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44 Oilfield Review
CO2 Capture and Storage—A Solution Within
Kamel Bennaceur
Gatwick, England
Neeraj Gupta
Battelle Memorial Institute
Columbus, Ohio, USA
Shinichi Sakurai
Bureau of Economic Geology
Austin, Texas
Steve Whittaker
Saskatchewan Industry and Resources
Regina, Saskatchewan
Mike Monea
Petroleum Technology Research Center
Regina, Saskatchewan, Canada
T.S. Ramakrishnan
Ridgefield, Connecticut, USA
Trygve Randen
Stavanger, Norway
For help in preparation of this article, thanks to Véronique
Barlet-Gouédart, Clamart, France; Austin Boyd, Ridgefield,
Connecticut, USA; Pietro Di Zanno, Air Liquide, Paris, France;
Martin Isaacs, Ali Mazen, Karen Sullivan Glaser, Erik Nelson
and Alexander Zazovsky, Sugar Land, Texas, USA; Philippe
Lacour-Gayet, New York, New York, USA; Susan Hovorka,
MDT (Modular Formation Dynamics Tester), NGS (Natural
Gamma Ray Spectrometry), Platform Express, RST (Reservoir
Saturation Tool) and USI (UltraSonic Imager) are marks 
of Schlumberger.
Bureau of Economic Geology, Austin, Texas; Geoff Maitland,
Cambridge, England; Lars Sonneland, Stavanger, Norway;
and Tore Torp, Statoil, Trondheim, Norway.
AIT (Array Induction Imager Tool), CMR (Combinable 
Magnetic Resonance), DSI (Dipole Shear Sonic Imager),
ECLIPSE 300, FMI (Fullbore Formation MicroImager), 
Burning fossil fuels releases carbon dioxide into the atmosphere. Many scientists believe this contributes, at least in part, 
to the current upward trend in the Earth’s surface temperature. Capturing and storing carbon dioxide in the subsurface may 
be one of the most promising of the likely short-term solutions to stabilize and reduce atmospheric carbon dioxide concentration.
The technology, although potentially costly, is available now and has been widely used in the oil and gas industry.
Autumn 2004 45
The people of Earth have a problem. Our planet’s
surface is warming at a rate that concerns many
scientists and climatologists. Various models
have predicted outcomes that beg for action.
While the data clearly show that the Earth’s
northern hemisphere is warming and there is
strong evidence that anthropogenic—human
influence on nature—effects exist, the pre-
dicted consequences are poorly understood and
contested because the complexities and uncer-
tainties in modeling are enormous. However,
there is credible evidence that the current
warming trend is partly due to the increased
carbon dioxide [CO2] concentration in the atmo-
sphere from burning fossil fuels and other
processes. With worldwide investment in, and
dependence on, low-cost fossil fuels, it is uncer-
tain whether we can extricate ourselves from
this potentially dire situation, particularly 
when we consider the colossal financial burden
associated with the restructuring necessary to
significantly decrease fossil fuel use.
Global warming and its potential impact
have been widely discussed in government,
academia and industry, and covered extensively
in science and technical journals.1 Between
those who deny the problem exists and those
who hyperbolize the global-warming conse-
quences and required actions, there is a rational
approach that relies on innovation and technol-
ogy. A seed taking root in this valuable middle
ground is the process of capturing and securely
storing CO2—also called CO2 sequestration—
that would otherwise be released into the
atmosphere. This article discusses subsurface
CO2 storage and its potential role in the reduc-
tion of CO2 emissions. We present case studies of
CO2 projects that explore the application of 
current oilfield technologies, and we examine
some industry challenges that lie ahead.
CO2 and the Climate
Since the late 19th century, the average global
surface temperature has increased by 0.6°C
[1.1°F], which according to the Intergovernmental
Panel on Climate Change (IPCC), represents the
largest warming rate for the last 1,000 years, as
derived from ice-core and tree-ring data. The
20th century warming largely occurred in two
periods, the first from 1910 to 1945, and the sec-
ond from 1976 to the present (above right).2
While the global surface temperature has fluctu-
ated throughout geological time, examination of
ice cores shows that the latest warming is occur-
ring with an increase in greenhouse gases
(GHGs), which include CO2, methane [CH4] and
nitrous oxide [N2O]. Atmospheric concentra-
tions of these GHGs increased drastically during
the 20th century. 
While CO2 has a relatively small global-
warming potential compared with other GHGs,
the sheer volume of CO2 released into the atmo-
sphere as a by-product of burning fossil fuels
makes it the largest contributor. Globally, over
23 billion short tons [21 billion metric tons] of
CO2, or 6.3 billion short tons [5.7 billion metric
tons] of carbon, were released into the 
atmosphere in 2001 as a result of burning oil,
gas, coal and wood. Some estimates place 
the total CO2 emissions from oil, gas and coal at
more than 35 billion metric tons [38.6 billion
short tons] by 2025.3
Sophisticated simulations have modeled
future climate response to higher GHG concen-
trations. In global-climate models, some factors
warm the Earth—positive forcing—while some
factors cool the Earth—negative forcing. Each
of these factors must be taken into account. For
example, increased GHG concentrations and 
1. Cannell M, Filas J, Harries J, Jenkins G, Parry M, Rutter P,
Sonneland L and Walker J: “Global Warming and the E&P
Industry,” Oilfield Review 13, no. 3 (Autumn 2001): 44–59.
2. “Climate Change 2001: Working Group I: The Scientific
Basis, Intergovernmental Panel on Climate Change (IPCC),”
http://www.grida.no/climate/ipcc_tar/wg1/067.htm#231
(accessed September 29, 2004).
3. “EIA, System for the Analysis of Global Energy Markets
(2004),” http://www.eia.doe.gov/oiaf/ieo/figure_17.html
(accessed September 8, 2004).
>Modern cooling and warming. Data from tree rings, corals, ice cores and
historical records (blue) for the last 1,000 years show fluctuations in the
northern hemisphere’s temperatures (top). However, recent data from
thermometers (red) show a pronounced warming trend. The recent record
from 1861 to 2000 shows combined annual land-surface, air and sea-
surface temperature deviation from the 1961–1990 average temperature
(bottom). The warming occurred in two periods, the first from 1910 to 1945,
and the second from 1976 to the present. Error bars indicate the certainty
of the temperature measurements in each year.
1600
De
pa
rtu
re
s 
in
 te
m
pe
ra
tu
re
fro
m
 th
e 
19
61
 to
 1
99
0 
av
er
ag
e,
 °C
–1.0
–0.5
0
0.5
1800 2000140012001000
Year
Northern Hemisphere
Data from thermometers (red) and from tree rings,
corals, ice cores and historical records (blue)
1860
Year
1880 1900 1920 1940 1960 1980 2000
–0.8
–0.4
0
0.4
0.8
De
pa
rtu
re
s 
in
 te
m
pe
ra
tu
re
fro
m
 th
e 
19
61
 to
 1
99
0 
av
er
ag
e,
 °C
Data from thermometers
Global
tropospheric ozone levels are positive forcing,
while increased tropospheric and stratospheric
aerosols and cloud cover produce negative forc-
ing. Some of these factors are well-understood,
as for example, that of CO2 concentrations
(above). However, other forcing mechanisms are
not understood. Cloud cover remains a major
source of uncertainty in climate modeling because
of the large variety of complex and interactive 
processes that contribute to cloud formation.4
During the last decade, climate modeling has
improved immensely, aided by steadily improving
computing power and increased resources
devoted to the global-warming phenomenon.
Improved modeling is extremely important
because it allows scientists to predict the scale,
timing and consequences of global warming with
greater certainty. After all, the consequences,
along with technology and economics, will 
ultimately drive government and business 
decisions about how best to address the problem.
Similar to reservoir forecasting, climate mod-
eling relies on history-matching and models. The
models include both naturaland anthropogenic
effects to yield a reasonable match. Numerous
scenarios based on future CO2 emissions and
other factors produce a wide range of outcomes.
CO2 concentration is predicted to increase from
today’s level of 374 parts per million (ppm) to
550 to 1,000 ppm by 2100, resulting in a temper-
ature increase of 2 to 4.5°C [3.6 to 8.1°F].5
However, the “business as usual” scenario
assumes that the world’s increased use of fossil
fuels continues as in the past. Projecting this
scenario to 2100 may be unrealistic, given the
steady advance of technology, the decreasing
supply and increasing cost of oil, the growing
use of cleaner-burning natural gas, and renew-
able energy sources—for example, solar and
wind power.6 It is for this reason that IPCC pro-
jections include a variety of scenarios.
Climate-change predictions for modeling
must be translated to actual climatic events on
Earth and described in terms of human costs.
Predictions based on conjecture include a rise in
sea level that would flood low-lying coastal
areas, impacting densely populated areas and
natural habitats. Weather events, including
floods and droughts, are predicted to radically
change the world’s vegetated zones. Glacier 
and arctic ice-melting rates are predicted 
to increase, threatening to change ocean 
circulation patterns and reduce the number of 
cold-water marine species, such as cod and 
haddock. Studies also foresee an increase in
human and animal diseases as a result of alter-
ing weather patterns. 
There is some evidence that several of these
symptoms of global warming are already occur-
ring, making the estimation of both human and
financial costs more urgent. However, many of
these studies do not take into account man’s his-
torical adaptive responses to climate changes,
and some experts argue that the economic cost
of adapting would be significantly less than the
cost of drastic actions to stabilize the climate.7
The debate on how likely and how severe the
consequences will be remains unresolved.
The Earth’s atmospheric CO2 content
increases as a result of both natural and 
man-made emissions. This CO2 remains in the
atmosphere for several decades, and is slowly
removed by natural sinks that store CO2 for
indefinite periods of time. Oceans store vast
amounts of CO2, and vegetation and soils also
produce a common sink mechanism. Never-
theless, it has become clear to many scientists
that humans must work to diminish anthro-
pogenic effects, primarily those derived from
burning fossil fuels.
Coal is the world’s most abundant fossil fuel
energy source. However, it also produces a large
amount—around 40%—of CO2 emissions from
fossil fuels. It remains a primary concern for 
climate and environmental scientists because, in
many regions, coal represents both a long-term
and economical supply of energy, and is mainly
burned for electricity generation in power plants.
Innovative ways to reduce CO2 emissions and
their impact on the environment and climate are
being developed to enable the continued burning
of this important fuel (see “Produce Coalbed
Methane, Hold the Carbon,” page 60).
Long-term remedies involve dramatic reduc-
tion or elimination of man-made CO2 emissions
from the burning of fossil fuels (next page, top).
In the short term, this is not a realistic solution
because the cost of switching to alternative
sources of energy would be enormous and would,
in itself, contribute to significant energy con-
sumption. Moreover, there is no suitable
replacement for oil, gas and coal currently 
available to power the world’s economies. Short-
term options may involve reducing CO2
emissions by using less energy through improved
46 Oilfield Review
> Forcing factors for global warming. The effect on global warming caused by changes in concentration
of some gas species, such as CO2, is well-understood, but the effects of solar activity and those of land
use, which affects reflectivity or albedo, are poorly known. The global, annual-mean radiative forcing
due to a number of agents is shown for the period from 1750 to the late 1990s. The height of the
rectangular bar denotes a central or best-estimate value. The vertical line about the rectangular bar
with “x” delimiters indicates an estimate of the uncertainty range. A vertical line without a rectangular
bar and with “o” delimiters denotes a forcing for which no central estimate can be given owing to
large uncertainties. The uncertainty range specified here is a best-guess and is not based on
statistics. A “level of scientific understanding” index represents the subjective judgment about the
reliability of the forcing estimate, involving factors such as the assumptions necessary to evaluate the
forcing, the degree of knowledge of the physical and chemical mechanisms determining the forcing,
and the uncertainties surrounding the quantitative estimate of the forcing.
Ra
di
at
iv
e 
fo
rc
in
g,
 W
/m
2
W
ar
m
in
g
Co
ol
in
g
3
2
1
0
–1
–2
–3
Stratospheric
ozone
Sulfate
Fossil
fuel
burning
(organic
carbon)
Biomass
burning
Mineral
dust
Halocarbons
N2O
CH4
CO2
Tropospheric
ozone
Fossil
fuel
burning
(black
carbon)
Contrails Cirrus
Solar
Land use
(albedo)
Tropospheric
aerosol direct
effect (1st type)
High Medium Medium Low Very
low
Very
low
Very
low
Very
low
Very
low
Very
low
Very
low
Very
low
Level of scientific understanding
Aviation-induced
clouds
Aerosols
Autumn 2004 47
efficiency while moving to low- or no-emission
energy sources. Many scientists believe part of
the short-term—within the next few decades—
solution is to capture and store CO2 from the
processes that create the largest or the most
concentrated streams of CO2 gas. Developing
these man-made CO2 sinks would allow the
world to continue using its cheapest and most
abundant energy resources while significantly
reducing CO2 emissions.
Capturing and Storing CO2 Emissions
The technology to separate and store CO2 is
available now, but will require extensive invest-
ment in infrastructure and considerable
measures to reduce its cost. The separation and
compression of CO2 from emission streams
remain the most expensive part of the process
and can occur before or after the combustion
process. Currently, the most widely used pro-
cess is based on chemical absorption to capture
CO2 from flue gas using monoethanolamine
(MEA) solvent. Flue gas is bubbled through the
solvent in a packed absorber column, where the
solvent preferentially absorbs the CO2. The sol-
vent is heated as it passes through a distillation
unit, stripping the CO2 from the solvent. A con-
centrated gas that is 99% CO2 is produced.8 This
is a high-cost process, so other methods are
being investigated to separate CO2 from the sol-
vent, including the use of microporous
membranes. The joint industry CO2 Capture
Project (CCP) is a collaboration of eight energy
producers, focusing on the development of tech-
nologies that would reduce the cost of carbon
separation and capture.9
New membranes that contain hollow poly-
meric fibers can be used in conjunction with
amine systems. For instance, Air Liquide, a 
company specializing in the treatment and 
distribution of industrial gases, has developed a
membrane technology that separates CO2 from
produced gas streams (right). The feed gas
enters from the outside shell at a higher pres-
sure than that in the internal sections and,
because of differential pressure and selective
permeation across the polymeric fiber mem-
brane, gases are separated.
4. “Climate Change 2001: Working Group I: The Scientific
Basis, Intergovernmental Panel on Climate Change (IPCC),”
http://www.grida.no/climate/ipcc_tar/wg1/271.htm
(accessed September 29, 2004).
5. The concentration of CO2 is not uniform across the Earth.
Higher concentrations are found in the northern 
hemisphere than in the southern hemisphere.
> Percentages of CO2 emissions produced by various economic sectors.
Other
4%
Agriculture
2%Residential
10%
Transport
23%
Industry
22%
Electricity generation
39%Global CO2 Emissions by Sector
> Advanced filters. Membrane technology separates CO2 from
produced gas streams by keeping the feed gas on the outside shell
at a higher pressure than that of the internal sections. Differential
pressure and selective permeation across the polymeric fiber
membrane enable the separation of methane [CH4] and CO2. Air
Liquide developed this technology as a compact, economical and
environmentally friendly CO2 capture alternative to amine-treatment
processes.
Closed fibers
Open fibers
Residue gas
59.8 bar
CH4, C2H6, C3H8
Permeate gas
3 bar
CO2, H2S, H2O
Feed gas
60 bar
CH4, C2H6, C3H8,
CO2’ H2S, H2O
6. Lomborg B: The Skeptical Environmentalist: Measuring
the Real State of the World. Cambridge, England: 
Cambridge University Press (2001): 258–324.
7. Lomborg, reference 6.
De Vries B, Bollen J, Bouwman L, den Elzen M,
Janssen M and Kreileman E: “Greenhouse Gas Emissions
in an Equity-, Environment and Service-Oriented World:
An IMAGE-Based Scenario for the Next Century,” 
Technological Forecasting & Social Change 63, no. 2–3
(February-March 2000): 137–174.
8. Herzog H and Golomb D: “Carbon Capture and 
Storage from Fossil Fuel Use,” http://sequestration.
mit.edu/pdf/enclyclopedia_of_energy_article.pdf
(accessed September 8, 2004).
9. For more on the CO2 Capture Project: http://www.
co2captureproject.org/index.htm (accessed 
October 11, 2004).
There are also methods to remove the CO2
from fuels prior to combustion. In addition, sepa-
ration of nitrogen from air using air-separation
units prior to combustion reduces the emission of
nitrogen oxides and sulfur oxides. Advanced fuel-
conversion technologies produce hydrogen [H2]
fuel from fossil fuels and capture CO2 to mitigate
emissions. For example, coal gasification uses sol-
vents to produce carbon monoxide [CO] and H2.
Reacting CO with water produces CO2 and more
H2. The CO2 can be processed, transported and
stored, while the H2 fuels gas turbines for elec-
tricity generation and can be used in hydrogen
fuel cells for transportation vehicles. 
This technology is the core of projects like
the US FutureGen project, a US$1 billion pilot
program, and the European HyPOGEN project,
to create a zero-emission, coal-fired power plant
that sequesters CO2 and produces H2 for use in
fuel cells.10 Separation infrastructure requires a
large capital investment, and the technologies
used must be appropriate for both the source
and volume being processed.
There are several ways of storing CO2 (above
left). Some involve enhancing natural sinks in
terrestrial ecosystems and oceans, such as refor-
estation on land and iron fertilization of oceans.
One proposed method dissolves CO2 into seawa-
ter and then injects the mixture into the ocean
at depths between 1,500 and 3,000 m [4,920 and
9,840 ft]. Another method directly places CO2
liquid deep in the ocean, exploiting the density
contrast between liquid CO2 and salt water.
Despite the fact that the ocean represents the
largest total storage potential, likely around
40,000 billion metric tons [44,000 billion short
tons] of carbon, the possible environmental
impact on marine life near the injection point is
a major drawback. Ocean storage is unlikely to
be the preferred mode, given that the environ-
mental impact has not been adequately
addressed. While the storage of the world’s
anthropogenic CO2 emissions will likely require
the combination of many different storage
options, the oil and gas industry has had little
involvement in ocean-storage techniques. Many
scientists view geological storage as the alterna-
tive that carries the lowest risk.
Given its vast experience in reservoir man-
agement and its extensive range of technologies,
the oil and gas industry is poised to take a 
leading role in the storage of CO2 in geological
formations, such as depleted reservoirs, deep
saline aquifers and coalbeds. Moreover, many
joint projects are under way to assess the 
potential of subsurface storage.
48 Oilfield Review
> CO2 storage options. Ocean storage represents the largest potential for carbon storage, but is
thought to carry a higher level of environmental risk. The remaining four are geologic storage options,
of which the largest capacity is estimated to be in saline reservoirs. The annual global carbon
emissions in the year 2000 were 6.2 billion metric tons [6.8 billion short tons].
Ca
pa
ci
ty
, b
ill
io
n 
m
et
ric
 to
ns
 c
ar
bo
n
100,000
10,000
6,000
3,000
2,000
1,000
0
4,000
5,000
Deep
ocean
Saline
reservoirs
Depleted
oil
reservoirs
Depleted
gas
reservoirs
Coalbed
reservoirs
Storage options
Year 2000
Annual global
carbon emissions
Maximum
Minimum
6.2 billion
metric tons
> CO2 phase diagram. The diagram describes the relationship between
temperature and pressure on the resultant phase of CO2. Subsurface storage
of CO2 is accomplished at supercritical conditions. To ensure this, both the
phase behavior of CO2 and the reservoir conditions must be understood,
since the reservoir temperature and pressure conditions are likely to change
throughout the life of a CO2 storage project.
Temperature, °F
Critical
point
Triple point
Liquid
Solid
Vapor
Normal boiling point
Hydrate
Liquid CO2
Liquid H2O
Liquid H2O
Vapor CO2
Hydrate
Pr
es
su
re
, M
Pa
0.07
0.007
7
0.7
Temperature, °C
-100 -80 -60 -40 -20 0 20 40
–160 –120 –80 –40 0 40 80 120
Pr
es
su
re
, p
si
a
1,000
100
10
1
Pure CO2
CO2 hydrate conditions
Water freezing conditions
Autumn 2004 49
Geological storage of CO2 will be more effi-
cient if it is in supercritical conditions. Carbon
dioxide has a low critical temperature of 31°C
[88°F] and a moderate critical pressure of
73.8 bar [1,070.4 psi] (previous page, bottom).
Generally, this means that storage depths of
600 m [1,970 ft] or deeper are required.
In 2002, more than 24 billion metric tons
[26 billion short tons] of CO2 were released into
the atmosphere as a result of fuel combustion.11
Geological storage capacity is estimated at 
hundreds to thousands of gigatons of carbon,
equivalent to hundreds of years of storage at the
current emission rate. The storage of CO2 in the
subsurface requires various technologies and
types of expertise to characterize the storage
zone and surrounding strata, to drill and accu-
rately place wellbores, to design and construct
surface facilities, to monitor wells and fields,
and to optimize systems (above).
The Sleipner Project
While CO2 has been used for enhanced oil 
recovery (EOR) for decades, CO2 capture and
storage (CCS) were first achieved in 1996 by 
Statoil and its partners in the North Sea 
Sleipner gas field, 250 km [150 miles] west of
Stavanger, Norway.12 The field produces natural
gas containing approximately 9% CO2, but to
meet specifications, the CO2 concentration had
to be reduced to 2.5%. Statoil must pay a 
Norwegian offshore carbon tax of 300 NOK—
currently around US$45—per metric ton of CO2
released into the atmosphere. Because Statoil is
required to separate the CO2, and incurs great
> Expertise in CO2 processing and storage. The broad expertise of the oil and gas service sector spans much of the process map of CO2 sequestration,
especially the secure storage of CO2 in the subsurface. Relevant processes are labeled in bold.
Injection plant
H2 storage
underground
Gas
Compression plant
CO2
injection
Coalbed
methane
Enhanced
coalbed
methane
CO2 capture
and separation
plant
Enhanced
horticulture
Mineral
products
Aluminum
Power
plant
Gas to liquids
Power plant
Carbonate products
CO2 sto
rage
in deep
 saline
aquifer
s
Enhanc
ed
oil reco
very
CO2
injection
Coal
Hydrocarbon or
hydrogen storage
Products
CO2
Fossil fuels
10. “FutureGen—Tomorrow’s Pollution-Free Power Plant,”
http://www.fossil.energy.gov/programs/powersystems/
futuregen/index.html (accessed September 29, 2004).
“FutureGen—A Sequestration and Hydrogen 
Research Initiative,” http://www.energy.gov/engine/
doe/files/import/FutureGenFactSheet.pdf (accessed
September 29, 2004).“European Hydrogen and Fuel Cell Technology Platform,
Steering Panel: Deployment Strategy June 16, 2004,”
http://www.hfpeurope.org/docs/
HFP-DS-005_V1-2004_Presentations_16JUN2004.pdf
(accessed October 5, 2004).
11. http://library.iea.org/dbtw-wpd/Textbase/nppdf/free/
2004/keyworld2004.pdf (accessed October 5, 2004).
12. “Best Practice Manual from SACS – Saline Aquifer 
CO2 Storage Project,” http://www.co2store.org/
TEK/FOT/SVG03178.nsf/Attachments/
SACSBestPractiseManual.pdf/$FILE/
SACSBestPractiseManual.pdf (accessed July 28, 2004).
Torp TA and Gale J: “Demonstrating Storage of CO2 in
Geological Reservoirs: The Sleipner and SACS Project,”
paper B1-1, presented at the 6th Greenhouse Gas Control
Technologies Conference (GHGT6), Kyoto, Japan, 
October 1–4, 2002.
Baklid A, Korbøl R and Owren G: “Sleipner Vest CO2
Disposal, CO2 Injection into a Shallow Underground
Aquifer,” paper SPE 36600, presented at the SPE 
Annual Technical Conference and Exhibition, Denver,
October 6–9, 1996.
expense when CO2 is released, CCS became 
economically viable.13 To deal effectively with
CO2, Statoil captures and separates it using MEA 
solvent and then injects CO2 into the Utsira 
formation using a single highly deviated injec-
tion well (above). The Sleipner project has been
injecting 1 million metric tons [1.1 million short
tons] of CO2 per year since September 1996 at a
supercritical bottomhole flowing pressure of
approximately 10.5 MPa [1,523 psi], which is
below the Utsira fracture pressure.
Since 1996, the Sleipner operation has
injected over 7 million metric tons [7.7 million
short tons] of CO2 and the plan is to continue until
2020. Through the dedicated work of scientists
and the support of industry, Sleipner represents
the first industry-scale CCS project and the
groundwork for successful future projects.
The Utsira formation, a regional saline
aquifer at a depth of 800 to 1,000 m [2,625 to
3,280 ft] below the seabed at Sleipner field, is
50 Oilfield Review
> A milestone at the Sleipner field. Statoil separates CO2 from gas produced from the Heimdal formation and injects 1 million metric
tons [1.1 million short tons] of CO2 per year into the overlying Utsira formation.
Ula
Ekofisk
Sleipner
Heimdal
Frigg
Gullfaks
Statfjord
Stavanger
NORWAY
GERMANY
DENMARK
Sleipner
West
Sleipner
East
m0 1,000
ft0 3,280
Sleipner T Sleipner A
CO2
Sleipner East production
and injection wells
CO2 injection well
Utsira formation
Heimdal formation
De
pt
h,
 m
1,000
500
0
1,500
2,000
2,500
Seabed
N o r t h
S e a
Autumn 2004 51
composed of uncemented quartz and feldspar
sand with porosities from 27% to 40% and perme-
abilities from 1 to 8 darcies. It contains thin
layers of shale that act as permeability baffles.14
Its thickness ranges from 200 to 300 m [656 to
984 ft], and its total available storage volume,
estimated at 660 million m3 [23.3 billion ft3],
could store 600 billion metric tons [660 billion
short tons] of CO2.
Well logs indicate that the Utsira zone 
is well-defined, with sharp upper and basal con-
tacts. An overlying caprock is several hundred
meters thick, beginning with a shale layer and
overlain by prograding sequences that grade
from shales at the basin center to sandier facies
towards the basin margins. The top of the
caprock sequence consists mostly of glacio-
marine clays and glacial tills. Close examination
of seismic, log and core data suggests that this
caprock sequence forms an effective seal over
the Utsira formation.
Potential stratigraphic and structural 
barriers within the Utsira formation could affect
CO2 migration dramatically. For this reason, an 
extensive characterization of the aquifer was
paramount. Established in 1998 and supported
under the European Commission’s Thermie 
Program, the Saline Aquifer CO2 Storage (SACS)
project and the subsequent SACS2 project
employed a multidisciplinary approach to
develop “best practices” in the research, moni-
toring and simulation of CO2 migration in
subsurface storage aquifers. An important part
of the project involves the time-lapse monitoring
of the CO2 storage volume using three-
dimensional (3D) seismic surveys.
Schlumberger has acquired four seismic 
surveys supporting this study: first in 1994
before injection started in 1996, the second in
1999, the third in 2001, and a fourth in 2002
(above right).15 The location and migration of
supercritical CO2 are visible, and geophysicists
have determined from modeling and time-lapse
(4D) seismic data that high impedance contrast
allows detection of CO2 accumulations as thin as
1 m [3.3 ft]. The ability to observe such thin
accumulations gives scientists confidence that
no CO2 leakage is occurring beyond the overlying
caprock. Schlumberger has been involved in
data analysis and in the development of CO2
monitoring and simulation workflows.
As the key monitoring technology, seismic
data have also shown the migration behavior of
CO2 in the aquifer. Thin shale layers within the
Utsira storage interval dramatically affect the
CO2 distribution. Because of its buoyancy, CO2 is
forced to migrate laterally for several hundred
meters beneath the shale layers. Modeling
shows that over long periods, as the brine
becomes more enriched with CO2, the mixture
grows denser than the water below, forming 
currents and enhancing dissolution.16 The
physics of dissolution, segregation and mixing
varies depending on the characteristics of the
reservoir, and specific simulations are necessary.
Storage mechanisms involving dissolution from
convective mixing of supercritical CO2 are
thought to take from centuries to millennia.
Exploiting the impedance contrasts between
the volume now containing CO2 and the volume
previously containing only brine, scientists have
built elastic models to simulate various CO2
accumulation scenarios.17 Geophysicists have
13. Herzog HJ: “What Future for Carbon Capture and
Sequestration?” http://sequestration.mit.edu/
pdf/EST_web_article.pdf (accessed July 28, 2004).
14. Chadwick RA, Zweigel P, Gregersen U, Kirby GA, 
Holloway S and Johannessen PN: “Geological 
Characterisation of CO2 Storage Sites: Lessons from
Sleipner, Northern North Sea,” paper B1-3, presented 
at the 6th International Conference on Greenhouse 
Gas Control Technologies, Kyoto, Japan, 
October 1–4, 2002.
15. Experts from various institutions, companies and 
governments have collaborated to produce a series of
best practices for future CO2 projects. This document is
available to the public at http://www.co2store.org/
TEK/FOT/SVG03178.nsf/Attachments/
SACSBestPractiseManual.pdf/$FILE/
SACSBestPractiseManual.pdf.
> The value of time-lapse seismic data. At Sleipner field, enhanced amplitude sections of time-lapse
seismic surveys indicate the growing CO2 bubble (top). Maps of the integrated reflection amplitudes
show the areal growth of the storage volume (bottom). Four surveys that monitored the migration and
dissolution behavior of injected CO2, verify the competence of the seal. Schlumberger and Statoil
gained valuable experience in monitoring CO2 storage operations. The 2002 survey is not shown
because it differs only slightly from the 2001 survey.
Enhanced Amplitude Sections
1999
Injection point
2001
PP
 tr
av
el
tim
e,
 s
–0.8
–1.0
–1.2
1994
Top Utsira sand
Base Utsira sand 500 m
1,640 ft
1999 2001
Integrated Reflection Amplitudes
1994
500 m
1,640 ft
16. Ennis-King J and Paterson L: “Role of Convective Mixing
in the Long-Term Storage of Carbon Dioxide in Deep
Saline Formations,” paper SPE 84344, presented at the
SPE Annual Technical Conference and Exhibition, 
Denver, October 5–8, 2003.
17. Chadwick A, Noy D, Arts R and Eiken O: “4D Geophysical
Monitoring of the CO2 Plume at Sleipner, North Sea: 
Current Status and Aspects of Uncertainty,” prepared 
for presentation at the 7th SEGJ International 
Symposium on Imaging Technology, Sendai, Japan,
November 24–26, 2004.
Lygren M, Lindeberg E, Bergmo P, Dahl GV, Halvorsen KÅ,
Randen T and Sonneland L: “History Matchingof CO2
Flow Models using Seismic Modeling and Time-Lapse
Data,” presented at the SEG International Exposition 
and 72nd Annual Meeting, Salt Lake City, Utah, USA,
October 6–11, 2002.
analyzed and modeled seismic pushdown effects,
which result from a reduction in compressional
wave velocity through the CO2 storage interval
and which cause an increase in traveltime for
reflections within and below the CO2 storage
interval (below right). Project scientists believe
that the CO2 is distributed as a combination of
thin high-concentration layers and dispersed
CO2. The modeled velocity pushdown due to the
thin layers alone is lower than the observed
pushdown. The difference, or residual push-
down, is attributed to the presence of dispersed,
lower saturation CO2 between the high-concen-
tration layers.
The distribution of dispersed CO2 can be cal-
culated by mapping saturations to the residual
pushdown. In addition, modeling reveals how
storage temperature influences the estimation
of total CO2 volume. Pushdown volumes from
time-lapse seismic data have been history-
matched with various flow models to help define
flow across the Utsira shale layers. This work has
been instrumental in understanding the size and
extent of the CO2 bubble and the estimation of
CO2 volume.
The SACS project also investigated another
long-term CO2 storage mechanism associated
with the subsurface called mineral trapping.
Mineral trapping could occur when CO2 reacts
with noncarbonate, calcium-rich, iron-rich and
magnesium-rich minerals to form carbonate 
precipitates. In the Sleipner case, drill-cuttings
studies have shown that mineral trapping is not
a major factor because of the limited reactivity
between CO2 and the Utsira formation. In addi-
tion, these studies have shown small porosity
decreases observed at the base of the caprock
could further enhance sealing on a very long
time scale.18 Mineral trapping could be a signifi-
cant geological storage mechanism in other
reservoirs and would likely impact the porosity
and permeability within the reservoir.19
Before the SACS2 project completion in 
June 2002, the SACS and SACS2 projects 
had examined a full range of reservoir-
characterization, monitoring and simulation
problems and published their findings and 
recommendations in a Best Practice Manual.
However, the work continues in a European
Union-supported project called CO2STORE,
which began in February 2003. The latest project
focuses on long-term storage aspects, other 
monitoring techniques and, with the knowledge
gained from the Sleipner project, the develop-
ment of site-specific plans for CO2 storage
elsewhere in Europe. Partnering with power 
producers, new CO2STORE projects have been
initiated in Denmark, Germany, Norway and the
United Kingdom.
Win-Win at Weyburn
Enhanced oil recovery (EOR) using CO2 has
occurred since the 1970s, and has proved to be
one of the most effective EOR methods in light-
to medium-oil reservoirs. Supercritical CO2 has a
density similar to that of oil, but with a substan-
tially lower viscosity. In miscible floods, CO2
mixes with the oil, causing the oil to swell and
become less viscous. Higher pressures at the
injector wells, coupled with the swelling oil,
push the oil to producing wells, boosting oil 
production and recovery. In traditional EOR
operations, concerns about the fate of the CO2
after injection were secondary to its impact on
production. Consequently, most operators did
not attempt to determine the amount of CO2
that was being stored, or that could be stored,
and did not tailor monitoring, modeling and 
simulation efforts to characterize the behavior
of CO2 in the swept reservoir, much less after
EOR was completed. Moreover, few EOR projects
have injected CO2 from anthropogenic sources to
help reduce GHG emissions.
PanCanadian Resources, now EnCana 
Corporation, Saskatchewan Industry and
52 Oilfield Review
18. Gaus I, Azaroual M and Czernichowski-Lauriol I: 
“Reactive Transport Modeling of Dissolved CO2 in the
Cap Rock Base during CO2 Sequestration (Sleipner Site,
North Sea),” presented at the 2nd Annual Conference on
Carbon Sequestration, Alexandria, Virginia, USA,
May 5–8, 2003.
19. Torp and Gale, reference 12.
> Pushdown of the base of the Utsira formation. Time-lapse surveys from 1994
and 1999 reveal the pushdown effects (top). The CO2 volumes are estimated
quantitatively from modeling the pushdown effects over time. In the pushdown-
volume maps, the black dot indicates the CO2 injection point (bottom).
0
10
20
30
40
50
60
Ti
m
e 
la
g,
 m
s
1999
500 m
1,640 ft
2001
Base Utsira sand
1994
500 m
1,640 ft
50
0 
m
1,
64
0 
ft
Base Utsira sand
Injection point
1999
Autumn 2004 53
Resources, the Petroleum Technology Research
Center (PTRC) and the International Energy
Agency (IEA) began a unique CCS project in
1999. It involved the transport of CO2 through a
325-km [202-mile] pipeline from a coal gasifica-
tion facility 12.1 km [7.5 miles] northwest of
Beulah, North Dakota, USA, to the Weyburn oil
field near Regina, Saskatchewan, Canada
(right). The Great Plains Synfuels Plant, oper-
ated by the Dakota Gasification Company,
produces methane from the gasification of coal
and the subsequent creation of methane from
the purified product gases. Before the building
of the pipeline, which is owned and operated by
the Dakota Gasification Company, the plant
released most of the CO2 that it produced into
the atmosphere. Currently, this gas is com-
pressed to a pressure of 15.2 MPa [2,200 psi] at
the plant, delivered by pipeline to the 
Weyburn field under supercritical conditions—
14.9 MPa [2,175 psi]—and injected into the 
subsurface. The CO2 is 96% pure, containing
traces of hydrogen sulfide [H2S], nitrogen [N2]
and hydrocarbons.
Discovered in 1954, the Weyburn field pro-
duces oil from the Midale carbonate reservoir at
an average depth of 1,419 m [4,655 ft] within the
Mississippian-age Charles formation (below).
> The first transnational EOR project involving CO2 capture, transport and
storage. The transport of CO2 is accomplished through a pipeline from a coal
gasification facility in North Dakota, USA, to EnCana’s Weyburn oil field in
Saskatchewan, Canada.
100
km0 100
miles0
Regina
Weyburn
Bismark
Beulah
Pipeline
Manitoba
North DakotaMontana
CANADA
USA
Saskatchewan
> Characterizing and modeling the geology of the Weyburn field. Many geologic factors have been incorporated into a risk-assessment model, including the
Midale reservoir and Watrous seal characteristics, regional tectonics, surface lineaments, river systems and hydrogeological flow directions, all of which
could influence CO2 migration behavior.
Bearpaw aqu
itard
Colorado a
quitard
Potable aquifers
Belly River
Joli Fou 
aquitard
Newcastl
e
Mannvill
e
Vanguar
d aquita
rd
CO2 injection well
Jurassic
Watrous
 aquitar
d
Mississ
ippian M
idale be
ds
Level of CO
2 injection
Surface lineaments
Area of detail
10 km
6.2 miles
N
1.
5 
km
0.
98
 m
ile
s
The Midale reservoir is 30 m [98 ft] thick and
includes, from deepest to shallowest, the Midale
Vuggy zone, the Midale Marly zone, and the
Midale Evaporite. The most extensive seal above
the injection interval is the low-permeability
Lower Watrous formation. The Midale Vuggy
zone has been largely swept by waterflood opera-
tions, which began in 1964. However, the Midale
Marly zone has lower permeability, lower sweep
efficiency and still contains significant volumes
of recoverable oil. Horizontal wells have tar-
geted the bypassed pay within the Midale Marly
zone since 1991, and this zone remains the focus
of current CO2 EOR operations. The field’s origi-
nal oil in place has been estimated at
approximately 223 million m3 [1.4 billion bbl]
and, prior to the start of CO2 injection in
September 2000, it had produced 55 million m3
[346 million bbl] of oil from primary and water-
flood production.
The Weyburn field covers 180 km2 [70 sq miles].
With more than 1,000 wells, including vertical
producer wells,vertical water-injection wells,
horizontal producer wells, horizontal CO2-injec-
tion wells and abandoned wells, reservoir
control from well logs is extensive. Additionally,
more than 600 wells have been cored, and pro-
duction and injection data provide a complete
historical record of the field.
In July 2000, IEA launched a comprehensive
geological study of the Weyburn CO2 storage
site.20 The IEA concluded that the geology of
Weyburn field is suitable for long-term CCS, that
the primary reservoir seals are competent, 
forming thick and extensive barriers to upward
fluid migration, and that faults and fractures in
the region show no fluid conductance. Risk-
assessment modeling suggests that only approxi-
mately 0.02% of the initial CO2 in place after
EOR operations are complete will migrate above
the reservoir in 5,000 years. Of this CO2, most
will diffuse into the overlying caprock, and none
will reach near-surface strata containing potable
aquifers. Moreover, the cumulative leakage
through existing wells in the field is expected to
be less than 0.001% of the initial CO2 in place.21
ECLIPSE 300 reservoir simulation software
was used to investigate the long-term migration
behavior of CO2 in the Weyburn reservoir. A
detailed reservoir model incorporating 75 injec-
tion patterns was inserted into a much larger
geological model, extending several hundred
meters below the reservoir to the ground surface
about 1,500 m [4,920 ft] above the reservoir.
ECPLISE 300 software was used to simulate 
dispersion, diffusion and advection of water,
hydrocarbons and CO2 within this region for
5,000 years beyond EOR.
A time-lapse seismic monitoring program is
improving understanding of CO2 flow behavior in
the reservoir. EnCana ran a baseline 3D seismic
survey in August 2000, prior to the start of CO2
injection. Two multicomponent time-lapse sur-
veys have been integrated with crosswell seismic
data, acquired by the Lawrence Berkeley
National Laboratory, and vertical seismic pro-
files (VSPs), acquired by Schlumberger, to
define the fluid-migration dynamics at a much
higher resolution than standard seismic tech-
niques. The time-lapse seismic results have
correlated with the CO2 flood-front movements,
supported by production and tracer data.
Scientists tested new passive seismic 
monitoring technology in the Weyburn field. In
2003, an array of eight triaxial geophones was
installed in a vertical well planned for abandon-
ment. Data acquisition, which began in 
August 2003, has detected discrete microseismic
events associated with the injection of CO2 and
demonstrates yet another possible monitoring
technology for CO2 storage operations.22
On a daily basis, 3 million m3 [106 MMcf], or
5,000 metric tons, of CO2 are transported and
injected into the Weyburn oil field to provide
secure CO2 storage and to improve oil recovery.23
As of March 2004, about 3 billion m3 [106 Bcf] of
anthropogenic CO2 has been injected, and over
the project’s lifetime an estimated 22 million
metric tons [24 million short tons] of anthro-
pogenic CO2 will ultimately be stored in Weyburn
field. On the production side, EnCana estimates
an additional 20.7 million m3 [130 million bbl] of
produced oil will be recovered over the next
30 years as a result of the CO2 storage project.
Daily production is anticipated to reach
4,770 m3/d [30,000 B/D] by 2008, compared with
1,590 m3/d [10,000 B/D] had the CO2 flood not
been initiated (above).
Sitting on Top of a Solution
An important field experiment entered its 
CO2-injection stage in September 2004. Designed
to test storage modeling, monitoring and 
verification techniques, the project is intended to
lower the cost, risk and time to implement a geo-
logic CO2 storage project. More specifically, the
project has several specific aims: to demonstrate
that CO2 can be injected safely and stored
securely, to determine the subsurface distribution
of CO2 using various monitoring techniques, and
to validate models and gain the appropriate level
of experience to advance to large-scale injection. 
The project is funded by the US Department
of Energy (DOE) National Energy Technology 
Laboratory. The Bureau of Economic Geology
(BEG) at the University of Texas at Austin is the
lead institution; it is supported by GEO-SEQ, a
research consortium that includes Lawrence
54 Oilfield Review
>Weyburn field production. The CO2 EOR storage project has clearly increased daily production rates
and is predicted to significantly extend the production plateau of the Weyburn field.
Ja
n 
55
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58
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76
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79
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n 
85
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88
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n 
91
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94
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n 
97
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n 
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Ja
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n 
09
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n 
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27
30,000
Pr
od
uc
tio
n,
 g
ro
ss
 B
OP
D
35,000
40,000
45,000
50,000
25,000
20,000
15,000
10,000
5,000
0
Date
Actual Forecast
Original vertical wells
Infill vertical wells
Horizontal infill wells
CO2 EOR
Autumn 2004 55
Berkeley National Laboratory, Oak Ridge
National Laboratory, Lawrence Livermore
National Laboratory, United States Geological
Survey (USGS) and the Alberta Research 
Council. The consortium selected Schlumberger
to provide formation evaluation, monitoring 
and sampling expertise. BP provides project
review and assumes an advisory role during 
the experiment.
The selected site is 30 miles [50 km] north-
east of Houston, in the South Liberty oil field. The
brine-filled injection zone is a stratigraphically
complex deltaic and strandplain sandstone inter-
val within the Oligocene-age Frio formation and
sits on the southeast flank of a salt dome. The
Frio C sand interval dips to the south and is iso-
lated above and below by shales and is bounded
to the north and south by northwest-dipping
faults (below). The injection zone, from 5,050 to
5,080 ft [1,539 to 1,548 m], has a measured pres-
sure of 2,211 psi [15.3 MPa], a temperature of
134.5°F [57°C], and contains no hydrocarbons.
The interval is heterogeneous, maintains log
porosities from 17% to 37%, and shows varying
permeability estimates, from 14 to 3,000 mD.24
The sequence is overlain by the Anahuac shale,
which is a 246-ft [75-m] thick regional shale con-
sidered to be a competent seal.
Site selection is a significant aspect of the
Frio project because of its proximity to one of
the highest CO2 emission areas in the USA. The
Gulf Coast margin has a large concentration of
power plants, refineries and chemical manufac-
turing plants, which emit roughly 520 million
metric tons [573 million short tons] of CO2 every
year. Fortunately, because of extensive hydrocar-
bon exploration in this area, similar brine-filled
sands are known to exist, making the project 
site especially relevant to practical emission-
reduction strategies.25 The CO2 storage capacity
of the Frio sands in this region has been estimated
at between 208 and 358 billion metric tons 
[229 and 395 billion short tons].
The experiment will be conducted in the 
volume around two wells: an existing well now
used as a monitoring well; and a new injection
well, drilled and completed 100 ft [30 m]
downdip of the monitoring well in July 2004. To
ensure the mechanical integrity of the existing
observation well, which was drilled in 1956, 
a workover was scheduled. Because conven-
tional portland cement tends to degrade when
exposed to CO2, the cement quality was investi-
gated using a cement bond log and the USI
UltraSonic Imager device to determine the need
for remedial work. The Frio interval in the moni-
toring well was perforated from 5,014 to 5,034 ft
[1,528 to 1,534 m] and completed, including the
installation of a Schlumberger electrical sub-
mersible pump (ESP), which would later be
used during aquifer drawdown tests between the
two wells. Given the fact that a lack of wellbore
integrity could lead to a rapid path for CO2 leak-
age, further evaluation of the long-term
performance—over hundreds of years—of
cement whenexposed to supercritical CO2 has
been undertaken.
The newly drilled injection well gave the pro-
ject members an opportunity to evaluate the
Frio section using modern openhole logging
technology, including porosity and resistivity
from the Platform Express integrated wireline
logging tool. Mechanical properties were
obtained using the DSI Dipole Shear Sonic
Imager tool. The FMI Fullbore Formation
MicroImager device defined a structural dip of
10° to 20° to the south, and was used to identify
formation complexities that could influence
20. Whittaker S, Rostron B, Khan D, Hajnal Z, Qing H,
Penner L, Maathuis H and Goussev S: “Theme 1: 
Geoscience Characterization,” in Wilston M and
Monea M (eds): Proceedings of the 7th International
Conference on Greenhouse Gas Control Technologies.
Volume 111: IEA GHG Weyburn CO2 Monitoring and 
Storage Project Summary Report 2000-2004. Regina,
Saskatchewan, Canada: Petroleum Technology Research
Centre (2004): 15–69.
21. Zhou W, Stenhouse M, Sheppard M and Walton F:
“Theme 4: Long-Term Risk Assessment of the Storage
Site,” in Wilston M and Monea M (eds): Proceedings of
the 7th International Conference on Greenhouse Gas
Control Technologies. Volume 111: IEA GHG Weyburn 
CO2 Monitoring and Storage Project Summary Report
2000–2004. Regina, Saskatchewan, Canada: Petroleum
Technology Research Centre (2004): 211–268.
22. Maxwell SC, White DJ and Fabriol H: “Passive Seismic
Imaging of CO2 Sequestration at Weyburn,” presented 
at the SEG International Exposition and 74th Annual
Meeting, Denver, October 10–15, 2004.
23. Brown K, Jazrawi W, Moberg R and Wilson M: “Role of
Enhanced Oil Recovery in Carbon Sequestration: The
Weyburn Monitoring Project, A Case Study,”
http://www.netl.doe.gov/publications/proceedings/01/
carbon_seq/2a1.pdf (accessed October 1, 2004).
24. Hovorka SD, Doughty C and Holtz MH: “Testing Efficiency
of Storage in the Subsurface: Frio Brine Pilot Experiment,”
paper M1-2, presented at the 7th International Conference
on Greenhouse Gas Control Technologies, Vancouver,
British Columbia, Canada, September 5–9, 2004.
25. Hovorka SD and Knox PR: “Frio Brine Sequestration Pilot
in the Texas Gulf Coast,” paper I1-2, presented at the 6th
International Conference on Greenhouse Gas Control
Technologies, Kyoto, Japan, October 1–4, 2002.
Hovorka SD, Doughty C, Knox PR, Green CT, Pruess K and
Benson SM: “Evaluation of Brine-Bearing Sands of the
Frio Formation, Upper Texas Gulf Coast for Geological
Sequestration of CO2,” presented at the 1st National 
Conference on Carbon Sequestration, Washington, DC,
May 14–17, 2001.
> The Frio Brine Pilot Experiment. The project site is located along
the subsurface trend of Frio brine aquifers (left). A block diagram
shows the spatial relationship between a monitoring well, an
injection well, the targeted CO2 storage zone in the Frio formation,
local faults and the South Liberty salt dome (right).
Frio form
ation
CO2 injection
well
Monitoring
well
South
Liberty
salt
dome
Injected
 CO2
Pilot site
Houston
High
-por
osit
y sa
nd t
rend
 in t
he F
rio
Power plant
Industrial sources
km0 20
miles0 20
fluid flow. The FMI log showed no evidence of
natural fractures within the interval between
the faults.
The MDT Modular Formation Dynamics
Tester measured pressure, determined fluid
mobility and acquired formation water samples
in the Frio and surrounding formations. Core-
derived permeabilities compared well with
permeability calculations from MDT tests
(above). Project scientists required knowledge of
the formation-water salinity to properly interpret
future continuous and time-lapse RST Reservoir
Saturation Tool measurements, a key technology
for quick detection of CO2 breakthrough.
The injection well was completed in 
June 2004 and was approved as a Class 5 
Experimental Well by the Texas Commission for
Environmental Quality. The USI tool was used to
evaluate the cement job from total depth to sur-
face to ensure that no CO2 leakage would occur
at the borehole.
Extensive geological and petrophysical 
characterizations were critical in developing
accurate earth and fluid-flow models, helping
ensure optimal experimental design and aiding
postinjection model verification. A preliminary
injection test was conducted with water and
tracer in the weeks prior to the start of the CO2
injection stage. Breakthrough occurred in nine
days for this preliminary injection test and 
suggests an average permeability of 2,500 mD, in
good agreement with core data.
The injection of 3,000 metric tons 
[3,333 short tons] of CO2 from a nearby refinery
occurred over a three-week period. Time-lapse
monitoring of the borehole fluid will occur peri-
odically throughout the remainder of 2004. The
small-scale experiment—small injection volumes
and closely spaced wells—facilitates the timely
delivery of high-confidence results, and will help
prepare for larger scale injections in the future.
Numerous CO2 monitoring techniques have
been investigated for use at the Frio experiment
site. The assessment of these techniques
requires response modeling that evaluates
changes in reservoir characteristics as injection
proceeds. For example, the use of crosswell 
electromagnetic (EM) technology, electrical
resistance tomography (ERT) and tiltmeters has
been considered. An EM baseline survey was
completed prior to the injection of CO2. Direct
CO2 monitoring is accomplished by measuring
the capture cross section and the carbon/oxygen
ratio with time-lapse logging of the RST device.
The utility of adding chemical tracers to the
CO2 has also been analyzed. On land, where the
number of potential monitoring wells is high,
tracers help scientists study CO2 transport pro-
cesses and breakthrough behavior. Additionally,
tracers provide monitoring assurances that help
bolster regulatory and public acceptance, neces-
sary in all CO2 storage operations. Common
tracers include noble gases such as argon, perflu-
orocarbons and anomalous amounts of the
natural stable isotopes of carbon and oxygen [13C
and 17O]. These natural stable isotopes usually
occur in small, but predictable, concentrations in
CO2. Sampling of the downhole fluid and testing
for tracers will detect the arrival of specific CO2
volumes at a monitoring well.
Crosswell seismic and VSP surveys have 
been selected to monitor the subsurface volume
between the injector and the monitor wells.
These seismic techniques, along with RST mea-
surements, will be performed in time-lapse
mode to validate models, track CO2 migration
and detect crosswell breakthrough of CO2. The
VSP data will be used to map the areal extent of
56 Oilfield Review
> Porosities and permeabilities from Bureau of Economic Geology (BEG) core-test data. Permeability
calculations from MDT Modular Formation Dynamics Tester data were consistent with core
measurements (Track 5). High-quality characterization was required for building geologic and 
fluid-flow models, the assessment of applicable monitoring techniques and successful postinjection
model verification.
5,050
5,100
Gamma Ray Core
Gamma Ray
De
pt
h,
 ft
API30 150
API0 150
0.2 20
0.2 20
ohm-m
ohm-m
0.2 20ohm-m
10-in. AIT Resistivity
0 1vol/vol vol/vol mD0.4 0
BEG Porosity
vol/vol0.4 0
Core Porosity
10,000 10
mD10,000 10
BEG Permeabiliy
mD10,000 10
Mobility
30-in. AIT Resistivity
90-in. AIT Resistivity Core Permeabiliy
Sand
Shale
Autumn 2004 57
the CO2 plume and to validate the interpretation
of a 3D seismic survey.
The Frio project is a major collaborative
effort between government, business and insti-
tutions to test current monitoring technologies
and validate the models used to simulate both
CO2 storage capacity and migration behavior. In
addition, this project lays the groundwork for
future CCS projects beneath this high-emissions
region of the Gulf Coast.
Power Plant Emissions
The Ohio Valley CO2 Storage Project is a collabo-
rative endeavor to examine the potential for CO2
storage beneath another high-emissions region
of the USA.Initiated in November 2002, the pro-
ject is supported by the US Department of
Energy’s National Energy Technology Laboratory
(NETL), Battelle Laboratories, American Elec-
tric Power (AEP), BP, the Ohio Coal
Development Office of the Ohio Air Quality
Development Authority, Pacific Northwest
National Laboratory and Schlumberger. Technical
support also comes from West Virginia University,
the Ohio Geological Survey and Stanford Univer-
sity.26 The Ohio Valley area relies heavily 
on large hydrocarbon-base power plants for elec-
tricity generation.
The goal of this project is to identify and char-
acterize reservoirs near major CO2 emission
sources and to assess the potential for subsurface
CO2 storage in the region. Mountaineer Power
Plant in New Haven, West Virginia, USA, was 
chosen as a project site because it sits above
potential geologic storage targets deep in the
Cambrian and Ordovician strata. The plant, which
is operated by AEP, produces 1,300 MW of power
from pulverized coal, and emits over 7 million
short tons [6.4 million metric tons] of CO2 annu-
ally.27 This project represents the first effort to
assess subsurface CO2 storage targets from a sur-
face site located within the power plant facility.
As a result, the project has encountered many
technical, regulatory and stakeholder issues that
were not seen during previous CCS projects.
A complete geologic characterization was
required to establish whether the target inter-
vals possessed the properties necessary for
successful and secure storage of injected CO2.
Project partners acquired a two-dimensional
(2D) seismic survey to define the geological
structure and confirm the continuity of the main
seismic horizons away from the site. The survey
quality was considered good. Special processing
steps minimized background noise from the
power plant and coal conveyor belt.
The next step in the site-characterization pro-
cess involved acquiring downhole measurements
across potential injection intervals. In 2003, a
9,190-ft [2,800-m] exploratory well was drilled on
the Mountaineer plant site to evaluate deep CO2
storage potential (left). The main targets
included the basal sandstone overlying the Pre-
cambrian igneous rocks, high-porosity zones
within the otherwise low-permeability carbonates
such as the Copper Ridge dolomite, and the Rose
Run sandstone and the Beekmantown dolomite. 
Prior to this, few wells had been drilled to
test these deep intervals in this area of the
Appalachian basin. Formation-depth predictions
based on seismic data and regional geology 
26. Gupta N, Jagucki P, Sminchak J, Meggyesy D, Spane F,
Ramakrishnan TS and Boyd A: “Determining Carbon
Sequestration Injection Potential at a Site-Specific 
Location Within the Ohio River Valley Region,” paper 302,
presented at the 7th International Conference on 
Greenhouse Gas Control Technologies, Vancouver,
British Columbia, September 5–9, 2004.
27. “West Virginia State Profile of Exposure to Coal-Fired
Power Plants,” http://www.catf.us/publications/
fact_sheets/children_at_risk/West_Virginia_Kids_
Facts.pdf (accessed September 10, 2004).
> The Mountaineer Power Plant near New Haven, West Virginia, USA. The
exploratory well is located within the coal-fired Mountaineer Plant facility
and is indicated by the red dot.
Plant, West
Virginia, USA
Mountaineer
provided a reasonable match to drilling results,
despite the scarcity of data. Extensive openhole
logging and coring programs determined forma-
tion properties, such as mineralogy, porosity,
permeability, water saturation and salinity,
mechanical properties and the presence of 
natural fractures. In conjunction with porosity
and resistivity measurements, formation miner-
alogy was defined by the NGS Natural Gamma
Ray Spectrometry tool. Permeability and grain-
size data, and a lithology-independent porosity
were acquired by the CMR Combinable Magnetic
Resonance sonde. Also, the FMI tool was used to
identify natural fracturing and structural 
complexities that might affect injectivity. In
addition, engineers used the MDT device to
acquire formation-pressure and permeability
data, and to take fluid samples. While one MDT
test was successful, a packer failure compro-
mised the data quality during the other tests.
Fullbore core testing and analysis also played
a crucial role in the complete characterization of
the target intervals. A total of 293 ft [90 m] of
core was taken across the Beekmantown
dolomite, Rose Run and basal sandstones. Full-
bore coring was not practical in zones with slow
coring rates, so the Mechanical Sidewall Coring
Tool (MSCT) was used later to take sidewall
cores in those intervals. Detailed core analysis
and petrography examined important small-scale
characteristics, such as sedimentary structures,
porosity types, grain sizes and mineralogy. Core
porosity and permeability were also measured.
The fullbore cores provided material for 
CO2-flood and relative-permeability experiments,
and geomechanical tests.
58 Oilfield Review
>Wireline logs across the Rose Run sandstone. Log analysis shows the Rose Run sandstone interval consists of sand with
interbedded dolomite layers (Track 1). Porosity streaks in the Rose Run sandstone exceed 12% (Track 3), and permeabilities
calculated from the CMR Combinable Magnetic Resonance data reach 10 mD (Track 2). The FMI Fullbore Formation MicroImager
data show the interbedded nature and vertical complexity of the Rose Run interval (right).
Gamma Ray
API0 200
vol/vol1 0
Volumetric Analysis
0.02 200
CMR Permeability
ohm-m0.2 2,000
Array Resistivity Mode 2
ohm-m0.2 2,000
Array Resistivity Mode 3
ohm-m0.2 2,000
Array Resistivity Mode 4
ohm-m0.2 2,000
Array Resistivity Mode 5
ohm-m0.2 2,000
Flushed Zone Resistivity
Photoelectric Effect
Density
Delta T
Neutron Porosity
CMR Porosity
0 10
1.95 2.95
1.40 40
g/cm3
ms/ft
vol/vol0.45 -0.15
vol/vol0.45 -0.15
vol/vol0.45 -0.15
Low High
Amplitude Distribution
ms
T2 Distribution
0.3 3,000
T2 Cutoff
7,750
7,800
7,850
Siderite
Quartz
Bound Water
Illite
4 in. 14
Caliper
Dolomite
De
pt
h,
 ft
Density Porosity
FMI Image
Res. Cond.
7,820
7,810
7,800
7,790
7,780
7,770
mD
0 120 240 360
Orientation North
Autumn 2004 59
Using seismic measurements, openhole log-
ging technology and core testing, this reservoir
characterization program identified the most
promising zones for testing at a larger reservoir
scale. Straddle packers isolated selected zones
for testing and retrieving water samples. 
Injectivity, or minifracture, tests helped 
engineers determine hydraulic fracture-pressure
thresholds in potential injection zones and also
helped them calculate the maximum sustainable
pressure in the caprock.
The wide range of measurements at different
volume scales revealed that the investigated 
formations were continuous but fairly hetero-
geneous. The basal sandstone was the most
homogeneous zone, but had low porosity and
permeability values and was not a suitable injec-
tion target at this site. However, several other
zones showed injection potential that could be
used for future tests of CO2 injection and 
monitoring, and potentially even for long-term
CO2 storage. For example, the Copper Ridge
dolomite section contains thin intervals with
good porosity and high permeability, and 
warrants further investigation to determine its
areal extent. The Rose Run sandstone showed
sufficient permeability, but the porosity was vari-
able, limiting its potential CO2-storage volume
(previous page). While the Beekmantown
dolomite exhibited thin layers with good poros-
ity and permeability, the gross CO2 storage
volume in this formation was low at this location
(above). In addition, formation-water analysis
indicated high salinities—300,000 mg/L
[2.50 lbm/gal]—indicating that, at these depths
and pressures, CO2 solubility in brine water
could be severely reduced.
>Wireline logs across the Beekmantown dolomite interval. The Beekmantown interval was dominantly dolomite with interbedded
sand and shale layers(Track 1). While the interval shows thin porous and permeable streaks, the overall storage quality of the
Beekmantown is poor (Tracks 2 and 3). The FMI image identified vugular porosity at 7,418 ft [2,261 m] and drilling-induced
fractures striking NE-SW at a depth of 7,430 ft [2,265 m] (right).
Acoustic Impedance
80,000 30,000
vol/vol1 0
Volumetric Analysis
mD0.02 200
CMR Permeability
ohm-m0.2 2,000
Array Resistivity Mode 2
ohm-m0.2 2,000
Array Resistivity Mode 3
ohm-m0.2 2,000
Array Resistivity Mode 4
ohm-m0.2 2,000
Array Resistivity Mode 5
ohm-m0.2 2,000
Flushed Zone Resistivity CMR Porosity
1 11
1.95 2.95
90
0.15 -0.05
0.15 -0.05
vol/vol0.15 -0.05
Amplitude distribution
ms
T2 Distribution
0.3 3,000
T2 Cutoff
4 14in.
Caliper
40
7,400
7,410
7,420
7,430
Dolomite
Siderite
Quartz
Bound Water
Illite
Gamma Ray
API0 200
De
pt
h,
 ft
Photoelectric Effect
g/cm3
vol/vol
Neutron Porosity
vol/vol
Density Porosity
Delta T
ms/ft
Density
Low High
0 120 240 360
Orientation North
FMI Image
Res. Cond.
(ft/s) (g/cm3)
7,400
7,450
The Ohio Valley CO2 Storage Project demon-
strates the importance of thoroughly evaluating
potential CO2 storage zones on a site-specific
basis. While the injectivity in individual zones
appeared to be low, the combined injection
potential in multiple zones seems to be suffi-
cient for medium- to large-scale injection tests.
In addition, commercial-scale injection is 
possible with the use of multilateral well and
reservoir-stimulation technologies. Tests also
showed that the containment of CO2 would
not be compromised. 
This project clearly demonstrated the value of
advanced logging measurements, such as those
provided by the CMR and FMI tools, to quickly
ascertain formation properties and characteris-
tics so that more costly testing can be directed to
the most promising intervals. This CCS project,
like the others, emphasizes gathering information
and multidisciplinary collaboration. The project
also provides a protocol for characterizing deep-
basin sedimentary sequences that have sparse
data but high potential.
Produce Coalbed Methane, Hold the Carbon
Unmineable coal seams have been identified as
another potential storage volume site for 
anthropogenic CO2, with an estimated CO2 stor-
age capacity at 7.1 billion short tons [6.4 billion
metric tons].28 Given coal’s intrinsic storage
potential and the growth in coalbed methane
(CBM) exploitation, placing CO2 in coal seams is
an attractive possibility.29
In dry-core tests, CO2 adsorbs at nearly twice
the rate—sorption separation factor—of CH4,
making CO2 injection an efficient production-
enhancement technique in CBM reservoirs, also
called enhanced coalbed methane (ECBM). In
some experiments in which the moisture con-
tent of the coal has been reconstituted, the
observed CO2 sorption was significantly less.30
Nonetheless, added production, as a result of
CO2 injection, could offset some, or all, of the
cost associated with injection operations.
The complexity of coal necessitates extensive
study at subsurface conditions. Coal is often 
heterogeneous and could possibly promote
unpredictable sweep behavior. For example, CO2
breakthrough at a producing well might occur
along the most connected and extensive frac-
ture—or cleat—networks.
Other concerns unique to ECBM are currently
being investigated. Special care must be taken
when drilling and completing both injection and
production wells for ECBM. In many cases, pro-
ducing wells may be converted to injection wells.
Coals frequently break out during drilling, or 
are stimulated by cavitation, increasing the 
likelihood of compromised cement jobs, poor 
isolation and loss of containment. A large per-
centage of CBM producing intervals have been
stimulated by hydraulic fracturing. Hydraulic
fractures that extend too far outside the target
interval may allow CO2 leakage, putting contain-
ment at risk. Also, replacing CH4 with CO2
causes coals to swell, changing the stress condi-
tions in the coals and surrounding layers.
The depth of coalbeds considered for CO2
storage is also crucial. Experience from CBM
production shows that the productivity of coals
significantly degrades below 5,250 ft [1,600 m],
because at those depths cleats close and perme-
ability decreases. This reduces injectivity at
injection pressures below the coal fracture 
pressure. Laboratory testing and field-scale 
simulations have investigated changes in coal-
storage properties with variations in stress and
water saturation.31
While the global CO2 storage capacity of
coalbeds is much smaller than that of deep saline
aquifers, the potential CBM production benefits
from injecting CO2 make this option attractive.
However, many questions remain. Energy produc-
ers and CO2 storage experts continue to study the
benefits and challenges of CO2 ECBM. CONSOL
Energy, the largest producer of high-Btu 
bituminous coal in the USA and a CBM producer,
is conducting a seven-year project to inject CO2
into coal seams in West Virginia. Burlington
Resources and BP are both studying ECBM in the
San Juan basin, USA. Many important projects
and studies are ongoing in Europe, including in
France, Germany, The Netherlands and Poland.
Special ECBM potential exists in those countries
that have vast coal resources, such as Canada,
Australia and China, prompting numerous 
projects and initiatives.
What the World Needs Now
The acidity of CO2 can corrode downhole tubu-
lars and degrade cement. While not considered
toxic, high concentrations of escaped CO2 above
ground or in freshwater aquifers could cause
damage. Because the storage of CO2 must be
long term—hundreds or thousands rather than
tens of years—the bar has been raised for 
well construction.
There is no better example of how oilfield
technology must respond to the challenges of CO2
storage than cementing technology for well con-
struction. Portland cement is the most common
material used in well cementing. When CO2 is dis-
solved in water, approximately 1% of the CO2
forms dissociated carbonic acid [HCO3-], which
reacts chemically with the compounds in the
hydrated portland cement matrix, such as calcium
silicate hydrate gel (C-S-H) and calcium hydroxide
[Ca(OH)2]. The major reaction products are cal-
cium carbonate and amorphous silica gel. The set
cement gradually loses strength and becomes
more permeable. As a result, cement failures have
been reported during the many years of CO2 EOR
experience (next page).32 Schlumberger is investi-
gating and testing CO2-resistant cements,
formulation and mixing techniques, cement simu-
lators, and periodic and permanent methods to
evaluate cement-sheath integrity.
To minimize risk in CO2 operations, accurate
modeling and simulation are important, and 
confidence in monitoring is essential at all levels.
Public confidence in industry’s ability to safely
and securely store CO2 below ground for exten-
sive periods is a requirement to move forward,
60 Oilfield Review
28. Herzog and Golomb, reference 8.
29. Anderson J, Simpson M, Basinski P, Beaton A, Boyer C,
Bulat D, Ray S, Reinheimer D, Schlachter G, Colson L,
Olsen T, John Z, Khan R, Low N, Ryan B and
Schoderbek D: “Producing Natural Gas from Coal,” 
Oilfield Review 15, no. 3 (Autumn 2003): 8–31.
30. Tsotsis TT, Patel H, Najafi BF, Racherla D, Knackstedt MA
and Sahimi M: “Overview of Laboratory and Modeling
Studies of Carbon Dioxide Sequestration in Coal Beds,”
Industry Engineering and Chemistry Research 43, no. 12
(2004): 2887–2901.
31. Wolf KHAA, Barzandji OH, Bruining H and Ephraim R:
“CO2 Injection in and CH4 Production from Coal Seams:
Laboratory Experiments and Image Analysis for 
Simulations,” in Proceedings of the 1st National 
Conference on Carbon Sequestration, Washington, DC,
(May 14–17, 2001) CD-ROM, DOE/NETL-2001/1144: 1–13.
32. Skinner L: “CO2 Blowouts: An Emerging Problem,” 
World Oil 224, no. 1 (January 2003): 38–42.
33. Damen K, Faaij A and Turkenburg W: “Health, Safety and
Environmental Risks of UndergroundCO2 Sequestration,”
http://www.chem.uu.nl/nws/www/publica/e2003-30.pdf
(accessed October 11, 2004).
Benson S, Hepple R, Apps J, Tsang CF and Lippmann M:
“Lessons Learned from Natural and Industrial Analogues
for Storage of Carbon Dioxide in Deep Geological 
Formations,” http://www.co2captureproject.org/
reports/reports.htm (accessed October 11, 2004).
34. The Kyoto Protocol is an international environmental
agreement that establishes country-by-country emissions
targets for greenhouse gases. The Protocol requires
industrialized countries to reduce their emissions by an
average of 5.2% below 1990 levels by 2010. The Protocol
will enter into force on the 90th day after the date it is
ratified by at least 55 countries accounting for at least
55% of the total carbon dioxide emissions, as calculated
in 1990. As of April 15, 2004, 122 countries had ratified or
acceded to the Kyoto Protocol and accounted for 44.2%
of baseline CO2 emissions.
Cannell et al, reference 1.
35. http://energy.er.usgs.gov/projects/co2_sequestration/
co2_overview.htm (accessed August 10, 2004).
36. For more on the Carbon Sequestration Leadership Forum:
http://www.cslforum.org/ (accessed October 11, 2004).
Autumn 2004 61
and this confidence is the core issue associated
with monitoring. Monitoring CO2 migration in 
the subsurface volume has come a long way in a 
short time, and involves advances in seismic 
measurements and processing techniques. Other
subsurface methods, such as passive seismic mon-
itoring and crosswell electromagnetic imaging,
show tremendous promise. Surface detection of
CO2 leaks is an active area of research, although
less mature than subsurface monitoring.
The capture, transportation and storage 
of CO2 are not risk-free, but if these are 
properly planned, operated and monitored, 
risk can be reduced substantially.33 Seventy
years of experience in natural gas storage 
operations have resulted in extremely low leak-
age rates. Consequently, today there are more
than 600 natural gas storage facilities, many
near population centers.
To be successful in reducing emissions, 
several key factors must be addressed for the
capture and storage of CO2. Secure storage would
likely be required for hundreds of years, eclips-
ing the anticipated lifespan of today’s oil and gas
infrastructure. Economics is a major factor. The
costs associated with CO2 separation, trans-
portation and storage must be minimized. The
risk to health and the environment should also
be minimized, and practices used to capture and
store CO2 must be in accordance with laws 
and regulations. Moreover, gaining the trust of 
the public, the media and nongovernmental 
organizations requires open and transparent dis-
semination of information to facilitate education.
Even if these general principles are achieved, the
economic task ahead is monumental.
The USGS estimates that the total CO2 gas-
emissions volume from fossil fuels in the USA,
which produces roughly 24% of the world’s CO2
emissions, is around 114 Tcf [3.2 trillion m3] per
year. This volume is almost five times the total
annual US natural gas consumption. To meet the 
conditions of the Kyoto Protocol by 2015, the US
would have to reduce emissions by 500 million
metric tons/yr [550 million short tons/yr].34 This
equates to almost twice the annual US 
natural gas production, and it would require the
infrastructure to process, transport, inject and
store the CO2.35 As large as that seems, the 
storage of CO2 represents only 20 to 30% of the
total costs of CO2 sequestration.
Today, multinational cooperation is evident
in the Carbon Sequestration Leadership Forum
(CSLF).36 The CSLF focuses on the policy and
technical framework needed to ensure the 
success of CCS in the coming decades. The CSLF
is involved in information exchange, planning,
collaboration, research and development, public
perception and outreach, economic and 
market studies, regulatory and legal issues, and
policy formulation.
Large CCS projects, like the Sleipner field
project, are under way or in the planning stages.
For example, the In Salah gas field in Algeria,
the Gorgon gas field in Australia and the Snohvit
field in the Barents Sea are targeting saline
aquifers. Strategic small-scale projects also play
an important role in developing technologies
and experience for CCS site monitoring and 
verification, as for example, the Ketzin project in
Germany and the K12 B project for enhanced
gas recovery (EGR) offshore The Netherlands.
For CCS to become an acceptable option to
reduce CO2 emissions, projects like these are
crucial and will become more numerous with
additional knowledge and experience.
Clearly we need more time—time to study
the global problem at hand and to make the best
decisions based on a reasonable degree of 
certainty. We also need time to develop new
forms of renewable energy sources to eventually
supplant fossil fuels. Additional investigation of
CO2 capture and storage sites is needed to
bridge that gap, allowing the continued use of
our most abundant and cost-effective energy
resources. This would help in advancing world
economies, which is key to the development of
technologies that may ultimately help stem
global warming. The capture and secure storage
of CO2 may be viewed as a way to buy some extra
time. The technology and expertise to store CO2
in the subsurface are available now and come
from within the oil and gas industry. —MGG
> Redefining cement sheath durability. Conventional portland cements
degrade when exposed to CO2 in wet conditions. In tests, cement samples
show degradation, cracking and the crystallization of aragonite when
exposed to CO2 (top). Defects in the cement sheath increase the exposure 
to degradation from CO2 (bottom). Risk-mitigation efforts will include a high
level of cement quality monitoring and more frequent logging than in the past.
W
el
lb
or
e
CO2
Cement
CO2