**STATEMENT OF**

**\
DR. ROBERT C. BURRUSS\
RESEARCH GEOLOGIST, ENERGY RESOURCES TEAM\
U.S. GEOLOGICAL SURVEY\
U.S. DEPARTMENT OF THE INTERIOR\
BEFORE THE\
SUBCOMMITTEE ON ENVIRONMENT AND HAZARDOUS MATERIALS\
HOUSE COMMITTEE ON ENERGY AND COMMERCE\
HEARING ON\
"CARBON SEQUESTRATION: RISKS, OPPORTUNITIES, AND**

**PROTECTION OF DRINKING WATER"\
**

**JULY 24, 2008**

Mr. Chairman and Members of the Subcommittee, thank you for the
opportunity to present testimony on geological sequestration of carbon
dioxide (CO~2~), addressing opportunities, risks, and protection of
drinking water resources within the United States. My remarks will
briefly discuss some of the basic principles of geological CO~2~
sequestration, provide an overview of current U.S. Geological Survey
(USGS) activities on these topics, and address some of the fundamental
principles of assessment of geological commodities that underlie USGS
methods, including the types of uncertainties that can affect estimates
of storage volume at the regional scale.

**Introduction**

The magnitude of addressing reductions in greenhouse gas emissions
necessary to impact global climate change is significant because fossil
fuel use, the major source of CO~2~ emissions to the atmosphere, will
continue for some time in both industrialized and developing nations.
Geologic sequestration of CO~2~ captured from large industrial sources
of emissions is one of a number of technologies for carbon management
that could be deployed to stabilize the concentration of CO~2~ in the
atmosphere. Although geologic sequestration is the topic of this
hearing, geologic CO~2~ sequestration alone cannot achieve the goal of
stabilizing the atmospheric CO~2~ concentration at a level that will
have a meaningful impact on climate change. The magnitude of reductions
needed may be on the order of 70 percent or more (IPCC, 2005), requiring
all methods of carbon management in addition to geologic sequestration.
These other methods include terrestrial sequestration, increased use of
renewable biological sources, electricity generation by solar and wind
systems, geothermal and nuclear power, increased efficiency in
transportation as well as electric power generation, transmission, and
end use.

Over the last nine years the USGS has engaged in several studies to
evaluate geological and geochemical factors that improve our
understanding of processes occurring during geologic storage of CO~2~,
the potential risks associated with storage of large volumes of CO~2~,
and some potential environmental impacts of geologic sequestration.

The USGS also collaborates with DOE on sequestration projects such as,
the DOE-lead Geo-SEQ program, a consortium of National Laboratories
working on monitoring technologies and simulation codes for carbon
storage; the DOE-sponsored Frio Brine project in Texas; and review of
the efforts by DOE to develop several large scale field projects
throughout the United States.

More recently, Section 711of the Energy Independence and Security Act
(P.L. 110-140), enacted into law in December 2007, authorized the
Secretary of the Interior, acting through the Director of the USGS, to
develop an assessment methodology and conduct a national assessment of
geological storage capacity in collaboration with the Secretary of
Energy, the Administrator of EPA, and the State geological surveys. USGS
will collaborate with DOE to incorporate the results of the assessment
into future revisions of the DOE "Carbon Sequestration Atlas of the
United States and Canada". The cumulative advances from these earlier
USGS studies and DOE-funded activities provide a basis for developing a
methodology to assess the national capacity to store CO~2~ and
understand the potential impacts of large-scale deployment of geologic
sequestration.

Subsequent to enactment of P.L. 110-140, the USGS received from Congress
funding to initiate a new activity to develop the methodology to conduct
a national assessment of carbon dioxide storage capacity in oil and gas
reservoirs and saline formations. The USGS has also recently updated its
website to promote the dissemination of information and research
relevant to this new activity:
<http://energy.er.usgs.gov/health_environment/co2_sequestration/>, and
has assembled a project team to begin development of the methodology.
The USGS will consult and collaborate with other organizations, as
appropriate, including state geological surveys, the Department of
Energy, the Environmental Protection Agency, other bureaus within the
Department, and other stakeholders. This will help ensure, to the
maximum extent possible, an efficient, effective, and coordinated
effort. As with all USGS energy resource assessment methodologies, an
independent non-USGS panel, consisting of individuals with relevant
expertise and representing a variety of stakeholder organizations, will
be convened to provide a technical review of the methodology. The full
methodology is expected to be released by spring 2009

**Basic principles of geologic sequestration of carbon dioxide**

Geologic storage involves injection of liquid CO~2~ into a subsurface
rock unit and displacement of the fluid that initially occupied the pore
space. This principle operates in all types of potential geological
storage formations such as oil and gas traps, deep saline formations,
coal beds, and other rock types.

At the pressures and temperatures that exist at depths in the Earth
greater than about 3,000 feet, carbon dioxide is a supercritical fluid
with density that ranges from 500 to about 700 kg/m^3^ at the greatest
depths considered for storage, about 12,000 feet below the land surface.
Because the density of CO~2~ is only 50 to 70 percent of the saline
formation water, the CO~2~ will be buoyant and rise vertically until it
is retained beneath an impermeable barrier, commonly called a seal. If
the structure of the seal forms a trap with both vertical and horizontal
barriers (closure), CO~2~ will accumulate in the same manner that other
natural buoyant fluids, like crude oil and natural gas, accumulate by
displacing formation water from the geologic trap. This process is
commonly referred to as *physical trapping*. Physical trapping of CO~2~
involves two factors critical for evaluation of storage risks: the
integrity of the seal and the total volume of water displaced by
injected CO~2~. The volume of displaced saline water relative to the
volume of CO~2~ injected must be understood to fully evaluate the
potential for leakage, including the potential for contamination of
drinking water.

Some of the injected CO~2~ will dissolve in the subsurface formation
water, a process known as *solubility trapping*. The solubility of CO~2~
is relatively low, however, reaching a maximum of about 5 percent of the
weight of pure water, and generally less, 2 to 3 percent of the weight
of saline water. This means that for complete solubility trapping, each
ton of injected CO~2~ must contact at least 20 tons of formation water,
possibly much more.

Another consideration is that dissolved CO~2~ forms a weak acid,
carbonic acid, which can react with other components dissolved in
formation water. Carbonic acid can also react with minerals in the
geologic storage formation, either dissolving them, or precipitating new
minerals, a process known as *mineral trapping*. The acidified formation
water may dissolve coatings on mineral grains, releasing trace metals
and residual organic components to the formation water and to the
supercritical CO~2~, raising the possibility of mobilizing potentially
hazardous, naturally occurring materials. This process increases the
potential for saline water that is displaced from a geologic storage
formation to contaminate shallower, potable water supplies if the
displaced water can migrate to shallower depths.

If residual oil is present in a storage formation, CO~2~ will dissolve
in the oil as another type of solubility trapping. However, CO~2~ is
much more soluble in residual oil than in water. In fact, at pressures
equivalent to depths of about 5000 feet in the subsurface, CO~2~ is
completely soluble in oil (also known as completely miscible). This
fact, together with the physical effects caused by dissolution of CO~2~
in oil, including the volume of oil swelling and the viscosity dropping,
provides the primary mechanism for enhanced oil recovery (EOR) using
CO~2~. When the oil is produced from a well, the CO~2~ dissolved in the
oil is separated from the oil, recycled and reinjected to recover
additional oil. In the overall process, some injected CO~2~ remains in
the geologic formation, equivalent to about 1 ton of CO~2~ stored for
every 2 additional barrels of oil recovered. At current prices for crude
oil, this additional recovery is clearly a valuable "by-product" of
potential CO~2~ storage in depleted oil fields.

**Geological Reserves, Resources, and the Role of the USGS in capacity
assessment**

An assessment of the geological capacity to store CO~2~ must be based on
fundamental principles that are analogous with any assessment of a
finite geological commodity such as petroleum or coal. Within the total
possible volume of storage, we must be able to distinguish potential
geologic CO~2~ reserves from resources (Bachu and others, 2007). The
resource is the quantity that, based on geological principles and
available knowledge, may exist within some portion of the Earth. The
reserve is that portion of the resource for which we have more
information and thus greater certainty with which we can define a volume
that can be evaluated with enough detail to assign a value to the
commodity. For clarification, use of the term "reserve" in this
testimony is broader and distinct from the term "proved reserves" which
connotes economic evaluation of a known quantity of resource. The
current and most precise definitions of the terms reserve and resource
as they pertain to oil and gas accumulations are provided in a 2007
joint publication of the Society of Petroleum Engineers, the American
Association of Petroleum Geologists, the World Petroleum Congress, and
the Society of Petroleum Evaluation Engineers (SPE, 2007). In the SPE
terminology, the USGS assessment will focus on "contingent resources", a
term indicating that additional economic factors must be evaluated
before a value can be assigned, thereby shifting the volume of
contingent resource to a reserve. In common usage "probable reserves" is
synonymous with "contingent resources".

The USGS has a long history of conducting national and international
assessments of natural resources. Given that geologic storage space for
CO~2~ in the subsurface is a finite geological commodity, USGS
scientists have the necessary geological expertise to build a robust
methodology for assessing geological CO~2~ storage capacity. This
expertise stems in part from many years of experience in conducting
impartial, scientifically robust oil, gas, and coal assessments where a
critical issue is the distinction between reserve and resource described
previously.

Equally important in developing an assessment methodology is the
significant expertise of the USGS in assessment of ground-water
resources. The unique knowledge within the USGS of regional ground-water
aquifer systems enables the USGS to develop methods to assess potential
storage in saline water-bearing geologic formations. Although very large
storage capacities can be calculated for saline formations,
incorporation of geological and hydrological risk factors that affect
these capacities is a challenging and difficult scientific task. These
factors are essential to defining the portion of the total geologic
CO~2~ storage resource that is actually technically feasible to utilize
and may ultimately meet the economic definitions of a reserve.

**Conceptual framework for storage assessment**

USGS methods for assessment of geological resources focus on evaluations
at the regional or basin scale where we can define geologically
consistent assessment units (AU). The application of a consistent
methodology across these scales will facilitate aggregation of results
from all assessment units, providing an overview of the national
endowment of storage capacity. For CO~2~ storage, the description of the
AU should include information from two types of geological formations,
the storage unit and the overlying regional seal. The most commonly
described formation types for geological storage of CO~2~ are depleted
oil and gas fields, saline formations, and unmineable coal beds. For
each storage type, a sealing formation must accompany the storage
formation to prevent the buoyant leakage of CO~2~ from the storage
formation to shallower levels or to the atmosphere. The geological
properties of the sealing formation provide a basis for evaluating the
geological risk of CO~2~ leakage from the storage formation that could
cause contamination of shallower aquifers for potable water supplies or
limit the effectiveness of sequestration if stored CO~2~ can return to
the atmosphere. The geological risk factors at the scale of the AU are
distinct in scale from risks specific to individual CO~2~ storage sites,
where additional factors such as the integrity of existing well bores
and cement must be taken into consideration.

Although CO~2~ storage in known oil and gas traps and saline formations
are commonly considered as distinctly different types of storage, in
most cases they are geologically linked. The physical traps of oil and
gas fields occur within almost every saline formation under
consideration for CO~2~ storage. Using the distinction between reserve
and resource described earlier, the physical traps that have retained
buoyant oil and gas for hundreds of thousands to hundreds of millions of
years are the best characterized part of the saline formation in which
we understand the integrity of the seal and the injectivity of the
formation. These areas are typically the most well characterized
settings for CO~2~ storage, and in this context can be considered
analogous to a reserve and the larger area of saline formation adjacent
to the trap can be considered the resource.

We can make conservative estimates of storage volume based on the amount
of oil and gas recovered from the trap. That initial conservative
estimate of storage volume can increase through additional recovery of
residual petroleum with enhanced oil recovery. Ultimately, it may be
possible to fill the trap to the maximum capacity defined by the spill
point of the trap. When a trap is filled to maximum capacity, if the
saline formation extending beyond the trap is adequately characterized,
then injection could continue and storage would "spill" into the larger
volume of the saline formation. Alternatively, storage could be
initiated in an adjacent trap in the same assessment unit or in a
different assessment unit. This concept of conservative definition of an
initial, well-characterized volume of a geological commodity (in this
case, storage volume) that can grow over time as the geologic setting of
the commodity continues to be evaluated is another way to describe the
fundamental definitions of reserve, resource, and reserve growth that
will be implemented in the USGS assessment methodology.

Although the geological relationships between the storage properties of
the physical traps of depleted oil and gas fields and the properties of
the larger potential storage volumes within the saline formation of the
same assessment unit are clear, developing geologically sound
mathematical methods to estimate the storage volume of saline formations
is difficult for several reasons. First, the number of direct
measurements of the properties of the storage unit and overlying seal
may be very limited. A saline formation may have only one well
penetration or no penetrations at all within a 100 square mile area.
Even if there is one or even several penetrations of the formation, the
amount of information available for characterization of the injectivity
of the formation or the integrity of the seal may be limited. The
limited data availability will not preclude estimates of storage volume,
but it will result in large ranges of uncertainties in the estimated
storage volumes. The largest uncertainties caused by sparse data may be
in the uncertainties in risk parameters such as potential for leakage
and/or the injectivity of the formation.

Risk parameters can be incorporated into numerical assessments of
geological commodities such as storage volume in two distinctly
different ways. Values can be assigned to risks on a standardized scale,
the values for all risks totaled, and then the calculated volumes can be
ranked by total risk. A more rigorous method is to assign a probability
to each independent risk factor, and then multiply these factors to
arrive at the overall "riskiness" of the storage volume. That overall
risk factor is then used to reduce the calculated volume of potential
storage. This method results in probabilistic ranges of storage volumes
that can be compared between assessment units within a single basin or
between basins and regions. This approach is analogous to the process
underlying USGS assessments of oil and gas resources that we describe as
"fully risked" and is the method we will incorporate in the USGS
methodology for assessment of CO~2~ storage capacity.

Another aspect of CO~2~ storage in saline formations that impacts our
evaluation of risk factors is the scale of storage projects and the
volumes of CO~2~ that must be injected into storage formations as
geological sequestration is fully deployed. The CO~2~ emitted by a
single, 1000 megawatt coal-fired electrical generating station is
roughly 8 million tons per year. If that CO~2~ is captured and injected
into the subsurface, it will displace about 84 million barrels of
formation water. Over the lifetime of a single full-scale storage
project of this size, for example, for 50 years, the total volume of
CO~2~ injected into the subsurface, and the volume of water displaced,
will be equivalent in volume to about 4.1 billion barrels of oil. This
volume corresponds to a 'giant' oil field, according to terminology used
in describing oil field sizes. There are physical traps of this size in
the United States, but the number is limited. The geospatial mismatch
between size of storage needed for sequestration projects and the
location of large sources of CO~2~ has been addressed in a USGS report
published in 2006 (Brennan and Burruss, 2006). If geologic sequestration
is deployed to the extent that the Nation is storing about 500 million
tons of CO~2~ per year, equivalent to emissions from 50 to 60 coal-fired
power plants of 1000 megawatt size, then we must recognize that the
storage process will displace about 0.6 km^3^ or 172 billion gallons of
formation water each year. Such large movements of saline formation
water have the potential to disturb regional ground-water flow systems,
possibly displacing saline formation water laterally or vertically to
near-surface environments where it could contaminate shallower drinking
water supplies or impact ecosystems

The size of storage projects also impacts our concepts for evaluating
risks of CO~2~ storage. Estimates of the total area of a geological
storage site will determine the area that must be characterized
geologically and hydrologically prior to injection, monitored during
injection, and then continually monitored for sometime into the future
once the injection phase of the project ends and long-term storage
begins. However, for the same volume of total storage, there is an
important difference between storage in physical traps and storage in
saline formations.

In a physical trap with lateral barriers to flow, injected CO~2~ will
fill a thickness of the formation up to a maximum defined by the spill
point of the trap. Within that interval, CO~2~ can occupy up to 50 or 60
percent of the pore volume of the formation. In contrast, the CO~2~
injected into saline formations will rise vertically to the base of the
sealing formation and spread laterally. Models of this process and
experience at the Sleipner project in the North Sea show that the total
fraction of pore space occupied by injected CO~2~ is small, on the order
of 2 to 5 percent, although in some geologically heterogeneous
formations this fraction could increase to 10 to 20 percent. This
difference between high efficiency of storage in traps and low
efficiency in saline formations means that for the same quantity of
CO~2~ stored, the surface area above a storage site in a saline
formation that corresponds to the spatial extent of injected CO~2~ in
the subsurface will be at least 2 times larger to as much as 20 times
larger than the area above equivalent storage in a physical trap. The
larger surface area above storage sites in saline formations will
increase the effort necessary to characterize risks of storage and to
monitor the site during the lifetime of a sequestration project.

The focus of USGS evaluations of risks of geologic sequestration is at
the regional or basin scale where the total volume of storage from
deployment of multiple, full-scale projects may have the greatest impact
on movement of formation water and injected CO~2~. Evaluation of these
risks is dependent on knowledge of the geology and hydrology of the
regional assessment unit. This analysis of risks is different from the
risks evaluated in the proposed EPA rules on geologic sequestration
where the emphasis is on evaluation and mitigation of the risks at the
scale of individual storage projects. USGS does not evaluate individual
projects. However, the regional scale risks may impact individual
projects. USGS collaboration with EPA on risk issues ranges from
informal discussions about subsurface fluid flow and area of review with
the Underground Injection Control Program, to USGS participation in the
public stakeholder meetings that EPA held as part of the current
rulemaking process. We look forward to closer collaboration with EPA as
development of our methodology proceeds and during assessment of storage
capacity.

**Concluding Remarks**

In this statement, I have summarized some of the basic aspects of
geological CO~2~ sequestration and described some of the fundamental
concepts underlying resource assessments that the USGS is employing to
develop a probabilistic methodology for assessment of CO~2~ storage
capacity in both the physical traps of depleted oil and gas fields and
in saline formations. In addition, I have discussed some of the concepts
of geological risk that must be incorporated into the assessment
methodology. The present USGS work addresses the activity authorized
under Section 711 of the Energy Independence and Security Act (P.L.
110-140) to develop an assessment methodology that can be applied
consistently across the Nation. As noted above, the methodology
development is being conducted in coordination with a number of
organizations to maximize the usefulness of the assessment to a variety
of partners and stakeholders, including the Department of Energy, the
Environmental Protection Agency, other Agencies within the Department of
the Interior, and State Geological Surveys.

Thank you for the opportunity to present this testimony. I will be happy
to answer any questions you may have.

References:

Bachu, S., Bonijoly, D., Bradshaw, J., Burruss, R., Holloway, S.,
Christensen, N.P., Mathiassen, O.M., 2007, CO~2~ storage capacity
estimation: Methodology and gaps, International Journal of Greenhouse
Gas Control, v. p. 430-443.

Brennan, S. T., and Burruss, R. C., 2006, Specific Storage Volumes: A
useful tool for CO~2~ storage capacity assessment, Natural Resources
Research, v. 15, pp. 165 -182, DOI: 10.1007/s11053-006-9019-0

Intergovernmental Panel on Climate Change (IPCC), 2005, IPCC Special
Report on Carbon Dioxide Capture and Storage. Prepared by Working Group
III of the Intergovernmental Panel on Climate Change \[Metz, B., O.
Davidson, H. C. de Coninck, M. Loos, and L. A. Meyer (eds.)\], Cambridge
University Press, Cambridge, United Kingdom and New York, NY, USA, 442
pp.

Society of Petroleum Engineers (SPE), American Association of Petroleum
Geologists (AAPG), World Petroleum Congress (WPC), and Society of
Petroleum Evaluation Engineers (SPEE), 2007, Petroleum Resources
Management System, 49 p.,
<http://www.spe.org/spe-app/spe/industry/reserves/prms.htm>, downloaded
July 2, 2008.