 or is it a question of 
getting it to where it can be used? We've talked some in this 
committee about the need to have policies to facilitate the 
building of CO2 pipelines.
    Is this an issue that we need to spend time on or is this 
not an issue from your perspective?
    Mr. Melzer. Yes, it is, sir. I think one of the issues that 
we'll face, as we always face, is that a lot of these resources 
are regional. A lot of the sources of CO2 are 
regional. Sometimes those regions don't match.
    You're exactly correct in that those cases pipelines will 
be necessary. Interstate Oil and Gas Compact Commission's 
report addressed this recently. I think it was published last 
year and looked at how to do that, how incentives might help do 
that.
    I actually believe in more to your first part of your 
question that the source of CO2 is limited today 
because of both the natural sources which we use are maxxed out 
or their pipelines serving them are maxxed out. The fact that 
we haven't, and we haven't as an industry or a dual industry, 
the surface facility industry and the subsurface industry are 2 
different cultures. We're having a lot of difficulty getting 
those folks to work together.
    They just--one of them has grown up in a utility 
environment and one of them has grown up in an entrepreneurial 
environment. It's amazing how different those groups of 
companies are. But we're making progress. DOE is working on 
that very hard.
    So what we're trying to do is take the low hanging fruit on 
the CO2 source which would be industrial by product 
like ammonia plants and the ones I've mentioned. Get those into 
the system to meet the needs of the EOR. Then, hopefully, down 
the road we'll change that gap, the cost capture and the value 
of the CO2 to get the coal plants on gasification or 
post combustion capture perhaps will evolve to commercial 
operation.
    The Chairman. Let me ask a different kind of question. I 
was visiting with a fellow who is very involved in the training 
of people to work in the oil field in my State. He made the 
point, which I thought was an interesting one. He said, you 
know, you can't make a living cutting people's hair in New 
Mexico without a license, but you can operate a drill rig 
without a license. Nobody requires any.
    I mean the individual companies do. But there's no official 
requirement that anyone be trained to any particular level 
before they operate a drill rig. Is that an accurate 
circumstance as you understand it, Dr. Davis? Should it be? I 
mean, in Colorado, for example, where you're located are there 
requirements for drill operators that we ought to try to 
persuade other States to adopt?
    Mr. Davis. Thank you for the question. Generally, it is 
true that you can, you know, go out and work on a drilling rig 
without any kind of training.
    The Chairman. I'm not talking about working on one. I'm 
talking about operating one, being, the operator.
    Mr. Davis. Yes. In terms of operations, I'm not 
knowledgeable about the extent, in other words, that individual 
States have on the allocation of, you know, training, the 
number of hours of training, that kind of thing. But again, as 
an educator I'm of course, would be in favor of that kind of a 
framework.
    But I imagine it's going to change State by State.
    The Chairman. Any of the rest of you have a comment on that 
or any knowledge about it?
    Mr. Banks.
    Mr. Banks. As an agency that does some regulation I would 
say that a barber doesn't have to meet the same kind of 
regulatory oversight that most oil drilling operations do. In 
Alaska that includes not only my agency that is concerned about 
the effect on the land, but also from our Department of 
Environmental Conservation. As I mentioned before, our 
Conservation Commission and several other agencies, Federal and 
State agencies that oversee the activities of a drilling 
operation that are highly scrutinized by the industry.
    What we do with barbers, I guess is certify them and let 
them go about their business and not trouble them too much 
after they begin.
    The Chairman. But wouldn't it be wise if you've got a very 
complicated, risky business someone is engaged in, such as 
drilling a well, to have some requirements up front before they 
start the operation?
    Mr. Banks. Senator, I think that that is the case from a, 
sort of, prescriptive regulatory point of view. That does 
happen with drilling activities. But I think--there's room I 
think for oversight to include performance based kinds of 
approaches to the oversight of these activities. Ones in which 
the responsibility of managing risk, for identifying risk is 
made by the operator. It is up to the agencies that regulate 
them to then make sure that the plans and the activities that 
the operator chooses to employ are conducted in a way to meet 
and minimize those risks.
    The Chairman. Senator Murkowski.
    Senator Murkowski. Thank you, Mr. Chairman.
    A lot of information before us today. Again, I really 
appreciate it. Listening to the conversation about how little 
we really know at this moment in terms of what really is 
accessible because the technologies are changing. The pie just 
appears to be growing bigger or expanding. I think that that's 
a good thing for us.
    It reminded me that when we were talking about production 
in Prudhoe Bay, some 30 years ago plus, when we first 
discovered oil up there. The belief was that we would be lucky. 
We were going to be seeing somewhere between one and 5 billion 
barrels coming out of Prudhoe. We're now at about 15 billion 
barrels that has been delivered over the course of these years 
and with the potential of yet more to come from that same 
field.
    So, again, it was not because we just really, really 
misjudged. It's because of the technologies that allow us to 
access more and to access it in a way that does respect that 
environment, that does work to minimize that footprint. Of 
course this takes us back to what we discuss so often here and 
have for decades. That's whether or not we can successfully 
move to open up portions of ANWR, something that I feel very, 
very strongly about.
    Yet we don't get credit for the fact that the technology 
has advanced as it has over these decades. Mr. Hendricks you 
introduced your son just back there. Just in the time period 
that he's been here what we've been able to do because of the 
technological advances has been remarkable.
    Mr. Banks, I want to ask you. You went into some detail 
about how we explore up north in the wintertime. It's not 
because we like to explore when it's the coldest and the 
darkest. It's because that's when we can be most considerate of 
the environment. We want to do things respectfully. I think 
we've demonstrated that we can.
    In recognizing that the legislation that I'm advancing, 
we've got 2 different proposals that are out there.
    One says, you know, basically little to no surface 
occupancy. We will access using directional drilling going in 
to reduce that impact.
    The other one says go onto to the coastal plain in the non 
wilderness areas and explore that way.
    Mr. Banks, is there recognizing that we want to try to be 
good environmental stewards up there. Want to try to reduce the 
footprint. Could the existing well drilled at Sourdough be a 
logical location for us to tap in using the technologies that 
we've talked about here today to gain access to some of that 
reservoir, that resource under ANWR?
    Mr. Banks. Senator Murkowski, if I were to predict what 
part of ANWR would be most interesting right now to the 
industry it would be the Sourdough prospect. It is one that 
about which we know a fair amount. I believe that----
    Senator Murkowski. Can you describe where that is?
    Mr. Banks. I'm sorry.
    Sourdough is part of the Point Thomson unit. It lies on 
State land just west of the Canning River which is the 
boundary, western boundary of ANWR in the State of Alaska. This 
prospect that was discovered some years ago has not been 
developed yet.
    However, we believe that there is some potential that the 
prospect itself could reach into the ANWR territory. So it's a 
logical spot to begin looking for or for producing oil. 
Extended reach drilling could certainly make quite an impact on 
being able to drill from there.
    I might also add that the well that was drilled in the 
1980s by, called the KIC No. 1 well, after the Kaktovik Inupiat 
Corporation, the ASRC and a landowner of the area. That also 
could be accessed from drilling on State submerged lands in the 
Beaufort Sea off the coast. It's close enough, I think, using 
today's technologies to reach into that area.
    However we don't know very much about what the prospect 
there looks like.
    Senator Murkowski. We wish that we did. We know that 
somebody out there knows a little bit more than you and I. 
Certainly wish that we could have access to that information. 
But again, I think it is important to recognize that we are not 
operating, we are not exploring and producing as we did 30 
years ago when Prudhoe first came on and as we did 50 years ago 
in some of the other fields that you gentlemen are discussing 
whether it's in Texas or North Dakota or elsewhere in the 
Rockies.
    I think, again, we need to recognize that our technologies 
have allowed us to do it safer, better, faster. That was the 
purpose of this hearing this morning. So I thank you for your 
testimony.
    Mr. Chairman, again, I thank you for scheduling it.
    The Chairman. Senator Hoeven, did you have additional 
questions?
    Senator Hoeven. I did, Mr. Chairman. Thank you.
    I would like to ask members of our panel what do you think 
the key regulatory piece is for us, for Congress to put in 
place that would help produce more of the shale play, both oil 
and gas in a responsible way. How do we continue to develop 
this in a responsible way and how can we advance that ball 
legislatively?
    In my State of North Dakota, I think we're up to about 
350,000 barrels a day of--in terms of our oil production, 
significant natural gas as well. We expect to double that 
within a few years primarily out of the Bakken and Three Forks 
and so forth, these shale plays, where we do use hydraulic 
fracturing and so forth. There are other areas being developed 
and discovered.
    So what do we do to make sure that we continue to develop 
this domestic production? How do we do it responsibly? What are 
the key things Congress needs to do? I start with Mr. Hendricks 
and Mr. Melzer, but give anybody, give everybody an opportunity 
to respond.
    Mr. Hendricks. You know, certainly from a drilling 
standpoint, you know, we're all very aware and sensitive to how 
busy things are in North Dakota between Williston and Minot 
especially and the number of active rigs that are there. For 
our standpoint, as an industry, when we want to be able to 
minimize the footprint and the impact that we have in the area, 
we know that it's good farmland and we want to make sure that 
we're protecting that going forward.
    So we want to continue, as industry, to work together with 
government, local and State, to make sure that we have the best 
outcome for everybody.
    Senator Hoeven. Is there only one key piece of legislation 
you'd like to see that would help?
    Mr. Hendricks. Uh.
    Senator Hoeven. Or just generically what would help?
    Mr. Hendricks. That's a very fair question, but 
unfortunately I'm not sure that I'm in the best position to 
answer that.
    Senator Hoeven. Alright.
    Mr. Hendricks. But again, you know, as an industry we 
certainly want to proceed with that dialog.
    Senator Hoeven. Mr. Melzer? I mean, are there some key 
things that would help advance the ball?
    Mr. Melzer. Thinking back, I'm fairly familiar with what is 
going on in North Dakota through the Pikor Group out of Grand 
Forks. I think I would say that the primary facilitators have 
been put in place. I guess I'm not seeing any holes.
    We've got one in Texas we've got with unitization. It's a 
real obstacle in our State. But you don't have that.
    So I'm at a loss to say that there's something that really 
has to be put in place to maximize your recovery.
    Senator Hoeven. So that Isla Barro and some of these other 
new possibilities, you think, can move--Colorado can move 
forward and get developed under the current legal and 
regulatory regime?
    Mr. Melzer. I believe so, sir.
    Senator Hoeven. Alright.
    Mr. Davis.
    Mr. Davis. Yes, I guess my point here is that again with 
the framework of primary recovery we're going to only access so 
much of the resource. But as we go forward we're going to have 
water flooding, secondary recovery in the Bakken and in the 
Niobara and in these other places. But we're going to 
eventually have to move very quickly I think to enhanced oil 
recovery.
    In doing so we're going to be able to amazingly change the 
economics here. We've been involved with some of the monitoring 
north of the border, right in the Manitoba/Saskatewan.
    Senator Hoeven. The Wayburn Field?
    Mr. Davis. In the area of Sinclair Field. This field 
operated by tundra exploration out of Calgary. Just the 
injection of CO2, even though it's far removed, 
they've been able to have industrial sources of CO2 
injected. We've been monitoring that injection. We've been 
doubling and tripling the production of those wells.
    So the framework, I guess from a governmental point of view 
is enhancing the availability of the CO2 perhaps not 
necessarily through regulatory agencies and that, but in just 
some kind of incentive that would allow us to capture the 
CO2 and be able to use it in these resource plays 
could have a tremendous uplift.
    Senator Hoeven. I think that it has tremendous potential 
particularly because of the convergence with CO2 
capture and carbon sequestration. We're already doing some of 
that. I'd be intrigued if you have some ideas I'd sure like to 
see them in that regard as far as incentives that might work.
    As you know we're a little budget challenged around here.
    Mr. Davis. Yes.
    Senator Hoeven. So incentives that pay for themselves are 
the ones that probably stand the best chance to advance. But 
I'm interested in those ideas.
    Mr. Davis. There's been, you know the cap and trade and 
that kind of thing. But again whether that goes to different 
States or how that's managed. Again just some incentives that 
could be to capture the CO2 and use it, not just 
store it, I think would be very, very helpful.
    Senator Hoeven. I want to give the others an opportunity.
    Mr. Melzer, did you have something else to add, though?
    Mr. Melzer. Yes, sir. In that vein I think there's ideas 
floating around for a tax credit that would do exactly what Dr. 
Davis is talking about. I actually look at that and think that 
would close this gap. It's really not related back to your 
shale question so much as it is the EOR question and carbon 
capture and storage.
    So I really would encourage people to look at that proposal 
that's going around.
    Senator Hoeven. Mr. Banks or Ms. Epstein.
    Mr. Banks. Senator, I already mentioned that I thought that 
better information about what kinds of products are being used 
in hydraulic fluids as they are used might help to relieve some 
concerns. Because I think a good deal of what's being injected 
in the ground is actually benign. I also mentioned too that I 
think in terms of managing for shale development the States are 
uniquely positioned to manage for that.
    I'd also say that I'm a little bit Alaska centric while 
there's still a lot of oil to be produced off from State land 
and around the existing infrastructure in the North Slope, most 
of the undiscovered potential lies outside of that area and on 
Federal lands. It's not a question so much of how much oil 
there is, but what kind of rates we can achieve so that the 
TAPS pipeline can remain operational and run successfully for a 
lot longer time. So that's of a very important matter for us.
    Senator Hoeven. What's the capacity on the pipeline?
    Mr. Banks. The pipeline when it was fully used or I should 
say at peak throughput was 2.1 million barrels today in 1989. 
Today it's down to 640,000 barrels a day.
    Senator Hoeven. Ms. Epstein.
    Ms. Epstein. Yes, thank you.
    I've spent my career trying to bring the laggards within 
the oil and gas industry up to the level of leaders. Which I 
think is incredibly important in terms of increasing the 
public's confidence in the industry itself. To answer your 
question, I would say that the targeted changes that Congress 
could make that would absolutely increase the public's 
confidence in the industry are--include potentially getting rid 
of the exemption that was created in the Energy Policy Act to 
the Safe Drinking Act that allowed fracking to move forward.
    If that was removed again, basically reverted back into 
what it used to be, you know, all of a sudden there will be 
increased confidence that drinking water would be protected, 
the well design requirements of the Safe Drinking Water Act 
would be in place. Then I do also agree that disclosure seems 
to be incredibly important to the public of fracking fluids. 
That's not, you know, in some sense a regulatory requirement. 
It is, in fact, just shining some sunshine onto what's going 
on.
    Then the discussions around that can take place. Those that 
are doing something that's different than what the leaders are 
doing will become apparent. That would be helpful.
    Senator Hoeven. I want to thank the panel. Mr. Chairman, 
thank you.
    The Chairman. Let me thank all of you for your testimony 
today. I think it's been very useful. We appreciate it.
    That will conclude our hearing.
    [Whereupon, at 11:35 a.m., the hearing was adjourned.]
                               APPENDIXES

                              ----------                              


                               Appendix I

                   Responses to Additional Questions

                              ----------                              

      Response of Kevin R. Banks to Question From Senator Bingaman
    Question 1. As a regulator for Alaska--do you feel that there are 
adequate safety and oil spill prevention and mitigation technologies 
available for E&P operators and drillers in the advent that a blowout 
or some other type of oil spill should occur onshore in arctic areas?
    Answer. Since the Exxon Valdez oil spill, oil spill response 
planning and equipment staging and availability have improved 
dramatically. As a direct result of the State's oil spill response 
program outlined in AS 46.04.200, the Alaska Department of 
Environmental Conservation, (ADEC) develops, annually reviews, and 
revises, as necessary, the State Oil and Hazardous Substance 
Contingency Plans (Unified Plan and Subarea Contingency Plans). These 
plans address all oil and gas related contingency planning activity in 
the state. The Unified plan is a coordinated and cooperative effort by 
government agencies and was written jointly by the Alaska Department of 
Environmental Conservation, the U.S. Coast Guard and the U.S. 
Environmental Protection Agency. The Unified Plan is then divided into 
10 Subarea Contingency Plans (SCP) that concentrate on issues and 
provisions specific to that region or subarea.
    As identified in the Unified Plan, ADEC, as the State of Alaska's 
lead agency for responses to oil and hazardous substance spills, has 
developed a network of response equipment packages positioned in at-
risk areas throughout the state.
    ADEC also requires that all municipalities, operators of facilities 
and private owners be able to respond to spills and must itemize all 
spill response equipment required in their respective spill response 
contingency plans. Through the Unified Plan and the Subarea Contingency 
Plans, the ADEC has a comprehensive list of spill response equipment 
available to be deployed throughout the state.
    In the North Slope subarea specifically, BPXA, ConocoPhillips 
Alaska and other companies operating in the North Slope oilfields have 
a substantial amount of spill response equipment, as identified in 
their respective contingency plans. In the event of a spill in this 
area, the industry spill response cooperative, Alaska Clean Seas, would 
provide much of the required response equipment and personnel. Industry 
equipment would also be utilized, especially when the company is 
identified as the responsible party for the spill.
    While appropriate response equipment is staged throughout Alaska 
and the North Slope, due to its vastness and sometimes extreme weather 
conditions, there is always the logistical challenge of getting the 
right piece of equipment to the right location at the right time.
    Responses of Kevin R. Banks to Questions From Senator Murkowski
    Question 1. As you are aware, there has been a strong effort to 
find new sources of oil to keep the Trans-Alaska Pipeline System 
operating at sound levels. With Prudhoe Bay, Alaska has a super-
enhanced oil recovery operation because so much gas is being re-
injected into that huge field.

    a. Can you address how Prudhoe was originally estimated to be maybe 
one third its size or less, and how much greater the recovery has been 
as technology has advanced?
    Answer. A reference to Alaska Department of Natural Resources (DNR) 
report from January 1982--TAPS start up was June 1977--estimated that 
the Prudhoe Bay, Sadlerochit reservoir in 1980 contained 7.8 billion 
barrels of recoverable oil. (DNR January 1982. Historical and Projected 
Oil and Gas Consumption) The most recent report published by DNR says 
that by the end of 2009, the Prudhoe Bay Unit produced 12.6 billion 
barrels of oil and still had remaining reserves of 2.4 billion-a total 
of 15 billion (DNR 2010 Annual Report). Total production to date from 
all of the fields on the North Slope exceeds 16 billion barrels.
    This growth of the Prudhoe Bay field over time can be attributed to 
two causes: technological advances in recovery methods, and the fact 
that as drilling progresses, additional reserves were added with 
discovery and development of over-and underlying horizons, and around 
the periphery of the field.
    Question 1b. Can you describe the progress that has been made, 
through the use of modern technologies, in shrinking the footprint for 
drilling areas, roads, and other facilities?
    Answer. In my written submission to the committee I provided 
several examples that show how the drilling technologies, including 
especially the use of extended reach drilling has significantly reduced 
the size of drill sites on the surface and the number of drill sites 
required to reach the oil reservoirs underground. To illustrate the 
point, one of the earliest drill sites built in the in the 1970's at 
Prudhoe Bay (DS-1), covered 65 acres of tundra. Well spacing, the 
distance between the well heads on the site, was 160 feet. Each early 
Prudhoe Bay drill site could accommodate 25-30 wells. These wells could 
be deviated from vertical only about a mile.
    The Alpine field (the Colville River Unit) is a recent example of 
how far the technology has advanced to reduce the industry's onshore 
footprint. The typical Alpine drill site is only 13 acres and supports 
54 wells. Extended reach drilling means that the wells can reach four 
miles from vertical and intercept 50 square miles of the reservoir from 
a single location on the surface. Alpine is also the first oil field on 
the North Slope that is not supported by a year-round road. During the 
winter, the operator builds an ice road to the central Alpine facility 
and equipment is staged there for summer work. Operations during the 
summer months are supported by air.
    Question 2. Is it fair to say that the technologies born in Alaska 
have grown out of necessity? In other words, has the combination of 
strict environmental laws and the economic considerations of not 
wanting to drag many new rigs and new equipment that great of a 
distance caused a natural inclination to make the most of seismic data, 
shrink footprints, reach further from one pad, and try to squeeze as 
much from one well as possible?
    Answer. Yes, it is fair to say that these technologies have been 
born out of necessity. We would add that the driving forces behind 
technological advancements reflect regulatory insistence and industry 
commitment to maximize economic benefit and recovery while minimizing 
the development footprint. It has been necessary to engineer the 
development of smaller fields at reduced costs, adopting more 
innovations to increase recovery efficiency, both at the level of 
individual wells and entire fields.
    The fact that the in-place oil volumes in several of the North 
Slope's largest fields (Prudhoe Bay, Kuparuk, and the various heavy oil 
reservoirs) are so enormous means that the economic return associated 
with increasing total recovery by even 1-2% is worth major investments 
in new technologies that make that additional recovery feasible. On the 
other hand, many of the North Slope's smaller fields face major 
economic challenges that were mitigated in large part by technological 
advances and efficiencies that originated in the giant fields nearby.
    The following are examples of some of the many technologies that 
have been created or refined in developing the major oil fields of the 
North Slope:




----------------------------------------------------------------------------------------------------------------
                           Technology                                                 Impact
----------------------------------------------------------------------------------------------------------------
                     Extended reach drilling                          Dramatically fewer surface pads needed to
                                                                                               access reservoir
                    Horizontal/designer wells                           Improves reservoir drainage relative to
                                                                                                 vertical wells
                     Coiled tubing drilling                         Reduces noise, fuel consumption, emissions,
                                                                                             cost, surface area
                     Multi-lateral drilling                           Drains more of reservoir per surface well
                                                                                                       location
                        Grind-and-inject                              Zero surface discharge of drilling wastes
                       Reservoir modeling                             Models oil-in-place, drainage, injection,
                                                                                pressure, etc. in 3-D over time
                       WAG, MWAG, MI, etc.                         Enhanced oil recovery methods, beyond simple
                                                                                                  waterflooding
                     Gas cap water injection                      Stabilizes reservoir pressure, increasing oil
                                                                                                       recovery
                   Gravity survey surveillance                       Monitors movement of reservoir fluids over
                                                                                                           time
                       3-D and 4-D seismic                           Sharper imaging of reservoir compartments,
                                                                                          fluid movements, etc.
                   BrightWater EOR treatments                     Improves waterflood efficiency by blocking off
                                                                                                    thief zones
                  Low-salinity water injection                                                                 Liberates oil molecules bound to clay
                                                                                particles in the reservoir rock
                  Heavy oil extraction methods                      Several different methods in development to
                                                                       enhance recovery, depending on reservoir
                                                                               temperature, oil viscosity, etc.
----------------------------------------------------------------------------------------------------------------


    a. Would the other witnesses like to comment on the Alaska 
experience and how it's allowed operations elsewhere to advance?
    Question 3. Some have suggested that the Trans-Alaska Pipeline 
System is perfectly capable of operating soundly until mid-century, 
even with no access to federally controlled oil deposits. As one of the 
State's leading oil experts, can you describe the throughput decline of 
TAPS and what it will take to maintain its operation through that point 
in the future?
    Answer. TAPS was originally designed to move about 1.5 million 
barrels per day. Throughput peaked at 2.03 million barrels per day in 
1988-a rate achievable with the application of drag reducing agents and 
other improvements. Throughput has declined in all but two years since 
1988. Current throughput is about 0.6 million barrels per day. Most 
forecasts show continued decline into the future.
    The TAPS line has already begun to be impacted by lower throughput. 
During the shut-down in January 2011 (leak at Pump Station No. 1), 
there was concern about being able to restart the line due to the 
temperature. TAPS will have some material operational issues as the 
flow rate reaches 0.3 million barrels per day. The operational issues 
are primarily related to the temperature of the crude as it moves 
through the pipeline. With less flow and without mitigating 
investments, the temperature may fall below 32 F. Lower temperatures 
may allow ice to form inside the pipeline that could damage equipment 
and cause possible frost heaving on buried sections of the pipeline 
route. Lower temperatures will also lead to more build-up of wax on the 
inside of the pipeline, and increase the viscosity of the crude moving 
in TAPS.
    More than 99% of TAPS throughput comes from fields on State or 
Native lands or from State waters. Production from Federal lands and 
the OCS today amounts to less than two thousand barrels per day.
    With the exception of development of the heavy oil resources known 
to exist around the Prudhoe Bay, Kuparuk, and Milne Point fields, and 
potential resource plays (like the Bakken in North Dakota) that may 
exist on the North Slope on State controlled lands, the natural field 
declines cannot be replaced without access to production from Federal 
lands and the OCS. There are no known conventional resources on State 
or Native lands that are likely sufficient to replace the decline in 
the existing production rates.
    Conoco-Phillips and Anadarko want to expand the Alpine field by 
developing a new drill site (CD-5). New production would come from 
State, Native, and Federal lands (60 miles west of TAPS). This 
development is on hold awaiting permits from the Corps of Engineers to 
allow construction of a bridge over the Colville River. The permit was 
first requested in 2005. Development in the National Petroleum Reserve 
Alaska (NPRA) can only proceed once the Alpine bridge over the Colville 
River is complete. Thankfully, the Administration has proposed having 
lease sales in the NPRA annually. We hope that these sales will be 
accompanied by a willingness of federal agencies to allow permits for 
development (e.g., CD-5 project) and that lands with high resource 
potential (e.g., north of Teshekpuk Lake) can be made available for 
leasing with appropriate environmental safeguards.
    There are current plans to develop an oil and gas field on State 
lands at Point Thomson (Miles east of TAPS). Development at Point 
Thomson has also been delayed due to Corps of Engineers permitting 
issues. Development of resources at Point Thomson would extend the 
feeder lines for TAPS about 30 miles east of the Badami field. This 
would lessen development costs and could lead to development in this 
relatively unexplored area. It is also at the boundary to ANWR and the 
1002 area.
    Question 4. Can you talk about the new technologies we're hearing 
about in terms of allowing for development of an area where the law 
doesn't currently allow for conventional access? In other words, are 
there applications for this technology that would provide an 
opportunity to extract resources from the 1002 area subsurface without 
having any permanent or significant impacts on the surface area?
    Answer. Although it remains unclear how far, if at all, the 
Sourdough or Pt. Thomson reservoirs discovered on State leases near the 
Canning River delta might extend beneath the 1002 area, there is the 
potential that extended reach drilling could at least partially develop 
these reservoirs. Without more detailed subsurface data on these and 
other prospects along ANWR's western border and along the coastline 
adjacent to state submerged waters, it will not be possible to 
accurately evaluate how much of these reservoirs would benefit from 
extended reach drilling techniques. Three-dimensional seismic 
acquisition and near-vertical exploration and delineation drilling 
would have to occur inside the 1002 area. These activities can be 
conducted in the winter with zero or minimal permanent surface impact. 
Allowing these activities would help answer the question of whether how 
much oil extended-reach production wells drilled from outside ANWR 
would be economically viable.
                                 ______
                                 
      Responses of Thomas Davis to Questions From Senator Bingaman
    Question 1. Are there recent advances that will help reduce the 
footprint of seismic activities in environmentally sensitive areas, 
both in terms of active seismic data acquisition and passive?
    Answer. Yes, major advances have occurred with the advent of 
wireless seismic technology and increased sensitivity and numbers of 
seismic sensors. Wireless recording systems now leave only human 
footprints in terms of placement of recording systems. The weight and 
power consumption of these wireless recorders is such that a person can 
carry several devices and plant them in environmentally sensitive areas 
provided they are accessible to humans. There has been recent 
experimentation with dropping these devices from helicopters as well, 
but retrieval remains an issue. These devices can record up to a month 
without being serviced. They contain GPS receivers and the clocks in 
the devices are synchronized and are highly accurate. The devices can 
be placed in active recording mode to record generated sources from 
hydraulic vibrators, weigh drops, or dynamite, for example. They can 
also be placed in continuous recording mode when the intention is to 
record passively the natural seismicity or induced seismicity, for 
example, from drilling or completion operations.
    Question 2. Have there been any recent advances in downhole seismic 
instrumentation that allows an operator to see further into the 
formation from the wellbore to areas that may not have been adequately 
imaged using conventional 2-or 3-Dimensional seismic data?

    a) Or to areas that cannot be accessed at the surface due to 
environmental sensitivities?
    b) In other words, is there a borehole version of conventional 
seismic?

    Answer. Yes, major advances have occurred in downhole seismic 
recording technology as well. We have developed capabilities to record 
with borehole arrays of receivers spanning different intervals and 
within different wells. The closer we can get to the formation the 
higher the definition that can be achieved. Fiber optic links to the 
sensors result in greater bandwidth and recording capacity. New fiber 
optic sensors are being deployed as well. Slimhole drilling devices are 
being used to embed arrays of sensors in the subsurface for permanent 
monitoring if wells are not accessible for installation of receivers. 
The distance can seismic events can be reliably detected varies 
dependent on area and background noise conditions. Generally distances 
are limited to less than one-mile between source and receiver. A 
personal preference is to record both surface and downhole arrays 
simultaneously. In some instances we can place vibratory sources or 
airguns in wells and record the wavefields in other boreholes and on 
the surface. Drill bits can also be used as active sources for 
wavefield imaging. Downhole seismic recording independently is more 
expensive and time consuming than surface seismic recording. As a 
result, there is less demand in the industry for this service. It is 
gaining momentum, however, as more companies are seeing value in 
monitoring hydraulic fracturing operations, for example.
     Responses of Thomas Davis to Questions From Senator Murkowski
    Question 1. Can you talk about the new technologies we're hearing 
about in terms of allowing for development of an area where the law 
doesn't currently allow for conventional access? In other words, are 
there applications for this technology that would provide an 
opportunity to extract resources from the 1002 area subsurface without 
any permanent or significant impacts on the surface area?
    Answer. Oil and gas resources still need to be accessed by well 
drilling. Other than extended reach drilling there is no other means 
that can be used to access resources under environmentally sensitive 
areas. Targeting these resources more precisely prior to or during 
drilling operations is a prudent operational procedure. Seismic while 
drilling offers a ``look ahead'' procedure to optimize target specific 
drilling objectives. In this instance the drill bit is used as the 
source and receivers are placed in the drilling assembly.
    Question 2. Judging by your location I'd guess that a lot of the 
field work you're doing with seismic is in the Rocky Mountain region. 
There are obviously some sensitive areas adjacent to the oil reservoirs 
which you've worked to explore. What kinds of precautions are necessary 
to minimize the impacts of seismic work on a landscape, and do you 
consider these operations to be unnecessarily impactful on wildlife?
    Answer. We have conducted seismic operations in various areas in 
the US and Canada and have worked in environmentally sensitive areas in 
the Piceance Basin of Northwest Colorado and more recently in 
northeastern Louisiana. As a landowner and farmer I treat every area as 
environmentally sensitive. I spend a great deal of my time speaking 
with landowners in designing the surveys we conduct to assure minimal 
environmental impact. There is little reason to believe that seismic 
operations cannot be conducted in an environmentally responsible manner 
especially with the advent of wireless recording systems. We work 
closely with all of our stakeholders to assure environmental 
preservation and conservation associated with our time-lapse 
operations. Knowing that you are coming back to an area time and time 
again means that you are truly a stakeholder in dealing with all 
aspects of the process. Proper pre-planning and coordination is 
essential along with on-site monitoring. In the Piceance Basin 
operations in 2003-2006 we have hired a wildlife specialist to monitor 
the influence of seismic operations on wildlife. We timed our 
operations to have minimal impact on wildlife, the operator, and 
landowners. We observed that there was little or no impact on wildlife 
due to our seismic operations and our wildlife specialist confirmed 
this observation. Minimizing the number of ``moving parts'' on a 
seismic crew operation is essential to operating in an environmentally 
responsible manner.
    Question 3. Thank you for your testimony. Mr. Melzer's chart on 
page 8, showing the third and fourth production peak at about 60 and 80 
years after an oilfield has been developed. Combined, those third and 
fourth heights of production are more than the main (secondary) 
production peak. That certainly fits with Mr. Melzer's other chart , 
showing the huge increase in EOR activity in the US and worldwide.
    Answer. We now realize the importance of oil and gas fields as 
``assets'' that require responsible management. Asset teams of 
geoscientists and engineers have been created to manage the life-cycle 
of these resources. There is no question that many of these peaks are 
related to employing new technologies in accessing new reserves in old 
fields. The fundamental cause of our inability to access more resource 
in the past has been the reservoir heterogeneity. New drilling and 
completions technologies, EOR, and seismic monitoring have helped us 
increase the recovery factors in many of our fields substantially. 
These efforts are important to our country and to the world.
    Question 4. So, are we doing an adequate job as a government in 
identifying what our true resource potential is? To clarify, is there 
an issue with the characterization that the US has only 2 percent of 
the world's oil reserves, in that it doesn't take into account 
unexplored areas, and it apparently doesn't take into account what 
impact EOR could have on current estimates?
    Answer. I believe that there is substantially more resource that is 
recoverable from mature fields and we are demonstrating that 
hypothesis. I also believe that more effectively exploration will be 
conducted in the future to access new reserves. Technology is key and 
educating people to use that technology wisely is key as well. There is 
an old adage that oil is found in the minds of men and women and to a 
large extent I believe that to be a fundamental truth. I have the 
responsibility as an educator to help champion that cause. I don't 
believe we are running out of oil. At times we tend to run out of 
ideas, but it is up to us to change the ideas and to challenge dogma. I 
try to do that through emphasizing the development of new technologies 
and employing these technologies where it can make a difference. We are 
seeing vast new reserves emerge from unconventional resources, EOR, 
etc. In addition, we have vast resources to access in remote areas and 
at greater drilling depths provided we can handle the environmental 
challenges that are associated. The key to meeting these challenges is 
working together to bring innovation through education. I welcome the 
opportunity to serve in this capacity and appreciate your insightful 
questions in this regard.
                                 ______
                                 
      Responses of Lois Epstein to Questions From Senator Bingaman
    Question 1. You mentioned hydraulic fracturing as it relates to 
Alaska and unconventional oil shale development similar to that of the 
Bakken in North Dakota. You state that there is great potential for 
this resource, but development should be handled with care and good 
environmental planning. What, in your view, would that entail?
    Answer. Hydraulic fracturing (or ``fracking''), whether of shale 
oil or shale gas, can have the following adverse environmental impacts 
if not well-regulated and done in a compact fashion:

          1. Contamination of groundwater that may be used for drinking 
        water and other purposes with methane and/or fracking fluids 
        which can contain toxic chemicals;
          2. Contamination of surface water from fracking wastewater or 
        drilling wastes including drilling muds which can contain toxic 
        chemicals;
          3. Groundwater flow or surface water quantity changes, with 
        associated ecosystem impacts, due to the large quantities of 
        water needed for fracking operations;
          4. Wildlife habitat disturbance and destruction from the 
        presence of fracking operations and associated pipelines, 
        roads, and related infrastructure; and,
          5. Conventional health-related air pollution\1\ and 
        greenhouse gas pollution1 from fracking operations and 
        associated pipelines, roads, and related infrastructure.
---------------------------------------------------------------------------
    \1\ A recent Cornell University study showed that shale gas 
development results in significantly more greenhouse gas generation 
than conventional natural gas production, ``Methane and the Greenhouse-
Gas Footprint of Natural Gas from Shale Formations,'' Bob Howarth, et 
al., Climatic Change Letter, 2011, see http://graphics8.nytimes.com/
images/blogs/greeninc/Howarth2011.pdf.

    In addition to environmental impacts, typically there are adverse 
social impacts associated with rapid industrialization (e.g., 
communities can become unaffordable to long-time residents), increased 
local drinking and crime,\2\ and lowered quality of life due to nearby 
industrialization including additional traffic, traffic accidents, road 
and bridge deterioration, school crowding, and noise.
---------------------------------------------------------------------------
    \2\ Jacquet, J. 2005. Index Crimes, Arrests, and Incidents in 
Sublette County 1995 to 2004: Trends and Forecasts. Report Prepared for 
Sublette County Wyoming.
---------------------------------------------------------------------------
    Both the federal and state governments can and should play a role 
in regulating hydraulic fracturing. For decades, the federal government 
has employed its scientific and technical expertise--which states often 
are lacking--to develop requirements that protect surface and 
groundwater under the Clean Water and Safe Drinking Water Acts. There 
should be no unique exceptions to this framework for fracking 
operations, especially if we want to restore confidence in governmental 
oversight of this industry. This means that the Energy Policy Act of 
2005 exemption from the Safe Drinking Water Act for fracking wells 
needs to be repealed to help ensure well integrity. Likewise, federal 
requirements for uniform disclosure of fracking fluid chemicals would 
be appropriate as a baseline that could be added upon by states, rather 
than having each state develop its own chemical disclosure standards 
and format. State-level regulatory oversight could include areas where 
state-specific conditions might result in a need to exceed federal 
requirements (e.g., requiring zero-discharge of wastewater to the 
surface through mandatory use of wastewater injection wells) or areas 
where the federal government has not acted (e.g., well-spacing and 
well-pad requirements to limit adverse effects on habitat). 
Governmental oversight also must include sufficient and effective 
enforcement of federal and state requirements. Federal and state 
enforcement personnel need adequate funding and the will to ensure 
widespread compliance or compliance will not happen uniformly. Strong 
governmental regulations are not valuable unless they are enforced.
    Question 2. Is it possible to do all aspects of oil and gas 
exploration and production through directional drilling or does the 
initial exploration to identify the resource require surface occupancy 
above the oil or gas reservoir? Is surface occupancy required for other 
purposes?
    Answer. It is not possible to conduct all aspects of oil and gas 
exploration, development, and production solely through directional 
drilling. Seismic activities (which provide information about the 
subsurface using sound waves) and exploratory well drilling take place 
directly on the surface above oil and gas reservoirs. As discussed in 
my May 10, 2011 testimony, directional drilling for oil has adverse 
impacts that are essentially no different than conventional oil 
drilling (with the single exception being reducing the number of well 
pads required to access oil deposits).
    Seismic activities involve convoys of exploration vehicles 
traveling over extensive areas. In the Arctic, large seismic vehicles 
crisscross over a fragile tundra ecosystem. Longterm studies have 
documented severe impacts from seismic trails to tundra vegetation and 
permafrost lasting over 20 years.\3\ Newer 3-D seismic surveys involve 
more vehicles in a very tight grid profile with a line spacing of a few 
hundred meters, resulting in greater surface disturbance of vegetation, 
bears in dens, and other wildlife. Although seismic exploration would 
only be conducted in winter in the Arctic, snow cover on the Arctic 
National Wildlife Refuge's coastal plain, for example, often is shallow 
and uneven, providing little protection for sensitive tundra vegetation 
and soils. The impact from seismic vehicles and lines depends on the 
type of vegetation, the texture and ice content of the soil, the 
surface shape, snow depth, and the type of vehicle.
---------------------------------------------------------------------------
    \3\ Jorgenson, J.C., VerHoef, J.M., and Jorgenson, M.T. 2010. Long-
term recovery patterns of arctic tundra after winter seismic 
exploration. Ecological Applications, 20(1): 205-221 (long-term studies 
of impacts from the onetime seismic exploration surveys mandated by 
Congress in the 1980s).
---------------------------------------------------------------------------
    According to the U.S. Fish and Wildlife Service's webpage 
discussing the potential impacts of proposed oil and gas development on 
the Arctic National Wildlife Refuge's coastal plain, ``Current seismic 
exploration methods require numerous vehicles to move in a grid pattern 
across the tundra. Maternal polar bears with newborn cubs can be 
prematurely displaced from their winter dens by the noise, vibrations 
and human disturbance associated with oil exploration activities. This 
displacement may result in potentially fatal human-bear conflicts, and 
may expose the cubs to increased mortality due to harsh winter 
conditions for which they are not yet prepared.''\4\
---------------------------------------------------------------------------
    \4\ See http://arctic.fws.gov/issues1.htm#section4 (accessed May 
25, 2011).
---------------------------------------------------------------------------
    As discussed by Mr. Kevin Banks of the Alaska Department of Natural 
Resources during the May 10, 2011 hearing, companies likely would not 
use directional drilling for exploratory wells because doing so would 
provide less technical information about subsurface conditions. 
Exploratory well drilling requires the use of large drill rigs on 
gravel and the building of associated transportation infrastructure 
(potentially helicopter or aircraft access), drilling mud/waste 
infrastructure, and human-support facilities. If ice is used instead of 
gravel for foundations, there will be water withdrawals from lakes, 
rivers, or constructed reservoirs. Note that there's insufficient 
winter water in the Arctic National Wildlife Refuge's coastal plain to 
assist in drilling operations.\5\
---------------------------------------------------------------------------
    \5\ U.S. Fish and Wildlife Service, 1995. A preliminary review of 
the Arctic National Wildlife Refuge, Alaska, coastal plain resource 
assessment: report and recommendation to the Congress of the United 
States and Final Legislative Environmental Impact Statement. Anchorage. 
This report concluded, ``Additional investigations since 1987 
substantiate the fact that water in the [coastal plain] area is very 
limited and the impact upon water resources should be considered 
major.''
---------------------------------------------------------------------------
    Statements that claim exploration can be conducted in a way that 
would leave ``no trace that we were ever there'' are simply not true. 
In the Arctic National Wildlife Refuge's coastal plain, exploration 
would cause severe and long-lasting damage to tundra and permafrost and 
would disturb the very wildlife and wilderness that the area was set 
aside to protect, such as denning polar bears and the Porcupine caribou 
herd which calves there.
    Question 3. Would you expand upon your testimony about current 
technology for directional drilling to explain the distances over which 
directional drilling is currently possible? Are there examples of 
current projects that demonstrate the state of the art for this 
technology?
    Answer. According to BP, the company will use directional drilling 
(angled drilling) along with horizontal drilling to reach up to eight 
miles to the Liberty reservoir,\6\ resulting in ``the longest extended-
reach wells ever attempted.''\7\. BP has had technical problems 
completing Liberty's extended-reach wells, however, with multiple 
postponements of the proposed dates of operation.\8\ Currently, BP is 
undergoing a ``design and engineering review to evaluate the project's 
safety systems.''\9\ There are significant technical challenges that 
need to be overcome before extended-reach drilling will extend beyond a 
small number of miles, i.e., approximately two to four miles.
---------------------------------------------------------------------------
    \6\ Reaching Out to Liberty, BP, undated, p. 2, see http://
www.bp.com/liveassets/bp_internet/us/bp_us_english/STAGING/
local_assets/downloads/l/final_liberty70808 .pdf.
    \7\ ``Liberty well,'' BP Magazine, Issue four--2009, see http://
www.bp.com/
sectiongenericarticle.do?categoryId=9031686&contentId=7058099.
    \8\ ``BP's Liberty project delayed again,'' KTUU-TV, February 1, 
2011, see http://www.ktuu.com/news/ktuu-bp-oilrig-in-beaufort-sea-
postponed-again-20110201,0,3719434.story.
    \9\ Ibid.
---------------------------------------------------------------------------
    Appendix C of the Cook Inlet (Alaska) Best Interest Finding 
regarding the 2009 Cook Inlet Areawide Oil and Gas Lease Sale, 
developed by the State Department of Natural Resources Division of Oil 
and Gas, provides factual information on the limitations of directional 
and extended-reach drilling including the significant additional costs 
involved compared with conventional drilling.\10\ This document shows a 
maximum horizontal departure of approximately 4 miles; as of June 2009, 
however, only one well on the North Slope exceeded 4 miles, and just 
barely at 4.025 miles.\11\ Fewer than 2% of the North Slope wells 
extend horizontally more than 3 miles, while 94% of the wells extend 
less than 2 miles from drill rigs.\12\ Even at ConocoPhillips' Alpine 
oil field, often touted for its use of directional drilling, the 
average horizontal distance drilled is only 1.74 miles.\13\
---------------------------------------------------------------------------
    \10\ Final Best Interest Finding, 2009 Cook Inlet Areawide Oil and 
Gas Lease Sale, January 20, 2009, Appendix C: Directional and Extended-
Reach Drilling, see http://www.dog.dnr.state.ak.us/oil/products/
publications/cookinlet/ciaw_2009_final_finding/
CI%20PrelimBIF%20AppC.pdf.
    \11\ Alaska Oil and Gas Conservation Commission well database. Data 
analyzed by Doug Tosa, Alaska Center for the Environment, using known 
tophole and bottomhole latitude/longitude locations of 5,549 completed 
wells. Data retrieved June 16, 2009. See http://wilderness.org/files/
Broken-Promises-3.pdf.
    \12\ Ibid.
    \13\ Ibid.
---------------------------------------------------------------------------
    In 2009, The Wilderness Society produced its Broken Promises 
report. Chapter 3, attached, is entitled ``Directional Drilling is no 
Panacea'' and provides additional information on the limitations of 
directional drilling. Key limitations are financial, as discussed 
above, and geologic. In some locations, directional drilling is not 
possible geologically due to, for example, unstable shale which could 
collapse drill holes, conditions that are present near the Alpine field 
on the North Slope.\14\
---------------------------------------------------------------------------
    \14\ The Wilderness Society. 2009. Broken Promises: The Reality of 
Oil Development in America's Arctic (2nd Edition), Chapter 3, p. 13, 
see http://wilderness.org/content/broken-promises-reality-oil-
development-americasarctic.
---------------------------------------------------------------------------
                                 ______
                                 
   Responses of L. Stephen Melzer to Questions From Senator Bingaman
    Question 1. You explained the role of CO2 in the next 
generation of enhanced oil recovery. Has the more widespread use of 
CO2 led to a decrease in the other types of enhanced oil 
recovery that has been used--such as the use of solvents or 
surfactants?
    Answer. Each of the enhanced oil recovery (EOR)\1\ methods has 
developed somewhat independently in their applications to various types 
of oil and reservoirs. For example, steam injection has had widespread 
application in shallow depths for heavy oils (San Joaquin Valley in CA 
as the best example). Carbon dioxide (CO2) works best on 
lighter oils and at deeper depths so the processes have not competed. 
Chemical EOR (ChEOR) such as surfactants (also alkaline and polymers) 
could have competed with the same reservoir and oil types as 
CO2 but widespread application of ChEOR has never taken off. 
Some excitement exists out there for today but much of it seems to be 
concentrated in reservoir depths too shallow for miscible 
CO2 applications (generally around 2500-3000' depth) or 
where affordable CO2 is not available.
---------------------------------------------------------------------------
    \1\ Industry often uses the terms ``enhanced oil recovery'' and 
``flooding'' interchangeably
---------------------------------------------------------------------------
    Other historically utilized methods of EOR are hydrocarbon miscible 
gas flooding (HCMF) and Nitrogen EOR (N2EOR). HCMF injects 
an injectant (methane + ethane + Butane . . . ) that has significant 
market value. The most common application for HCMF has been in Alaska 
and Canada where it was impossible to get the gaseous hydrocarbons 
pipelined to a market. Therefore, the produced gas was reinjected to 
maintain pressure in the reservoir and perform the sweep of the liquid 
commodity, crude oil. As the pipelines for natural gas developed in 
Canada, the HCMF process lost its commercial appeal and possible new 
flood applications opted to sell the gaseous products. The number of 
active HCMF projects are very close to nil today except for the North 
Slope of Alaska.
    N2EOR works in a miscible process only at much deeper 
depths than does CO2 EOR. The depths are generally in excess 
of 9000'. The advantage of N2EOR is that an air separation 
unit can be collocated at the field and the injectant, nitrogen, 
extracted from air, thus requiring no long distance N2 
source pipeline. Mexico employed N2EOR at their Canterell 
offshore field in Mexico and Exxon employs it at their Hawkins field in 
East Texas. New reservoir applications are fairly limited and 
CO2 has effectively displaced N2EOR as the 
flooding technique preferred by industry in light oil reservoirs.
    Question 2. Can you discuss briefly the volume of water that is 
generally used in a waterflood prior to utilizing CO2? What 
happens to the wastewater from a waterflood? Is the water reclaimed or 
reinjected into a disposal well? What volume of CO2 is being 
utilized annually for CO2 EOR on a per field basis?
    Answer. The easiest way to visualize the volumetrics of injectant 
utilized during waterflooding or in EOR is to think of it in the sense 
of maintaining a volume (pressure) balance within a reservoir. For 
example, if a reservoir is producing 1000 barrels\2\ of oil per day, 
the oil company will want to replace the produced volume of oil with a 
substance so as to maintain the reservoir pressure. Hence, in a 
waterflood, 1000 barrels of water per day will be injected. And, over 
the life of the reservoir, the cumulative volume of produced oil will 
have seen about that much ``new'' water introduced into the reservoir. 
Confusion often arises from the fact that the normally reported 
injection volumes are total injected barrels which does, of course, 
include the produced (or recycled) volumes of water plus what we call 
the new (aka ``make-up'') barrels. As mentioned in my earlier 
testimony, the new water injected today is generally brackish water, 
sea water, or formation water from deeper formations and not from an 
Underground Source of Drinking Water (USDW). Some exceptions to that 
rule are present today but not many.
---------------------------------------------------------------------------
    \2\ There are 42 gallons in a barrel of oil
---------------------------------------------------------------------------
    The wastewater in a waterflood is reinjected since the flood 
operator needs the water to return to the formation in order to 
maintain reservoir pressure. When a new CO2 flood is 
implemented, we are effectively replacing formation water and oil with 
CO2. So there is some wastewater in CO2 flooding. 
That water is handled in one of two fashions: 1) injected into a deep 
disposal well or 2) reinjected back into the reservoir being 
CO2 flooded in what we like to call our water-alternating 
gas (WAG) process where water is used intermittently to assist the 
CO2 in spreading out within the reservoir.
    As to the question related to the average size of CO2 
injection volumes on a field basis today, probably the best way to 
answer is to use the total volumes of CO2 being purchased 
today and the number of active fields under flood. According to a 
recent report and our own studies, approximately 3100 million cubic 
feet (ft3) of CO2 are purchased daily in the U.S. 
for 111 flood projects (there are some situations where there are 
multiple and separate flood projects in a field). That gives us an 
average metric of 28 million ft3 per day of purchased 
CO2 per project. That is about 1450 MT per day or 530,000 MT 
per year of new carbon dioxide\3\ per flood project. A good rule of 
thumb for the Permian Basin is that, in a mature project, we ultimately 
recycle about the same volume of CO2 that we have purchased. 
If all the fields currently under flood were very mature (of course not 
the actual case since many are immature), we would expect to be 
recycling about the same volume we are purchasing which is 1.8 billion 
ft3 per day. In actual practice, my estimate of recycle 
volumes in the Permian Basin is 1.1 billion ft3 per day.
---------------------------------------------------------------------------
    \3\ There are 19,250 cubic feet (ft3) of CO2 
in one MT and 17,500 ft3 in one english ton; A handy, quick 
conversion to remember is 50 million ft3 per day is roughly 
equivalent to 1 million tons per year (slightly less (.95) for metric 
and slightly more (1.04) for english)
---------------------------------------------------------------------------
  Responses of L. Stephen Meltzer to Questions From Senator Murkowski
    Question 1. Your chart on page 8, showing the third and fourth 
production peak at about 60 and 80 years aft3er an oilfield 
has been developed. Combined, those third and fourth heights of 
production are more than the main (secondary) production peak. That 
certainly fits with Mr. Davis' other chart, showing the huge increase 
in EOR activity in the US and worldwide.
    So, are we doing an adequate job as a government in identifying 
what our true resource potential is? To clarify, is there an issue with 
the characterization that the US has only 2 percent of the world's oil 
reserves, in that it doesn't take into account unexplored areas, and it 
apparently doesn't take into account what impact EOR could have on 
current estimates?
    Answer. Coincidentally, I left the Washington hearing to attend a 
workshop conducted by the U.S. Geological Survey at Stanford University 
where I had been asked to address this ``size of EOR resource'' 
question. A lot of folks (like the USGS and the National Petroleum 
Council to name two) are attempting to reassess our resources right 
now. First, we have new, on-going projects that are proving that we can 
economically target and produce the residual oil zones (ROZs) with EOR 
techniques. Second, we now have a new understanding that these ROZs are 
more widespread than previously imagined. These two new developments 
emphatically confirm the reality that our published U.S. oil resources 
are badly understated today. The USGS is currently charged with 
reassessing our EOR resources but they, like anyone else, will need 
some help from industry and an extended time frame to accomplish such a 
wholesale reassessment. The linkage between the availability of 
affordable CO2 and those potential resources is a matter of 
great importance to many of us in the industry and state and national 
policies will be critical to ensuring adequate availability of 
CO2.
    Can we realize the large EOR potential? We have an oil and gas 
industry that is busy drilling for new fields and a very, very small 
subsector of it concentrating on getting more oil out of an existing 
reservoir. Some of that has to do with the long term nature of the EOR 
projects--something that does not appeal to public money looking for 
fast returns. However, I often argue that a better balance is needed; 
i.e., some quick adds to the reserve base and some long term additions. 
We need to have the long range interests of a country to be better 
placed on long term reserves and not just the flash effect of quick 
returns. I view this `quick return' partiality not as a market failure 
problem; it is probably better characterized as just a market bias.
    Finally, I have never been involved in anything with as large a 
potential as CO2 EOR. What started out as an interesting 
``trip'' into the science of the ROZs has turned into a revolutionary 
opportunity for the industry and our Country. As I mentioned in the 
questions session near the end of the hearing, our group has done a 
``back-of-the-envelope'' estimate of the size of the ROZ resource in 
just one West Texas county. The numbers are shocking: 30 billion 
barrels of in-place oil. We believe that 20% to 30% of this ROZ in-
place oil resource could be recoverable.
    Question 2. Please describe how much oil is recoverable using next-
generation CO2 EOR in the US.
    Answer. Work is currently underway to attempt to get a handle on 
the size of the new EOR resources. A proposal has been submitted to the 
Research Partnership to Secure Energy for America intended to assess 
the size of the San Andres formation ROZ resource in the entire Permian 
Basin and utilize the new methodology developed to begin looking at the 
Bighorn Basin in Wyoming and the southern Williston Basin (SD, ND, MT). 
Additionally, Advanced Resources International has been following the 
ROZ studies since the original report in 2005\4\. They performed a 
survey of fields in five U.S. basins and reported the results of the 
ROZ studies in a series of five reports\5\. Most recently, they have 
authored a report looking at the potential of all next-generation 
CO2 EOR technologies. In addition to a new limited look at 
the ROZ resources, they are examining the use of additives to the WAG 
injection water to improve sweep efficiency in complex reservoirs via 
additional wells and utilizing higher volumes of CO2 
injection. They have just submitted a draft3 for review at 
DOE and the CO2 economically recoverable numbers are very 
large, on the level of 37 billion barrels from the conventional 
reservoir targets and almost double that to 66 billion barrels using 
next generation flooding technologies--more than three times the 
current proven oil reserves. The technically recoverable total 
including the limited look at ROZ resources would be on top of these 
figures and, based on the early work done to date, would double that 
again to an estimated total of 135 billion barrels.
---------------------------------------------------------------------------
    \4\ Improving Domestic Energy Security and Lowering CO2 
Emissions with ``Next Generation'' CO2-Enhanced Oil Recovery 
(CO2-EOR)'', Activity 04001.420.02.03, Jun 2011.
    \5\ Stranded Oil in the Residual Oil Zone, Advanced Resources 
International Corp and Melzer, L.S. (2008), Feb `06, http://
www.fossil.energy.gov/programs/oilgas/eor/Stranded--Oil--in--the--
Residual--Oil--Zone.html
---------------------------------------------------------------------------
    Question 3. How much CO2 is needed to realize the 
domestic oil production potential of next-generation EOR?
    Answer. The same ARI report5 discussed the 
CO2 requirements for producing these recoverable resources. 
The total mass required is 19.5 billion MT (375 trillion 
ft3)\6\. They looked at where the CO2 will come 
from and conclude that only 12% is likely to come from existing 
sources.
---------------------------------------------------------------------------
    \6\ A common metric used is that a typical existing 1 Gigawatt coal 
power plant would yield 10 million MT/yr at a 90% CO2 
capture rate
---------------------------------------------------------------------------
    Question 4. How much of this new CO2 would be needed 
from anthropogenic sources?
    Answer. Most of our industry counterparts are convinced that 
natural sourced CO2, albeit very reliable and affordable, is 
likely not to expand beyond its current levels of 2.5 billion 
ft3 per day (45-50 million MT per year). Some observers, 
including myself, are very concerned about the industry's ability to 
maintain these current natural CO2 production levels. The 
required growth in the CO2 supply market must come from 
anthropogenic sources. The existing anthropogenic and short term growth 
is from the easier sources; i.e., natural gas, ammonia, and ethanol 
plants. The more difficult ones use coal or petroleum coke as the fuel 
and will be more expensive sources of CO2. Incentives like 
the ones currently being provided by the Department of Energy through 
their US Industrial CCS Projects Initiative\7\ are a good start but 
another set of incentives is worthy of mention and will be addressed in 
the next question/ answer.
---------------------------------------------------------------------------
    \7\ http://powerplantccs.com/blog/2010/03/12-us-industrial-ccs-
projects-pursue-1-4-billion-in-doe-funding.html
---------------------------------------------------------------------------
    Consistent with an industry average net utilization factor of 3 
barrels of oil per MT of CO2, the volume of CO2 
needed is 45 billon MT to realize the technically recoverable oil and 
about 20 billion MT to realize the economically recoverable oil 
available from ``next generation'' CO2 EOR technology. 
Existing natural sources and gas plant supplies of CO2 can 
only provide a little over 2 billion MT. As such, the capture and 
productive use of anthropogenic CO2 will be essential for 
realizing the vast domestic oil production potential available from our 
existing oil fields through application of ``next generation'' 
CO2 EOR.
    Question 5. What kinds of federal policies are needed to build the 
CO2 supply needed to realize the domestic oil production 
potential from next generation EOR?
    Today, favorable market forces and complimentary federal policies 
have an opportunity to create dramatic increases in domestic oil 
production while sequestering this CO2 that otherwise be 
emitted. Unfortunately, with some exceptions, the parties representing 
climate concerns and those capable of CO2 EOR can be 
accurately characterized as being on opposite sides of a wall 
separating CO2 capture and sequestration from resource 
recovery. Again with very few exceptions, both sides seem intent on 
keeping the respective playgrounds to themselves. Federal policies can 
help remove this ill-conceived barrier.
    In today's world where giving any benefit to the oil industry is 
difficult because of the perceived poor reception by the public, we 
believe the best approach for realizing the carbon emission reductions 
and oil production enhancements is to incentivize CO2 
capture. For the oil (injection) industry, the effect of making 
captured and pressurized CO2 affordable can have roughly the 
same positive effect of ``discovering'' new reserves, not unlike the 
revolution occurring with technology and unconventional shale 
formations today. I will say however, there are two exceptions to the 
principle that only a capture incentive is needed. The first is 
avoiding unnecessarily onerous additional requirements on a 
CO2 EOR project to prove storage when such verification can 
be done with only a modest enhancement of standard industry practices. 
The second involves elevating the EOR investments in the oil industry 
to more effectively compete against those short term rates of return 
available to them in the new world of unconventional shale exploration. 
With these issues in mind, it is best to examine the policies and 
incentives for the a) capture and b) CO2 injection sectors 
separately.
    First, is there an approach wherein future Federal tax revenues 
from EOR production can be used to finance the upfront investments in 
the capture of CO2? It is my understanding that Senator 
Lugar's office is developing a proposal that would extend tax credit 
for CCS linked to future CO2 EOR revenues to come to the 
federal government. There are two problems being addressed with this 
approach:

   The jump start needed for addressing capture economics and 
        risks and
   Addressing a classic ``chicken and egg'' syndrome: it takes 
        available CO2 to get the oil projects planned and 
        implemented but, on the other hand, one will not go to the 
        risks and expense to capture the CO2 unless the oil 
        projects are there. Both parties sit around waiting on the 
        other. By addressing the incentivized capture from future oil 
        revenues, you should get both.

    The justifying concepts are that the enhanced oil revenues for the 
economy and tax base will not materialize unless the CO2 
supply is available for the projects to be implemented. And leadership 
in CO2 capture for the U.S. can occur at a less expensive 
cost to the economy than the non-EOR alternatives.
    According to recent studies, the U.S. Treasury directly receives 
$23 from a domestically produced $100 oil barrel\8\. It should be noted 
that this amount does not count the employment, state and local taxes 
paid; i.e., the wealth creation reaching well beyond the federal 
receipts. Knowing that a MT of captured CO2 delivered to the 
oil field will yield, on average, 3 barrels of crude oil production 
and, given current and projected oil prices, the future federal oil 
revenues are highly likely to exceed the upfront cost for the capture. 
The anthropogenic CO2 projects must qualify and the details 
of such eligibility are being studied.
---------------------------------------------------------------------------
    \8\ Op Cit, Improving Domestic Energy Security and Lowering 
CO2 Emissions
---------------------------------------------------------------------------
    Available CO2 is an absolute key to realization of the 
EOR barrels but it is not sufficient. CO2 EOR is already a 
long rate of return and labor intensive proposition. And, the EOR 
industry can be characterized as having an apprehension that `business 
as usual' EOR will be altered in such a fashion as to make it more 
difficult to undertake new projects. For example, the state of Texas 
chose to address this exact concern in two ways: 1) with an incremental 
production tax credit of 1.125% of the oil revenues when using 
anthropogenic CO2 and 2) to have the regulatory agency 
familiar to the industry provide the permits to qualify the project for 
``incidental'' storage. What is meant by `incidental' is that storage 
of the purchased CO2 automatically occurs as a result of the 
CO2 EOR process. And this process now has a body of rules 
very similar to the rules already in force for CO2 EOR wells 
and project operation. Thus, by formalizing the ``new'' CCS rules for 
all to see, the barrier of regulatory uncertainty was essentially 
removed. I should add here that the federal rules published by the EPA, 
while attempting to consider the Texas approach, effectively added a 
complexity and uncertainty that has not been useful to qualifying 
storage during CO2 EOR. I am hearing that one particular 
plant company and a separate injection organization have chosen to opt 
out of the CCS + EOR pathway for these reasons.
    One additional comment I would make has to do with long term 
stewardship and liability. Texas tried very hard to keep CO2 
out of the waste world. It is enormously difficult for the 
Environmental Protection Agency to accomplish that goal considering 
their name and mission. They are to be commended for creating a 
separate class of injection wells (Class VI UIC) rather than dropping 
CO2 injection wells into waste Class I but the EOR industry 
has thoroughly examined the specifications of Class VI and drawn the 
conclusion that it is effectively a renamed Class I. I am led to 
believe that the pressures that were exerted on the EPA in Washington 
were so intense that the EPA erred in being overly prescriptive to 
accommodate the worst case scenarios. The result is that CO2 
EOR + CCS is still ``stuck in the mud.''
    Because of the dual value of CO2 EOR and the new 
developments as to the size of the resources available to EOR plus CCS, 
Congress, industry and markets could benefit from more detailed, timely 
and broadly available information. One possibility would be a 
``National CO2 EOR Center'', able to foster the development 
and deployment of ``next generation'' EOR. This entity could help 
accelerate the use of advanced CO2-based oil recovery 
technology in domestic oil fields, with great benefits to the nation's 
energy security, economy, and environmental goals. Such a ``Center'' 
should be located near the oilfield laboratories for CO2 
EOR. On the one hand, such a ``Center'' would be a most valuable 
resource center for smaller independents looking to implement 
CO2 EOR in their mature fields. On the other hand, such a 
``Center'' would also provide timely studies and information to 
Congressional members and their staff, assisting formulation of sounder 
policies and possibly legislation of great benefit to U.S. energy 
security, jobs and economic progress.
    The CCS world is an expensive one. It can also be made to be a very 
complex place to do business. Because of the U.S.'s wonderful endowment 
of coal and oil resources, a unique convergence of the dual needs for 
domestic oil and reducing greenhouse gas (CO2) emissions is 
in front of us. The wall between CO2 capture plus waste 
injection sequestration and the experienced companies doing resource 
production does a disservice to both CCS objectives and resource 
production.
                              Appendix II

              Additional Material Submitted for the Record

                              ----------                              

                           broken promise #3
                   Directional Drilling is no Panacea
The Promise
    New directional drilling technology enables drilling without any 
surface impacts.
The Reality
    Directional drilling is not new and requires the same 
infrastructure with the same impacts as all oil development, including 
surface impacts.
    Proponents of oil and gas development in the Arctic National 
Wildlife Refuge and other sensitive areas of Alaska assert that new 
advances in directional drilling will reduce, and even eliminate, 
environmental impacts. In fact, directional drilling has limitations, 
and its impacts are no different than those of conventional drilling.

          ``The industry touted roadless development as the way of the 
        future, and is now abandoning the concept.''

    Community of Nuiqsit, 2004\1\
---------------------------------------------------------------------------
    \1\  U.S. Bureau of Land Management. 2005, January. Final Amendment 
to the Northeast National Petroleum Reserve: Integrated Activity Plan/
Environmental Impact Statement. Vol. 2, Response to comments. Kuupik 
Corporation, Native Village of Nuiqsut, City of Nuiqsut, and 
Kuukpikmuit Subsistence Oversight Panel. Comment Letter No. 197616. P. 
6-262.
---------------------------------------------------------------------------
            Directional drilling is not a new practice
    According to the U.S. Department of Energy, the fi rst true 
horizontal well\2\ was drilled in 1929 in Texas.\3\ Since then, 
thousands of horizontal wells have been drilled across the world. But 
as of 1999 horizontal boreholes accounted for only fi ve to eight 
percent of all U.S. land wells, and extended-reach horizontal drilling 
is still uncommon.\4\ In Arctic Alaska, oil companies have rarely 
drilled horizontal distances of more than a few miles. Of the 5,549 
wells drilled on Alaska's North Slope to date, only 41 have reached 
horizontal offset distances of three miles or more.\5\
---------------------------------------------------------------------------
    \2\ The terms horizontal and directional drilling are used 
interchangeably in this document to refer to non-vertical drilling.
    \3\ Horizontal and Multilateral Wells. Frontiers of Technology. 
(1999, July). Journal of Petroleum Technology. Retrieved March 18, 2009 
from website: http://www.spe.org/spe-app/spe/jpt/1999/07/
frontiers_horiz_multilateral.htm#.
    \4\ Pratt, Sara, (2004, March). A Fresh Angle on Oil Drilling, 
GeoTimes.
    \5\ Horizontal offsets calculated by Doug Tosa, GIS Analyst, Alaska 
Center for the Environment. August 2009. Source data: Alaska Oil and 
Gas Conservation Commission well database, http://www.state.ak.us/
local/akpages/ADMIN/ogc/publicdb.shtml.
---------------------------------------------------------------------------
            Exaggerated claims
    Claims that directional drilling can reach eight to ten miles away 
are exaggerated.\6\ Oil companies have drilled distances over seven 
miles, but such distances are still extremely rare in the industry.\7\ 
On the North Slope, 94% of all existing wells extend less than two 
miles from the drill rig, and fewer than 2% extend more than three 
miles. As of August 2009 the maximum horizontal distance drilled was 
4.025 miles. Even at ConocoPhillips' Alpine oil fi eld, which is touted 
as a model of new directional drilling technology, the average 
horizontal drill distance is only 1.74 miles.\8\
---------------------------------------------------------------------------
    \6\ Senator Lisa Murkowski's website claims that her directional 
drilling bill will enable ``oil wells to be drilled from the western 
Alaska state-owned lands, outside of the refuge's boundary, or from 
state waters to the north, and still to [sic] be able to tap oil and 
gas deposits located between eight and 10 miles inside the refuge. 
http://murkowski.senate.gov/public/
index.cfm?FuseAction=IssueStatements. View&Issue_id=8160a71d-9c6e-945d-
f605-a8959dfbf80b (last visited April 8, 2009).
    \7\ British Petroleum's Wytch Farm set the current world extended 
reach drilling record in June of 1999 when its well M16 reached a 
``horizontal displacement distance of 10,728 m[eters] a total length of 
11,278 m[eters] and a depth of 1638 m[eters].'' http://www. bpnsi.com/
index.asp?id=7369643D312669643D313531 (last visited March 18, 2009).
    \8\ Directional drilling data analysis by Doug Tosa, GIS Analyst, 
Alaska Center for the Environment. August 2009. Source data: Alaska Oil 
and Gas Conservation Commission well database retrieved June 16, 2009 
from http://www.state.ak.us/local/akpages/ ADMIN/ogc/publicdb.shtml.
---------------------------------------------------------------------------
            Longer-reach drilling is expensive and often presents 
                    geologic and engineering challenges
    Truly state-of-the art practices are often impractical if not 
impossible for oil companies. Factors such as where the oil or gas 
deposit is in relation to the drilling rig, the size and depth of the 
mineral deposit, and the geology of the area, are all important 
elements in determining whether directional drilling is possible.\9\ 
Drilling a horizontal or extended-reach well can cost two or three 
times more than drilling a vertical well in the same reservoir.\10\ In 
2000, British Petroleum ``stopped drilling extended reach wells-those 
that reach out a long distance from the pad-after oil prices crashed in 
the late 1990s, because extended-reach drilling is expensive.''\11\ In 
a 2003 draft environmental impact statement for the National Petroleum 
Reserve-Alaska, the Bureau of Land Management (BLM) wrote:

    \9\ Judzis, A., K. Jardaneh and C. Bowes. 1997. Extended-reach 
drilling: managing, networking, guidelines, and lessons learned. SPE 
Paper 37573 presented at the 1997 SPE/IADC Drilling Conference, 
Amsterdam. March 4-6, 1997.
    \10\ Horizontal and Multilateral Wells. (1999, July); Van Dyke, 
Bill, petroleum manager, Alaska Department of Natural Resources. Quoted 
in Pratt, Sara. (2004, March).
    \11\ Petroleum News Alaska. (2000, 0ctober). BP plans busy 
exploration season, both in NPR-A and satellites.

          ``The cost of extended-reach [ERD] wells is considerably 
        higher than conventional wells because of greater distance 
        drilled and problems involving well-bore stability. Alternative 
        field designs must consider the cost tradeoffs between fewer 
        pads with more extended-reach wells as opposed to more pads 
        containing conventional wells. In most instances, it is more 
        practical and cost effective to drill conventional wells from 
        an optimum site, [than] it would be to drill ERD wells from an 
---------------------------------------------------------------------------
        existing drill site.''\12\

    \12\ U.S. Bureau of Land Management. (2003). Northwest National 
Petroleum Reserve-Alaska Draft Integrated Activity Plan/Environmental 
Impact Statement. Sec. IV, p. 20-21.

    ConocoPhillips' Alpine oil fi eld is an example of how optimistic 
claims about directional drilling technology can quickly fall fl at. 
Alpine was advertised in 1998 as a state-of-the-art roadless 
development. But the oil field already has several miles of permanent 
gravel road, and plans for expansion could add as much as 122 more 
miles.\13\ In 2004 the federal government approved plans to expand 
Alpine from two to seven drill sites.\14\ Also in 2004 the Bureau of 
Land Management granted ConocoPhillips an exemption from a lease 
stipulation that had previously prohibited the company from building a 
drill site in a 3-mile buffer zone along Fish Creek.\15\ The agency 
cited economic and geological limitations of directional drilling as 
the reason:
---------------------------------------------------------------------------
    \13\ U.S. Bureau of Land Management. September 2004. Alpine 
Satellite Development Plan Final Environmental Impact Statement. Vol. 
1, Sec. 2. Pp. 69-71.
    \14\ U.S. Bureau of Land Management. (2004, November). Alpine 
satellite development plan Record of Decision.
    \15\ U.S. Bureau of Land Management. (2004, September). Alpine 
Satellite Development Plan. Final Environmental Impact Statement. Vol. 
3. Appendix I, CPAI request for exception to stipulations. 
ConocoPhillips letter dated April 8, 2004 to BLM. Pp.3-4.

          ``Drilling from outside the setback would require directional 
        drilling for long distances through geologically unstable 
        shale. This drilling approach is very problematic because shale 
        in this area tends to collapse holes. Maintaining drill holes 
        would be diffi cult and expensive.''\16\
---------------------------------------------------------------------------
    \16\ BLM. November 8, 2004. Alpine Satellite Development Plan 
Record of Decision. p. 17.

    In 2008 British Petroleum announced its plans to drill distances of 
seven miles or more to reach its offshore Liberty oil field. But the 
technology remains to be proven. It will also demand doubling the size 
of Endicott Island-an offshore, man-made island-to make room for 
extended pipe racks, the massive drilling rig, and a worker's camp.\17\
---------------------------------------------------------------------------
    \17\ Delbridge, Rena, ``BP begins development of Liberty oil fi eld 
project on North Slope, Fairbanks Daily News Miner, July 14, 2008, 
http://www.newsminer.com/news/2008/ jul/14/bp-begin-developing-liberty-
oil-field/ (last visited June 30, 2009). http://www.alaskajournal.com/
stories/050109/oil_img_oil001.shtml (last visited June 30, 2009) http:/
/www.alaskajournal.com/stories/060509/oil_10_001.shtml (last visited 
June 30, 2009)

           Directional drilling is not a new practice.
           Claims about distances directional drilling can 
        reach are exaggerated.
           Directional drilling is expensive and often limited 
        by geology.
           Directionally drilled wells require the same 
        infrastructure and have the same environmental impacts as 
        conventional wells, including surface impacts.
            Claims that directional drilling will incur no surface 
                    impacts are misleading
    Before production wells are drilled, seismic testing is conducted 
and exploration wells are drilled to refi ne the location of oil 
deposits. These activities have direct surface impacts.
    Seismic exploration typically involves many vehicles driving across 
the tundra in a grid pattern. Sensitive tundra soil and plants are 
easily compressed under the weight of these heavy vehicles, even in 
winter.\18\ Seismic lines are often visible on the Arctic tundra for 
years after exploration, and studies have shown that fragile tundra 
plants can take decades to recover.\19\ Despite industry claims to the 
contrary, winter exploration can also disturb wildlife.\20\
---------------------------------------------------------------------------
    \18\ Jorgensen, J.C. 1998. Emers, M., J.C. Jorgenson, and M.K. 
Raynolds. 1995. Response of arctic tundra plant communities to winter 
vehicle disturbance. Can. J. Bot. 73: 905-917.
    \19\ U.S. Fish and Wildlife Service. 2001. Potential impacts of 
proposed oil and gas development on the Arctic Refuge's coastal plain: 
historical overview and issues of concern. Web page of the Arctic 
National Wildlife Refuge, Fairbanks, Alaska: http://arctic.fws.gov/
issues1.htm.
    \20\ Ibid.
---------------------------------------------------------------------------
            The notion that directional drilling allows for a smaller 
                    footprint is misleading
    Although directional drilling may reduce the number of well pads 
required to access an oil deposit, it requires the same infrastructure 
and has the same environmental impacts as conventional drilling. 
Permanent gravel roads and air strips are still used for access, long 
pipelines are still required to connect the well sites, and pollution 
and toxic spills are still inevitable.
    Oil production is a high-impact activity, regardless of how you 
drill. New technology has yet to demonstrate that it can minimize, 
mitigate, or eliminate the inevitable impacts of oil development to 
America's Arctic and other sensitive ecosystems.
                                 ______
                                 
Statement of Pamela A. Miller, Arctic Program Director, Northern Alaska 
                    Environmental Center, Fairbanks
                    published friday, march 20, 2009
                                                     March 17, 2009
To the editor:
    It is welcome news that President Obama's Interior secretary has 
clearly rejected the approach of Sen. Lisa Murkowski's latest scheme to 
open the Arctic National Wildlife Refuge to oil exploitation. At a U.S. 
Senate hearing today, Interior Secretary Ken Salazar said ``ANWR as a 
national refuge needs to be absolutely protected,'' contradicting your 
erroneous headline printed this morning.
    Secretary Salazar was right to question the efficacy of directional 
drilling to reach potential oil in the Arctic refuge from outside its 
boundaries. In fact, a closer look at Sen. Murkowski's bill reveals 
exploratory drilling and disruptive seismic exploration could be 
allowed directly on the refuge coastal plain; operations would be 
exempt from many of the nation's laws to protect clean air, clean water 
and environmental quality. Furthermore, even if the bill jibed with its 
PR spin, offshore drill rigs and pipelines along nearly a hundred miles 
of refuge coast pose risks of oil spills and disruption to the coastal 
habitats and migratory movements of threatened polar bears, birds and 
Porcupine Herd caribou.
    The truth is that this is just another in a long line of drill 
bills for the Arctic refuge. Oil and gas exploration and development 
simply cannot be done without harming the people, plants and animals 
depending on our Arctic refuge for survival. At a time when there are 
nearly 100 million acres of land and water already open to the oil 
industry in America's Arctic--with little to no baseline science 
supporting such expansive development--the last thing Alaska needs is 
to open our only protected lands on Alaska's North Slope.
    Who do you think operates leases next to the Arctic refuge? Exxon. 
Next week is the 20th anniversary of the Exxon Valdez oil spill. It 
also has been more than 20 years since the debate to drill the Arctic 
refuge was first brought before Congress. It seems that, by now, we 
would have heeded the lessons learned--oil development is a risky, 
dirty business that has no place in or around what Secretary Salazar 
called one of our ``special and treasured places we will not disturb.''
                                 ______
                                 
              Statement of the Alaska Coalition, on S. 503
    Dear Senator, On behalf of the millions of conservationists our 
organizations and businesses from across the country represent, we 
write in opposition to S. 503, the `No Surface Occupancy Western Arctic 
Coastal Plain Domestic Energy Security Act' introduced by Senators 
Murkowski (AK-R) and Begich (AK-D). This legislation would undermine 
the fundamental purpose of the Arctic National Wildlife Refuge to 
protect wilderness and wildlife by opening the area to oil leasing and 
development.
    At a time when Congress has a historic opportunity to pass 
legislation focused on clean, renewable energy sources, energy 
efficiency and conservation, and reversing climate change, we are 
deeply disappointed that the Alaska delegation is trying, once again, 
to divert attention from necessary policy to rehash the unproductive 
debate over developing the Arctic National Wildlife Refuge.
    Our nation is already on a path to significantly reduce its oil 
addiction through sustainable clean energy solutions. In fact, changes 
in policy and practices from just the past few years have set us on 
track to reduce our oil consumption by an amount 17 times that of the 
speculative oil potential estimated from the Refuge over the same 
period. And with the current legislation being considered in Congress, 
there is so much more that can be done. With the right leadership, 
America can have energy policy that continues to reduce our use of 
fossil fuels, while ensuring that our most important wild places are 
passed on to our children and grandchildren.
    The Arctic National Wildlife Refuge is a national treasure, and 
protecting the Arctic Refuge has long been a top priority for the 
members of our organizations. The Refuge's coastal plain sustains 
hundreds of species of wildlife, as well as the culture and way of life 
of the Gwich'in Nation and other Alaska Native communities. S. 503 
would seriously threaten these resources. The bill's sponsors tout 
unproven, exaggerated oil potential from the Refuge's speculative 
reserves, sought ostensibly through directional drilling and pipeline 
technology that is currently untested in Alaska. At the same time, S. 
503 would allow surface activities including seismic and exploratory 
drilling across the biological heart of the Refuge, disturbing denning 
habitats used by imperiled polar bears and harming sensitive tundra 
vegetation. The legislation promotes increased development focused 
along the Canning River and across the entire Refuge coast, activity 
which risks dangerous spills in key wildlife and subsistence areas of 
the coastal plain. Furthermore, the bill would waive vital 
environmental laws and destroy the very values for which the Refuge was 
originally set aside nearly 50 years ago--its unparalleled wilderness 
and wildlife.
    With so many loopholes and exaggerated claims, it is hard to take 
this legislation as much more than a Trojan horse aimed at opening the 
entire Arctic Refuge Coastal Plain to oil leasing, exploration, and 
development.
    Americans deserve a cheaper, quicker, safer and cleaner energy 
policy that safeguards the wild places we care so deeply about. 
Congress has repeatedly rejected attempts to open the Arctic Refuge to 
oil drilling. Instead of trotting out dead-on-arrival proposals, it's 
time for America to prioritize clean, renewable energy solitons that 
move our country away from our addiction to oil and protect the Arctic 
National Wildlife Refuge as Wilderness.

