[House Hearing, 111 Congress]
[From the U.S. Government Publishing Office]



 
                         UNCONVENTIONAL FUELS


                               PART II:

                            THE PROMISE OF


                           METHANE HYDRATES

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

                           OVERSIGHT HEARING

                               before the

                       SUBCOMMITTEE ON ENERGY AND
                           MINERAL RESOURCES

                                 of the

                     COMMITTEE ON NATURAL RESOURCES
                     U.S. HOUSE OF REPRESENTATIVES

                     ONE HUNDRED ELEVENTH CONGRESS

                             FIRST SESSION

                               __________

                        Thursday, July 30, 2009

                               __________

                           Serial No. 111-32

                               __________

       Printed for the use of the Committee on Natural Resources



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                     COMMITTEE ON NATURAL RESOURCES

              NICK J. RAHALL, II, West Virginia, Chairman
          DOC HASTINGS, Washington, Ranking Republican Member

Dale E. Kildee, Michigan             Don Young, Alaska
Eni F.H. Faleomavaega, American      Elton Gallegly, California
    Samoa                            John J. Duncan, Jr., Tennessee
Neil Abercrombie, Hawaii             Jeff Flake, Arizona
Frank Pallone, Jr., New Jersey       Henry E. Brown, Jr., South 
Grace F. Napolitano, California          Carolina
Rush D. Holt, New Jersey             Cathy McMorris Rodgers, Washington
Raul M. Grijalva, Arizona            Louie Gohmert, Texas
Madeleine Z. Bordallo, Guam          Rob Bishop, Utah
Jim Costa, California                Bill Shuster, Pennsylvania
Dan Boren, Oklahoma                  Doug Lamborn, Colorado
Gregorio Sablan, Northern Marianas   Adrian Smith, Nebraska
Martin T. Heinrich, New Mexico       Robert J. Wittman, Virginia
George Miller, California            Paul C. Broun, Georgia
Edward J. Markey, Massachusetts      John Fleming, Louisiana
Peter A. DeFazio, Oregon             Mike Coffman, Colorado
Maurice D. Hinchey, New York         Jason Chaffetz, Utah
Donna M. Christensen, Virgin         Cynthia M. Lummis, Wyoming
    Islands                          Tom McClintock, California
Diana DeGette, Colorado              Bill Cassidy, Louisiana
Ron Kind, Wisconsin
Lois Capps, California
Jay Inslee, Washington
Joe Baca, California
Stephanie Herseth Sandlin, South 
    Dakota
John P. Sarbanes, Maryland
Carol Shea-Porter, New Hampshire
Niki Tsongas, Massachusetts
Frank Kratovil, Jr., Maryland
Pedro R. Pierluisi, Puerto Rico

                     James H. Zoia, Chief of Staff
                       Rick Healy, Chief Counsel
                 Todd Young, Republican Chief of Staff
                 Lisa Pittman, Republican Chief Counsel
                                 ------                                


              SUBCOMMITTEE ON ENERGY AND MINERAL RESOURCES

                    JIM COSTA, California, Chairman
           DOUG LAMBORN, Colorado, Ranking Republican Member

Eni F.H. Faleomavaega, American      Don Young, Alaska
    Samoa                            Louie Gohmert, Texas
Rush D. Holt, New Jersey             John Fleming, Louisiana
Dan Boren, Oklahoma                  Jason Chaffetz, Utah
Gregorio Sablan, Northern Marianas   Cynthia M. Lummis, Wyoming
Martin T. Heinrich, New Mexico       Doc Hastings, Washington, ex 
Edward J. Markey, Massachusetts          officio
Maurice D. Hinchey, New York
John P. Sarbanes, Maryland
Niki Tsongas, Massachusetts
Nick J. Rahall, II, West Virginia, 
    ex officio
                                 ------                                
                                CONTENTS

                              ----------                              
                                                                   Page

Hearing held on Thursday, July 30, 2009..........................     1

Statement of Members:
    Costa, Hon. Jim, a Representative in Congress from the State 
      of California..............................................     1
        Prepared statement of....................................     2
    Lamborn, Hon. Doug, a Representative in Congress from the 
      State of Colorado..........................................     3

Statement of Witnesses:
    Boswell, Dr. Ray, Senior Management and Technology Advisor, 
      National Energy Technology Laboratory, U.S. Department of 
      Energy.....................................................    17
        Prepared statement of....................................    18
        Response to questions submitted for the record...........    21
    Collett, Dr. Timothy S., Research Geologist, U.S. Geological 
      Survey.....................................................     5
        Prepared statement of....................................     6
        Response to questions submitted for the record...........    14
    Hancock, Steven H., P.ENG., Well Engineering Manager, RPS 
      Energy Canada..............................................    24
        Prepared statement of....................................    25
        Response to questions submitted for the record...........    32
                                     


 OVERSIGHT HEARING ON ``UNCONVENTIONAL FUELS, PART II: THE PROMISE OF 
                          METHANE HYDRATES.''

                              ----------                              


                        Thursday, July 30, 2009

                     U.S. House of Representatives

              Subcommittee on Energy and Mineral Resources

                     Committee on Natural Resources

                            Washington, D.C.

                              ----------                              

    The Subcommittee met, pursuant to call, at 10:07 a.m. in 
Room 1334, Longworth House Office Building, The Honorable Jim 
Costa [Chairman of the Subcommittee] presiding.
    Present: Representatives Costa, Lamborn, Holt, Sablan, 
Heinrich, and Lummis.

STATEMENT OF HON. JIM COSTA, A REPRESENTATIVE IN CONGRESS FROM 
                    THE STATE OF CALIFORNIA

    Mr. Costa. Good morning. The Subcommittee on Energy and 
Mineral Resources will now come to order. This morning we are 
having a continuum of a series of hearings that we have been 
holding as we look at various types of fuels, some refer to 
them as unconventional fuels, and the potential it has as we 
look at all the energy tools in our nation's energy toolbox to 
deal with the challenges that we face in the 21st Century. 
Clearly, a comprehensive energy package, in my mind, involves 
dealing with the near-term strategies, the mid-term and the 
longer term. Today's hearing, as it relates to the promise of 
methane hydrates, is the longer-term strategy as we look at the 
ability to try to come together with a comprehensive bipartisan 
energy policy that will take advantage of all the opportunities 
that I think are there.
    Our first hearing on this series dealt with shale gas, a 
resource that is already considered to be conventional, and it 
has already become a major part of our nation's energy supply, 
but the situation a few decades ago was that shale gas was 
determined to be far more difficult to realize as a part of our 
energy portfolio. Obviously, in the last several decades, 
technologies have been developed that took that shale gas that 
previously was unaccessible and uneconomical, and now it is 
being utilized as a part of our energy resource. My sense is 
that potentially methane hydrates may follow in that same 
category.
    Methane hydrates can be thought of roughly as natural gas. 
As it was explained to me, it is frozen and it is found in many 
places frozen in ice, not only in terms of the Arctic, but also 
under the permafrost in the Arctic as well as under oceans on 
the edges of continents. Our witnesses will testify this 
morning on its potential as a future source of natural gas for 
our nation and what that potential is.
    The U.S. Geological Survey has estimated that there might 
be 200,000 trillion cubic feet of natural gas stored in the 
hydrates. I would hope that our witnesses this morning can try 
to explain to me what 200,000 trillion cubic feet of natural 
gas looks like. Clearly, it is bigger than a breadbox, but give 
us some perspective. Give us some perspective on how our 
country that uses approximately 23 trillion cubic feet per 
year, you divide 200,000 by 23, and I guess, as my staff has 
tried to explain to me, that is kind of what it looks like, but 
I would like more description from our witnesses.
    Of course, the figure is an estimate, and I am told that it 
is an old one. Just because there is a tremendous amount of 
methane hydrate does not mean that it is accessible today. What 
are the challenges of getting it and producing it? Just as we 
have done with gas from shale, how far away are we in terms of 
the technologies?
    Even if 1 percent of that was recoverable, that would be, I 
am told, a source of energy for our country for over 80 years' 
worth of natural gas.
    The Subcommittee helped put this together. I want to thank 
the staff with the Methane Hydrate Research and Development 
Program that was established over 10 years ago. We are pleased 
that we can have the status report on where things stand, and 
more importantly, where we should be going in the future. There 
have been tremendous strides that have taken place. Wells have 
been drilled in the Arctic and the Gulf of Mexico to test the 
ability to locate and produce the gas from these hydrates.
    So, we will also hear today about what it might take to 
make this methane hydrate gas production economical. I am 
understanding that there are a number of things that have been 
done by a number of companies in this area. We would like to 
get an update on that. It seems that shale gas, as I said, was 
far beyond the horizon just 20 years ago, and while methane 
hydrates may be viewed in that same way today, hopefully in 
less than 20 years from now they will not be.
    I am optimistic about this potential. I am also interested 
in hearing--since there are those who believe that as it 
relates to coastal development of oil and natural gas--although 
I think the examples we have seen for decades in the Gulf of 
Mexico, as well as the California coast and other coastal areas 
in the United States' boundaries--that oil and gas can be and 
has been produced safely and successfully. I suspect some of 
the same people who differ with me on that view may have the 
same attitude toward gas hydrates off the coast, and so how do 
you overcome that hurdle?
    So with that said, I would defer to the Ranking Member of 
the Subcommittee here for his opening comments, and then we 
will begin with our witnesses.
    [The prepared statement of Mr. Costa follows:]

            Statement of The Honorable Jim Costa, Chairman, 
              Subcommittee on Energy and Mineral Resources

    Good morning, and welcome to the Energy and Mineral Resources 
Subcommittee's second hearing on unconventional fuels. Our first 
hearing in this hearing in this series, on shale gas, dealt with a 
resource that, while still technically considered unconventional, has 
already become a major component of our nation's domestic fuel supply. 
Today's hearing is on methane hydrates, a truly unconventional fuel 
source, albeit one that has the potential to make a massive impact in 
the future.
    Methane hydrates can be thought of as natural gas frozen in ice. 
They have a structure where water molecules form a cage around 
individual molecules of methane, essentially trapping them in a solid 
state. Because the methane molecules are held together much closer than 
they would be if they were a free gas, one cubic foot of methane 
hydrate can release over 160 cubic feet of methane gas.
    Originally these substances were thought to just be a laboratory 
curiosity or a pipeline nuisance. But since they were discovered in 
nature nearly 50 years ago, they have become viewed as a significant 
hazard for offshore oil and gas drillers, a potential major player in 
global climate change, and, most importantly for the purposes of this 
hearing, possibly the largest source of fossil fuel in the entire 
world. Estimates from the U.S. Geological Survey peg the amount of gas 
in hydrate form in the United States to be over 200,000 trillion cubic 
feet. That sounds large by itself, but is even more impressive when the 
total amount of conventional natural gas in the United States is 
estimated to be around 1,700 trillion cubic feet. And in 2008, the 
nation used about 23 trillion cubic feet. So, in theory, we might have 
almost 8,500 years worth of natural gas locked up beneath our feet as 
hydrates.
    However, the total resource figure tells us nothing about how much 
natural gas we would actually be able to get out of these hydrates, 
which will be highly limited because of economic and technological 
factors. And the resource estimates themselves are highly uncertain. 
The Department of Energy and the U.S. Geological Survey, both of whom 
are here today, have been working for decades to try to answer the 
questions: How much gas hydrate do we really have? Where is it? And can 
we get to it in a way that will help provide a new robust source of 
domestically produced natural gas for this nation.
    We do have a good general sense for where methane hydrates are--we 
know they exist in Arctic regions, beneath permafrost, and also 
offshore beneath the seabed. These offshore hydrates have been 
discovered off the coasts of South Carolina and Oregon, and in the Gulf 
of Mexico. In both the Arctic and the Gulf of Mexico, the indications 
are that natural gas can be produced from methane hydrates using 
traditional drilling technology. I understand there were some 
particularly promising results from the Gulf of Mexico earlier this 
year, which we will hear more about in the testimony.
    The situation now with methane hydrates might resemble how things 
looked for gas shales just a couple of decades ago. At that time, gas 
shales were seen as uneconomic and technologically inaccessible--they 
were truly an unconventional fuel whose time would be far in the 
future. Those barriers were overcome, and I believe that with continued 
research, the barriers for production of natural gas from hydrates will 
be overcome as well in the not-too-distant future. I am extremely 
optimistic about the promise of methane hydrates, and I look forward to 
hearing from our witnesses about how that promise might turn into 
reality.
    I now recognize our Ranking Member, Mr. Lamborn, for his opening 
statement.
                                 ______
                                 
    Mr. Costa. The gentleman from Colorado, Mr. Doug Lamborn.

 STATEMENT OF HON. DOUG LAMBORN, A REPRESENTATIVE IN CONGRESS 
                   FROM THE STATE OF COLORADO

    Mr. Lamborn. Thank you, Mr. Chairman, and I commend you for 
continuing this series of important hearings on the nation's 
future unconventional energy resources. Today's hearing will 
focus on the promise of methane hydrates, the development of 
which was once considered a distant reality because of the 
technological challenges associated with producing gas from 
this type of resource.
    Like the research and technological advances needed to 
develop our deepwater oil and gas and onshore shale gas fields, 
methane hydrate research will allow the United States and other 
nations to access this important energy resource in the near 
future. This will be especially important as the United States 
and other nations' economies begin to improve and energy demand 
around the world will again continue to rise. Many countries 
will be looking at the possibility of using methane hydrates to 
meet their domestic natural gas demands.
    I am interested in hearing today about the state of methane 
hydrate research and the opportunities that this research 
offers the United States to access this significant domestic 
energy resource. However, while the promise of this energy 
resource is tantalizing, it is important to remember that much 
of this resource is unavailable for domestic development, even 
if the technology needed to harvest it were available today.
    Domestically, our methane hydrate resources lie off the 
coast in the Outer Continental Shelf and onshore in Alaska. It 
has been more than a year since President Bush lifted the 
moratorium on OCS leasing, and which the Congress in similar 
manner did not renew, and began work to amend the current five-
year leasing plan. However, we are no closer today in being 
able to access our conventional or unconventional energy 
resources, such as methane hydrates, for areas previously under 
moratorium.
    By delaying planned development by six months, the 
Secretary of the Interior has significantly delayed the 
planning process and hampered the completion of other studies, 
including an environmental impact statement required to develop 
a final five-year OCS leasing plan. Meanwhile, environmental 
allies of this Administration have filed lawsuits which have 
stopped all development under the current plan for the Chukchi, 
Beaufort and the Bering Seas of Alaska, the same areas with 
such great promise for methane hydrates.
    Furthermore, the Chairman of the Democratic National 
Committee has called upon the Secretary of the Interior to stop 
the planned leasing scheduled for 2011 off the coast of 
Virginia, the only Atlantic process included in the 2007 to 
2012 five-year OCS plan, and an area with significant natural 
gas prospects.
    Meanwhile, Dominion Cove Point LNG terminal in Maryland is 
receiving liquified natural gas imports from Nigeria and 
Venezuela, and Elba Island LNG terminal in Georgia is receiving 
imported gas from Egypt. I would prefer to have the job 
creation which comes along with domestic leasing rather than 
the energy dependence and loss of jobs created by importing LNG 
from other countries.
    Allowing access to our domestic conventional and 
unconventional resources does three important things: It 
provides an opportunity to create high-paying family wage jobs 
and unique business development opportunities which stimulate 
the economy; it provides a strong stream of revenue for 
Federal, state, and local government treasuries which helps the 
bottom line on budgets; and it makes us less dependent on 
foreign sources of energy, which also helps our domestic 
economy.
    Finally, Mr. Chairman, I would like to take this 
opportunity to also propose that this Committee continue this 
series of hearings by examining the tremendous promise of oil 
shale. As you know, Mr. Chairman, I am a strong advocate of oil 
shale development, and I think we would benefit from holding a 
hearing to get a clear understanding from this Administration 
on the status of the oil shale commercial leasing program, 
including the cancellation of the research development and 
demonstration leases.
    In closing, there are a number of questions I will have 
about this technology and the promise of methane hydrates, and 
I am looking forward to hearing from the witnesses.
    Thank you, Mr. Chairman, and I yield back.
    Mr. Costa. Thank you, and we look forward to hearing from 
our witnesses and I will take the gentleman from Colorado's 
suggestion as it relates to other types of unconventional 
energy sources, and we will see if we can work that out.
    Mr. Lamborn. Excellent.
    Mr. Costa. Our witnesses this morning are the following: 
Dr. Timothy Collett, a Research Geologist for the United States 
Geological Survey; Dr. Ray Boswell, Senior Management and 
Technology Advisor for the National Energy and Technology 
Laboratory for the United States Department of Energy; and Mr. 
Steve Hancock, a Well Engineering Manager at RPS Energy, is 
that correct? Good, and I pronounced all of your names, I 
think, properly, I hope. I do want to inform the Subcommittee 
that we had a hope that a representative from ConocoPhillips 
would be here as a part of the panel because they have done 
some work on this. However, a couple of days ago they told us 
that they would not be able to provide the witness. Obviously, 
we are disappointed but we hope that in the future they may be 
able to update us on their efforts in this area with methane 
hydrates.
    So, without further ado, we still have three excellent 
witnesses, and why don't we begin with Dr. Timothy Collett. I 
do not know if the three gentlemen here have testified before 
but, just in case, let me explain the rules.
    The rules are that we get to ask the questions and you have 
to answer them. But beyond that, we give you five minutes for 
your opening statement. That light there in front of you it is 
green for four minutes, it becomes yellow for the last minute, 
and then it turns red after your five minutes has expired, and 
then your chair drops down if you are still speaking. No, that 
is not the case, but the Chair does try to be flexible, but we 
do want you to keep it within five minutes so we can get to the 
question-and-answer period. Obviously, if you have a longer 
statement, that will be submitted for the record.
    So, again, Dr. Timothy Collett, Research Geologist for 
United States Geological Survey. What do you want to tell us 
about methane hydrates?

             STATEMENT OF DR. TIMOTHY S. COLLETT, 
           RESEARCH GEOLOGIST, U.S. GEOLOGICAL SURVEY

    Dr. Collett. Thank you. Mr. Chairman and members of the 
Subcommittee, thank you for the opportunity to discuss the 
importance of the energy resource potential of gas hydrates. In 
this statement, I will discuss the USGS's assessment of the 
energy resource potential of natural gas hydrates. In our 
written testimony we also examine the research issues that need 
to be resolved to safely and economically produce gas hydrates.
    Gas hydrates, also known as methane hydrates, are naturally 
occurring crystal and solids composed of water and natural gas 
in which solid cages of water trap the gas. Gas and water 
becomes a solid under certain temperature and pressure 
conditions within the earth called the gas hydrate stability 
zone. Gas hydrates are widespread in the Arctic, below 
permafrost and beneath the sea floor in sediments of the outer 
continental margins.
    The amount of gas contained in the world's hydrate 
accumulations is enormous, and it is generally believed they 
hold more natural gas than the world's conventional 
accumulations. In 1995, the USGS made the first systematic 
assessment of the in-place natural gas hydrate resources of the 
U.S. This study showed that the amount of gas in the hydrate 
accumulations of the U.S. greatly exceeds the volume of known 
conventional domestic resources.
    Early in 2008, the U.S. Minerals Management Service 
released the first comprehensive assessment of gas hydrates in 
the U.S. Gulf of Mexico since the USGS 1995 assessment. The 
2008 MMS assessment predicted that gas hydrates in the Gulf of 
Mexico may hold as much as 21,000 trillion cubic feet of in-
place gas. The MMS continues to work on the assessment of gas 
hydrates in the OCS of the U.S. and also assessing what part of 
the marine gas hydrate resources can be technically recovered.
    In the fall of 2008, with the support of the U.S. Bureau of 
Land Management, U.S. researchers announced a giant step 
forward with the completion of the first ever assessment of the 
amount of gas hydrate that can actually be recovered or 
technically recovered from gas hydrates. In this landmark study 
the USGS estimated that more than 85 trillion cubic feet of 
natural gas could be extracted from the gas hydrates on the 
north slope of Alaska, which would be one of the largest single 
sources of natural gas in the U.S.
    And I would also like to add in regards to the Chairman's 
question, put that into context, that would be approximately 
enough heat or enough energy to heat 100 million U.S. homes for 
10 years, so really an extraordinary amount of gas what we 
determine to be technically recoverable from the north slope if 
it could be economically produced and exported.
    Finally, the USGS has supported gas hydrate research since 
the early 1980s, and with our Federal partners, including BLM, 
MMS, and DOE, as well as a number of international research 
partners in Canada, Japan, India and South Korea, we have made 
significant contributions to our understanding of the energy 
resource potential of gas hydrates. The USGS will continue to 
investigate all aspects of gas hydrates, understand their 
geological origin, their natural occurrence, the factors that 
affect their stability, their environmental impact, and 
possibly the use of this vast new energy resource.
    Thank you, Mr. Chairman, for this opportunity to present 
this information, and I will be happy to respond to any 
questions you may have.
    [The prepared statement of Dr. Collett follows:]

       Statement of Dr. Timothy S. Collett, Research Geologist, 
        U.S. Geological Survey, U.S. Department of the Interior

    Mr. Chairman and Members of the Subcommittee, thank you for the 
opportunity to discuss the importance of the energy resource potential 
of natural gas hydrates. In this statement I will discuss the USGS 
assessment of the energy resource potential of natural gas hydrates and 
examine the research and development issues that need to be resolved to 
safely and economically produce gas hydrates. It is important to note 
that many different gases form gas hydrates, but methane, which is the 
main component of natural gas and is used to heat homes and for other 
domestic purposes, is the most common gas included in gas hydrates and 
that is why they are often referred to as methane hydrates. It is also 
important to note that this testimony will focus on the technical and 
economic aspects of gas hydrate production potential. The environmental 
impacts from gas hydrate production, including the potential impacts on 
global climate change, require additional study and analysis as the 
role of gas hydrates in the total energy mix is further defined and 
considered.
    In 1995, USGS made the first systematic assessment of the in-place 
natural gas hydrate resources of the United States. That study shows 
that the amount of gas in the hydrate accumulations of the United 
States is estimated to greatly exceed the volume of known conventional 
domestic gas resources. However, gas hydrates represent both a 
scientific and technologic challenge and much remains to be learned 
about their characteristics and possible economic production. The 
primary objectives of USGS gas hydrate research are to: 1) document the 
geologic parameters that control the occurrence and stability of gas 
hydrates, 2) to assess the volume of natural gas stored within various 
gas hydrate accumulations, 3) to analyze the production response and 
characteristics of gas hydrates, 4) to identify and predict natural and 
induced environmental impacts of natural gas hydrates, and 5) to 
analyze the effects of gas hydrate on drilling safety.
Gas Hydrate Occurrence and Characterization
    Gas hydrates are naturally occurring crystalline substances 
composed of water and gas, in which a solid water-lattice holds gas 
molecules in a cage-like structure. The gas and water become a solid 
under specific temperature and pressure conditions within the Earth, 
called the hydrate stability zone. Gas hydrates are widespread in 
Arctic regions beneath permafrost and beneath the seafloor in sediments 
of the outer continental margins. The amount of gas contained in the 
world's gas hydrate accumulations is enormous, estimates of in-place 
gas within natural gas hydrates range over three orders of magnitude 
from about 100,000 to 270,000,000 trillion cubic feet (TCF) of gas. By 
comparison, the conventional global gas endowment (undiscovered, 
technically recoverable gas resources + conventional reserve growth + 
remaining reserves + cumulative production) has been estimated at 
approximately 15,400 TCF (USGS World Petroleum Assessment, 2000). 
Despite the enormous range of these estimates, and the notable 
differences between in-place gas-hydrate estimates and the 
aforementioned estimates of conventional gas, gas hydrates seem to be a 
much greater resource of natural gas than conventional accumulations.
    Even though gas hydrates are known to occur in numerous marine and 
Arctic settings, relatively little is known about the geologic controls 
on their distribution. The presence of gas hydrates in offshore 
continental margins has been inferred mainly from anomalous seismic 
reflectors that coincide with the base of the gas-hydrate stability 
zone. This reflector is commonly called a bottom-simulating reflector 
or BSR. BSRs have been mapped at depths ranging from about 0 to 1,100 
meters below the sea floor. Gas hydrates have been recovered by 
scientific drilling along the Atlantic, Gulf of Mexico, and Pacific 
coasts of the United States, as well as at many international 
locations.
    Onshore gas hydrates have been found in Arctic regions of 
permafrost and in deep lakes such as Lake Baikal in Russia. Gas 
hydrates associated with permafrost have been documented on the North 
Slope of Alaska and Canada and in northern Russia. Direct evidence for 
gas hydrates on the North Slope of Alaska comes from cores and 
petroleum industry well logs, which suggest the presence of numerous 
gas hydrate layers in the area of the Prudhoe Bay and Kuparuk River oil 
fields. Combined information from Arctic gas-hydrate studies shows 
that, in permafrost regions, gas hydrates may exist at subsurface 
depths ranging from about 130 to 2,000 meters.
    The USGS 1995 National Assessment of United States Oil and Gas 
Resources focused on assessing the undiscovered conventional and 
unconventional resources of crude oil and natural gas in the United 
States. This assessment included, for the first time, a systematic 
appraisal of the in-place natural gas hydrate resources of the United 
States, both onshore and offshore. The offshore assessment, on which 
USGS partnered with the U.S. Minerals Management Service (MMS), 
identified eleven gas-hydrate plays within four offshore provinces. 
There was one gas-hydrate province identified onshore. The offshore 
provinces lie within the U.S. 200 mile Exclusive Economic Zone adjacent 
to the lower 48 States and Alaska. The only onshore province assessed 
in that study was the North Slope of Alaska. In-place gas hydrate 
resources of the United States are estimated to range from 113,000 to 
676,000 TCF of gas, at the 0.95 and 0.05 probability levels, 
respectively. Although this range of values shows a high degree of 
uncertainty, it does indicate the potential for enormous quantities of 
gas stored in gas hydrates in these accumulations. The mean in-place 
gas hydrate resource for the entire United States is estimated to be 
320,000 TCF of gas and approximately half of this resource occurs 
offshore of Alaska and most of the remainder is beneath the continental 
margins of the lower 48 states, underlying the Federal outer 
continental shelf (OCS). It is important to note that this 1995 
assessment does not address the issue of gas hydrate recoverability. 
The USGS mean estimate of 320,000 TCF (gas hydrate in-place), despite 
its uncertainty, is more than two orders of magnitude larger than 
current estimates of natural gas from conventional sources (reserves 
and technically recoverable undiscovered resources) in the U.S., which 
is approximately 1,400 TCF.
    In the fall of 2008, the USGS completed the first-ever resource 
estimate of technically recoverable gas from natural gas hydrates. That 
study found that there is 85.4 TCF (mean value) of technically 
recoverable gas in gas hydrates on the North Slope of Alaska. This 
assessment indicates the existence of technically recoverable gas 
hydrate resources--that is, resources that can be discovered, 
developed, and produced using current technology. The area assessed in 
northern Alaska extends from the National Petroleum Reserve in Alaska 
(NPRA) on the west through the Arctic National Wildlife Refuge (ANWR) 
on the east, and from the Brooks Range northward to the State-Federal 
offshore boundary (located three miles north of the coastline). This 
area consists mostly of Federal, State, and Native lands covering about 
44,310 mi2. For the first time, the USGS has assessed gas hydrates, an 
``unconventional resource,'' as a producible resource in discrete 
hydrocarbon traps and structures. The approach used to assess the gas 
hydrate resources in northern Alaska followed standard geology-based 
USGS assessment methodologies that have been developed to assess 
conventional oil and gas resources. In order to use this approach for 
gas hydrate resources, it was documented through the analysis of three-
dimensional industry-acquired seismic data, that the gas hydrates on 
the North Slope occupy limited but discrete volumes of rock bounded by 
faults and downdip water contacts. The USGS conventional assessment 
approach also assumes that the hydrocarbon resource being assessed can 
be produced by existing conventional technology. The production 
potential of the known and seismically-inferred gas hydrate 
accumulations in northern Alaska has not been adequately field tested, 
but has been the focus of multi-organizational research efforts in 
Alaska and Canada. Numerical production models of gas hydrate-bearing 
reservoirs suggest that gas can be produced from gas hydrate with 
existing conventional technology and this conclusion has been verified 
by limited field testing. Using a geology-based assessment methodology, 
the USGS estimated the total undiscovered technically recoverable 
natural gas resources in gas hydrates in northern Alaska to be between 
25.2 and 157.8 TCF (95% and 5% probabilities of greater than these 
amounts, respectively), with a mean estimate of 85.4 TCF.
    In anticipation of gas hydrate production in Federal waters, the 
U.S. Minerals Management Service (MMS) has recently launched a project 
to assess gas hydrate energy resource potential on acreage under MMS 
jurisdiction. The MMS is currently working to assess the resource 
potential of gas hydrate on the Atlantic OCS and to address the 
technical recoverability of gas hydrate in the marine environment. 
Early in 2008, MMS reported on their systematic geological and 
statistical assessment of in-place gas hydrate resources in the Gulf of 
Mexico OCS. This assessment integrated the latest findings regarding 
the geological controls on the occurrence of gas hydrate and the 
abundant geological and geophysical data from the Gulf of Mexico. The 
in-place volume of undiscovered gas estimated within the gas hydrates 
of the Gulf of Mexico was reported as a cumulative probability 
distribution, with a mean volume estimate of 21,436 TCF. In addition, 
the assessment reported that 6,710 TCF of this mean estimate are in 
relatively highly concentrated accumulations within sand reservoirs, 
with the remainder in clay-dominated sediments.
Gas Hydrate Production
    Gas recovery from hydrates is a challenge because the methane is in 
a solid form and because hydrates are usually widely dispersed in 
frontier areas such as the Arctic and deep marine environments. 
Analogous to conventional hydrocarbon production, first recovery of a 
gas hydrate resource will occur where the gas is concentrated. Proposed 
methods of gas recovery from hydrates usually deal with dissociating, 
in-situ, the gas and water from its hydrate (solid) phase by: (1) 
heating the reservoir beyond the temperature of hydrate formation, (2) 
decreasing the reservoir pressure below hydrate equilibrium, or (3) 
injecting an inhibitor, such as methanol, into the reservoir to 
decrease hydrate stability conditions. Computer models have been 
developed to evaluate hydrate gas production from hot water, steam 
injection, and depressurization. These models are based on data from 
the short term production tests in Canada and Alaska and suggest that 
gas can be produced from hydrates at sufficient rates to make gas 
hydrates a technically recoverable resource. Similarly, the use of gas 
hydrate inhibitors in the production of gas from hydrates has been 
shown to be technically feasible; however, the use of large volumes of 
chemicals comes with a high economic and potential environmental cost. 
Among the various techniques for production of natural gas from in-situ 
gas hydrates, initial evaluations suggest that the most economically 
promising method is considered to be depressurization.
    The pace of gas hydrate energy projects has accelerated over the 
past several years. Researchers have long speculated that gas hydrates 
could eventually be a commercial resource, yet technical and economic 
hurdles have historically made gas hydrate development a distant goal 
rather than a near-term possibility. This view began to change over the 
past five years with the realization that this unconventional resource 
could be developed in conjunction with conventional gas fields and with 
existing technology. Research coring and seismic programs carried out 
by the Ocean Drilling Program (ODP), Integrated Ocean Drilling Program 
(IODP), government agencies, and several consortia have significantly 
improved our understanding of how gas hydrates occur in nature and have 
verified the existence of highly concentrated gas hydrate accumulations 
at several locations. The most significant development was the 
production testing conducted at the Mallik site in Canada's Mackenzie 
Delta in 2002 and 2008. In December 2003, the partners (including the 
Geological Survey of Canada and USGS, as co-leads, and other partners 
such as the Department of Energy (DOE)) in the Mallik 2002 Gas Hydrate 
Production Research Well Program publicly released the results of the 
first modern, fully integrated field study and production test of a 
natural gas hydrate accumulation. The Mallik 2002 gas hydrate 
production testing and modeling effort has for the first time allowed 
for the rational assessment of the production response of a gas hydrate 
accumulation. Project-supported gas hydrate production simulations have 
shown that under certain geologic conditions gas can be produced from 
gas hydrates at very high rates exceeding several million cubic feet of 
gas per day.
    It is recognized that the Mallik 2002 project contributed much to 
the understanding of gas hydrates; however, it fell short of delivering 
all of the data needed to fully calibrate existing reservoir 
simulators. It was also determined that longer duration production 
tests would be required to assess more definitively the technical 
viability of long-term production from gas hydrates. The 2006-2008 
Mallik Gas Hydrate Production Research Program was conducted by the 
Japan Oil Gas and Metals National Corporation (JOGMEC), Natural 
Resources Canada (NRCan), and the Aurora College/Aurora Research 
Institute to build on the results of the Mallik 2002 project with the 
main goal of monitoring long-term production behavior of gas hydrates. 
The primary objective of the 2006-2007 winter field activities was to 
install equipment and instruments to allow for long term production gas 
hydrate testing during the winter of 2007-2008. The following winter 
(2007/2008), the team returned to the site to undertake a longer-term 
production test. The 2007/2008 field operations consisted of a six day 
pressure drawdown test, during which ``stable'' gas flow was measured. 
The 2007/2008 testing program at Mallik established a continuous gas 
flow ranging from about 70,000 to 140,000 ft3/day, which was maintained 
throughout the course of the six-day (139-hour) test as reported by 
JOGMEC, NRCan, and the Aurora College/Aurora Research Institute. The 
2006-2008 Mallik production test is a significant event in our 
understanding of gas production from hydrates, in that ``sustained'' 
gas production from hydrates was achieved with existing conventional 
technology through simple well depressurization alone.
    The potential for gas hydrates as an economically viable resource 
has been impacted by higher natural gas prices and forecasts of future 
tighter supply. However, gas hydrates have yet to be produced 
economically on a large scale. Gas hydrates have been compared to other 
unconventional resources, which were also considered to be uneconomic 
in the not too distant past, such as coalbed methane and tight gas 
sands. Once those resources were geologically understood and production 
challenges were addressed, these unconventional resources became part 
of the nation's energy mix.
Safety and Seafloor Stability
    Safety and seafloor stability are two important issues related to 
gas hydrates. Seafloor stability refers to the susceptibility of the 
seafloor to collapse and slide as the result of gas hydrate 
dissociation. The safety issue refers to petroleum drilling and 
production hazards that may occur in association with gas hydrates in 
both offshore and onshore environments.
Seafloor Stability
    Under the ocean floor, the depth to the base of the gas hydrate 
stability zone becomes shallower as water depth decreases and the base 
of the gas hydrate stability zone intersects the seafloor at about 
1,500 ft, a depth characterized by generally steep topography on the 
continental slope. It is possible that both natural and human induced 
changes can contribute to in-situ gas hydrate destabilization by 
changing the pressure or temperature regime, which may then convert 
hydrate-bearing sediments to a gassy water-rich fluid, triggering 
seafloor landslides. Evidence implicating gas hydrates in triggering 
seafloor landslides has been found along the Atlantic Ocean margin of 
the United States. The mechanisms controlling gas hydrate-induced 
seafloor landslides are not well known; however, these processes may 
release large volumes of methane, a potent greenhouse gas, to the 
Earth's oceans and atmosphere.
Safety
    Throughout the world, oil and gas drilling is moving into regions 
where safety problems related to gas hydrates may be anticipated. Oil 
and gas operators have described numerous drilling and production 
problems attributed to the presence of gas hydrates, including 
uncontrolled gas releases during drilling, collapse of wellbore 
casings, and gas leakage to the surface. In the marine environment, gas 
leakage to the surface around the outside of the wellbore casing may 
result in local seafloor subsidence and the loss of support for 
foundations of drilling platforms. These problems are generally caused 
by the dissociation of gas hydrate due to heating by either warm 
drilling fluids or from the production of warm hydrocarbons from depth 
during conventional oil and gas production. The same problems of 
destabilized gas hydrates by warming and loss of seafloor support may 
also affect subsea pipelines.
National Research Agenda for Gas Hydrate Energy Development
    In 1982, scientists onboard the Research Vessel Glomar Challenger 
retrieved a three-ft-long sample of massive gas hydrate off the coast 
of Guatemala. This sample became the impetus for the first national 
research and development program dedicated to gas hydrates by the 
United States. Over the next 10 years, the USGS, Department of Energy 
(DOE), and a number of other organizations compiled data demonstrating 
the potential for vast gas hydrates accumulations around the world. By 
the mid 1990s, it was widely accepted that gas hydrates represented an 
enormous storehouse of gas.
    Recognizing the importance of gas hydrate research and the need for 
coordinated effort, the U.S. Congress enacted Public Law 106-193, the 
Methane Hydrate Research and Development Act of 2000. The Act called 
for the Secretary of Energy to begin a methane hydrate research and 
development program in consultation with the National Science 
Foundation; the U.S. Departments of Commerce, represented by the 
National Oceanographic and Atmospheric Administration (NOAA); Defense, 
represented by Naval Research Laboratory; and Interior, represented by 
USGS and MMS. In August, 2005, the Act was reauthorized through 2010 as 
Sec. 968 of the Energy Policy Act of 2005 (Public Law 109-58), and the 
Bureau of Land Management (BLM) was added to the interagency effort.
    It is important to highlight that for two decades prior to this Act 
the bureaus of the Department of the Interior studied gas hydrates 
within their various missions using base research funds. This base 
funded research continues, but in partnership with a variety of 
organizations. The USGS is investigating many aspects of gas hydrates 
to understand their geological origin, their natural occurrence, the 
factors that affect their stability, the environmental impact and the 
possibility of using this vast resource in the world energy mix. The 
USGS is investigating the resource potential of gas hydrates around the 
world in partnership with many organizations: (1) in the Mackenzie 
Delta of Canada in partnership with an international consortium; (2) on 
the North Slope of Alaska in partnership with DOE and BP Exploration 
(Alaska); (3) the DOE/ConocoPhillips gas hydrate production by 
CO2 sequestration project, (4) in the U.S. Gulf of Mexico 
Joint Industry Partnership (JIP) with Chevron, DOE, and others; (5) the 
DOE/North Slope Borough, Alaska project; (6) in India in partnership 
with the Indian Directorate General of Hydrocarbons; and (7) Ocean 
Drilling Program (ODP) Leg 204 and Integrated Ocean Drilling Program 
(IODP) Expedition 311. Other countries and groups have expressed 
interest in cooperative activities including Japan, China, South Korea, 
Taiwan, and others.
    A major emphasis of USGS research focuses on the North Slope of 
Alaska, where USGS is participating in several gas hydrate energy 
research projects with DOE, BLM and various industry partners. The USGS 
is analyzing the recoverability and potential production 
characteristics of onshore natural gas hydrate accumulations overlying 
the Prudhoe Bay, Kuparuk River, and Milne Point oil fields. With the 
success of the 2008 technically recoverable Alaska gas hydrate 
assessment, the USGS and BLM have expanded their cooperative gas 
hydrate research efforts in northern Alaska to further characterize the 
potential environmental and economic impact of gas hydrate exploration 
and development.
    Another major emphasis of USGS research is the U.S. Gulf of Mexico. 
Several Gulf of Mexico hydrate research programs are underway and the 
most comprehensive study is a Joint Industry Project (JIP) led by DOE 
in partnership with Chevron which is designed to further characterize 
gas hydrates in the Gulf of Mexico. Participants include 
ConocoPhillips, Total, Schlumberger, Halliburton Energy Services, MMS, 
Japan Oil Gas and Metals National Corporation, and India's Reliance 
Industries.
    On May 6, 2009, the JIP, including DOE, USGS, and MMS research 
scientists, completed the first-ever drilling project with the 
expressed goal to collect geologic data on gas-hydrate-bearing sand 
reservoirs in the Gulf of Mexico. This was an important goal because 
other resource assessment studies in northern Alaska by the USGS and 
offshore Japan, have shown that gas hydrates in conventional sand 
reservoirs are likely the closest to potential commercialization. In 
2005, the Gulf of Mexico Gas Hydrate JIP Leg I conducted drilling, 
coring, and downhole logging operations designed primarily to assess 
gas hydrate-related hazards associated with drilling through the clay-
dominated sediments that typify the shallow sub-seafloor in the 
deepwater Gulf of Mexico. Upon analysis of Leg I results, the JIP 
membership decided to expand its effort to assess issues related to the 
occurrence of gas hydrate within coarser-grained sediments. The 2009 
drilling project, named the Gulf of Mexico Gas Hydrate Joint Industry 
Project Leg II (GOM JIP Leg II), featured the collection of a 
comprehensive set of logging-while-drilling (LWD) data through expected 
gas-hydrate-bearing sand reservoirs in seven wells at three locations 
in the Gulf of Mexico. The semi-submersible drilling vessel Helix Q4000 
was mobilized at sea in the Gulf Mexico and drilling was conducted in 
the Walker Ridge, Green Canyon and the Alaminos Canyon blocks. The LWD 
sensors just above the drill bit provided important new information on 
the nature of the sediments and the occurrence of gas hydrate. The full 
research-level LWD data set on formation lithology, electrical 
resistivity, acoustic velocity, and sediment porosity enabled the 
greatly improved evaluation of gas hydrate in both sand and fracture 
dominated reservoirs.
    The two holes drilled at Walker Ridge yielded evidence of a 
laterally continuous thick fracture-filling gas hydrate section, but 
more importantly both wells also encountered sand reservoirs, between 
40- to 50-ft-thick, nearly saturated with gas hydrate. Gas-hydrate-
bearing sands were also drilled in two of the Green Canyon wells, with 
one occurrence slightly more than 100-ft-thick. Initial interpretation 
of the Alaminos Canyon drilling results is that the sands appear to 
exhibit uniformly low gas hydrate saturation over a large area. 
Nevertheless, the discovery of thick hydrate-bearing sands at Walker 
Ridge and Green Canyon validates the integrated geological and 
geophysical approach used in the pre-drill site selection process in 
order to predict hydrate accumulations before drilling, and provides 
increased confidence in assessment of gas hydrate volumes in the Gulf 
of Mexico and other marine sedimentary basins. The presence of 
significant gas hydrate accumulations as both pore-filling sands and 
fracture-filling material in shallow muds, make both Walker Ridge and 
Green Canyon likely locations for future research into energy targets 
of gas hydrates in marine environments. While the primary goal of this 
JIP is to better understand the safety issues related to gas hydrates, 
the results of the program will also allow a better assessment of the 
commercial potential of marine gas hydrates.
    Seismic-acoustic imaging to identify gas hydrate and its effects on 
sediment stability has been an important part of USGS marine and 
onshore studies since 1990. USGS work in this area has allowed for 
prediction of the occurrence as well as the thickness and saturation of 
gas hydrates ahead of drilling. USGS has also conducted extensive 
geochemical surveys and established a specialized laboratory facility 
to study the formation and dissociation of gas hydrate in nature and 
also under simulated deep-sea conditions.
    The USGS, as well as many groups, participate in the IODP, the ODP, 
and their predecessor the Deep Sea Drilling Project (DSDP)--which have 
contributed greatly to our understanding of the geologic controls on 
the formation, occurrence, and stability of gas hydrates in marine 
environments. The gas hydrate research efforts under IODP-ODP-DSDP have 
been mostly directed to assess the role of gas hydrate in climate 
change. In the summer of 2002, ODP Leg 204 investigated the formation 
and occurrence of gas hydrates in marine sediments at Hydrate Ridge off 
the Oregon coast. The shipboard scientists successfully deployed new 
core systems for recovering and analyzing gas-hydrate-bearing sediments 
at in situ pressure conditions; thus allowing the correlation of 
sediment properties with seismic, conventional wireline and logging-
while-drilling downhole data. IODP Expedition 311 with a USGS co-chief 
scientist, established a transect of four research drill sites across 
the northern Cascadia margin off the west coast of Canada. In addition 
to the transect sites, a fifth site was established at a cold vent with 
active fluid and gas flow. The most significant findings of the coring 
and logging programs during IODP Expedition 311 included the 
observation that gas hydrate is formed mainly within the sand-rich 
reservoir-quality formations and is virtually absent in the fine-
grained and clay-rich sediments. Thus, the presence of gas hydrate is 
mainly controlled by lithology much like conventional hydrocarbon 
resources.
    BP Exploration (Alaska), DOE, and the USGS have undertaken a 
project to characterize, quantify, and determine the commercial 
viability of gas hydrates and associated free gas resources in the 
Prudhoe Bay, Kuparuk River, and Milne Point field areas in northern 
Alaska. Under Phase 1 of this project, gas hydrates and associated free 
gas-bearing reservoirs in the Milne Point oil field have been studied 
to determine reservoir extent, stratigraphy, structure, continuity, 
quality, variability, and geophysical and petrophysical property of 
these hydrocarbon-bearing reservoirs. The objective of Phase 1 is to 
characterize reservoirs and fluids, leading to estimates of the 
recoverable gas reserve and commercial potential, and the definition of 
procedures for gas hydrate drilling, data acquisition, completion, and 
production. Phases 2 and 3 will integrate well, core, log, and 
production test data from additional test wells. Ultimately, the 
program could lead to development of a gas hydrate pilot project with a 
long term production test, and determine whether gas hydrates can 
become a part of the Alaska North Slope gas resource portfolio. In 
2005, extensive analysis of 3-D seismic data and integration of that 
data with existing well log data by the USGS identified more than a 
dozen discrete and mappable gas hydrate prospects within the Milne 
Point area. Because the most favorable of those targets was a 
previously undrilled, fault-bounded accumulation, BP Exploration 
(Alaska) and DOE decided to drill a vertical stratigraphic test well at 
that location (named the ``Mount Elbert'' prospect) to acquire critical 
reservoir data needed to develop a longer term production testing 
program. The Mount Elbert gas hydrate stratigraphic test well acquired 
sediment cores, well logs, and downhole production test data. Gas 
hydrates were expected and found in two stratigraphic zones--an upper 
zone containing about 45 ft of gas hydrate-bearing reservoir-quality 
sandstone, and a lower zone containing about 50 ft of gas hydrate-
bearing reservoir. Both zones displayed gas hydrate saturations that 
varied with reservoir quality, with typical values between 60% and 75%. 
This result conclusively demonstrated the soundness of the gas hydrate 
prospecting methods developed primarily at the USGS. The Mount Elbert 
gas hydrate stratigraphic test well project also included the 
acquisition of pressure transient data from four short-duration 
pressure-drawdown tests. Each test consisted of a period of fluid 
withdrawal (thereby reducing formation pressure) followed by a period 
where the pump is shutoff and the subsequent pressure build-up is 
monitored. The Mount Elbert press tests confirmed again that gas could 
be produced from hydrates by simple depressurization and the presence 
of a mobile pore-water phase even in the most highly gas hydrate-
saturated intervals lends itself to higher expected gas hydrate 
production rates. This project yielded one of the most comprehensive 
datasets yet compiled on naturally-occurring gas hydrates.
International Gas Hydrate Research and Development Efforts
    Many countries are interested in the energy resource potential of 
gas hydrates. Countries including Japan, India, China, South Korea, and 
Canada have established large gas hydrate R&D programs, while Norway, 
Mexico, Columbia, Chile, and others are investigating the viability of 
forming government-sponsored gas hydrate research programs. It is also 
not surprising that the most aggressive and well funded gas hydrate 
research programs are in countries highly dependent on imported energy 
resources, such as Japan and India.
    In 1995, the Government of Japan established the first large-scale 
national gas hydrate research program, which now plays a leading role 
in worldwide gas hydrate research efforts. The first five years of the 
Japan National Gas Hydrate Program culminated in 1999/2000, with the 
drilling of a series of closely spaced core and geophysical logging 
holes in the Nankai Trough. In 2001, the Ministry of Economy, Trade and 
Industry (METI) launched a more extensive project entitled ``Japan's 
Methane Hydrate Exploitation Program,'' operated by the Methane Hydrate 
2001 Consortium, to evaluate the resource potential of deepwater gas 
hydrates in the Nankai Trough area. This project is intended to promote 
the technical development and recovery of gas hydrates, and to provide 
a long-term stable energy supply, with plans for field production 
testing as soon as 2011 and development of the technologies needed for 
commercial production by 2016.
    The government of India also is funding a large national gas 
hydrate program to meet its growing energy requirements. One of the 
primary goals of the Indian National Gas Hydrate Program (NGHP) is to 
conduct scientific ocean drilling/coring, logging, and analytical 
activities to assess the geologic occurrence, regional context, and 
characteristics of gas hydrate deposits along the continental margins 
of India in order to meet the long term goal of exploiting gas hydrates 
as a potential energy resource in a cost effective and safe manner. In 
2006, the Directorate General of Hydrocarbons (India) and the USGS 
conducted research drilling off the Indian Peninsula and along the 
Andaman convergent margin, with special emphasis on gaining an 
understanding of the geologic and geochemical controls on the 
accumulation of gas hydrate in these two diverse settings. NGHP 
Expedition 01 was among the world's most complex and comprehensive 
methane hydrates field ventures yet conducted. NGHP Expedition 01 
established the presence of gas hydrates in the Krishna-Godavari, 
Mahanadi, and Andaman sedimentary basins. The expedition discovered one 
of the richest gas hydrate accumulations yet documented in the Krishna-
Godavari Basin, recorded the thickest and deepest gas hydrate stability 
zone yet known in the Andaman Sea, and established the existence of a 
fully-developed gas hydrate system in the Mahanadi Basin. It is 
anticipated that future NGHP efforts will likely include drilling, 
coring, and field production testing.
Production Potential of Gas Hydrates--Technical Challenges
    In order to release, or produce, the gas from a gas hydrate, we 
must change the temperature or pressure conditions controlling its 
occurrence and stability. The most economically promising method of 
producing gas from gas hydrates appears to be depressurization of the 
reservoir. Results from the Mallik and Mount Elbert test wells support 
this supposition. However, it is important to note that much more 
information is needed before production of this unconventional resource 
in these frontier regions becomes economic. For example, gas production 
is dependent upon the permeability of the host rock, and therefore, the 
type of sediment in which the hydrate occurs and understanding flow 
rates and paths is critical to potential production.
    Onshore Alaska and the offshore Gulf of Mexico are proven 
exploration targets for gas hydrates. In the Gulf of Mexico, industry 
has begun assessing hydrate potential on their oil and gas leases. New 
and existing industry-Government partnerships are expected to drill 
hydrate prospects on the North Slope of Alaska in the near future--
hence, the first domestic production of hydrates is expected to occur 
in Alaska, where gas from the hydrates will either support local oil 
and gas field operations, or be available for commercial sale if and 
when a gas pipeline is constructed. In both Alaska and the Gulf of 
Mexico, critical drilling and transportation infrastructure exists, 
which will allow gas hydrate prospects to be drilled and produced from 
existing installations.
    The timing for expected commercial production of hydrates is 
uncertain. The DOE has estimated that gas production from gas hydrate 
could begin no earlier than 2015. In September of 2003, the National 
Petroleum Council (NPC) reported that we will not likely see 
significant production from gas hydrates until sometime beyond 2025. 
Initial production from gas hydrates could occur much sooner, 
especially in areas such as the North Slope of Alaska or in other 
countries. Estimates vary on when gas hydrate production will play a 
significant role in the total world energy mix. It is not currently 
possible to determine whether hydrates will be able to contribute to 
the domestic energy supply. The future contribution of this resource 
will depend not only on further progress in gas hydrate production, but 
also on research into the environmental impacts of gas hydrate 
production, which are not fully understood.
Next Steps to Gas Hydrate Production
    The immense volume of gas hydrates worldwide may be a significant 
potential energy resource at some point in the future. Our 
understanding of these resources, however, is still evolving--we do not 
yet know if these accumulations exist in sufficient concentration to 
make them economically viable, nor do we know whether even concentrated 
accumulations can be developed economically. Additional science-driven 
production tests will contribute to our understanding of gas hydrate 
production. It is generally believed that gas hydrates can be produced 
by standard techniques used today to exploit conventional oil and gas 
resources. However, it is very likely that new drilling and production 
technology would contribute to the ultimate producibility of gas 
hydrates. We know that hydrates must be produced by releasing the gas 
from the hydrate form by the methods previously described. However, 
there has only been one industry scale hydrate production test to date 
(the 2008 Mallik project). Much more information is needed on: (1) the 
geology of the hydrate-bearing formations, both on a large scale (the 
distribution of hydrates throughout the world) and on a small scale 
(their occurrence and distribution in various host sediments); (2) the 
reservoir properties/characteristics of gas hydrate reservoirs; (3) the 
production response of various gas hydrate accumulations; and (4) the 
economics controlling the ultimate resource potential of gas hydrates. 
The USGS will continue to play a vital role in studying, evaluating, 
and understanding the geologic and engineering properties critical to 
the realization of hydrates as a viable energy source. The USGS will 
also continue to work with other Federal agencies and within domestic 
and international consortiums to conduct needed gas hydrate production 
test studies.
Conclusions
    Our knowledge of naturally occurring gas hydrates is growing and it 
can be concluded that: (1) a huge volume of natural gas is estimated to 
be stored in gas hydrates; (2) production of natural gas from gas 
hydrates is technically feasible with existing technology; (3) gas 
hydrates hold the potential for natural hazards associated with 
seafloor stability and release of methane to the oceans and atmosphere; 
and (4) gas hydrates disturbed during drilling and petroleum production 
pose a potential safety problem. USGS research on gas hydrates is 
focused on: (1) the energy-resource potential they represent; (2) the 
hazards they might pose to drilling and the environment; and (3) the 
impact they might have on global climate change. Thus, the USGS 
welcomes the opportunity to collaborate with domestic and international 
scientific organizations and industry to further collective 
understanding of these important geologic materials.
    Thank you, Mr. Chairman for the opportunity to present this 
information. I will be happy to respond to any questions you may have.
                                 ______
                                 

     Response to questions submitted for the record by Dr. Collett

Questions from Chairman Jim Costa from the State of California
1.  Dr. Collett, what have we learned from the Ocean Drilling Program 
        expeditions on the Atlantic and Pacific coasts? Do there appear 
        to be promising gas hydrate resources in those areas? Also, is 
        there any time-frame for getting a better assessment of hydrate 
        resources on the Atlantic and Pacific coasts?
    In response to the first part of your question regarding the 
contribution of the Ocean Drilling Program (ODP) expeditions on the 
Atlantic and Pacific coasts, I am proud to note that I had the great 
opportunity to directly participate in both the ODP expedition Leg 164 
on the Atlantic margin and ODP expedition Leg 204 on the Pacific 
margin. These expeditions and other research have provided seismic 
profiles along the Atlantic margin of the United States, typically 
marked by large-amplitude seismic reflectors named ``bottom-simulating-
reflectors--or BSRs. BSRs are believed to be caused in this region by 
large acoustic impedance contrasts at the base of the gas hydrate 
stability zone that mark the contact between sediments containing gas 
hydrates with sediments containing free-gas rather than hydrates. BSRs 
have been extensively mapped at two locations off the east coast of the 
United States--offshore South Carolina along the crest of the Blake 
Ridge and beneath the upper continental rise of New Jersey and 
Delaware. The most extensively studied gas hydrate deposit on the 
Atlantic coast of the United States is on the Blake Ridge. ODP Leg 164 
was designed to investigate the occurrence of gas hydrate in the 
sedimentary section beneath the Blake Ridge. The presence of gas 
hydrates on the Blake Ridge was documented by direct drilling and 
sampling and analysis of recovered sediment cores and downhole logging 
data. Although a significant portion of the Blake Ridge appears to be 
underlain by gas hydrates, the concentration appears to be low. 
Further, the host sediments are mostly clay, which raises a concern 
over the production technology required to produce gas from widely 
disseminated gas hydrate accumulations in clay-rich sediments. Much 
less is known about the potential gas hydrate occurrences of the 
northeastern Atlantic margin of the United States.
    ODP Leg 204 to Hydrate Ridge, located on the Pacific continental 
margin offshore Oregon, was the first deep-sea drilling expedition 
dedicated to providing an understanding of gas hydrate processes in 
accretionary complexes. Gas hydrate presence was confirmed at most of 
the sites drilled during ODP Leg 204. The amount of gas hydrate 
present, when averaged over the entire gas hydrate stability zone, is 
generally estimated to be low (about 2 percent of the sediment pore 
space). However, gas hydrate concentrations increase to approximately 
20-30 percent near several methane vents that were drilled during the 
expedition. Geochemical data indicate that most of the gas forming the 
hydrate deposits associated with vents has migrated from a greater 
depth and has either a thermogenic or altered biogenic origin. The 
regionally pervasive gas hydrate occurrences, at relatively low 
concentrations, on both Hydrate Ridge and the Blake Ridge appear to 
have formed from gas produced locally through microbial alteration of 
in-situ organic matter.
    The gas hydrate accumulations discovered during ODP Legs 164 and 
204 occur at low concentrations and are disseminated in fine-grained, 
clay-dominated sediments or at high concentrations associated with 
natural fluid and gas vent sites on the seafloor. On the other hand, 
gas hydrates occurring at high concentrations are associated with 
conventional type sand reservoirs, as discovered recently in the Gulf 
of Mexico, and are believed to represent the most promising targets for 
future gas hydrate production.
    The assessment of hydrate resources on the Atlantic and Pacific 
coasts was first dealt with by the USGS in the 1995 National Assessment 
of United States Oil and Gas Resources, which focused on assessing the 
undiscovered conventional and unconventional resources of crude oil and 
natural gas in the United States. This assessment included, for the 
first time, a systematic appraisal of the in-place natural gas hydrate 
resources of the U.S. onshore and offshore regions. In 1995, the USGS 
estimated that the amount of gas within the gas hydrates of the United 
States may be as much as 317,832 trillion cubic feet. More recently, 
the U.S. Minerals Management Service (MMS) conducted a systematic 
geological and statistical assessment of in-place gas hydrate resources 
in the Gulf of Mexico which was reported in the spring of 2008 (http://
www.mms.gov/revaldiv/GasHydrateAssessment.htm). It is our understanding 
that MMS is moving ahead with the assessment of gas hydrate resources 
for the entire OCS of the United States. We would suggest contacting 
MMS for more information on their assessment of marine gas hydrate 
resources on the Atlantic and Pacific margins of the United Sates.
2.  Dr. Collett, the permafrost contains a great deal of methane, which 
        is a concern when it comes to climate change because as the 
        Arctic warms as the permafrost thaws, that methane gets 
        released into the atmosphere where it makes warming even worse. 
        Does production of methane from hydrates help remove this 
        methane from the permafrost before it gets released to the 
        atmosphere?
    Atmospheric methane, a greenhouse gas, is increasing at a rate such 
that the current concentration will probably double in the next 50 
years. Because methane is 21 times more radiatively active than carbon 
dioxide, it is predicted that methane will surpass carbon dioxide as 
the predominant atmospheric greenhouse gas in the second half of the 
next century. The source of this atmospheric methane is uncertain; 
however, numerous researchers have suggested that destabilized natural 
gas hydrates may be contributing to the build-up of atmospheric 
methane. Recent studies have shown that most of the known gas hydrate 
deposits occur deep within the Earth both within and below thick 
sections of permafrost or under oceanic sediments. It appears that most 
of these gas hydrate accumulations are insulated from any rapid climate 
changes and are unlikely to be significantly affected by atmospheric 
temperature changes. However, the relationship between gas hydrate 
dissociation and the release of potential greenhouse gases is poorly 
understood and is the topic of ongoing research within the USGS. It 
should be noted, however, that it is unlikely that the intentional 
production of gas (methane) from hydrates that are deeply buried 
beneath permafrost or the world's oceans would have either a positive 
or negative feedback on the release of methane to the atmosphere. 
First, the gas hydrates most susceptible to climate change, those 
occurring near the surface, are not being targeted for production. 
Second, the total volume of gas that will likely be produced from gas 
hydrates under any reasonable scenario will only be a small percentage 
of the total volume of gas contained in hydrates. In the second case, 
the unintentional release of gas from a producing hydrate deposit has 
been predicted to be on a scale similar to that experienced with 
production from conventional gas deposits. Thus, the production of gas 
hydrates is not expected to either add to or subtract from the volume 
of methane being released to the atmosphere by either natural or human-
induced processes.
3.  Dr. Collett, what do we know about the risk of slope instability on 
        the Atlantic continental margins, and the potential threat of 
        submarine landslides and tsunamis because of that?
    Gas hydrates as well as free-gas and salt tectonics have been 
implicated as triggers for major seafloor landslides along the Atlantic 
Ocean margin of the United States. However, the mechanisms controlling 
gas hydrate-induced seafloor landslides are not well known. Under the 
ocean floor, the depth to the base of the gas hydrate stability zone 
becomes shallower as water depth decreases, and the base of the gas 
hydrate stability zone intersects the seafloor at about 1,500 feet, a 
depth characterized by generally steep topography on the continental 
slope. It is possible that both natural and human-induced changes can 
contribute to in-situ gas hydrate destabilization by changing the 
pressure or temperature regime, which may then convert hydrate-bearing 
sediments to a gassy water-rich fluid, triggering seafloor landslides. 
Using our new understanding of the geology of the Atlantic margin and a 
deeper appreciation of the geologic and engineering controls on natural 
slides, the first landslide-induced tsunami models are being developed.
4.  Congress passed royalty relief for gas hydrate production in the 
        Energy Policy Act of 2005. Dr. Collett, have the rules for this 
        royalty relief been issued? And do you believe it is realistic 
        that production will occur prior to the 2018 deadline that is 
        in that legislation?
    The USGS did not participate in the rule making process for the 
gas-hydrate-related royalty relief considerations in the Energy Policy 
Act (EPA) of 2005. The U.S. Minerals Management Service (MMS) took the 
lead on the rule making process as included in EPA. MMS determined a 
rule was not appropriate at this time.
    On March 8, 2006, MMS and the Bureau of Land Management (BLM) 
published in the Federal Register a joint Advance Notice of Proposed 
Rulemaking. In August 2006, the Secretary completed the required review 
of further opportunities to enhance production of gas hydrate resources 
on the OCS and on Federal lands in Alaska through the provision of 
other production incentives or through technical or financial 
assistance and delivered the Report to Congress. The report was 
prepared by the Department of the Interior, MMS, and is based on 
information within the Federal interagency hydrate working groups 
(which represent Department of the Interior bureaus--MMS, BLM, and 
USGS--and the National Energy Technology Laboratory of the Department 
of Energy). The report also reflected the public comments received on 
the March 8, 2006, Advance Notice of Proposed Rulemaking.
    In summary, the conclusion of the report was that, given the 
current lack of information about gas hydrate production potential, the 
ongoing research in progress, and the absence of industry exploration 
activity, royalty relief would not encourage production of natural gas 
from gas hydrates at that time, and the report did not recommend 
specific government production incentives for gas hydrates. The report 
stated that production incentives, like royalty relief, would be 
better-suited for encouraging prospect-specific exploration and 
development of gas hydrate resources if needed once commercial 
recoverability is established. Additionally, the report recommended 
that Federal incentives--through technical and financial assistance for 
research and development programs, database development, education and 
training, and assistance and collaboration in field testing of 
production methods--would be the most effective way to help accelerate 
the process of commercial production of gas hydrate resources.
    MMS can provide further information about royalty relief for gas 
hydrate production, and we recommend you contact them if you have 
further questions.
    In response to the second part of your question that deals with gas 
hydrate production prior to the 2018 legislation deadline, it is likely 
there could be limited gas hydrate production from a few areas in the 
Arctic and possibly the Gulf of Mexico within this timeframe. Thus, 
with this relatively short deadline, it is unlikely that many companies 
will be able to take advantage of this proposed gas hydrate royalty 
relief.
5.  Dr. Collett, what kind of other stimuli could we enact to spur the 
        production of methane hydrates?
    Reauthorization of the Methane Hydrate Research and Development Act 
of 2000 is one option to stimulate the development of gas hydrates as 
an energy resource. Recognizing the importance of gas hydrate research 
and the need for coordinated effort, the U.S. Congress enacted Public 
Law 106-193, the Methane Hydrate Research and Development Act of 2000. 
The Act called for the Secretary of Energy to begin a methane hydrate 
research and development program in consultation with the National 
Science Foundation; the U.S. Departments of Commerce, represented by 
the National Oceanographic and Atmospheric Administration (NOAA), 
Defense, represented by Naval Research Laboratory, and Interior, 
represented by USGS and MMS. In August 2005, the Act was reauthorized 
through 2010 as Sec. 968 of the Energy Policy Act of 2005 (Public Law 
109-58), and the BLM was added to the interagency effort. Work 
conducted under the Methane Hydrate Research and Development Act has 
had very significant and long lasting impact on our understanding of 
the energy resource potential of gas hydrates. Under this legislation, 
through a number of highly successful field drilling and testing 
programs in northern Alaska and the Gulf of Mexico, the USGS has 
determined that a huge volume of natural gas is stored with the world's 
gas hydrate accumulations and that the production of natural gas from 
gas hydrates is technically feasible with existing technology. However, 
the USGS has also learned that gas hydrates represent a natural hazard 
associated with seafloor stability and the release of methane to the 
oceans and atmosphere. The work carried out by the Department of Energy 
and other agencies named above under the Methane Hydrate Research and 
Development Act, coupled with and supported by the research with 
funding by other agencies such as the USGS, has allowed significant 
breakthroughs in our understanding of gas hydrates, especially as it 
relates to becoming a viable part of our domestic energy mix. 
Information on work being carried out under the Methane Hydrate 
Research and Development Act can be found at http://www.netl.doe.gov/
technologies/oil-gas/FutureSupply/MethaneHydrates/maincontent.htm. 
Information on work being carried out at the USGS on gas hydrates can 
be found at http://energy.usgs.gov/other/gashydrates/.
6.  Dr. Collett, what is the administration's position on 
        reauthorization of the Methane Hydrate Research and Development 
        Act, which expires next year?
    At this time, the Administration does not have a position on 
reauthorization.
                                 ______
                                 
    Mr. Costa. Thank you very much, and you obviously stayed 
within the timeframe and for that you get extra bonus points.
    Dr. Collett. I appreciate it.
    Mr. Costa. Our next witness is Dr. Ray Boswell who is the 
Senior Management and Technology Advisor for the National 
Energy Technology Laboratory for the United States Department 
of Energy, and Dr. Boswell, we look forward to hearing your 
comments.

STATEMENT OF DR. RAY BOSWELL, SENIOR MANAGEMENT AND TECHNOLOGY 
ADVISOR, NATIONAL ENERGY TECHNOLOGY LABORATORY, U.S. DEPARTMENT 
                           OF ENERGY

    Dr. Boswell. Thank you, Mr. Chairman, and thank you members 
of the Subcommittee. I appreciate this opportunity to discuss 
the Department of Energy's research on naturally occurring gas 
hydrates.
    Since 2000, DOE, through the Office of Fossil Energy's 
National Energy Technology Laboratory--that is where I work--
has led the national research program in gas hydrates. The 
program is conducted through partnerships with private 
industry, institutions, and universities, and supported using 
the unique capabilities of DOE's national laboratories and the 
expertise of collaborating scientists from six other Federal 
agencies.
    DOE also has active ongoing collaborations with many of the 
world's leading gas hydrate research efforts, including the 
national programs of Japan, Korea, Canada and India.
    The program is driven by the relatively recent recognition 
that gas hydrates represent a significant global storehouse of 
methane, a fact with far-reaching implications for our 
understanding of the environment as well as for the nation's 
and the world's future energy supplies. In the past few years 
researchers have documented that gas hydrates occur in a wide 
variety of accumulations.
    Not all gas hydrates are equal, and we have determined that 
those that form within sandy sediments are the most promising 
initial resource targets. Sand rich sediments appear critical 
to enabling both the concentration of gas hydrate to high 
levels as well as enabling the potential production of the 
enclosed methane through application of largely existing well 
drilling and completion technologies.
    This refined focus on hydrate-bearing sands has resulted in 
a series of encouraging research findings in both Arctic and 
marine settings. Notably, DOE-sponsored field programs in 
Alaska in 2007 and in the Gulf of Mexico earlier this year 
demonstrated the occurrence and the ability to remotely detect 
and assess, prior to drilling, resource quality gas hydrate 
accumulations through the application of the same integrated 
geological-geophysical approaches that guide traditional 
hydrocarbon exploration.
    So we now have a much clearer picture of the promise of gas 
hydrates. The emerging estimates of potentially recoverable 
resources, such as Dr. Collett was just mentioning, while lower 
than those incredibly large in-place volumes that had 
previously framed gas hydrate resource potential, are far more 
relevant and meaningful that grounded in data from the field 
now, and they continue to indicate significant potential 
resources of domestic natural gas from hydrates.
    DOE and our research partners are positioned to conduct the 
next stage of gas hydrate research and development, including 
extended field testing of alternative production methods and 
comprehensive drilling and sampling programs for resource 
evaluation and validation of our exploration models. In 
addition, DOE understands that acceptance of gas hydrates as a 
new energy supply option will require a demonstration of an 
advance understanding of the role gas hydrates play in the 
natural environment.
    To that end, we are supporting a range of studies to 
document gas hydrates response to environmental changes and the 
interaction of gas hydrate associated methane with global 
carbon cycling and global climate.
    Despite all the progress of recent years, there is still 
much to learn about the details of gas hydrate occurrence and 
behavior in nature. The potential is very large, the 
uncertainties remain very large. The department looks forward 
to meeting this challenge and to providing the knowledge and 
technology that may provide a valuable additional domestic 
option for meeting future energy demands.
    Mr. Chairman, members of the Subcommittee, I would be happy 
to take any questions you may have. Thank you.
    [The prepared statement of Dr. Boswell follows:]

 Statement of Dr. Ray Boswell, National Energy Technology Laboratory, 
                       U.S. Department of Energy

    Thank you, Mr. Chairman and Members of the Subcommittee. I 
appreciate this opportunity to provide testimony on the status of the 
United States Department of Energy's (DOE's) research efforts in 
naturally-occurring gas hydrates.
INTRODUCTION
    Since 2000, DOE, through the Office of Fossil Energy's National 
Energy Technology Laboratory (NETL), has led the national research 
program in gas hydrates. The program is conducted through partnerships 
with private institutions and universities, and supported using the 
unique capabilities of DOE's National Laboratories.
    Program planning and implementation is also greatly aided by the 
expertise of scientists from the Department of the Interior's U.S. 
Geological Survey (USGS), Minerals Management Service (MMS) and Bureau 
of Land Management (BLM), the U.S. Naval Research Laboratory (NRL), the 
National Science Foundation (NSF), and the Department of Commerce's 
National Oceanic and Atmospheric Administration (NOAA).
    Scientific program oversight is conducted through regular external 
merit reviews, which include a Federal Advisory Committee comprising 
leaders from industry and academia, and periodic reviews by the 
National Research Council. DOE also has active, ongoing collaborations 
with many of the world's leading gas hydrate programs in Japan, Korea, 
Canada, and India.
    The program is driven by the recognition that gas hydrates 
represent a significant global storehouse of methane--a fact with far-
reaching implications for the environment and for the Nation's (and the 
world's) future energy supplies. DOE is now conducting and supporting a 
comprehensive suite of field and modeling studies of gas hydrates' link 
to climate and carbon cycling, greatly elucidating the role gas 
hydrates may play during changing climates.
    Regarding gas hydrates as an energy source, notable recent 
successes within the program's primary field efforts have confirmed 
significant accumulations of the most promising gas hydrate resource 
targets. We have and continue to prepare for the next stage of gas 
hydrate research and development (R&D) that will include extended 
testing of alternative production methods, as well as comprehensive 
resource confirmation and sample collection. While much work remains to 
be done, results, to date, are consistently encouraging, and the 
program remains on pace to accomplish its resource and environmental 
goals.
BACKGROUND
    Through the past 50 years, the Nation's available supply of natural 
gas has steadily expanded to meet growing demands. Key to this 
expansion is periodic advances in knowledge and technology that enable 
new and increasingly remote and challenging resources to be 
commercially developed.
    Over the past half-century, technology has provided the ability to 
safely and efficiently extract natural gas from previously unobtainable 
resources, including ultra-deep formations, and those 
``unconventional'' formations that do not readily release natural gas, 
including tight gas formations, coal-bed methane, and shale gas 
reservoirs. Federally-funded R&D has been a critical part in enabling 
many of these successes to benefit the Nation. The next resource 
element poised to be added to this list is gas hydrates, which may be 
considered a frontier resource.
    Gas hydrates form wherever appropriately-sized molecules of gas 
(most commonly, methane) and water occur together under specific 
conditions of low temperature and high pressure. These conditions exist 
on land in areas of permafrost, and within the shallow sediments of 
continental margins where water depth exceeds roughly 500 meters.
    Until the early 1970s, gas hydrates were not confirmed to exist in 
the natural environment; however, by the late 1990s, a general 
consensus had emerged that gas hydrates occurred in vast quantities, 
perhaps housing more organic carbon than all of the world's coal, oil, 
and natural gas deposits combined. The total resource estimates are 
astronomical: the most commonly-cited estimate for the global abundance 
of methane stored in gas hydrate form is 700,000 trillion cubic feet. 
However, these volumes are poorly constrained.
    Recent estimates continue to range over nearly two orders of 
magnitude, pointing out the immensity of the problem in assessing gas 
hydrate resources, and the limited data available on the occurrence and 
fundamental controls on gas hydrates in nature. The implications of the 
vast scale of gas hydrates in nature, for our understanding of carbon 
cycling and climate change, are critically important and are the 
subject of extensive ongoing studies. However, the primary driver for 
the rapidly accelerating international investment in gas hydrates 
research is the emerging potential of gas hydrates as an energy 
resource.
A RECENT PARADIGM SHIFT
    A key development in gas hydrates research in recent years is the 
realization, based on the findings of a series of recent scientific 
drilling programs around the world, that all gas hydrates accumulations 
are not created equal. Gas hydrates accumulations range from large, 
diffuse accumulations in clay sediments, to smaller, discrete, high-
concentration accumulations in sand reservoirs. Gas hydrates occur both 
on the sea-floor as solid massive mounds, as well as buried several 
thousands of feet below the sea-floor. When considering gas hydrate 
potential as an energy supply, we now recognize that those deeply-
buried deposits housed within coarse-grained (sand) sediments are the 
most favorable. It is significant as well that these are the deposits 
that are most highly-buffered from environmental change.
    What makes sand reservoirs attractive is their permeability--a 
measure of the ease with which fluids can move through the sediment. On 
the one hand, this permeability appears to be critical in enabling gas 
hydrates to accumulate to very high concentrations, typically 60 
percent to 90 percent of the pore space. In addition, reservoir 
permeability may be the key to enabling methane production from gas 
hydrate reservoirs using, to a large extent, existing drilling and 
completion technologies. Numerical simulations conducted in both the 
United States and Japan have shown that conventional wellbores 
penetrating sand reservoirs can be used effectively to: 1) impart 
changes in reservoir conditions that dissociate the gas hydrates in 
place; and 2) then gather the released methane at rates that make 
commercial production a possibility. As a result, substantial resources 
may be available using largely existing drilling and production 
technologies. More exotic or potentially intrusive approaches, such as 
deep sea mining or dredging, are not under consideration.
    This refined focus is now enabling more targeted technological 
development, and more sophisticated and relevant assessments of gas 
hydrate resources. Recently, the USGS, building on several decades of 
their own efforts, and integrated with DOE-sponsored field data 
collection and numerical simulation studies, reported a mean estimate 
of 85 trillion cubic feet (tcf) of technically-recoverable gas 
resources in hydrate-bearing sands underlying the Alaska North Slope 
(ANS). In the marine environment, MMS also reported last year that of 
more than 20,000 tcf of gas in-place in gas hydrate deposits in the 
Gulf of Mexico, more than 6,700 tcf is contained at high concentrations 
in sand reservoirs. These estimates, while less than the volumes that 
had previously framed gas hydrate potential, are far more meaningful, 
and indicate that significant potential resources of domestic natural 
gas from hydrates occurs within areas of existing oil and gas 
production infrastructure. Assessments of resources in other regions of 
the United States, including Atlantic and Pacific offshore areas, is 
also underway within the Department of the Interior, but supporting 
data are notably absent at this time.
STATUS OF THE EFFORT: RECENT ADVANCES AND REMAINING CHALLENGES
    DOE's stated goals in gas hydrates research are to provide the 
knowledge and technology to enable environmentally-sound and 
commercially-viable production of gas from gas hydrates by 2015 (for 
arctic resources) and 2020 (for resources in the Gulf of Mexico). We 
remain firmly on track to accomplish these goals. Prior research within 
the program has established a strong foundation of fundamental science 
and experimental modeling capabilities. Completing this will require a 
continuation of these efforts, as well as a strong commitment to 
conducting extensive field operations in both arctic and deep-water 
marine settings.
    Key to fulfilling the promise of gas hydrates as a resource is the 
ability to confirm resource volumes, and effectively explore for the 
most favorable deposits. In Alaska, efforts by the USGS, in 
collaboration with the cooperative research program between DOE and BP 
Exploration Alaska (BPXA), resulted in the recognition of more than a 
dozen discrete and potentially drillable accumulations within a small 
area of the greater Prudhoe Bay region, using existing geophysical and 
geologic data. A logging, coring, and testing program, conducted at the 
BPXA-DOE-USGS ``Mount Elbert'' test well in February of 2007, validated 
these predictions, provided insight into the planning for future 
production testing, confirmed the ability to safely conduct scientific 
data acquisition within an operating oil field with minimal impact to 
operations, and increased the confidence in the broader assessment of 
gas hydrate resources throughout the ANS.
    More recently, a concerted effort within the interagency technical 
coordination team, enabled by the DOE-sponsored gas hydrates Joint 
Industry Project (JIP), resulted in the development of a series of gas 
hydrate-bearing sand prospects in the deepwater Gulf of Mexico. A 
three-week drilling program conducted by the JIP in the spring of 2009 
similarly validated this prospect development, finding highly-
concentrated gas hydrates in reservoir-quality sands, as predicted, in 
4 of 7 wells drilled. Future work in the Gulf of Mexico includes 
dedicated coring programs, utilizing specialized devices in development 
by the JIP, to collect samples of these reservoirs for further detailed 
studies.
    The potential to safely and efficiently produce gas from hydrate 
reservoirs is also clarifying. For example, results from an independent 
2002 test, led by Japan and Canada, determined that the 
depressurization method (withdrawal of fluids from the well-bore and 
the formation, reducing pressures below the stability point of gas 
hydrates) was likely the most effective means to produce gas from gas-
hydrate bearing sands. This finding is in agreement with analyses 
conducted using data obtained at the ``Mount Elbert'' test well in 
2007. Further depressurization tests at Mallik in 2008 and 2009 
confirmed relatively high volume, sustainable flow rates over a six-day 
testing period.
    These tests, combined with findings from laboratory studies, have 
enabled increasingly sophisticated numerical simulations to be 
conducted, which indicate that commercially viable production rates are 
possible in certain settings. However, it remains a challenge to 
predict the long-term behavior of any reservoir, particularly a non-
conventional one, based on short-duration tests. Longer-term (up to a 
year or more) production tests are needed to understand the true 
deliverability of gas hydrate reservoirs. At present, the only 
locations where such tests can be feasibly conducted are the known gas 
hydrate accumulations within the Prudhoe Bay region on the ANS. DOE is 
currently coordinating with ANS operators on the complex problem of 
developing such a test within an area of established production.
    An additional promising opportunity that has recently emerged is 
the potential to inject CO2 into gas hydrate reservoirs, 
leading to the release of the methane and the sequestration of the 
CO2 within hydrate form. DOE has recently established a 
research agreement with ConocoPhillips to conduct a field trial of this 
concept on the ANS, building on prior and encouraging laboratory and 
modeling findings by a ConocoPhillips-University of Bergen (Norway) 
research team. If successful, this project could provide a sound option 
for the disposition of CO2 that comprises a portion of 
existing conventional gas resources on the ANS.
    Ultimate acceptance of gas hydrates as a new energy supply option 
will also require demonstration of a full understanding of the role gas 
hydrates play in the natural environment. To that end, DOE is 
supporting a range of studies to document the processes that impact the 
stability of gas hydrates, their response to environmental changes, the 
flow of methane in sediments, and the ability of released methane to 
traverse the sea-floor and the water column. In addition, we recognize 
the need to monitor methane movement and geomechanical changes in 
reservoirs during field tests.
SUMMARY
    Research results over the past decade, including drilling and 
coring programs, experimental studies, and numerical simulations are 
clarifying the resource potential of gas hydrates. In particular, 
application of the concepts that guide the assessment and exploration 
of traditional hydrocarbon resources are now enabling researchers to 
focus on the most promising gas hydrate occurrences--those reservoired 
in sandstone formations--yielding a series of encouraging research 
findings in both arctic and marine settings.
    The DOE-led program in gas hydrates R&D is working to integrate and 
leverage efforts throughout the United States and internationally to 
enable gas hydrates to become a viable option for meeting future energy 
demands. The approach is to integrate three distinct lines of research.
      First, utilize the known gas hydrate accumulations on the 
ANS as a natural laboratory to study issues related to gas hydrate 
production. Based on the success of the 2007 ``Mount Elbert'' field 
program, DOE and its industry partners in Alaska are now poised to 
conduct a range of scientific production tests using different 
approaches.
      Second, conduct additional drilling and data collection 
expeditions in the Gulf of Mexico to confirm resource occurrence, 
refine exploration technologies, and identify sites for future 
production testing. That testing will build on the most promising 
approaches identified in the arctic testing program. With the 
successful completion of the spring 2009 JIP drilling and logging 
expedition, this effort is fully on track.
      Third, demonstrate an understanding of gas hydrate's role 
in nature and the potential environmental implications of gas hydrate 
production. To that end, DOE is supporting a broad range of studies to 
determine the links between gas hydrates, the oceans and the 
atmosphere, and is committed to ensuring full monitoring of all field 
testing programs
    Despite all the progress of the past several years, there is still 
much to learn about the details of gas hydrate occurrence and behavior 
in nature. The research being conducted is wide-ranging, complex, and 
multi-disciplinary. The current effort is designed to simultaneously 
advance fundamental scientific understanding of gas hydrates, 
characterize marine resources, and explore gas hydrate production 
potential through Arctic field tests.
    The Department looks forward to the challenge of completing these 
strategic activities that, in concert, support a potential global 
paradigm shift in energy supply.
    Mr. Chairman, Members of the Subcommittee, I would be happy to take 
any questions you may have.
                                 ______
                                 

     Response to questions submitted for the record by Dr. Boswell

QUESTIONS FROM CHAIRMAN COSTA
1.  Dr. Boswell, how much money is the United States spending on 
        methane hydrate research, and is that enough to meet the DOE 
        goals of production from arctic hydrates in 2015 and marine 
        hydrates in 2020?
    Answer 1. Six Federal agencies receive funding for methane hydrate 
research: U.S. Geological Survey (USGS), National Oceanic and 
Atmospheric Administration, Naval Research Lab, Bureau of Land 
Management, National Science Foundation, and Minerals Management 
Service. The Department of Energy (DOE) was appropriated $9 million in 
FY 2006, $12 million in FY 2007, $15 million in FY 2008, and $15 
million in FY 2009 for methane hydrates research. An additional $1 
million was appropriated in FY 2006 and FY 2008 to the University of 
Mississippi Hydrate Research Consortium (MHRC), a Congressionally 
Directed Project. In FY 2009, the MHRC received $1.1 million. The 
Arctic Energy Office, another Congressionally Directed Project, 
committed a portion of its funds to methane hydrate R&D: $1.85 million 
in FY 2006, $2.9 in FY 2008 and $1.7 million in FY 2009.
    The DOE program goals, with respect to natural gas production from 
gas hydrates, are to provide the science and technology such that 
production is commercially feasible by 2015 for Alaska North Slope 
resources and by 2020 for Gulf of Mexico resources. These goals were 
developed in collaboration with our Federal research partners in the 
context of program authorizations provided by the Methane Hydrate 
Research and Development Act of 2000. The President's request of $25 
million in FY 2010 is enough for DOE to work over the next fiscal year 
toward providing knowledge and technology to enable commercial 
production of natural gas from hydrates starting in FY 2015 (Alaska) 
and 2020 (Gulf of Mexico).
2.  Dr. Boswell, what is the difference between the long-term 
        production tests that you described us still needing to do and 
        the sorts of tests that have already been conducted in the 
        Arctic and the Gulf? How close are we to doing these production 
        tests?
    Answer 2. The critical difference between the few tests that have 
been conducted thus far and what is needed is time. Given the nature of 
gas hydrates reservoirs and the lack of any established production 
history, we believe a series of tests of extended duration (many months 
to two years) will be required before we can develop a good 
understanding of potential gas production rates and, therefore, 
potential commerciality. We intend to conduct such tests first in the 
Arctic, and then apply the knowledge gained to more challenging marine 
production tests. This information will add greatly to what has been 
determined from the three field testing programs (all conducted onshore 
in the Arctic; two funded primarily by the governments of Japan and 
Canada; the third funded by the U.S. DOE in partnership with BP), which 
have been conducted to date.
    There have been no production tests conducted or attempted in the 
marine setting. The three tests that have been conducted have all 
occurred onshore and have been of very short duration--the longest 
(conducted by the governments of Japan and Canada in the Northwest 
Territories in 2007 and 2008) spanned a total of six days. These tests 
provided critical scientific information on the response of gas hydrate 
reservoirs to various phenomena, and have enabled us to identify 
pressure reduction as the most favorable technique. However, they fall 
well short of the conventional definition of a ``production test,'' 
which are generally conducted over sufficient time-frames to enable 
estimation of potential gas deliverability over the multi-year lifespan 
of producing wells. DOE plans to initiate its production testing 
program in FY 2010.
3.  Dr. Boswell, are we at the point that we can reliably tell from 
        seismic data whether or not methane hydrates are present at a 
        given location?
    Answer 3. Our recent efforts in Alaska and the Gulf of Mexico show 
that we can greatly improve our ability to detect and assess gas 
hydrate prospects of resource-relevant thickness and concentrations, 
given access to industry-standard seismic and other datasets. This is 
perhaps the most critical recent finding in gas hydrates research. In 
2006, an effort lead by the USGS delineated potential reservoirs from 
seismic data in Alaska. These predictions were confirmed by the 
subsequent 2007 test well drilled by DOE and BP. In 2008, similar 
predictions were developed for three sites in the Gulf of Mexico. These 
predictions were then tested by seven wells drilled in the spring of 
2009--gas hydrate was expected in high concentrations in sands at five 
of those locations and at moderate concentrations in two of the 
locations: in six of the seven wells drilled, initial analysis of log 
data confirmed the pre-drill predictions.
4.  Dr. Boswell, most of the recent work seems to have been done with 
        depressurization. Where do things stand with other 
        technologies, such as thermal injection?
    Answer 4. The 2002 test conducted by Japan, Canada, the United 
States, and other nations at the Mallik site in northwest Canada, 
combined with subsequent work in the lab and in numerical simulators, 
has clearly indicated to us that thermal stimulation alone is not 
effective as the primary means of gas hydrate production. Subsequent 
short-term tests in Alaska (in 2007) and in Canada (in 2007 and 2008) 
and associated favorable numerical simulation results indicate that 
depressurization is the most promising method. However, as optimal 
long-term well production and operational strategies are developed, 
thermal injection and other methods will likely play a key role, 
depending on local conditions. For example, our latest simulations show 
that periodic thermal stimulation will be necessary to maintain optimal 
wellbore conditions during depressurization-based production. 
Therefore, planning for the initial long-term scientific production 
test in Alaska includes the application (as required by test results) 
of thermal injection, hydraulic fracturing, and other methods.
5.  Dr. Boswell, is there any potential for mining the methane hydrate 
        mounds that appear on the bottom of the sea?
    Answer 5. Gas hydrate is known to occur as solid masses, some as 
large as 10's of feet across, within the shallow deepwater sediment. 
Portions of these mounds are exposed on the seafloor. Such occurrences 
likely represent only a small percentage of the projected global gas 
hydrate resource, with individual mounds likely containing very limited 
resources. In addition, these sea-floor gas hydrate mounds represent 
unique and poorly-understood ecosystems. Any potential benefit to be 
gained from trying to capture these outcroppings as a resource, through 
mining or dredging, is small compared to the environmental concerns. As 
such, mining techniques, or any approaches to extraction of seafloor 
mounds, are not being considered under the current program.
6.  Dr. Boswell, one of the witnesses that was supposed to be at the 
        hearing, from ConocoPhillips, was going to discuss technology 
        where they use carbon dioxide to displace methane from the 
        hydrate, which would leave the carbon dioxide behind. Could you 
        provide some detail about that technology, and what its 
        advantages might be if it works as advertised?
    Answer 6. The carbon dioxide displacement technology, which has 
thus far only been studied in a laboratory setting, involves the simple 
injection of CO2 into a gas hydrate reservoir via a 
conventional wellbore. Previous lab studies have shown that exposing 
methane hydrate to CO2 results in the spontaneous exchange 
of the methane and CO2 molecules. More recently, experiments 
conducted by ConocoPhillips and the University of Bergen (Norway) 
showed that, in sand reservoirs, this exchange can happen efficiently 
and without substantial destruction of the hydrate structure. The 
initial attempt to test this technology at a field scale is planned to 
occur as soon as FY 2010, as part of a collaborative project between 
DOE and ConocoPhillips.
    As compared to depressurization-based technologies for gas hydrate 
production, the potential advantages of the carbon dioxide displacement 
technology are: 1) the ability to sequester CO2 while 
producing methane (a key element for Alaska, in particular, as existing 
stranded gas resources in the Prudhoe Bay region include 12% 
CO2 that will need to be appropriately handled as part of 
future production); 2) a substantial reduction in associated water 
production, improving well economics, and simplifying well completions; 
3) maintenance of reservoir strength, with reduced risk for sand 
production and production-related reservoir and ground subsidence; and 
4) potential applicability across a wider range of initial pressure and 
temperature conditions. Among the remaining hurdles are: 1) unknown 
ability to inject CO2 at a field scale; 2) potential low 
rates of methane production; and 3) various issues related to potential 
sources of CO2.
7.  Dr. Boswell, what kind of other stimuli could we enact to spur the 
        production of methane hydrates?
    Answer 7. The most important means to spur the production of 
methane hydrates is to continue to conduct the needed research and 
development to demonstrate production potential. The primary barrier to 
conducting this research at the required pace is the cost of the needed 
arctic and deepwater field programs. Going forward, as the program 
begins to conduct these long-term tests, achieving sufficient industry 
cost-share for these projects will also be an issue, as industry may 
still prefer to limit direct investment in projects that they deem 
long-term and high-risk. As a result, some incentives for participation 
in basic research programs may be warranted.
                                 ______
                                 
    Mr. Costa. Thank you, and you too did very well in terms of 
staying within the five minutes. We will use both of you as 
examples, good examples.
    Our next witness, last but certainly not least, is a 
gentleman who has firsthand experience, I believe. Mr. Steve 
Hancock is a Well Engineering Manager at RPS Energy. I am 
looking forward to your testimony and then the question period 
on how this is really extracted, because we have a general 
concept of how we get oil and how we get gas, and how we get 
it--whether it is onshore or offshore--to where it is refined, 
but I am still trying to figure out how these hydrates work in 
that same fashion.
    So, Mr. Hancock, you have your five minutes. Please 
proceed.

                  STATEMENT OF STEVE HANCOCK, 
             WELLS ENGINEERING MANAGER, RPS ENERGY

    Mr. Hancock. Thank you, Mr. Chairman, and members of the 
Subcommittee, and thank you for the opportunity to appear today 
to discuss the production and economics of gas hydrate 
development.
    Gas hydrate wells will be more complex than most other gas 
wells due to a number of requirements, including maintaining 
commercial gas flow rates with high water production, operating 
at low pressures and low temperatures, controlling sand 
production into the well bore, and ensuring well structural 
integrity with reservoir subsidence.
    Technologies exist to address all of these issues, but this 
will add significantly to both capital and operating costs for 
gas hydrates. Gas hydrates also have one distinct challenge 
compared to the other unconventional resources, and that is the 
high cost of transportation to market.
    Onshore gas hydrates in North America are located on the 
north slope of Alaska and in the Mackenzie Delta in Canada. 
These resources, along with significant volumes of already 
discovered conventional gas, are stranded without a pipeline to 
market. In order to compete for pipeline capacity when a 
pipeline is eventually available, the economics of onshore gas 
hydrate developments must be attractive at the prevailing gas 
prices. This fact may delay major onshore gas hydrate 
development. However, unique circumstances may allow production 
of gas hydrates for local community or industrial use.
    Gas hydrates have also been discovered in the deepwater 
areas of the Gulf of Mexico and along deep coastal margins 
throughout the world. Deepwater drilling technology and 
experience continues to evolve and the worldwide deepwater 
fleet continues to expand. However, the deepwater environment 
is still a very high cost and very high risk area of operation. 
Offshore gas hydrate developments must have strong economic 
drivers in order to compete with other deepwater exploration 
and development opportunities.
    A number of studies have been conducted to determine the 
economics of gas hydrate developments. Numerical simulation 
models calibrated to actual gas hydrate tests were used to 
develop production forecasts for a variety of reservoir 
conditions. Commercial field development planning software was 
used to determine the capital and operating costs for both 
onshore and offshore locations. The results of these 
investigations, while preliminary, have been very encouraging.
    For onshore gas hydrates, stand-alone development could be 
economic with a gas price in the upper range of historical 
North American gas prices, and for deepwater developments 
stand-alone gas hydrate fields could be economic with a gas 
price in the upper range as what has been paid for liquified 
natural gas on the spot market.
    Improved understanding of gas hydrate reservoir 
performance, new technologies to improve production rates and 
recoveries, and opportunities to reduce costs will improve gas 
hydrate economics further. However, we do not know everything 
about gas hydrate production. The small-scale production 
experiments conducted at both Mallik and the Milne Point 
projects provided valuable insight. The recent five-day 
production test conducted at Mallik demonstrated that gas 
hydrates can be produced with current technology. However to 
prove gas hydrates as a viable source of natural gas a 
production test at commercial rates will be required. The long-
term production test planned for the north slope of Alaska is 
an important step in achieving this goal.
    Thank you, Mr. Chairman, and I will also be happy to answer 
any questions you may have.
    [The prepared statement of Mr. Hancock follows:]

   Statement of Steven H. Hancock, P.ENG., Well Engineering Manager, 
                           RPS Energy Canada

    Mr. Chairman and Members of the Subcommittee, thank-you for the 
opportunity to appear before you today to discuss the production and 
economics of gas hydrate development.
INTRODUCTION
    Unconventional oil and gas resources such as heavy oil, coal bed 
methane, and shale gas, required development of new technologies such 
as horizontal and multi-lateral drilling before they could be 
economically produced. Based on our current understanding of gas 
hydrate properties and reservoir performance, we theoretically have the 
technology to drill, complete, and produce gas hydrate wells at 
relatively high gas rates. So the question has been asked--when will 
gas hydrates be economic to produce?
    There are no simple answers as to the commerciality of any 
particular gas hydrate accumulation. The economics of any hydrocarbon 
development can be highly variable due to uncertainties in geology, 
drilling and facility costs, reservoir properties, markets and 
commodity prices. Each development must stand on its own merit and 
unique set of circumstances. We can however examine a number of 
hypothetical developments to gauge the relative economics of gas 
hydrates compared to conventional gas. For gas hydrate developments, 
additional uncertainty must be assumed at this time because there has 
not been a well test at commercial gas production rates. All gas 
hydrate production forecasts are based on theoretical numerical 
simulation models calibrated to small scale controlled experiments 
conducted at the Mallik (Canada) and Milne Point (Alaska) test wells.
PRODUCTION STRATEGIES
    Gas hydrates can be dissociated into natural gas and water by three 
main methods [1]:
      Depressurization, in which the pressure is reduced below 
the gas hydrate stability point at the prevailing reservoir 
temperature;
      Thermal stimulation, in which the temperature is raised 
above the hydrate stability point at the prevailing reservoir pressure; 
and
      Injection of inhibitors such as methanol which changes 
the gas hydrate stability conditions.
    Production strategies can use one or a combination of these 
methods. Depressurization is thought to be the most technically 
efficient means of production from natural gas hydrate deposits [10], 
and is the basis for the economic studies reported in this statement.
    Most research programs have targeted coarse-grained sand deposits 
as the most promising reservoirs for the production of gas hydrates. 
Natural gas hydrate accumulations within these types of reservoirs can 
exist in a number of ways, including [2, 3]:
      A gas hydrate layer in contact with a free gas layer--
this situation has the obvious advantage that the free conventional gas 
can produced initially, with contribution from the gas hydrate layer 
starting as reservoir pressure declines below the stability point. The 
free gas is theoretically in contact with a large surface area of gas 
hydrate, which should increase gas hydrate response.
      A gas hydrate layer in contact with a free water layer--
dissociation can be initiated by producing the free water layer and 
dropping reservoir pressure below the stability point. As above, the 
free water is theoretically in contact with a large surface area of gas 
hydrate, which should increase gas hydrate response.
      A gas hydrate layer only, with no free water or gas 
contacts--dissociation can be initiated in the wellbore contact area 
only.
    The onshore gas hydrate developments evaluated in this study 
compared two gas hydrate reservoirs with single free gas and free water 
contacts. The offshore gas hydrate study considered a gas hydrate only 
reservoir
TECHNICAL CHALLENGES
    Gas hydrate wells will be more complex than most conventional and 
unconventional gas wells due a number of technical challenges, 
including:
      Maintaining commercial gas flows with high water 
production rates;
      Operating with low temperatures and low pressures in the 
wellbore;
      Controlling formation sand production into the wellbore; 
and
      Ensuring well structural integrity with reservoir 
subsidence.
    Technologies exist to address all of these issues, but will add to 
development costs. Gas hydrate development also has one distinct 
challenge compared to other unconventional resources, and that is the 
high cost of transportation to market.
    Most gas fields require some compression to maximize reserve 
recovery, but this typically occurs later in the life of the field 
after production starts to fall below the plateau rate. For a gas 
hydrate development, the required pressure to cause dissociation will 
require the use of inlet compression throughout the life of the field 
including the plateau production time. This will require a larger 
capital investment for compression at the front end of the project, and 
will also result in higher operating costs over the life of the 
project.
    Water production is not uncommon in gas wells, however water rates 
are typically less than say 10 bbls/MMscf (barrels of water per million 
standard cubic feet of gas) for water of condensation and/or free water 
production. Wells that produce excessive amounts of water are typically 
worked-over to eliminate water production or shut-in as non-economic. 
The water production from a gas hydrate reservoir could be highly 
variable, however water:gas ratios in excess of 1,000 bbls/MMscf are 
possible. This water must be removed from the reservoir and wellbore to 
continue the dissociation process. On this basis, a gas hydrate 
development will require artificial lift such as electric submersible 
pumps or gas lift, which will also increase capital and operating costs 
over the life of the field. But it is important to highlight that the 
water in gas hydrate contains no salts or impurities, it is fresh water 
and may be a valuable coproduced product of a gas hydrate development.
    The combination of low operating pressures and high water rates 
will require larger tubing and flowlines for a gas hydrate development, 
in order to minimize friction losses and maximize production. 
Additional water handling facilities and water disposal will also be 
required. Larger inhibitor volume (such as glycol) will be required to 
prevent freezing and hydrate formation in tubing and flowlines. Other 
items such as sand control, reservoir subsidence, downhole chemical 
injection, possible requirements for near wellbore thermal stimulation, 
etc., will also require additional capital and operating costs for gas 
hydrate developments compared to conventional gas developments.
ONSHORE GAS HYDRATE ECONOMICS
    Onshore gas hydrates in North America are located on the North 
Slope of Alaska and on the Mackenzie Delta in Canada. These resources, 
along with significant volumes of already discovered conventional gas, 
are stranded without a pipeline to market. In order to compete for 
pipeline capacity, the economics of onshore gas hydrate developments 
must be attractive at prevailing gas prices. This may have an impact on 
the timing of major onshore gas hydrate development, however, unique 
circumstances may allow production for local community or industrial 
use. For example, an oil lease on the North Slope in short supply of 
gas for heating and power generation could make use of gas hydrate 
production--the produced gas could be used for fuel, and the produced 
water could be used for waterflood operations to improve oil recovery.
    The preliminary economics of two different hypothetical onshore gas 
hydrate developments are presented in this statement:
      The first case was based on a reservoir in which gas 
hydrate is underlain by free-gas. The gas hydrate layer in this case 
had an initial gas in place volume of 1.07 TCF (trillion cubic feet). 
The free gas layer added an initial gas in place volume of 0.23 TCF, 
for a total gas volume of 1.30 TCF.
      The second case was based on a reservoir in which gas 
hydrate is underlain by water. As above, the gas hydrate layer in this 
case had an initial gas in place volume of 1.07 TCF (with no free gas 
component).
    Gas and water production rates were predicted using the commercial 
reservoir simulator CMG-STARS (Computer Modeling Group's Steam, Thermal 
and Advanced Processes Reservoir Simulator).
    The field development plan consisted of 5 production wells and 2 
water disposal wells. Production was initiated via depressurization in 
both cases. The capital and operating costs for the various field 
development plans considered in this evaluation were generated using 
IHS Energy's Que$torTM planning software and costing 
database, plus information from a variety of sources.
    Full discussion of these evaluations cannot be presented here. 
Additional information on reservoir properties, simulation results, 
capital and operating costs, and detailed economic discussions are 
presented in [4]. Key results from these investigations are summarized 
in the following discussion. Note that all prices in this document 
refer to 2009 United States dollars.
    Figure 1 presents the predicted gas production rates for the two 
cases.
    The first case starts out at a plateau or peak rate of 125 MMscf/d 
(million standard cubic feet per day), and declines thereafter. Note 
that conventional gas field developments are normally designed around a 
plateau or peak production rate lasting say two to five years. This is 
typically the most economic way to develop and produce a gas field 
considering capital costs and operating life. The high initial 
production rate is largely due to the free gas below the hydrate layer. 
After approximately five years, the total field production rate 
declines as the free gas is exhausted, and the gas production is due 
largely to gas hydrate dissociation.
    The second case starts out at a low gas production rate, and builds 
slowly to a peak rate at approximately year five and declines slowly 
thereafter. In this type of reservoir setting, the free water must be 
produced to initiate gas hydrate dissociation, which itself produces 
significant water volumes. These water volumes must be produced prior 
to the start of significant gas production, which results in a slow 
build-up to peak gas production.
    Typical project economic evaluations are based on risked net 
present value economics. In this procedure, annual capital and 
operating costs, along with revenues from gas production, are 
discounted annually from a starting point. Annual discount rates (or 
internally rates of return) typically range from 10% to 20% to account 
for cost of capital and risk. Compared to events which occur early in 
the life of the project, activities in future years are more heavily 
discounted and thus have less of an impact on the overall project 
economics.
    A gas hydrate only development will characteristically have peak 
gas production rates occur later in the life of the field, as well as a 
lower peak production rate and a longer field operating life, compared 
to a typical conventional gas field. Thus gas hydrate only developments 
will be somewhat penalized for the expected production characteristics 
when using net present value economics.
    Figure 2 illustrates the sensitivity of internal rate of return to 
gas price for the two cases considered. This evaluation includes 
revenues, capital and operating costs, typical frontier royalties, but 
with no incentives or taxes. In addition, a pipeline tariff to the 
southern U.S. markets of $2.50/mscf (thousand standard cubic feet) has 
been assumed.
    The first case is reasonably robust as the gas price increases over 
$ U.S. 6.00/mscf. This is due primarily to the production of free gas 
early in the project. The rate of return for the second case is 
somewhat insensitive to increasing gas price, as the discounting on the 
delayed peak gas production reduces the impact of increasing price. To 
achieve a rate of return of 15%, the first case would require a gas 
price of approximately $ 6.50/mscf, and the second case would require a 
gas price of approximately $12.00/mscf.
    Complexities and geologic heterogeneities encountered in any 
natural settings may either reduce or improve the well performance, 
which could significantly change project economics. However these 
preliminary analyses do indicate that the gas price required for a 
reasonable rate of return for an onshore gas hydrate development is 
only slightly beyond the peak historical gas prices that have been 
observed in North America. It is also obvious from these analyses that 
comparable conventional gas resources will always be more attractive in 
net present value terms than gas hydrates.
OFFSHORE GAS HYDRATE ECONOMICS
    Gas hydrates have also been discovered in the deepwater areas of 
the Gulf of Mexico and along most of the deep coastal margins 
throughout the world. Deepwater drilling technology and experience 
continues to evolve, and the worldwide deepwater fleet continues to 
expand. However the deepwater environment is still a very high cost and 
very high risk area of operation. Offshore gas hydrate developments 
must have strong economic drivers in order to compete with other 
deepwater exploration and development opportunities.
    By all estimates, the majority of gas hydrates considered for 
production are located in sandstone reservoirs in deepwater 
environments. In order to understand the economics of deepwater gas 
hydrates, stand alone field development plan were prepared for a gas 
hydrate accumulation not in contact with gas or water-bearing 
reservoirs. The gas hydrate production rates were based on a study 
conducted in [4] for a deepwater Gulf of Mexico reservoir condition, 
which used the TOUGH+HYDRATE (Transport of Unsaturated Groundwater and 
Heat) numerical simulation model. Capital and operating costs were 
again developed using IHS Energy's Que$torTM development 
planning tool and costing database program. For comparison purposes, a 
similar sized deepwater conventional gas field was developed using the 
same tools in order to determine comparative economics.
    The field development plans for both fields assumed a subsea 
development in 5000 feet of water. A new purpose built floating 
production facility plus a 75 mile pipeline are added to standard costs 
such as compression, dehydration, and separation. Extra costs 
associated with hydrate gas production, such as artificial lift, 
reduced platform pressure, and flow assurance are also considered, in 
addition to sand control. It was assumed that there would be sufficient 
wells in place to maintain a plateau production rate of 500 MMscf/day, 
and recover 2.0 TCF of produced gas over a 20 year life. Additional 
wells were added for both development types to account for structural 
and drainage issues typically encountered in large areal discoveries.
    Figure 3 illustrate the typical gas production profile for the gas 
hydrate wells studies in [5]. This result follows the previous 
discussion regarding delayed onset of peak production followed by a 
decline as the gas hydrate is exhausted. Also as discussed, significant 
production of water is required to continue the gas dissociation 
process. Figure 4 illustrates the predicted water to gas ratio for the 
simulated well. For the first several years, the predicted water 
volumes are significantly higher than the well could naturally flow 
with, therefore artificial lift would be required to initiate and 
assist production through most of the life of the field.
    Based on the predicted gas production profile, 48 wells would be 
required for the deepwater gas hydrate development. For the 
conventional gas case, it was assumed that 18 wells would be required, 
but it is noted that this will count could be significantly reduced in 
prolific offshore gas fields. Figure 5 presents the total gas 
production forecast for both cases.
    Full discussion of these evaluations cannot be presented here. 
Additional information on reservoir properties, simulation results, 
capital and operating costs, and detailed economic discussions are 
presented in [6]. Key results from these investigations are summarized 
in the following discussion. Note that all prices in this document 
refer to 2009 United States dollars.
    For the comparative analysis, risked cost and production profiles 
were developed in order to account for greater uncertainty in a gas 
hydrate development compared to a conventional gas development. Figure 
6 illustrates a pre-tax, pre-royalty plot of rate of return versus gas 
price for the expected results for both the conventional gas and gas 
hydrate developments.
    Given the risks associated with conventional deepwater hydrocarbon 
developments, the gas hydrate developments probability adds another 
level of risk which cannot be quantified at this level of 
investigation. The capital and operating costs developed for this 
evaluation considered the unique differences between conventional gas 
and gas hydrate developments and allowed significant contingency to 
account for these unknowns. While the absolute costs at this level of 
study have a wide range of uncertainty, the comparative analysis is 
considered a reasonable indication of the differences between the two 
types of developments: i.e. while the gas price required to make a gas 
hydrate discovery economic will be higher than that for conventional 
gas discovery, the difference in price is measured in terms of dollars, 
not orders of magnitude. This also again illustrates that on a 
comparable basis, a conventional gas development will be more 
attractive than a gas hydrate development in net present values terms.
CONCLUSIONS
    The results of these investigations, while preliminary, have been 
very encouraging:
      For onshore gas hydrates, stand-alone developments could 
be economic with a gas price in the upper range of historical North 
American prices, and
      For deepwater gas hydrates, stand-alone developments 
could be economic with a gas price in the upper range of what India has 
paid for liquefied natural gas imports on the spot market.
    As with all hydrocarbon developments, the economics of gas hydrates 
will be highly variable, depending upon such factors as well 
performance, sediment type, gas-in-place, thermodynamic conditions of a 
reservoir, and the access to existing infrastructure. It is also clear 
that comparable conventional gas reservoirs will generally be 
economically more attractive than gas hydrate only reservoirs, 
suggesting that the production of gas hydrates on a large commercial 
scale may be delayed.
    Unique circumstances may allow production of onshore has hydrates 
for local community or industrial use, especially where there is some 
underlying gas. Offshore gas hydrate developments may proceed sooner on 
the basis that the premium price required may not be onerous when there 
is no conventional gas competition, and where security of supply may be 
a major consideration.
    Significant scientific and exploration work must be completed 
before gas hydrates can be considered as a viable source of natural 
gas. Critical among these tasks remains the validation reservoir and 
well performance through extended field testing that demonstrates the 
ability to produce gas hydrates at commercial rates with current 
technology. The small scale production experiments conducted at Mallik 
and Milne Point provided valuable insight into gas hydrate reservoir 
performance. The short term production test recently conducted at 
Mallik also demonstrated that gas hydrates can be produced with current 
technology. The long term production test planned for the North Slope 
of Alaska is an important step in achieving this goal.
    Thank you Mr. Chairman, for this opportunity to provide an overview 
of the production and economics of gas hydrate developments. I would be 
happy to answer any questions you may have.
REFERENCES
    \1\ Moridis, G.J., Kowalsky, M.B., and Pruess, K. Depressurization-
induced Gas Production from Class 1 Hydrate Deposits. SPE 97266, 2005
    \2\ Moridis, G.J. and Sloan, E.D., Gas Production of disperse low-
saturation hydrate accumulations in oceanic sediments. Energy 
Conversion and Management. 2007; 48; 1834-1849
    \3\ Moridis, G.J., and Collett, T.S., Strategies for Gas Production 
from Hydrate Accumulations Under Various Geologic Conditions, Report 
LBNL-52568; Lawrence Berkeley National Laboratory, Berkeley, CA 2004
    \4\ Hancock S., Okazawa, T., and Osadetz, K. A Preliminary 
Investigation of the Economics of Onshore Gas Hydrate Production, 
Presented at the 7th annual conference on unconventional gas, Calgary, 
Alberta, Nov. 2005
    \5\ Moridis G.J., and Reagan, Matthew. Strategies for Production 
from Oceanic Class 3 Hydrate Accumulations. OTC 18865, 2007
    \6\ Hancocks S, Development of Gas Hydrates, New Zealand Petroleum 
Conference, Auckland, New Zealand, March 2008
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  Response to questions submitted for the record by Steven H. Hancock

Questions from Chairman Jim Costa from the State of California
1.  Mr. Hancock, what has the industry s financial role been in methane 
        hydrate research efforts? How much money are they putting in 
        now, and at what point would they be able to take over this 
        research entirely?
    Answer: I do not have access to any financial data representatives 
from the USGS and USDOE will be in a better position to address this 
part of the question.
    Most of the large independents and all of the major oil companies 
conduct research and experimentation on drilling, completions and 
production technology--once a potential resource becomes a strategic 
part of their reserves portfolio. The development of heavy oil is a 
classic example of this, and gas hydrates should follow as similar 
pattern. As with heavy oil, federally and/or state funded research will 
be required to prove up the resource potential of gas hydrates. 
Obviously certain companies such as BP, Chevron, and Conoco-Phillips 
among others have already identified gas hydrates as possibly being 
strategically important and have dedicated some resources for research, 
but the major investigations are still lead by agencies such as the 
USDOE and USGS. Industry is unlikely to take a lead role until 
commerciality is proven.
2.  Mr. Hancock, how do methane hydrates compare with other 
        unconventional fuels? How would you rank methane hydrates 
        versus things like oil shale, tar sands, etc., in terms of 
        timing and resource potential?
    Answer: The unconventional oil and gas hydrocarbons currently being 
developed in North America have one distinct advantage compared to gas 
hydrates that being location. Development of shale oil and gas, tar 
sands, coal bed methane etc. can proceed when the required technology 
and capital/operating costs are attractive with current market prices.
    Unconventional gas projects can generally proceed quite quickly 
because capital and operating costs are relatively low. Some of the 
major unconventional gas plays are also close to market, which results 
in significantly reduced transportation tariffs compared to frontier or 
offshore gas. This makes it easier for unconventional gas such as tight 
gas, shale gas, or coal bed methane gas to compete in the North 
American gas market, even at the low prevailing prices of the current 
market.
    Gas hydrates are located onshore under permafrost in the U.S. and 
Canadian Arctic regions, and in the deepwater margins around the North 
American continent there are currently no unconventional developments, 
oil or gas, in these frontier areas. These areas also contain 
significant amounts of developed and undeveloped conventional gas 
resources, much of which is stranded without a way to get to market.
    On this basis, gas hydrates will not compete directly with other 
unconventional gas resources, but rather will have to compete with 
frontier conventional gas developments. This puts gas hydrates at a 
distinct disadvantage compared to other unconventional gas resources 
for access to the larger North American gas market. While a local 
market use of gas from gas hydrates may be feasible at some point (say 
fuel for a North Slope industrial requirement or for a town or 
village), this situation will largely defer the timing of gas hydrate 
developments until sometime in the distant future.
3.  Mr. Hancock, what is the difference between the long-term 
        production tests that you described us still needing to do and 
        the sorts of tests that have already been conducted in the 
        Arctic and the Gulf? How close are we to doing these production 
        tests?
    Answer: The short term production tests conducted at Mallik 
(Canada) in 2002 and Mt. Elbert (Alaska) in 2007 were actually small 
scale production experiments conducted using advanced logging tools 
similar to those used in other exploration wells. The test intervals 
were thin (<3 ft in thickness) and the test durations were short (3-12 
hours). The gas production rates were relatively small but measurable. 
In these tests no gas was produced to surface. The thermal experiment 
conducted at Mallik did produce gas to surface, but again at relatively 
low rates. It should be noted that these tests were small scale by 
design planned to investigate the response of small hydrate layers with 
known and consistent properties such as pressure, temperature, porosity 
and hydrate saturation.
    During the 2007/8 Mallik flow test, gas was produced to surface and 
flared over a 5 day period. Again, gas rates were relatively small for 
this type of test but were still measurable. This test has been the 
only conventional type of flow test conducted on a gas hydrate well. 
All of the offshore activities in the Gulf of Mexico have consisted of 
coring and well logging operations only no testing has been conducted.
    Depending upon permeability, short term conventional gas tests can 
be used to determine reservoir properties several hundred to thousands 
of feet from the wellbore. Properties such as permeability, pressure, 
and fluid properties, as well as well productivity and reservoir 
geometry can be determined from these tests. For the gas hydrate tests 
conducted to date, the depth of investigation, or distance into the 
reservoir that has been investigated can be measured in terms of inches 
or feet. This has provided excellent data regarding the dissociation 
response and production of gas hydrates in the near wellbore area, and 
this data has been used to calibrate reservoir simulation models in 
order to predict long term performance
    In conventional gas reservoirs, the gas properties are typically 
uniform through-out the reservoir, and gas flows from the extreme of 
the drainage radius of the well (typically 1000 ft. or more) once the 
well reaches a steady state flowing condition. In a gas hydrate well, 
gas and water are present and flowing in the reservoir up to the 
distance where dissociation has taken place past that point the gas 
remains as a solid in hydrate form. Long term production tests are 
required to demonstrate that gas hydrate dissociation can be conducted 
effectively at asignificant distance from the wellbore, and to 
understand the effects of multi-phase flow of gas and water, pressure 
response, and temperature or heat flow in the reservoir, combined with 
the geological complexity in a real life reservoir setting. In 
addition, a long term test must eventually demonstrate that gas hydrate 
reservoirs can be produced at commercial gas rates.
    For an onshore gas hydrate well drilled from an existing pad, the 
time required to plan, drill, and complete a well for testing purposes 
can be accomplished in less than 12 months. A deepwater offshore well 
test may take more time to execute, especially if subsea equipment is 
required for a tieback to an existing facility. Arranging funding, 
agreements, and approvals will add to the timeline, as well as the 
actual testing time required.
4.  Mr. Hancock, you mentioned ranges of prices in your testimonies, 
        but you don t actually provide any numbers. Could you be a 
        little more specific about what sorts of prices would make 
        methane hydrate production economic?
    Answer: The work conducted to date on gas hydrate development and 
economics is considered preliminary at this time. Cost estimates done 
at this stage of a development plan are typically assumed to have an 
accuracy of +40% to -25%. Production forecasts used for the gas hydrate 
developments considered in these studies have been based on theoretical 
numerical simulation models which have been calibrated only to the 
short term tests conducted at Mallik and Mt. Elbert. To date there has 
been no long term or high rate gas tests to demonstrate gas hydrate 
production potential. Lastly, almost all developments have a degree of 
geological uncertainty with respect to reservoir extent and variation 
in properties such as porosity, permeability, and thickness. In 
addition, proximity to existing infrastructure and processing 
facilities can have a significant effect on capital and operating 
costs.
    All of these factors contribute to a wide range of uncertainty with 
respect to capital costs, revenues, and gas recovery, which therefore 
results in a wide range of gas prices required for the economic 
development of gas hydrates. In other words there is no single gas 
price at which gas hydrates can be declared to be economic. Each field 
development, conventional or unconventional, must stand on its own 
technical and economic merit.
    Many corporations also have widely varying criteria for economic 
evaluation, and differing risk tolerance. Most of the companies that 
work frontier or offshore deepwater projects are also large in nature, 
and have a large inventory of prospects for exploration and development 
gas hydrates will have to be competitive with these projects in order 
to attract funds.
    Forecasting oil and gas prices have proven to be a difficult task, 
even for those who specialize in this type of work. While these price 
forecasts may be interesting for macro type economic studies, most oil 
companies take a very conservative approach to prices for evaluating 
the economics of any development. For example, the current price of oil 
is $70/barrel, and has ranged to well over $100/barrel in the recent 
past. However, the economics of deepwater developments in the Gulf of 
Mexico are still typically evaluated with a price forecast of say$35/
barrel to $38/barrel. This is done because in addition to the 
uncertainty discussed above, the stability of commodity prices over the 
life of a project is also a major risk that must be considered.
    The work done on a very few examples of gas hydrate developments 
suggest that reasonable returns on investment can be achieved with 
prices in the order of $6.00 to $12.00/thousand standard cubic feet for 
offshore and onshore projects respectively. However, considering the 
risks and uncertainties discussed above, sustained gas contract prices 
in the range of $10.00 to $16.00/thousand standard cubic feet for 
offshore and onshore projects respectively may be required before gas 
hydrate projects will proceed. Lastly, fundamental changes in the North 
American gas market supply picture, as well as advances in technology 
may have a significant impact on the price range required for gas 
hydrate development.
5.  Mr. Hancock, most of the recent work seems to have been done with 
        depressurization. Where do things stand with other 
        technologies, such as thermal injection?
    Answer: Dissociation of gas hydrates can be accomplished by 
lowering the pressure below the stability point, increasing the 
temperature above the stability point, or using chemicals (methanol or 
glycol) to change the stability conditions. Depressurization can be 
used alone. Thermal or chemical stimulation techniques must be combined 
with some depressurization in for the well to flow. All of these 
techniques can be used in conjunction with vertical wells, or high 
angle, horizontal, or multi-lateral wells. Fracture stimulations to 
increase surface contact area with the wellbore may also be used in 
conjunction with these well types. It should be noted that both the 
Mallik and Mt. Elbert wells were vertical. Other well types may be 
considered as part of the long term tests currently being planned.
    Pressure drawdown in the wellbore is very easy to control by 
flowing the well against a low pressure at surface. Artificial lift 
(downhole pumps or some other method) will be required to remove 
produced water in order maintain low pressure in the wellbore. Pressure 
reductions in the reservoir can be effective many hundreds or even a 
thousand or so feet away from the wellbore can be effectively used to 
cause gas hydrate dissociation.
    Thermal stimulation techniques have been used effectively in heavy 
oil applications. Steam applied in SAGD (steam assisted gravity 
drainage) operations or huff and puff (alternate steam injection and 
oil/water production cycles) are used most commonly. Electrical, 
including induction and resistance heating as well as microwave, has 
had some limited success. Heavy oil wells are typically quite shallow 
and relatively low cost. Thermal conductivity in the reservoir is low 
therefore steam injection wells must be drilled relatively close to the 
production wells. Because of the value of the product (oil), heavy oil 
developments can afford the capital and operating costs associated 
additional well and thermal operations.
    For gas hydrate developments, the value of the product produced 
(gas) is much lower than the value of the product produced in heavy oil 
operations on a per volume basis. Therefore gashydrate developments 
cannot be effectively drilled at the close well spacing that is used in 
heavy oil. In addition, most of the product heated in the reservoir is 
actually water (1 cubic feet of gas hydrate releases 0.9 cubic feet of 
water) which means that much of the heat transferred into the reservoir 
is wasted. On this basis thermal operations for gas hydrates will 
probably not be economic.
    Likewise chemical usage to cause gas hydrate dissociation will 
probably not be economic on the basis of the shear amount of chemical 
required on a reservoir scale. However research in both thermal and 
chemical stimulation methods will continue, and some elements of both 
may be incorporated in the long term test currently being planned.
    Based on the results of various numerical simulation studies 
performed on a variety of gas hydrate reservoirs, simple 
depressurization will be the most effective and economical method of 
gas hydrate dissociation and production.
6.  Mr. Hancock, what sort of difference is there in the cost of 
        production between conventional gas and hydrates?
    Answer: Capital and operating costs for gas hydrate developments 
will be highly variable depending a number of factors including 
geological model, well productivity, presence of free gas associated 
with the gas hydrate, and availability of capacity in existing 
processing plants and pipelines, among others. Thus an absolute 
comparison of the costs of gas hydrate and conventional gas 
developments is somewhat difficult.
    Only one study has been completed comparing a conventional 
deepwater gas field to an equal sized deepwater gas hydrate field. Both 
cases were stand alone developments with sufficient wells to produce 
the same amount of gas over a 20 year life. For the assumptions used in 
this study, the capital and operating costs for the gas hydrate 
development were approximately twice that of the conventional gas 
field.
    On the basis of the studies done to date, gas hydrate developments 
will have capital and operating costs significantly higher than other 
unconventional or conventional developments due to well productivity, 
low operating pressures and temperatures, and high water production 
rates. Surface facilities for gas hydrate developments will also be 
higher due to the requirements for larger surface flowlines and inlet 
facilities (required because of low pressures and water production 
rates) and the requirement for inlet compression into the processing 
plant.
7.  Mr. Hancock, why do methane hydrate production rates peak in later 
        years, while conventional natural gas wells peak immediately?
    Answer: Unconventional hydrocarbons are so called because they are 
found in formations other than the typical sandstone or carbonate 
reservoirs i.e. extremely low permeability or tight,reservoirs, shale, 
or coal beds the hydrocarbons are in their normal fluid condition and 
can typically flow without undergoing a fundamental change (except of 
course for bitumen).
    The types of reservoirs targeted for gas hydrate testing (and 
eventual development) are relatively high permeability conventional 
sandstone reservoirs however the methane gas is locked in a solid gas 
hydrate crystal so actually the gas is unconventional, not the 
reservoir.
    All gas reservoirs, conventional or unconventional, are capable of 
their maximum rate on day one of operation. This is because the 
reservoir pressure is at its maximum (average reservoir pressure 
declines with production for most reservoirs), the gas that initially 
flows into the well is in the near wellbore area, and of course the gas 
is continuous throughout the reservoir. As gas production continues the 
gas that flows into the wellbore flows through the reservoir rock from 
greater and greater distances away. Flowing gas through the reservoir 
rock results in additional pressure loss, and the production rate 
begins to decline. Some gas wells in high permeability conventional 
reservoirs can flow at a more or less constant rate or steady state 
condition for some time, but eventually the production rate will 
decline. Unconventional gas reservoir production rates typically 
decline quite rapidly, and may never actually reach any sort of steady 
state production, although the rate of decline will drop and the wells 
may produce for many years.
    At the start of production for a gas hydrate reservoir, there is no 
free gas in the reservoir it is all locked up in the hydrate crystals 
in the pores space of the reservoir rock. The hydrate must first be 
dissociated, and then the water and free gas can flow to the well. 
Because water and gas is flowing simultaneously (termed multi-phase 
flow), the pressure loss through the reservoir will be higher than if 
just gas only was flowing. Gas and water saturations through the 
dissociated region will change with time, and gravity will affect the 
gas and water phases, therefore the flow mechanism will be quite 
complex.
    Gas hydrate dissociation initially occurs in the near wellbore 
area, and the area where dissociation takes place gradually moves way 
from the wellbore. If you imagine this dissociation front as the 
surface area of a cylinder, the surface area of gas hydrate being 
dissociated increases proportionally to the increasing radius or 
distance away from the wellbore. Therefore, as this surface area grows, 
the rate of hydrate dissociation increases, and the rate of gas 
production also increases. Based on simulation studies, the maximum gas 
production rate therefore occurs not on days one as with conventional 
gas reservoirs, but some time into the future, typically years.
8.  Mr. Hancock, what kind of other stimuli could we enact to spur the 
        production of methane hydrates?
    Answer: Economics, and perhaps a unique opportunity, will determine 
the timing of the first gas hydrate production. Given the current state 
of the gas market in North America, royalty and tax relief along with 
incentives or subsidies may be required to bring forward the timing of 
the first gashydrate production.
    The SEC (Securities Exchange Commission) has very strict rules 
defining when gas resources such as gas hydrates can be defined as 
reserves (and can therefore add value). Among other requirements, a 
demonstration of sustained production at commercial rates is required. 
Therefore the greatest need at this time in order to spur the 
production of gas hydrates is an extended well test (or series of 
tests) that demonstrate long term production capability and that gas 
hydrates can be commercially produced.
                                 ______
                                 
    Mr. Costa. My, my, my, we have to invite these witnesses 
back.
    [Laughter.]
    Mr. Costa. Really. Thank you very much. We do appreciate 
the concise, precise brevity of your statements, and that is 
very much appreciated.
    Now comes the fun part. We get to ask questions, and let me 
begin with my first question.
    Dr. Collett, how accurate do you think those estimates are 
in the availability of nationwide methane hydrates? The last 
estimates were 1995, I think.
    Dr. Collett. Sure. What is important when we look at the 
assessments is to understand their evolution much like your 
question is trying to address. In 1995, we made a very basic 
assessment based on geologic concepts of our understanding of 
hydrates at that time, the geologic controls, and tried to 
forward predict how much gas is in the hydrates--and that is to 
the molecular count. That is, the amount of gas we feel is in 
the hydrates is irrelevant, and not linked at all to 
recoverability. We had no understanding----
    Mr. Costa. And clearly the testimony indicated that based 
upon where we have identified levels of those hydrates, 
methane, that some has higher concentrations----
    Dr. Collett. Right.
    Mr. Costa.--of methane than others.
    Dr. Collett. And as the evolution of our understanding has 
moved forward over the last 10 years, or now 14 years, we have 
focused much more on concentrated gas hydrate accumulations in 
sand reservoirs, as Dr. Boswell has indicated. The concentrated 
reservoirs are critical when you start thinking about rate of 
return, the amount of gas it actually yields from the reservoir 
per unit time, and the production rate itself.
    Mr. Costa. So the estimates----
    Dr. Collett. So our assessments have moved away from this 
kind of molecular calculation of all the gas out there to more 
closely what gas can actually be produced from hydrates, so we 
are focusing on only a small part now of that total large 
number. The large number probably has not changed--you know, 
the total volume of hydrate--volume of gas and hydrates 
worldwide--but as you look at the volume of what we think can 
be producible, our assessments in more recent time has focused 
on that component.
    So last year when we reported our five-year-long study from 
the north slope of Alaska, we felt our information on Alaska, 
our knowledge of the hydrates had reached the point that we 
believe they are technically producible in that environment 
from sand reservoirs. So, that assessment number at 85 trillion 
cubic feet, unlike the 200,000 TCF, which you hear for the 
entire U.S., this is an area on the north slope, we believe 
that 85 TCF----
    Mr. Costa. Is recoverable.
    Dr. Collett.--is recoverable.
    Mr. Costa. OK. Dr. Boswell, obviously based on the 
testimony this morning a lot of work has been done. What do you 
think is the biggest lesson we have learned about hydrates over 
this time as it relates to a potential energy source not only 
as it relates to other conventional energy sources but the 
other energy tools in our energy toolbox that I spoke of in my 
opening statement?
    Dr. Boswell. Thank you for the question.
    I think the major thing that we have learned is that our 
prior conceptions of gas hydrates, which was based on not very 
much data at all, were very simplified.
    Mr. Costa. Speak more into the microphone.
    Dr. Boswell. I am sorry. We had some very simplified 
concepts of gas hydrates just even 5 or 10 years ago, and 
through a series of field expeditions throughout the oceans of 
the world we have now realized that gas hydrates in the marine 
environment take a wide variety of forms. There was a prior 
conception that gas hydrates in Alaska were one thing and gas 
hydrates out in the ocean were something different, and people 
could see how the gas hydrates in Alaska would be produced, but 
they thought the gas hydrates out in the ocean were widely 
dispersed, diffused, low concentration, big accumulation but 
very lean, and no one really had a concept of how you might go 
about producing them, and that is why hydrates stayed this 30 
years off thing in a lot of peoples' minds.
    But recently what we have learned is out in the marine 
environment there are concentrated deposits of gas hydrates and 
perhaps a significant amount of them, and we have an MMS 
assessment that suggests there is 6,700 TCF of gas in sand 
reservoirs, likely at high concentrations, just in the Gulf of 
Mexico. So that is a smaller number than the 200,000, but it is 
still a very big number.
    So that is probably the main thing that we have learned. 
The marine resource is no longer this exotic, strange thing 
that is going to require some brand new technological 
breakthrough to get to. It exists in accumulations that are not 
entirely unlike what industry is used to drilling, and we can 
use technologies existing, well drilling and completion 
technologies that industry is using.
    Mr. Costa. Before my time expires, thank you. Mr. Hancock, 
you talked about among the challenges facing on retrieving this 
methane hydrates the availability of pipeline and the cost. But 
could you please give us a little more descriptive--I mean, 
some of us have been to both onshore oil and gas wells and we 
have been to offshore platforms, and so we have a sense of how 
they operate. But when you see a methane hydrate, I mean, it is 
composed, like was said, of molecules in ice, but how do you 
actually retrieve that gas whether you are onshore or offshore?
    Mr. Hancock. Actually the process is almost identical to 
flowing any other conventional oil or gas. You create a 
pressure drawdown just by removing the water, the hydrostatic 
head in the well, opening a valve, and doing that the hydrate 
will disassociate into both gas and water in the formation, in 
the reservoir, and then you simply produce the gas and the 
water much as you would in any other well.
    Mr. Costa. And so it comes up and it separates from the 
water?
    Mr. Hancock. The gas and water in the reservoir will flow 
to the well bore. You may need artificial lift to actually 
produce the water because of the volume, but basically the gas 
will flow naturally up the well just like every other gas well, 
and the water, of course, will flow or will be pumped up the 
well just like any other well that has water production.
    The disassociation, the complex understanding of how gas 
hydrates disassociate, takes place in the reservoir away from 
the well bore. All the well sees actually is just gas and 
water.
    Mr. Costa. And the issues with regards to its impact on air 
quality, CO2 and other impacts?
    Mr. Hancock. Basically we are talking about pure methane. 
No CO2, no hydrogen sulfite, no heavier 
hydrocarbons; basically pure methane and essentially fresh 
water. So the impact will be no different than any other carbon 
fuel.
    Mr. Costa. And my time has run out but maybe if we come 
back to it. I guess as intrigued as I am about the potential 
here, I am also wondering--I am one who supports expansion of 
offshore oil and gas, but for those who are opposed to it I am 
wondering whether or not they would have the same reasons to 
oppose the extraction of methane hydrates because of their 
concerns of spills, their concerns of platforms, their concerns 
about the potential impacts of oil and gas that I don't share 
but, nonetheless, they feel are issues of concern.
    Mr. Hancock. With gas hydrates or methane hydrates, of 
course, we are producing methane only. It is the cleanest 
hydrocarbon that we have. The water that is produced will be 
slightly saline, but certainly much fresher than sea water. 
Disposal will require dedicated disposal wells if you're 
onshore. It will be released to the ocean if you are offshore. 
But there is no hydrocarbon carryover that you have to worry 
about or anything like that, and certainly there can be no 
hydrocarbon spills.
    Mr. Costa. OK. Well, my time has expired, and I will defer 
to the gentleman from Colorado, Mr. Lamborn.
    Mr. Lamborn. Thank you, Mr. Chairman, and this is 
fascinating.
    Were any of you surprised by the production test at the 
Mallik test well that these good results came about just 
through the simplest method of production using 
depressurization?
    Mr. Hancock. Pleasantly surprised, yes. When we first 
planned the tests at both the Canadian site at Mallik and in 
Alaska at Milne Point, the expectation was that we would be 
measuring gas at extremely low rates, almost too small to 
measure. But when we did the first experiments, which were just 
very small-scale pressure drawdown experiments, and pressure 
depletion is seen as sort of the most economic or easiest way 
to cause hydrate disassociation, the hydrate response was 
instantaneous, and that was shocking, to say the least. We 
expected to be doing something quite different.
    So, we actually in the testing process tested it like we 
would test any other tight gas well, or say a cold-bed methane. 
It was more a conventional test. So, the response actually was 
pretty good. We also did a thermal test where again we had a 
very good response from the reservoir, and both of these have 
been used to calibrate some of the simulation models that we 
have used to look at how we would flow these wells on a 
commercial scale.
    Mr. Lamborn. OK, thank you.
    Is the co-produced water associated with methane hydrate 
reservoirs potable, that is, fit for human consumption?
    Mr. Hancock. I don't believe it is. The pour water in the 
reservoir has some salinity. The water released from the 
hydrate is fresh, but there will be some mixing of those waters 
so it will not be potable.
    Mr. Lamborn. Would it take much treatment to make it so?
    Mr. Hancock. If you are talking about desalination, and I 
am not an expert on that at all, but the salinity will be much 
less than sea water so theoretically I guess it could be 
easier.
    Mr. Lamborn. OK. And for anyone of you, how important is 
the joint partnership with industry in identifying the methane 
hydrate resources and in developing the technology to produce 
these resources?
    Dr. Boswell. It is very important. We conduct our research 
through cooperative agreements with industry, and that is a 
requirement for our projects to go forward primarily because 
they own the land rights and the leases and they have 
facilities that we need, and they have data that we need. So we 
have been very fortunate to have BP, ConocoPhillips, Chevron 
willing to participate with us on this science. Without their 
help we would have certainly a much tougher time getting to the 
answers to these questions.
    Mr. Lamborn. Now, did anyone else want to add to that 
before I go to my next question?
    OK, Dr. Collett, two questions. Are there methane hydrates 
off the coast of California?
    Dr. Collett. Yes, there is. One of the most interesting 
ones are these near-surface type hydrate accumulations, what 
occur in vent sites where there are actually gas seeps, and 
those are relatively common off the southern coast of 
California. As you look at the entire California margin, in 
fact, the entire western margin of the United States, hydrates 
are well known, particularly a place called Hydrate Ridge 
offshore Oregon where they actually have been drilled during 
the ocean drilling program.
    So we feel hydrates are almost ubiquitous. They are pretty 
much uniform to the entire continental margins and most marine 
basins, but the critical aspect is the nature of the hydrate 
occurrence, the sand reservoirs versus the disseminated.
    The vent sites, I should also add, most of us don't look at 
the vent sites as any of a potential resource. This is an 
environmentally very delicate, very sensitive environment. The 
hydrates we look at as a potential resource are deeply buried, 
you know, well deep into the sediment column below the hydrate 
stability field, or in the stability field and below in sand 
reservoirs. So it is important to understand that sometimes 
when we see hydrates you see this outcropping nature, but that 
is not exactly what we are looking at for the resource.
    Mr. Lamborn. Now, for that which might be usable as a 
resource off the coast of a place like California where fresh 
water is also----
    Dr. Collett. Right.
    Mr. Lamborn.--a concern, is the slightly salty yielded 
water which would be, I assume, easier to desalinate than sea 
water----
    Dr. Collett. Yes, I would like to add to that conversation, 
you know, that question and answer, is that when you look at 
hydrate itself, the physical nature of hydrates, it has no salt 
in it at all. The crystalline solid excludes salt. It actually 
is used in industry procedures as a purification project or 
product where you can actually purify water by removing all the 
solids from it. So the hydrate itself has no salt content at 
all.
    What Mr. Hancock was indicating is that the co-produced 
waters, the non-hydrate bearing waters can be elevated in salt. 
In most environments we find that those salts aren't highly 
elevated at all, so there would be a mixing of these 
components.
    So through either complex well completions, focusing on 
just hydrates, or where you could just produce hydrate water 
alone, or these co-produced waters need to be dealt with, but 
in most cases they are going to be very low salinity production 
streams, and there are actually companies that are looking at 
hydrates as a potential source of water, of fresh water where 
it could be an important commodity, maybe even in some 
environments more important than the gas itself.
    Mr. Lamborn. OK, thank you very much, and thank you all for 
being here.
    Mr. Costa. All right, the gentleman's time has expired, and 
the next colleague on our list here is a gentleman who has been 
voted among the most attractive Members in the Congress. I 
don't know how you get that designation. I have been trying for 
years. Mr. Heinrich.
    Mr. Heinrich. Mr. Chairman, you need both your wife and 
your mother on the selection committee, it helps.
    [Laughter.]
    Mr. Costa. Mr. Heinrich.
    Mr. Heinrich. Thank you, Mr. Chair.
    I want to get a sense for the geographic distribution of 
concentrated hydrates where they would be technically 
recoverable. Do they tend to occur in areas that are 
geographically separate from some of the other more 
conventional sources of gas we have had in the past, or would 
there be cases where they would co-occur at different 
elevations in the sea floor, different elevations in a sediment 
column? How does that work, or what is your experience, I 
should say?
    Dr. Collett. Our experience is they are closely related, 
and one reason for that is the reservoir component itself; you 
know, the sand reservoir where conventional reservoirs occur 
have the same geologic controls, and this is very important. As 
you get closer to understanding gas hydrates, we find there are 
many similarities with conventional gas reservoirs. So the 
nature of the reservoir itself in the co-existence of hydrates 
near existing hydrocarbon accumulations because of this 
depositional environment is consistent.
    The other issue is the source of the gas itself within 
hydrates. It is a very simple concept. If you have a lot of 
hydrate, you need a significant source of the gas, and 
oftentimes the gas source for hydrates, the highly concentrated 
ones, particularly in the Arctic, the Caspian Sea, the Gulf of 
Mexico, the Black Sea, are areas where you have a thermogenic 
source coming from depths from the conventional resources 
themselves also sourcing the hydrates.
    So, when we visualize hydrates today, we see hydrates as a 
continuation of these what we call petroleum systems where they 
are often closely related to conventional resources.
    Mr. Heinrich. Would we have inadvertently developed some 
portion of these hydrates in taking conventional gas and 
reducing the pressure on a hydrate system and have that flow 
into some of the places that are already producing?
    Dr. Collett. Right. Yes, one of the particular places where 
we believe this has taken place is actually since the late 
1960s in a field--I actually had the opportunity to work in the 
late 1980s called the Messoyakha Field in the West Siberian 
Basin. It has a conventional gas field capped by hydrates, and 
when that field was brought online as a conventional gas the 
hydrate disassociated the top of the hydrate cap supporting 
production over time.
    There is also a project that Dr. Boswell could elaborate 
on, on the north slope of Alaska with DOE in the community of 
Barrow, one of the native communities, where they are looking 
at co-production of hydrates in an existing gas field that is 
being produced since the 1940s called the Barrow Gas Field.
    So this could be happening. We don't think it is a common 
event because most production, particularly marine 
environments, have been very separated from the hydrate 
stability field, would have been much deeper. But as we 
advanced into those deeper water environments and also in these 
higher Arctic environments, this has probably been a common 
event, but we are just starting to realize it.
    Mr. Heinrich. So someone who currently holds a lease in one 
of those areas where you might have co-existence of the 
hydrates at one elevation and conventional sources at another 
elevation, they would already have the production rights to 
potentially produce those hydrates, wouldn't they?
    Dr. Collett. It is my understanding as a scientist when I 
have been asked this question and discussed this with BLM and 
also MMS, there is no official ruling but every discussion 
about it has made that assumption that would be true. There 
hasn't been a case where that has been documented and been 
asked within a lease or the request, but every discussion that 
has taken place that I have been witness to has indicated that 
they would be combined.
    Mr. Heinrich. Because we take sort of a bird's eye view to 
leasing, right? So everything as you look down within----
    Dr. Collett. Right.
    Mr. Heinrich.--those sections----
    Dr. Collett. Yes, the center of the earth to the surface of 
the earth, and it would be hard to imagine as a scientist how 
to separate them, but again, our experience has not been as 
such, that a permit has been issued or on a gas hydrate lease, 
so the official event of that ruling event has never taken 
place, but every indication has been from all the interested 
parties that it would be.
    Mr. Heinrich. OK. And I would assume as these disassociate 
into water and methane, that basically means that the post-
production portion of dealing with the fuel is exactly what we 
do now with methane, so there is not really any technology 
after production that is different than producing conventional 
methane or am I wrong about that assumption?
    Dr. Collett. I think I will defer to Mr. Hancock on that 
one because I think he----
    Mr. Heinrich. Mr. Hancock.
    Mr. Hancock. Correct. Once the gas is produced basically it 
just has to be dehydrated and it is ready for use as a fuel.
    Mr. Heinrich. OK.
    Mr. Hancock. No other processing.
    Mr. Heinrich. I yield back, Mr. Chair.
    Mr. Costa. I thank the gentleman from New Mexico, and that 
is very interesting. The next member of our Subcommittee is the 
gentlewoman from Wyoming, Cynthia Lummis.
    Mrs. Lummis. Thank you, Mr. Chairman.
    This is fascinating. I come from a state that produces a 
tremendous amount of----
    Mr. Costa. I stand corrected, Ms. Lummis. I apologize.
    Mrs. Lummis. Thank you. Of cold-bed methane, and so I have 
some exposure to the recovery of methane through different 
hydrocarbon sources, so this is wonderful news.
    Could you tell me what the next steps are, if there are 
regulatory mechanisms that the Federal government needs to 
establish or loosen in order to facilitate the recovery of 
these resources? And that question is to anyone.
    Dr. Boswell. I can address what the next steps in terms of 
science and technology development are.
    Mrs. Lummis. OK.
    Dr. Boswell. And certainly the next big step is to conduct 
an extended term production test, and we have a project 
underway with the three major--well, with BP, and we are trying 
to develop a cooperative project with them--ConocoPhillips and 
Exxon--to conduct an extended test in Alaska, and that is 
really the next step, and it is also the only place on the 
planet where such a test can be feasibly executed right now.
    And so we have a lot of international interest in that 
test, a lot of interest in seeing it go forward, and it is a 
test that we hope to start next year, and it will be an 
extended term test, at least a year perhaps. That is really the 
next big thing that needs to be done. There also needs to be 
more drilling and examination out in the marine environment. 
Thus far we have been concentrating on the Gulf of Mexico, but 
there are certainly a lot of gas hydrates elsewhere to look at. 
So those are the two big things that need to happen science-
wise.
    Mr. Hancock. From an engineering point of view, the next 
step or the process of steps really needs to demonstrate that 
we can produce gas hydrates at a commercial rate with the 
technologies that are available. Based on the information we 
have now theoretically we think we can. However, we still have 
to prove that.
    Mrs. Lummis. And Mr. Chairman, what amount is deemed 
commercially recoverable for purposes of making a well or a 
well field cash flow?
    Dr. Collett. And Steve is looking at me. You know, I think 
the important aspect when we look at that it is always going to 
be site-dependent, which your question has already indicated.
    Mr. Costa. Slightly what?
    Dr. Collett. Site-dependent.
    Mr. Costa. Oh, site-dependent. Oh, sorry.
    Dr. Collett. And a marine hydrate well is going to be very 
different than an onshore well on the north slope of Alaska, 
and I think Mr. Hancock has experienced that. We have actually 
looked at some of the breakeven or the cost returns in 
particularly Arctic wells and also in situations in the marine 
if you wanted to, I think, add that detail.
    Mr. Hancock. We have looked at a number of scenarios, if 
you will, for the economics of gas hydrate developments, and as 
Tim pointed out, each field is unique and each will stand or 
fall on its own set of circumstance so there is no sort of 
general price that says, you know, above $7 MCF all gas 
hydrates are economic. It all is going to depend on a lot of 
the site-specifics.
    But we have looked at developments onshore in the Arctic 
and, of course, in doing that we have to include a pipeline 
tariff to come to the main market in the continental U.S., and 
I don't want to dwell too much on prices. When we first started 
this work it was really to try to understand will gas hydrates 
ever be economic.
    Mrs. Lummis. Yes.
    Mr. Hancock. We actually have found in doing the work for 
both onshore and offshore developments that the price required 
is only a few dollars beyond what conventional gas requires for 
a similar type development, but those few dollars can make the 
difference between whether a project goes or doesn't go. So, it 
can be economic at prices we have already paid in North 
America, but there is a lot of gas ahead of it, so the 
commerciality has yet to be sort of proven, and therefore the 
recovery in terms of how much of the technically recoverable 
reserves can be economically recovered is open to debate just 
because of the volatility of gas prices in North America.
    Mrs. Lummis. Yes. And Dr. Boswell, quickly, I would ask why 
is Alaska the appropriate platform for the next long-term test? 
And what cooperation occurred between the government and the 
private sector in order to complete the 2002 Mallik test?
    Dr. Boswell. Well, our program is going on two tracks. One 
track is, is there a significant volume of gas hydrate that 
makes this a prize worth pursuing, and the other is, if there 
is, can we produce it, and we have been doing those in 
parallel, and we have been using the known occurrences of gas 
hydrates, and Dr. Collett through 20 years in Alaska has pretty 
much given us a good feeling that there are gas hydrates there, 
and we know where they are, we know how to find them, so it is 
a natural laboratory for investigating producibility.
    In the marine environment, we don't have that same 
database, and so we are exploring to see how much is there and 
where it is. So that, I think, is the answer to your first 
question. Alaska is the first place where we know where they 
are, and we can do a test economically also because it is not 
out in the deepwater.
    As far as the Mallik test in 2002, that was a project that 
was supported by Japan and Canada with a number of 
international collaborators, including the DOE and groups from 
India and others.
    You asked about the industry involvement in Mallik? I don't 
believe there was an extensive industry involvement, but Steve 
and Tim are much more familiar with that project.
    Dr. Collett. Yes, I was the co-chief scientist on both the 
first two phases of the Mallik project in Canada. Then there is 
the Mount Elbert, similar sounded project with BP that Dr. 
Boswell was involved in two years ago. The Mallik project 
really started off as a catalyst between the U.S. Geological 
Survey, the Geological Survey of Canada proposing to Japan who 
was interested in marine hydrates--again, very poorly 
understood--come to the Arctic to understand hydrates, and we 
decided on the Mallik site because of previous industry 
drilling. Again, this database and insight moved through a 
series of geologic, then testing programs over now a 10-year 
period of testing at Mallik of looking at hydrates from a 
geologic and other perspective.
    So, again, very heavily leveraged when you look at the 
Japanese National Oil Company, the surveys of the two 
countries, DOE, it is a heavily governmental-leveraged program, 
and again, it is pretty logical why, is that you have something 
that is at a pretty high risk resource still. Our knowledge is 
not well developed, so the industry had been slow to really 
gain this, but I think particularly Dr. Boswell can add the 
ConocoPhillips projects in Alaska. Partnered with DOE, the BP 
projects have all been significant projects to evolve over the 
last 10 years.
    Dr. Boswell. Another 30 seconds. The Milne Point project 
that we had in 2007 was very important because we want to 
conduct this test, we want to conduct it in the Greater Prudhoe 
Bay area, and that is a science project coming into an existing 
business environment, and there is quite a lot of concern by 
industry on whether we were going to cause a problem--you know, 
we were going to cause them to lose revenue and things.
    So our project up there which we conducted went very well. 
It didn't cause a single problem, and the demonstration that we 
could do that, go up there and do that sort of scientific 
experiment in their back yard is part of the reason why we are 
getting a lot more interest from industry now to collaborate 
with us on the upcoming longer term test.
    Mrs. Lummis. Thank you all for being here. Thanks, Mr. 
Chairman.
    Mr. Costa. Thank you. The gentlewoman's time has expired.
    Mrs. Lummis. I snuck that question right under the----
    Mr. Costa. I saw that. Unfortunately, Mr. Holt had to go to 
the Floor because I was hopeful that he would get a chance to 
get his questions in.
    I am reminded by our panel experts of an old respond when 
sometimes I am with a large group that if you make answers to 
questions long enough you discourage further questioning. I 
hope that is not the strategy with our panel members here.
    Mr. Hancock, given the economic considerations here, what 
do you think is realistic in terms of the industry's ability to 
start producing natural gas from hydrates?
    Mr. Hancock. I think realistically you need to try to 
understand how industry actually selects its projects, and 
every company has an inventory of prospects and only the top 
prospects get drilled and developed each year. So until the 
economics of hydrates actually start to approach the economics 
of their conventional or unconventional prospects it is going 
to be difficult to see how industry is going to be driven 
toward hydrate development at this point in time.
    Mr. Costa. All right, a couple of other quick questions 
here. We do have Floor debate going on and some other hearings 
that are taking place concurrently.
    Dr. Boswell, how much money is the United States spending 
on this with DOE, and what is the goals for production of 
hydrates in 2015, and marine hydrates in 2020?
    Dr. Boswell. I am sorry. I didn't catch the second half of 
that question. What are the?
    Mr. Costa. What are the goals for----
    Dr. Boswell. OK.
    Mr. Costa.--hydrates both production in the Arctic in 2015 
and production in marine hydrates by 2020?
    Dr. Boswell. The amount of money that we spend in the U.S. 
has historically been probably around $20 million.
    Mr. Costa. How does that compare to Japan?
    Dr. Boswell. Japan does not officially say how much they 
spend, but based on the level of their activity I am sure that 
they are spending at least double that.
    Mr. Costa. OK.
    Dr. Boswell. Probably triple that.
    As far as the goals, our goal is by 2015 to have all the 
knowledge and technology and the demonstration in place so this 
is now an option that industry has to consider for meeting 
demands, by 2015 for the Arctic.
    It is going to take more time to do that, of course, in the 
offshore. The tests are going to be much more expensive, and we 
just don't know quite as much about it, so that is why that 
date is further back in time, but it is the same thing. It is 
demonstrating that there is the ability and the technology that 
can make commercial production viable.
    Mr. Costa. Because Japan is spending twice as much as we 
are, does this put us at a competitive disadvantage if in fact 
would we have to import at some point their technology?
    Dr. Boswell. We have active ongoing collaborations with 
Japan that we hope will address that issue. I don't think that 
it is going to put us at a competitive disadvantage. I think we 
are spending our money fairly efficiently right now, and the 
projects that we have in place, if they are able to go forward 
the way they should, I think will keep us at the head of that 
curve.
    Mr. Costa. Mr. Hancock, you talked about ranges of prices 
and I think natural gas--of course, I come from an area in 
California where we have air quality issues and we are non-
attainment areas, as well as in southern California, trying to 
meet those goals are challenging, and I think gas, natural gas 
is one of the energy--I call it du jour.
    Where does methane hydrates fit in--in terms of its ability 
to become cost effective?
    One of the arguments that I am told is that we don't use 
more gas is because even though it has been found available and 
we increase our known finds, that it doesn't compete 
economically with other forms of energy. Where does methane 
hydrates fit in--in terms of its break-even point? What price 
of natural gas do we have to have for the extraction of 
hydrates ultimately to economically pay off?
    Mr. Hancock. For gas hydrates onshore to be competitive, 
return a reasonable rate of return for the people who are 
investing the money in the development, and I hate to give an 
exact number, but it is probably closer in the range of the 10 
to 12 dollar per MCF where our current market is in the $4 per 
MCF range in North America.
    Mr. Costa. That is a problem.
    Mr. Hancock. That is a problem. Offshore, it actually can 
be slightly lower but the problem is, as the price of gas 
increases in North America, more and more of the unconventional 
resources that are already in the Lower 48 states become more 
attractive and hence we get into the cyclic nature of the gas 
industry, which right now is at a fairly low point. North 
America is basically, even though some gas is imported because 
of heritage-type contracts and things like that, North America 
is basically self-sufficient in gas.
    Mr. Costa. OK, my time has expired. Any other questions for 
the witnesses?
    I want to thank the members of the panel. I think this was 
very informative this morning. I am sorry that I was a bit 
late. As I noted in my opening statement, this is part of a 
series of hearings that we are holding to try to figure out 
where all the various energy sources that are available to our 
country are, and how they fit together as a part of a 
comprehensive long-term energy plan. So the three of you have 
been very helpful. We appreciate that.
    As customary with the hearing process, the Subcommittee 
Members will have 10 working days to submit any additional 
questions that they may have to the three witnesses. We would 
appreciate, to the degree that those questions are submitted to 
you, that you provide as effective a response as you did in 
your opening statements, which was concise and precise and 
brief. So, we thank you for that, and we thank you for your 
time.
    The Subcommittee is now adjourned.
    [Whereupon, at 11:08 a.m., the Subcommittee was adjourned.]

                                 
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