[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.
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\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.
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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.
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* 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.
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\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.
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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.
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\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).
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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\
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\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.
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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\
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\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.
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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.
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\7\ Broken Promises: The Reality of Oil Development in America's
Arctic (2nd Edition), The Wilderness Society, 2009.
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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.
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\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.
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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).
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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\
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\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.
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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\
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\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\
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\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.
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\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.
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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\
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\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\
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\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)
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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.
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\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
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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.
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\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
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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.
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\7\ http://powerplantccs.com/blog/2010/03/12-us-industrial-ccs-
projects-pursue-1-4-billion-in-doe-funding.html
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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.
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\8\ Op Cit, Improving Domestic Energy Security and Lowering
CO2 Emissions
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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\
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\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.
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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.
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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\
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\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:
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\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\
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\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\
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\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\
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\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.
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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.