1
Carbon Dioxide Storage: Geological Security and Environmental
Issues – Case Study on the Sleipner Gas Field in Norway
Semere Solomon
1
, The Bellona Foundation
July 2006
Summary
Carbon dioxide capture and storage (CCS) is one option for mitigatining atmospheric emissions of carbon dioxide and
thereby contributes in actions for stabilization of atmospheric greenhouse gas concentrations. Carbon dioxide storage in
geological formations has been in practice since early 1970s. Information and experience gained from the injection
and/or storage of CO
2
from a large number of existing enhanced oil recovery (EOR) projects indicate that it is feasible
to safely store CO
2
in geological formations as a CO
2
mitigation option. Industrial analogues, including underground
natural gas storage projects around the world and acid gas injection projects, provide additional indications that CO
2
can
be safely injected and stored at well-characterized and properly managed sites. Geological storage of CO
2
is in practice
today beneath the North Sea, where nearly 1 MtCO
2
has been successfully injected annually in the Utsira formation at
the Sleipner Gas Field since 1996. The site is well characterized and the CO
2
injection process was monitored using
seismic methods and this provided insights into the geometrical distribution of the injected CO
2
. The injected CO
2
will
potentially be trapped geochemically pressure build up as a result of CO
2
injection is unlikely to occur. Solubility and
density dependence of CO
2
-water composition will become the controlling fluid parameters at Sleipner. The solubility
trapping has the effect of eliminating the buoyant forces that drive CO
2
upwards, and through time it can lead to mineral
trapping, which is the most permanent and secure form of geological storage. Overall, the study at the Sleipner area
demonstrates the geological security of carbon dioxide storage. The monitoring tools strengthen the verification of safe
injection of CO
2
in the Utsira formation. This proves that CO
2
capture and storage is technically feasible and can be an
effective method for greenhouse mitigation provided the site is well characterized and monitored properly.
1 Introduction
1
Dr. Semere Solomon, Advisor at The Bellona Foundation, P.O.Box 2141 Grunerløkka, N-0505 Oslo, Norway.
Contact e-mail: semere@bellona.no
The greenhouse gas (GHG) making the
largest contribution to atmospheric emissions
from human activities is carbon dioxide (CO
2
).
It is released by burning fossil fuels and
biomass as a fuel; from the burning, for
example, of forests during land clearance; and
by certain industrial and resource extraction
processes. Emissions of CO
2
due to fossil fuel
burning are the dominant influence on the
increasing
trends
in
atmospheric
CO
2
concentration because according to the
International Energy Agency (IEA) 80 % of the
global energy consumption is based on coal,
oil, and natural gas (IEA, 2005). Global
average temperatures and sea level are
projected to rise if appropriate measures are not
taken. Due to increased emissions of GHG, the
global average temperature will increase by 1.4
to 5.8
o
C from 1990 to 2100, according to The
Intergovernmental Panel on Climate Change
(IPCC, 2001c). An increase in global
temperature by more than 2
o
C will have
dramatic impacts on life on earth. Steps should
be taken that aim in the stabilization of
greenhouse
gas
concentrations
in
the
atmosphere at a level that would prevent
dangerous anthropogenic interference with
climatesystems.
Several technological options for reducing
net CO
2
emissions to the atmosphere exist
2
(IPCC, 2005). These include energy efficiency
improvements, the switch to less carbon-
intensive fuels, nuclear power, renewable
energy sources, enhancement of biological
sinks,
reduction
of
non-carbon
dioxide
greenhouse gas emissions and capture and store
CO
2
chemically or physically. Improvements in
energy efficiency have the potential to reduce
global CO
2
emissions by 30% using existing
technologies (IPCC, 2005). However, on their
own, efficiency gains are unlikely to be
sufficient, or economically feasible, to achieve
deep reductions in emissions of GHGs (IPCC,
2001a). Wider use of renewable energy sources
was also found to have substantial potential.
Nonetheless, many of the renewable sources
face constraints related to cost, intermittency of
supply, land use and other environmental
impacts (IPCC, 2005). Carbon dioxide capture
and storage (CCS) can be a good option
because it can be implemented on a larger scale
and has also the potential capacity for deep
emission reduction.
The IPCC has stated that global GHG
emissions should be reduced by 50 to 80 %
within 2050. In order to obtain such a huge
emission reduction, a combination of increasing
energy efficiency, switching from fossil fuel to
renewable energy sources, and wide implem-
entation of CCS is necessary (Stangeland,
2006). If CCS is fully implemented there is a
potential of capturing and storing 240 billion
ton CO
2
globally by 2050 (Stangeland, 2006).
This corresponds to a 37 % reduction in global
CO
2
emissions in 2050 compared to emissions
today which indicates that only CCS is not
enough to meet the targeted CO
2
emission
reduction.
Several types of storage reservoir may
provide storage capacities of this magnitude. In
some cases, the injection of CO
2
into oil and
gas fields could lead to the enhanced
production of hydrocarbons, which would help
to offset the cost due to the increased income
from the increased fossil fuels production. CO
2
capture technology can be applied to fossil-
fuelled power plants and other large industrial
sources of emissions; it can also be applied in
the manufacture of hydrogen as an energy
carrier as well as biomass.
Carbon dioxide storage in geological
formations has been in practice since early
1970s. Information and experience gained from
the injection and/or storage of CO
2
from a large
number of existing enhanced oil recovery
(EOR) projects indicate that it is feasible to
store CO
2
in geological formations as a CO
2
mitigation
option.
Industrial
analogues,
including underground natural gas storage
projects around the world and acid gas injection
projects, provide additional indications that
CO
2
can be safely injected and stored at well-
characterized and properly managed sites.
Injecting CO
2
into deep geological formations
at carefully selected sites can store it
underground for long periods of time.
Actions have to be taken now in order to
avoid dramatic future climate changes. There is
a need for short-term strategies for ensuring
energy production with the lowest GHG
emissions possible, and the best strategy is to
establish
carbon
capture
sequestration
(Stangeland
et al
., 2006). This paper analyzes
the current state of knowledge about the
scientific and technical dimensions of CO
2
storage option with emphasis on geological
storage, security and environmental impacts.
This paper reviews literature published on
geological storage of carbon dioxide in deep
saline aquifers with emphasis on the Sleipner
Gas Field project in Norway. Sections 2-6 give
detail on the technical aspects of geological
storage of CO
2
. After reviewing the current
state of knowledge, the existing gaps in
knowledge are outlined in Section 7 before a
case study from the Sleipner Gas Field in
Norway is presented in Section 8. This is
followed by the conclusions drawn in Section
9.
2 Geological Framework
2.1
Geological formations
Geological storage of CO
2
can be undertaken in
a variety of geological settings in sedimentary
basins. Within these basins, oil fields, depleted
gas fields, deep coal seams and saline
formations are all possible storage formations
(Figure 1). Other geological formations which
may serve as storage sites include caverns,
basalt and organic-rich shales.
3
Figure 1:
Options for storing CO
2
in deep underground geological formations ( source IPCC 2005).
Figure 2:
Distribution of sedimentary basins around the world. In general, sedimentary basins are likely to be the most
prospective areas for storage sites. However, storage sites may also be found in some areas of fold belts and in some of
the highs. Shield areas constitute regions with low prospectivity for storage. (Source IPCC, 2005).
4
In this study emphasis is given to deep
saline aquifer formations. Saline formations are
deep
sedimentary
rocks
saturated
with
formation waters or brines containing high
concentrations of dissolved salts. These
formations
are
widespread and
contain
enormous quantities of water, but are unsuitable
for agriculture or human consumption. Saline
formations occur in sedimentary basins
throughout the world (Figure 2), both onshore
and on the continental shelves and are not
limited to hydrocarbon provinces or coal
basins. The Sleipner Project in the North Sea is
the best available example of a CO
2
storage
project in a saline formation and details are
presented in Section 8.
2.2
Storage requirements
There are many sedimentary regions in
the world (Figure 2) variously suited for CO
2
storage. In general, geological storage sites
should have: (1) adequate capacity and
injectivity, (2) a satisfactory sealing caprock or
confining unit and (3) a sufficiently stable
geological environment to avoid compromising
the integrity of the storage site.
Adequate porosity and thickness (for
storage capacity) and permeability (for
injectivity) are critical; porosity usually
decreases with depth because of compaction
and cementation, which reduces storage
capacity and efficiency. The storage formation
should be capped by extensive confining units
(such as shale, salt or anhydrite beds) to ensure
that CO
2
does not escape into overlying,
shallower rock units and ultimately to the
surface. Extensively faulted and fractured
sedimentary basins or parts thereof, particularly
in seismically active areas, require careful
characterization to be good candidates for CO
2
storage.
The pressure and flow regimes of
formation waters in a sedimentary basin are
important factors in selecting sites for CO
2
storage (Bachu
et al.
, 1994). Injection of CO
2
into formations overpressured by compaction
and/or hydrocarbon generation may raise
technological and safety issues that make them
unsuitable. Underpressured formations in
basins located midcontinent, near the edge of
stable continental plates or behind mountains
formed by plate collision may be well suited for
CO
2
storage. Storage of CO
2
in deep saline
formations with fluids having long residence
times (millions of years) is conducive to
hydrodynamic and mineral trapping.
To geologically store CO
2
, it must first be
compressed to allow injection, usually to a
dense fluid state known as ‘supercritical’.
Supercritical means at a temperature and
pressure above the critical temperature and
pressure of the substance concerned, i.e. carbon
dioxide (temperatures higher than 31.1
o
C and
pressure greater than 73.9 bar). The critical
point represents the highest temperature and
pressure at which the substance can exist as a
vapour and liquid in equilibrium. Depending
on the rate that temperature increases with
depth (the geothermal gradient), the density of
CO
2
will increase with depth, until about 800 m
or greater, where the injected CO
2
will be in a
dense supercritical state. The efficiency of CO
2
storage in geological media, defined as the
amount of CO
2
stored per unit volume
(Brennan and Burruss, 2003), increases with
increasing CO
2
density. Storage safety also
increases with increasing density, because
buoyancy, which drives upward migration, is
stronger for a lighter fluid.
‘Cold’ sedimentary basins, characterized
by low temperature gradients, are more
favourable for CO
2
storage (Bachu, 2003)
because CO
2
attains higher density at shallower
depths (700–1000 m) than in ‘warm’
sedimentary basins, characterized by high
temperature
gradients
where
dense-fluid
conditions are reached at greater depths (1000–
1500 m).
Reservoir heterogeneity also affects CO
2
storage efficiency. The density difference
between the lighter CO
2
and the reservoir oil
and/or saline water leads to movement of the
CO
2
along the top of the reservoir, particularly
if the reservoir is relatively homogeneous and
has high permeability, negatively affecting the
CO
2
storage and oil recovery. Consequently,
reservoir heterogeneity may have a positive
effect, slowing down the rise of CO
2
to the top
of the reservoir and forcing it to spread
laterally, giving more complete invasion of the
formation and greater storage potential
(Kovscek, 2002; Flett
et al.
, 2005).
5
The presence of impurities (e.g., SO
x
, NO
x
,
H
2
S) in the CO
2
gas stream affects the
engineering processes of capture, transport and
injection, as well as the trapping mechanisms
and capacity for CO
2
storage in geological
media. Gas impurities in the CO
2
stream affect
the compressibility of the injected CO
2
(and
hence the total volume to stored) and reduce the
capacity for storage in free phase, because of
the storage space taken by these gases. In the
case of CO
2
storage in deep saline formations,
the presence of gas impurities affects the rate
and amount of CO
2
storage through dissolution
and precipitation. Additionally, leaching of
heavy metals from the minerals in the rock
matrix by SO
2
or O
2
contaminants is possible.
3 Storage mechanisms and
storage security
The effectiveness of geological storage
depends on a combination of physical and
geochemical trapping mechanisms. The most
effective storage sites are those where CO
2
is
immobile because it is trapped permanently
under a thick, low-permeability seal or is
converted to solid minerals or through a
combination of physical and chemical trapping
mechanisms.
3.1
Storage mechanisms
The storage mechanism known as
physical trapping of CO
2
below low-
permeability seals (caprocks), such as very-
low-permeability shale or salt beds, is the
principal means to store CO
2
in geological
formations (Figure 1). Sedimentary basins have
such closed, physically bound traps or
structures, which are occupied mainly by saline
water, oil and gas. Structural traps include those
formed by folded or fractured rocks. Faults can
act
as
permeability
barriers
in
some
circumstances and as preferential pathways for
fluid flow in other circumstances (Salvi
et al.
,
2000). Stratigraphic traps are formed by
changes in rock type caused by variation in the
setting where the rocks were deposited. Both of
these types of traps are suitable for CO
2
storage, although, care must be taken not to
exceed the allowable overpressure to avoid
fracturing the caprock or re-activating faults
(Streit
et al.
, 2005).
Hydrodynamic trapping can occur in
saline formations that do not have a closed trap,
but where fluids migrate very slowly over long
distances. When CO
2
is injected into a
formation, it displaces saline formation water
and then migrates buoyantly upwards, because
it is less dense than the water. When it reaches
the top of the formation, it continues to migrate
as a separate phase until it is trapped as residual
CO
2
saturation or in local structural or
stratigraphic traps within the sealing formation.
In the longer term, significant quantities of CO
2
dissolve in the formation water and then
migrate with the groundwater. Where the
distance from the deep injection site to the end
of the overlying impermeable formation is
hundreds of kilometres, the time scale for fluid
to reach the surface from the deep basin can be
millions of years (Bachu
et al.
, 1994).
Carbon dioxide in the subsurface can
undergo a sequence of geochemical interactions
with the rock and formation water that will
further
increase
storage
capacity
and
effectiveness,
a
mechanism
known
as
Geochemical trapping. First, when CO
2
dissolves in formation water, a process
commonly called solubility trapping occurs.
The primary benefit of solubility trapping is
that once CO
2
is dissolved, it no longer exists
as a separate phase, thereby eliminating the
buoyant forces that drive it upwards. Next, it
will form ionic species as the rock dissolves,
accompanied by a rise in the pH. Finally, some
fraction may be converted to stable carbonate
minerals
(mineral
trapping),
the
most
permanent form of geological storage (Gunter
et al.
, 1993). Mineral trapping is believed to be
comparatively
slow,
potentially
taking
thousands of years or longer. Nevertheless, the
permanence of mineral storage, combined with
the potentially large storage capacity present in
some geological settings, makes this a desirable
feature of longterm storage.
3.2
Storage security
Natural geological accumulation of CO
2
occur, as gaseous accumulations of CO
2
, CO
2
6
mixed with natural gas, and CO
2
dissolved in
formation water. These natural accumulations
have been studied in the United States,
Australia and Europe (e.g. Pearce
et al.
, 1996;
Watson
et al.
, 2004) as analogues for storage of
CO
2
, as well as for leakage from engineered
storage sites. Production of CO
2
for EOR and
other uses provides operational experience
relevant to CO
2
capture and storage. Natural
accumulations of relatively pure CO
2
are found
all over the world in a range of geological
settings, particularly in sedimentary basins,
intra-plate volcanic regions and in faulted areas
or in quiescent volcanic structures.
For instance, 200 Mt trapped in the
Pisgah Anticline, northeast of the Jackson
Dome in the USA, is thought to have been
generated more than 65 million years ago
(Studlick
et al.
, 1990), with no evidence of
leakage, providing additional evidence of long-
term trapping of CO
2
. Conversely, some
systems, typically spas and volcanic systems,
are leaky and not useful analogues for
geological storage, but can be useful for
studying the health, safety and environmental
effects of CO
2
leakage.
Underground natural gas storage projects
that offer experience relevant to CO
2
storage
(Lippmann and Benson, 2003; Perry, 2005)
have operated successfully for almost 100 years
in many parts of the world. The majority of gas
storage projects are in depleted oil and gas
reservoirs and saline formations, although
caverns in salt have also been used extensively.
While underground natural gas storage is safe
and effective, some projects have leaked,
mostly caused by poorly completed or
improperly plugged and abandoned wells and
by leaky faults (Lippmann and Benson, 2003;
Perry, 2005).
Acid gas injection operations represent a
commercial analogue for some aspects of
geological CO
2
storage. Acid gas is a mixture
of H
2
S and CO
2
, with minor amounts of
hydrocarbon gases that can result from
petroleum production or processing. In Western
Canada, operators are increasingly turning to
acid gas disposal by injection into deep
geological formations. Carbon dioxide often
represents the largest component of the injected
acid gas stream, in nodt cases, 14–98% of the
total volume. A total of 2.5 MtCO
2
and 2
MtH
2
S had been injected in Western Canada by
the end of 2003, at rates of 840–500,720 m
3
day
–1
per site, with an aggregate injection rate
in 2003 of 0.45 MtCO
2
yr
–1
and 0.55 MtH
2
S yr
–
1
, with no detectable leakage. Acid gas injection
occurs over a wide range of formation and
reservoir types.
In many parts of the world, large volumes
of liquid waste are injected into the deep
subsurface every day. For example, for the past
60 years, approximately 9 34.1 million m
3
of
hazardous waste is injected into saline
formations in the United States from about 500
wells each year (IPCC, 2005). In addition, more
than 2843 million m
3
of oil field brines are
injected from 150,000 wells each year. This
combined annual US injectate volume of about
3000 million m
3
, when converted to volume
equivalent, corresponds to the volume of
approximately 2 GtCO
2
at a depth of 1 km.
Therefore, the experience gained from existing
deep-fluid-injection projects is relevant in terms
of the style of operation and is of a similar
magnitude to that which may be required for
geological storage of CO
2
.
4 Site characterization and
performance prediction
4.1
Site characterization
The storage site and its surroundings need
to be characterized in terms of geology,
hydrogeology, geochemistry and geomechanics
(structural geology and deformation in response
to stress changes). The greatest emphasis will
be placed on the reservoir and its sealing
horizons. However, the strata above the storage
formation and caprock also need to be assessed
because if CO
2
leaked it would migrate through
them (Haidl
et al.
, 2005).
Documentation of the characteristics of
any particular storage site will rely on data that
have been obtained directly from the reservoir.
These include:
•
core and fluids produced from wells at
or near the proposed storage site
•
pressure transient tests conducted to test
seal efficiency
7
•
indirect remote sensing measurements
such as seismic reflection data, and
•
regional hydrodynamic pressure
gradients.
Integration of all of the different types of
data is needed to develop a reliable model that
can be used to assess whether a site is suitable
for CO
2
storage.
Financial constraints may limit the types
of data that can be collected as part of the site
characterization and selection process. Today,
no standard methodology prescribes how a site
must be characterized. Instead, selections about
site characterization data will be made on a
site-specific basis, choosing those data sets that
will be most valuable in the particular
geological setting. However, some data sets are
likely to be selected for every case. These are
listed below:
•
Geological
site
description
from
wellbores and outcrops are needed to
characterize the storage formation and
seal properties
•
Seismic surveys are needed to define
the subsurface geological structure and
identify faults or fractures that could
create leakage pathways
•
Formation pressure measurements are
needed to map the rate and direction of
groundwater flow, and
•
Water quality samples are needed to
demonstrate the isolation between deep
and shallow groundwater.
4.2
Performance prediction and optimization
modelling
Computer simulation also has a key role
in the design and operation of field projects for
underground injection of CO
2
. Predictions of
the storage capacity of the site or the expected
incremental recovery in enhanced recovery
projects, are vital to an initial assessment of
economic feasibility. In a similar vein,
simulation can be used in tandem with
economic assessments to optimize the location,
number, design and depth of injection wells.
For enhanced recovery projects, the timing of
CO
2
injection relative to production is vital to
the success of the operation and the effect of
various strategies can be assessed by
simulation. Modelling of the long-term
distribution of CO
2
in the subsurface (e.g.,
migration rate and direction and rate of
dissolution in the formation water) are
important for the design of cost-effective
monitoring programmes, since the results will
influence the location of monitoring wells and
the frequency of repeat measurements, such as
for seismic, soil gas or water chemistry. During
injection and monitoring operations, simulation
models can be calibrated to match field
observations and then used to assess the impact
of possible operational changes, such as drilling
new wells or altering injection rates, often with
the goal of further improving recovery (in the
context of hydrocarbon extraction) or of
avoiding migration of CO
2
past a likely spill-
point.
Numerical simulators currently in use in
the oil, gas and geothermal energy industries
provide important subsets of the required
capabilities. They have served as convenient
starting points for recent and ongoing
development efforts specifically targeted at
modelling the geological storage of CO
2
. Many
simulation codes have been used and adapted
for this purpose (e.g. White and Oostrom, 1997;
Steefel, 2001; Xu
et al.
, 2003).
The principal difficulty is that the complex
geological models on which the simulation
models are based are subject to considerable
uncertainties, resulting both from uncertainties
in data interpretation and, in some cases, sparse
data sets. Measurements taken at wells provide
information on rock and fluid properties at that
location, but statistical techniques must be used
to estimate properties away from the wells.
When simulating a field in which injection or
production is already occurring, a standard
approach in the oil and gas industry is to adjust
some parameters of the geological model to
match selected field observations. This proves
that the model is inaccurate, but it does provide
additional constraints on the model parameters.
However, better models and simulation tools
are required.
8
5 Monitoring and verification
Monitoring is needed for a wide variety of
purposes. It can be used to ensure and
document effective injection well controls,
specifically for monitoring the condition of the
injection well and measuring injection rates,
wellhead pressure and formation pressures.
Monitoring also can serve as a verification tool
to quantify the injected CO
2
that has been
stored by various mechanisms; and to
demonstrate, with appropriate monitoring
techniques, that CO
2
remains contained in the
intended storage formation(s). This is currently
the principal method for assuring that the CO
2
remains
stored
and
that
performance
predictions can be verified. It can also be
applied to detect leakage and provide an early
warning of any seepage or leakage that might
require mitigating action.
Before monitoring of subsurface storage
can take place effectively, a baseline survey
must be taken. This survey will provide the
point of comparison for subsequent surveys.
This is particularly true of seismic and other
remote-sensing
technologies,
where
the
identification of saturation of fluids with CO
2
is
based on comparative analysis. Baseline
monitoring
is
also
a
prerequisite
for
geochemical monitoring, where anomalies are
identified
relative
to
background
concentrations.
Additionally,
establishing
baselines of CO
2
fluxes resulting from
ecosystem cycling of CO
2
, both on diurnal and
annual cycles, are useful for distinguishing
natural fluxes from potential storage-related
releases.
Standard
procedures
of
monitoring
currently in use include:
•
routine measurements of injection rates
and pressures,
•
monitoring the distribution and
migration of CO
2
in the subsurface,
•
monitoring injection well integrity,
•
monitoring local environmental effects,
and
•
monitoring network design and
duration.
There are currently no standard protocols or
established network designs for monitoring
leakage of CO
2
. Monitoring network design
will depend on the objectives and requirements
of the monitoring programme, which will be
determined by regulatory requirements and
perceived risks posed by the site (Chalaturnyk
and Gunter, 2005).
A number of standard technologies are
available for monitoring but the applicability
and sensitivity of the techniques in use are
somewhat site-specific. Given the long-term
nature of CO
2
storage, site monitoring may be
required for vey long periods.
6 Risk assessment and
environmental impact
The risks due to storage of CO
2
in
geological reservoirs fall into two broad
categories: global risks and local risks. Global
risks involve the release of stored CO
2
to the
atmosphere that may contribute significantly to
climate change if some fraction leaks from the
storage formation. In addition, if CO
2
leaks out
of storage formation, local risks include hazards
for humans, ecosystems and groundwater.
With regard to global risks, observations
and analysis of current CO
2
storage sites,
natural systems, engineering systems and
models indicate that the likelihood or
probalility of leakage in appropriately selected
and managed reservoirs is nearly absent or very
negligible over long periods of time. The risk of
leakage is expected to decrease over time as
other mechanisms provide additional trapping.
With regard to local risks, there are two
types of scenarios in which leakage may occur.
In the first case, injection well failures or
leakage up abandoned wells could create a
sudden and rapid release of CO
2
. This type of
release is likely to be detected quickly and
stopped using techniques that are available
today for containing well blow-outs. Hazards
associated with this type of release primarily
affect living species in the vicinity of the
release at the time it occurs, or workers called
in to control the blow-out. A concentration of
CO
2
greater than 7–10% in air would cause
immediate dangers to human life and health.
9
Figure 3:
Some potential escape routes for CO
2
injected into saline formations (IPCC, 2005).
Containing these kinds of releases may take
hours to days and the overall amount of CO
2
released is likely to be very small compared to
the total amount injected. These types of
hazards are managed effectively on a regular
basis in the oil and gas industry using
engineering and administrative controls.
In the second scenario, leakage could occur
through undetected faults, fractures or through
leaking wells where the release to the surface is
more gradual and diffuse. In this case, hazards
primarily affect drinking-water aquifers and
ecosystems where CO
2
accumulates in the zone
between the surface and the top of the water
table. Groundwater can be affected both by
CO
2
leaking directly into an aquifer and by
brines that enter the aquifer as a result of being
displaced by CO
2
during the injection process.
There may also be acidification of soils and
displacement of oxygen in soils in this scenario.
Additionally, if leakage to the atmosphere were
to occur in low-lying areas with little wind, or
in sumps and basements overlying these diffuse
leaks, humans and animals would be harmed if
a leak were to go undetected. Humans would be
less affected by leakage from offshore storage
locations than from onshore storage locations.
Leakage routes can be identified by several
techniques and by characterization of the
reservoir. Figure 8 shows some of the potential
leakage paths for a saline formation. When the
potential leakage routes are known, the
monitoring and remediation strategy can be
adapted to address the potential leakage.
Careful storage system design and site
selection, together with methods for early
detection of leakage (preferably long before
CO
2
reaches the land surface), are effective
ways of reducing hazards associated with
diffuse leakage. The available monitoring
methods are promising, but more experience is
needed to establish detection levels and
resolution. Once leakages are detected, some
remediation techniques are available to stop or
control them. Depending on the type of
leakage, these techniques could involve
standard well repair techniques, or the
extraction of CO
2
by intercepting its leak into a
shallow groundwater aquifer (see Figure 3).
7 Knowledge gaps
Knowledge regarding CO
2
geological
storage is founded on basic knowledge in the
earth sciences, on the experience of the oil and
gas industry (extending over the last hundred
years or more) and on a large number of
10
commercial activities involving the injection
and geological storage of CO
2
conducted over
the past 10–30 years. Nevertheless, CO
2
storage
is a new technology and many questions
remain. Here, are summarised what are known
now and what gaps remain. Gaps in the
knowledge of geological storage of CO
2
are
presented in this paper in accordance to the
rating on the scale (1-5) given in the Review of
Special Report on Carbon dioxide Capture and
Sstorage Gaps in Knowledge (IPCC, 2006).
The scales are: (1) Very important and needs to
be addressed to move the technology towards
full scale implementation, (2) Important and
needs to be addressed with some urgency, (3)
Less important but needs to be undertaken, (4)
Not important – CCS can be implemented
without this gap being addressed or gap will be
addressed through natural development, and (5)
Unimportant – gap does not need to be
addressed.
At present there are no knowledge gaps that
hinder full scale implementation of geological
storage of CO
2
(1). Important gaps in
knowledge that need to be addressed with some
urgency (2) are:
A)
Storage Capacity
Need to get universal agreement on a storage
capacity assessment method, particulary for
aquifers. This knowledge is needed to
determine effective capacity for CO
2
storage in
geological formations to derive policy and
research initiatives. There is need for a full
global data set – presently most data set is from
Australian, Japan, North America and Western
Europe.
B)
Improved Confidence
Risks of leakage from abandoned wells and
methods of leakage need to be determined.
Assessment of the environmental impact of
CO
2
seepage on the marine seafloor is required.
Also quantitative assessment of risks to human
health is required. Besides more leakage rates
data from more storage sites or projects need to
be collected. Development of a reliable
coupledhydrogeological-geochemical-
geomechanical simulation models to use as a
prediction tools.
C)
Monitoring Techniques
Improve fracture detection and characterization
of leakage potential.
D)
Cost
Only a few experience-based cost data from
non CO
2
-EOR storage sites are available, more
would be useful.
E)
Regulation and Liability
Framework has yet to be established. It should
consider: the role of pilot projects, Verification
of CO
2
storage for accounting purposes,
approaches for selecting, operation and
monitoring CO
2
storage sites in the short and
long term stewardship and requirements for
decommissioning a storage project.
Unimportant (5) knowledge gaps on
geological storage of CO
2
do not need to be
addressed. However, knowledge gaps in the
categories (3) and (4) can be found in detail
(IPCC, 2006).
8 Case study - The Sleipner Gas
field
8.1
Background
The offshore gas field Sleipner, in the
middle of the North Sea (Figure 4), has been
injecting 1 Mt CO
2
per year since September
1996 (Baklid
et al.,
1996). The CO
2
content in
the natural gas varies from 4 to 9.5 % and the
CO
2
content has to be reduced below 2.5% for
export quality. The CO
2
is injected into a salt
water containing sand layer, called the Utsira
formation, which lies 1000 meter below sea
bottom. The Utsira Formation was deposited
during the late Middle Miocene (~20 million
years ago) to Early Pliocene (~14 million years
ago), Eidvin et al. 2002. The formation belongs
to the Nordland Group present in the Viking
Graben (Gregersen and Michelsen 1997).
During 1998, a group of energy
companies together with scientific institutes
and environmental authorities in Norway,
Denmark, the Netherlands, France and the UK
formed the Saline Aquifer CO
2
Storage (SACS)
Project Consortium (supported under the
European Commission’s Thermie Programme)
and started to collect relevant information about
the injection of CO
2
into the Utsira formation
and similar underground structures around the
North Sea.
11
Figure 4:
Location map showng areal extent of the
Utsira Formation and the Sleipner licence.
In 1999 the SACS (Phase 1) project
started monitoring the CO
2
behaviour and
established a baseline by shooting a first 3D
seismic survey (Gale
et al
, 2001). The Phase 1
Project was extended to SACS2 in 2000 and
continued the work undertaken in Phase 1 with
further repeat 3D seismic surveys completed to
track the fate of the injected CO
2.
In addition, it
is using the seismic data to verify available
models and tools originally developed for
hydrocarbons and water that have been applied
to a CO
2
and water system. The SACS2 project
terminated in 2003.
The document Best Practice Manual
(Best Practice Manual, 2004) outlines the main
findings of the SACS projects. This paper
reviews this document including recent studies
with emphasis on geological security and
environmental issues in this section.
8.2
Site characterisation
Characterisation of both the reservoir and
caprock was carried out both at local and
regional scales. The whole reservoir was
mapped and characterised using regional 2D
seismic datasets and well data. More detailed
work was carried out around the injection site
using a 3D seismic dataset and more closely
spaced well data. Several datasets were
available to the SACS project (See Best
Practice Manual, 2004 for details).
The 2D and 3D seismic data constituted
the key datasets, essential for delineating the
reservoir limits, structure and stratigraphical
correlation (Figure 5a). As CO
2
is buoyant (in
both gaseous and fluid phases) it will tend to
rise to the top of the repository reservoir.
Assessment of the depth to the top of the
reservoir is therefore a basic prerequisite of site
characterization for CO
2
storage (Figure 5b).
Uncertainties in reservoir geometry are
significant if the injection is into a reservoir
with gentle dips and only minor topography at
its top (as at Sleipner), therefore, very detailed
depth mapping is required (Figure 5c).
The Utsira formation is a highly
elongated sand reservoir, extending for more
than 400 km from north to south and between
50 and 100 km from east to west, with an area
of some 26 100 km
2
(Figure 5b). The distance
from the top Utsira formation to the surface
generally varies relatively smoothly, mainly in
the range 550 to 1500 m, but mostly from 700
to 1000 m. The thicknesses of the sand layer
vary from 200 m and range up to more than 300
m locally (Chadwick
et al.,
2000).
During the SACS-project, it has been
shown that the Utsira Formation has good
storage quality with respect to porosity,
permeability, mineralogy (Table 1), bedding,
depth, pressure and temperature (e.g. Zweigel
and Lindeberg 2000). It is a very large aquifer
with a thick and extensive claystone top seal
with good sealing capacity. The aquifer is,
however, unconfined along its margins, and the
time before migrating CO
2
might reach the
margins of the aquifer is unknown.
It is estimated that the Utsira Formation,
below 800 m depth, has a pore volume of 9.18
x 10
11
m
3
, a storage capacity in traps of 847 Mt
(megatonnes) CO
2
, and that the storage
capacity of the entire aquifer is 42 356 Mt CO
2
( See details in Bøe et al. 2002, Table 6). The
total pore volume of the aquifer is also
estimated to be 5.5 x 10
11
m
3
(Kirby
et al.
2001)
and 6.05 x 10
11
m
3
(Chadwick et al. 2000).
Injection-induced pressure changes could lead
to compromise of the caprock seal and possible
geomechanical
consequences
should
be
assessed prior to injection commencing. At
Sleipner, the required injection pressures are
considered most unlikely to induce either
dilation of incipient fractures (due to increased
12
pore-pressures) or microseismicity (due either
to raised pore pressures or a reduction in
normal stress due to buoyancy forces exerted
CO
2
plume).
________________________________________________________________________________
Figure 5:
a) Typical 2D seismic reflection profile across the Utsira reservoir b) Regional depth map to top of Utsira
Sand based on 2D seismic surveys and incorporating 3D data around Sleipner injection point. c) Detailed depth map of
Top Utsira Sand around Sleipner injection point (IP), based on 3D seismic data. (Best Practice Manual, 2004).
Table 1
Generalised properties of the Utsira Sand from core and cuttings. Mineral percentages based on whole-rock
XRD (x-ray diffraction) analysis. (Best Practice Manual, 2004).
% Mineral
Grain
size
Porosity
Permeability
Sand/shale
ratio
Quartz Calcite
K-
feldspar
Albite Aragonite
Mica
and
others
Fine
(medium)
35-40 %
(27-42%)
1-3 Darcy
0.7-1.0
(0.5-1.0)
75
3
13
3
3
3
13
8.3
Monitoring
Work at Sleipner demonstrated that
conventional, time-lapse, p-wave seismic data
can be a successful monitoring tool for CO
2
injected into a saline aquifer with CO
2
accumulations as low as about a metre thick
(Eiken et al. 2000). It is the detection of
relatively thin CO
2
accumulations on the time
lapse seismic signal that has built confidence
that any major leakage into the overlying
caprock succession would have been detected.
So far, no changes in the overburden have been
observed in the Sleipner, implying that there
are no leakages from the Utsira formation.
The time lapse seismic data have
provided
insights
into
the
geometrical
distribution of the injected CO
2
at different time
steps and show the different migration
pathways indicated in Figure 6. Due to the
lower density of CO
2
with respect to the
formation water, bouyancy is the dominant
physical process governing the migration. The
seismic data have revealed at least temporary
barriers (very thin shale layers) to vertical
migration of the CO
2
that could not be resolved
on the pre-injection baseline data alone. Due to
the pronounced effect of the CO
2
on the
amplitude of the time lapse seismic signal these
barriers have been mapped locally, markedly
increasing the understanding of the CO
2
migration within the reservoir. At various
locations chimneys have been observed where
CO
2
passes through the thin shale layers. The
presence of thin shale layers has radically
affected the CO
2
distribution in the reservoir,
with CO
2
migrating laterally for several
hundred metres beneath the intra-reservoir
shales (Fig. 6). In the longer term, this
dissemination of CO
2
throughout the reservoir
thickness (rather than just being concentrated at
the top) may allow more efficient dissolution of
CO
2
and effectively increase the reservoir
capacity (Torp and Gale, 2004).
Monitoring is also used to assess whole
reservoir performance. Time-lapse 3D and 4D
seismic surveys have been successfully
employed to image the underground CO
2
(Chadwick
et al.
2005; Figure 5 and 6). These
studies were able to monitor the known injected
amounts of CO
2
, however, some aspects of
reservoir structure and properties remained
imperfectly understood and thus they could not
provide a unique verification of complete
reservoir behaviour (Chadwich
et al.
, 2006).
The Key aspects of the seismic data that
constrain models of CO
2
migration through the
reservoir were assessed at Sleipner (Chadwich
et al.
, 2006). These key aspects of the seismic
data comprise derivation of layer thicknesses
from
seismic
amplitudes
data
(tuning),
topographic analysis of the reservoir top versus
CO
2
- water contact (static ponding), and
thickness determination from combinations of
the amplitudes and the structural analysis
(Chadwich
et al.
, 2006). Their study has shown
that the topmost layer of the CO
2
plume can be
most accurately characterized, its rate of growth
quantified, and CO
2
flux at the reservoir top
estimated. Seismic reflection amplitude maps
(Figure 7) show how the topmost layer has
grown from two small patches in 1999 to an
accumulation of considerable lateral extent by
2002.
The volume of CO
2
within the topmost
layer was computed for three methods of
thickness determination (Table 2), assuming a
mean sand porosity of 0.38 with saturations
computed using a laboratory determined
relationship between buoyancy forces and
capillary pressure. From the topmost layer
volumes, the rate at which CO
2
has arrived at
the top of the reservoir was estimated. Taking,
for
example,
the
amplitude-structure
thicknesses, an estimated 1.8 x 10
5
m
3
of CO
2
arrived at the reservoir top between the 1999
and 2001 surveys, an average flux of ~250 m
3
per day. Between the 2001 and 2002 surveys
~1.1 x 10
5
m
3
of CO
2
arrived at the reservoir
top, an average flux of ~450 m
3
day
-1
. Between
the 2002 and 2004 surveys a further ~3.1 x 10
5
m
3
of CO
2
arrived at the reservoir top,
averaging ~400 m
3
day
-1
. These volumes
correspond to ~3.7%, ~6.2 % and ~6.5% of the
total amount of CO
2
injected during the
respective periods. The analysis indicates that,
following early and quite rapid establishment of
flow pathways, mudstone flow properties have
remained
fairly
stable.
This
improves
confidence in likely caprock stability in the
presence of CO
2
, and more generally in the
14
Figure 6
: Repeat seismic surveys and position of injected CO
2
(Source Torp and Gale, 2004).
Figure 7
: Growth of the topmost CO
2
layer mapped through time via seismic amplitudes (circle denotes location of
injection point), Chadwick
et al.
2006.
Table 2
Volume of CO
2
in topmost layer computed from three different methods (Chadwick
et al.
2006).
________________________________________________________________________________
validity of longer-term simulations of plume
development (Chadwich
et al
., 2006).
8.4
Reservoir simulation
Reservoir simulation was carried out to
verify and improve the seismic and geological
interpretations of the reservoir around the
injection site. Moreover to use the history
matched reservoir model of the area around the
injection site to build a large-scale model to
predict the long-term fate of CO
2
.
Although the geophysical interpretation
of the seismic is non-unique, iteration between
the geophysical interpretation of the seismic
reflections attributed to the injected CO
2
and
the reservoir simulations showed good matches
15
between observed and simulated bubble areas
even if CO
2
solubility was completely neglected
(Best Practice Manual, 2004). From this it was
also concluded that the shale layers do not
disperse large amounts of CO
2
into small leak
streams when it is transported from layer to
layer, rather it is concentrated at localised spill
points, curtains, or holes.
The information from the calibrated
local model was extrapolated to build a 3D
reservoir model covering an area of 128 km
2
to
predict the fate of CO
2
over a time period of
thousands of years. The results of the
simulations show that most of the CO
2
accumulates in one bubble under the cap seal a
few years after the injection is turned off. The
CO
2
bubble spreads laterally on top of the brine
column and the migration is controlled by the
topography of the cap seal only.
It has been shown that diffusion of CO
2
from the gas cap into the underlying brine
column will have a most pronounced effect.
The brine on top of the column, which becomes
enriched in CO
2
, is denser than the brine below
due to the special volumetric properties of the
CO
2
-brine system. This creates an instability
that sets up convectional currents maintaining a
large concentration gradient near the CO
2
/brine
interface, enhancing the dissolution of CO
2
.
Reservoir simulations under various
scenarios were tested to predict the long-term
fate of CO
2
(Best Practice Manual, 2004). The
results show that the bubble will reach a
maximum size after probably less than 300
years. After this time dissolution is the
dominating effect on bubble extension and the
bubble will gradually shrink and finally
disappear after less than 4000 years. This
process is commonly called solubility trapping
(Section 3.1). Thus preliminary results suggest
that in the long term (> 50 years) the phase
behaviour (solubility and density dependence of
composition) will become the controlling fluid
parameters at Sleipner.
During and after the injection of CO
2
,
some of the CO
2
can dissolve in the formation
water, some can react with the present minerals
and some of the CO
2
can exists as a separate
phase (immiscible). Mobility of immiscible
CO
2
is of major importance for evaluating the
risk of leakage. Khattri
et al.
, 2006 studied the
impact of regional water flow on the
distribution of immiscible CO
2
using numerical
modelling of reactive transport at the Utsira
formation. Their analyses show that immiscible
CO
2
is mobilized due to buoyancy forces, and
the immiscible CO
2
get carried away by the
regional water flow. Regional flow can thus
dramatically affect the CO
2
distribution. This
hints further that pressure build up as a
consequence of CO
2
injection is unlikely to
occur.
8.5
Geochemical characterization
It is essential to have a good
understanding of the fluid chemistry and
mineralogical composition of reservoir and
caprock so as to elucidate their reactivity with
CO
2
.
At the start, only limited geochemical
baseline data were available within the SACS
project. This necessitated the use of certain
(logical) assumptions in the design of the
experimental
programme
and
in
the
geochemical characterization and modelling
work (Best Practice Manual, 2004). In general,
the Utsira sand showed only limited reaction
with CO
2
. Most reaction occurred with
carbonate phases (shell fragments), but these
were a minor proportion (about 3%; Table 1) of
the overall solid material. Silicate minerals
showed only slow and minor reaction. Then, in
terms of geochemical reactions, the Utsira sand
would appear to be a good reservoir for storing
CO
2
.
Recent studies strengthen further these
observations while assessing the behaviour of
CO
2
with
the
reservoir
seal.
Earlier
observations from laboratory experiments
during the SACS project show that the Utsira
sand have revealed changes in fluid chemistry,
associated mainly with dissolution of primary
minerals. The experiments pressurised by CO
2
led
to
large
and
rapid
increases
in
concentrations of Group II metals (and in
particular Ca and Sr), as well as slow and slight
increases
in
silica
concentrations.
This
suggested fast partial dissolution of carbonate
phases, while dissolution of silicate or
aluminosilicate minerals was a much slower but
16
real process. Numerical modelling was used to
interpret, and hence to better understand the
laboratory
experiments,
based
on
thermodynamic, kinetic, flow and transport
processes. For most of the major elements, the
predicted trends were in reasonable agrement
with the experimental observations on the
Utsira sand.
The impact of CO
2
storage on the Utsira
reservoir and its cap rock at Sliepner was
studied using a long term coupled transport and
geochemical modelling (Gaus
et al.
2006). This
is a key to understanding the long term
geochemical impact of CO
2
storage. Results on
impact of dissolved
CO
2
on the cap rock after 3000
years at Sleipner shows that
vertical diffusion of
CO
2
can be retarded as a consequence of
geochemical
interactions.
The
calculated
porosity change was found to be small and
limited to the lower few metres of the cap rock.
The calculations were positive with respect to
the
sealing
efficiency
meaning
slight
improvement of the cap rock sealing capacity.
Moreover, at the cap rock/reservoir interface
minor carbonate dissolution is expected to
occur. Overall in the Utsira case geochemical
reactions, other than dissolution of CO
2
with pH
change, are unlikely to play a major role due to
its low reservoir temperature (37°C) leading to
very slow reaction kinetics and little reactive
mineralogy. After a 10 000 year simulation
Gaus
et al.
2006 concluded that CO
2
is
completely dissolved in the formation water
due to carbonate dissolution and in the form of
bicarbonate ions. Main mineralogical changes
take place where the dense temporary CO
2
bubble was present and there most of the
carbonates dissolve.
Caprock properties of the Nordland Shale
recovered from the 15/9-A11 well, was
assessed for intergrity at the Sleipner area
(Springe
and Lindgren, 2006). The results show
that the CO
2
bubble spreading beneath the seal
is unlikely to enter the Nordland Shale,
implying good sealing capacity. However, this
conclusion may change if regional variation in
grain size exceeds the range observed in the
15/9-A11 well.
8.6
Geological security
Geological security of carbon dioxide
storage depends on a number of factors. The
first and formost prerequisite is a carefull
storage
site
selection.
At
Sleipner,
characterisation of the reservoir and caprock
was carried out at a range of scales. Available
geological information show that extensive
rifting and normal faulting occurred in the
North Sea and the Norwegian Sea before and
during early Cenozoic (Paleogene period, 65-23
million years ago). The Utsira formation was
deposited in late Middle Miocene (ca.20
million years ago) to Early Pliocene (~13
million years ago). Recent geological structures
are associated with mud volcanoes and
intraformational faults and are more likely to
affect the underlying Oligocene (ca. 36 million
years) sediments (Fabriol 2001). Microseismic
studies show that the injection of CO
2
in sands
of the Utsira Formation should not trigger any
measureable microseismicity. Absence of major
tectonic events after the deposition of the Utsira
formation coupled with the evidence from
microseismic
studies
further
builds
the
confidence in geological security of carbon
dioxide storage at Sleipner. Moreover, evidence
(e.g. reservoir flow modelling and seismic
monitoring of the injected CO
2
) from ten years
experience shows no leakages of carbon
dioxide from storage site.
Monitoring is needed primarily to build
our confidence in geological security of CO
2
storage. This is currently the principal method
for assuring that the CO
2
remains stored and
that performance predictions can be verified
and requires some combination of models and
monitoring. At Sleipner the CO
2
injection
process was monitored using seismic methods
and this provided insights into the geometrical
distribution of the injected CO
2
. It also allowed
increase understanding of the CO
2
migration
within the reservoir and to make storage
inventory and verification of CO
2
injection.
This is a key tool to assess potential leakage.
The results of reserviour simulations and
geochemical characterization show that the CO
2
bubble will in the long term be dissolved with
the phase behaviour (solubility and density
dependence of composition) as controlling fluid
17
parameters at the early stage. The primary
benefit of solubility trapping is that once CO
2
is
dissolved, it no longer exists as a separate
phase, thereby eliminating the buoyant forces
that drive it upwards. Next, it will form ionic
species as the rock dissolves, accompanied by a
rise in the pH. Finally, some fraction may be
converted to stable carbonate minerals (mineral
trapping), the most permanent and secure form
of geological storage. The recent studies at
Sleipner area strengthens further the geological
security of carbon dioxide storage in the Utsira
formation. Moreover regional flow can have
dramatic effect on the CO
2
distribution. This
hints further that pressure build up as a
consequence of CO
2
injection is unlikely to
occur and eliminating the prospects of CO
2
leaks.
Evidence from oil and gas fields indicates
that hydrocarbons and other gases and fluids
including CO
2
can remain trapped for millions
of years (Magoon and Dow, 1994; Bradshaw
et
al.
, 2005). Carbon dioxide has a tendency to
remain
in
the
subsurface
(relative
to
hydrocarbons) via its many physicochemical
immobilization
mechanisms.
World-class
petroleum provinces have storage times for oil
and gas of 5–100 million years, others for 350
million years, while some minor petroleum
accumulations have been stored for up to 1400
million years. However, some natural traps do
leak, which reinforces the need for careful site
selection,
characterization
and
injection
practices.
8.7
Environmental issues
Carbon dioxide storage in geological
formations is a safe way to achieve large-scale
reductions in emissions. The dominant safety
concern about geological storage is potential
leaks that can cause potential local and regional
environmental hazards. Leaks can either be
slow or rapid. Gradual and dispersed leaks will
have very different effects than episodic and
isolated ones. The most frightening scenario
would be a large, sudden, catastrophic leak.
This kind of leak could be caused by a well
blowout or reactivation of earlier unidentified
geological structures due to for instance
microseismic or earth quack events. The most
noteworthy natural example of a catastrophic
CO
2
release was in the deep tropical Lake Nyos
in Cameroon in 1986 in which a huge released
CO
2
gas cloud killed 1,700 people in a nearby
village. A sudden leak also could result from a
slow leak if the CO
2
is temporarily confined in
the near-surface environment and then abruptly
released.
CO
2
being a nontoxic at low concentrations
can cause asphyxiation primarily by displacing
oxygen at high concentrations. For large-scale
operational CO
2
storage projects, assuming that
sites are well selected, designed, operated and
appropriately monitored, the balance of
available evidence suggests that it is very likely
the fraction of stored CO
2
retained is more than
99% over the first 1000 years, implying very
negligible risks. However, should leaks occur,
the possible local and regional environmental
hazards are those described in Section 6.
At Sleipner CO
2
storage project it is
important to demonstrate through monitoring
and verification procedures to detect potential
leaks if any. Monitoring technology that can
measure CO
2
concentrations in and around a
storage location to verify effective containment
of the gas needs to be placed. Leakage from a
naturally occurring underground reservoir of
CO
2
such as in Lake Nyos in Cameroon
provides some perspective on the potential
environmental impacts. The leaking led to the
death of plants, soil acidification, increased
mobility of heavy metals and human fatality.
This site can be a useful natural analog for
understanding potential leakage risks, but it is
situated in a seismically active area, unlike the
sedimentary basins where engineered CO
2
storage would take place. Still, we should be
wary of undue optimism and continue to
question the safety of artificial underground
CO
2
storage. Given potential risks and
uncertainties, the implementation of effective
measurement, monitoring, and verification
tools and procedures will play a critical role in
managing
the
potential
leakage
risks.
Continued research on the mobility of the
injected CO
2
(and the risks associated with its
leakage) should be high priorities. Risks
associated
with
leakage
from
geologic
reservoirs beneath the ocean floor are less than
risks of leakage from reservoirs under land,
because in the event of leakage, the dissipating
18
CO
2
would diffuse into the ocean rather than
reentering the atmosphere. But then hazards to
marine ecosystems will be of concern.
9 Conclusions
The security of carbon dioxide storage in
geological formations first and foremost
depends on carefull storage site selection
followed by characterization of the selected
site. The Utsira Formation is well characterized
with respect to porosity and permeability (good
storage capacity and injectivity), mineralogy,
bedding, depth, pressure and temperature. It is a
very large aquifer with a thick and extensive
claystone top seal. Available geological
information shows absence of major tectonic
events after the deposition of the Utsira
formation. This implies that the geological
environment is tectonically stable and a site
suitable
for
carbon
dioxide
storage.
Microseismic studies suggest that the injection
of CO
2
in sands of the Utsira Formation can not
trigger any measureable microseismicity. This
further builds the confidence in geological
security of carbon dioxide storage at Sleipner.
Moreover, evidence from ten years experience
of carbon dioxide storage shows no leakages.
The Sleipner project is a commercial
CO
2
injection project and has demonstrated that
CO
2
storage is both safe and has a low
environmental impact. The work that has been
undertaken at Sleipner Gas Field has shown
that the injected CO
2
can be monitored within a
geological storage reservoir, using seismic
surveying. The geochemical and reservoir
simulation work have laid the foundations to
show how the CO
2
has reacted and what its
long term fate in the reservoir will be. The
injected CO
2
will potentially be trapped
geochemically and pressure build up as a result
of CO
2
injection is unlikely to occur. In the
long term solubility and density dependence of
composition will become the controlling fluid
parameters at Sleipner. The solubility trapping
has the effect of eliminating the buoyant forces
that drive CO
2
upwards and through time can
lead to mineral trapping, which is the most
permanent and secure form of geological
storage.
The recent studies at the Sleipner area
reenforce the integrity of the cap rock and there
is efficient sealing capacity. Monitoring and
modelling proved to be key tools in
understanding the whole reservoir performance.
Overall, the study at the Sleipner area
demonstrates the geological security of carbon
dioxide
storage.
The
monitoring
tools
strengthen the verification of safe injection of
CO
2
in the Utsira formation. This proves that
CO
2
capture and storage is technically feasible
and can be an effective method for greenhouse
mitigation
provided
the
site
is
well
characterized and monitored properly.
References:
Bachu,
S., 2003: Screening and ranking of sedimentary
basins for sequestration of CO
2
in geological media.
Environmental Geology
,
44
(3), 277–289.
Bachu,
S., W.D. Gunter and E.H. Perkins, 1994:
Aquifer disposal of CO
2
: hydrodynamic and mineral
trapping,
Energy Conversion and Management
,
35
(4),
269–279.
Baklid
, A, Korbøl, R. and Owren, G., 1996. SPE 36600,
Denver, Colorado, USA.
Best Practice manual
, 2004: S. Holloway, A.
Chadwick, E. Lindeberg, I. Czernichowski-Lauriol and
R. Arts (eds.), Saline Aquifer CO
2
Storage Project
(SACS), 53 pp.
Bradshaw,
J., C. Boreham and F. la Pedalina, 2005:
Storage retention time of CO
2
in sedimentary basins:
Examples from petroleum systems. Proceedings of the
7th International Conference on Greenhouse Gas
Control Technologies (GHGT-7), September 5–9, 2004,
Vancouver, Canada, v.I, 541-550.
Brennan,
S.T. and R.C. Burruss, 2003: Specific
Sequestration Volumes: A Useful Tool for CO
2
Storage
Capacity Assessment. USGS OFR 03-0452 available at
http://pubs.usgs.gov/of/2003/of03-452/
.
Bøe,
R., C. Magnus, P.T. Osmundsen and B.I. Rindstad,
2002: CO
2
point sources and subsurface storage
capacities for CO
2
in aquifers in Norway. Norsk
19
Geologische Undersogelske, Trondheim, Norway, NGU
Report 2002.010, 132 pp.
Chadwick
, R.A., Holloway, S., Kirby, G.A., Gregersen,
U. & Johannessen, P.N. 2000. The Utsira Sand, Central
North Sea – an assessment of its potential for regional
CO
2
disposal. Proceedings of the 5
th
International
Conference on Greenhouse Gas Control Technologies
(GHGT-5), Cairns, Australia, 349 – 354.
Chadwick,
R.A., R. Arts and O. Eiken, 2005: 4D
seismic quantification of a growing CO
2
plume at
Sleipner, North Sea. In: A.G. Dore and B. Vining (eds.),
Petroleum Geology: North West Europe and Global
Perspectives - Proceedings of the 6th Petroleum
Geology Conference. Petroleum Geology Conferences
Ltd. Published by the Geological Society, London, 15pp
(in press).
Chadwick
, A., Noy, D., Lindeberg, E., Arts, R., Eiken,
O.,
Williams,
G.,
2006:
Calibrating
reservoir
performance with time-lapse seismic monitoring and
flow simulations of the Sleipner CO
2
plume. 8
th
Greenhouse Gas Control Technologies conference
(GHGT-8), Trondheim, June 2006.
Chalaturnyk,
R. and W.D. Gunter, 2005: Geological
storage of CO
2
: Time frames, monitoring and
verification. Proceedings of the 7th International
Conference on Greenhouse Gas Control Technologies
(GHGT-7), September 5–9, 2004, Vancouver, Canada,
v.I, 623-632.
Eidvin
, T., Rundberg, Y. & Smelror, M. 2002: Revised
chronology of Neogene sands (Utsira and Skade
Formations) in the central and northern North Sea.
In
NGF/NPF (eds.): Onshore-offshore relationships on the
North Atlantic Margin, Trondheim, 13th-15th May
2002. Extended Abstract. et al. 2002
Eiken
, O., Brevik, I., Arts. R., Lindeberg, E., &
Fagervik, K. 2000: Seismic monitoring of CO
2
injected
into a marine aquifer. SEG Calgary 2000 International
conference and 70th Annual meeting, Calgary, paper
RC-8.2.
Fabriol,
H., 2001. Feasibility study of microseismic
monitoring (Task 5.8). BRGM Commissioned Report
BRGM/RP-51293-FR (Confidential).
Flett,
M.A., R.M. Gurton and I.J. Taggart, 2005:
Heterogeneous saline formations: Long-term benefits
for geo-sequestration of greenhouse gases. Proceedings
of the 7th International Conference on Greenhouse Gas
Control Technologies (GHGT-7), September 5–9, 2004,
Vancouver, Canada, v.I, 501-510.
Gale
, J.J.et al, 2001. Environ. Geoscience, 8, 3,
September
Gaus,
I., Audigane, P., Thibeau, S., 2006: Long term
coupled transport and geochemical modelling of the
impact of CO
2
storage on the Utsira reservoir and its cap
rock at Sleipner (North Sea). 8
th
Greenhouse Gas
Control
Technologies
conference
(GHGT-8),
Trondheim, June 2006.
Gregersen
, U., Michelsen, O. & Sørensen, J.C. 1997:
Stratigraphy and facies distribution of the Utsira
Formation and Pliocene sequences in the northern North
Sea.
Marine and Petroleum Geology 14
, 893-914.
Gunter,
W.D., E.H. Perkins and T.J. McCann, 1993:
Aquifer disposal of CO
2
-rich gases: reaction design for
added capacity.
Energy Conversion and Management
,
34
, 941–948.
Haidl
, F.M., S.G. Whittaker, M. Yurkowski, L.K.
Kreis, C.F. Gilboy and R.B. Burke, 2005: The
importance of regional geological mapping in assessing
sites of CO
2
storage within intracratonic basins:
Examples from the IEA Weyburn CO
2
monitoring and
storage project, Proceedings of the 7th International
Conference on Greenhouse Gas Control Technologies
(GHGT-7), September 5–9, 2004, Vancouver, Canada,
v.I, 751-760.
Holloway
S, Chadwick RA, Kirby GA, Pearce JM,
Gregersen U, Johannessen PN, Kristensen L, Zweigel P,
Lothe A, Arts R, 2002. Final Report of SACS 1 Project.
Saline Aquifer CO
2
Storage: A Demonstration Project at
the Sleipner Field. Technical report, The SACS Project.
http://www.iku.sintef.no/projects/IK23430000/index.ht
ml.
IEA,
2005: World Energy Outlook 2004, OECD and
International Energy Agency report, Paris, France.
IPCC,
2001a: Climate Change 2001 - Mitigation. The
Third Assessment Report of the Intergovernmental
Panel on Climate Change. B. Metz, O. Davidson, R.
Swart, and J. Pan (eds.). Cambridge University Press,
Cambridge, UK
IPCC,
2001c: Climate Change 2001: the Scientific
Basis. Contribution of Working Group I to the Third
Assessment Report of the Intergovernmental Panel on
Climate Change. J.T. Houghton, Y. Ding, D.J. Griggs,
M. Noguer, P.J. van der Linden, X. Dai, K. Maskell,
and C.A. Johnson, (eds.). Cambridge University Press,
Cambridge, UK.
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.
IPCC
, 2006: Review of IPCC Special Report on
Carbon Dioxide Capture and Storage (SRCCS) Gaps in
Knowledge. Report Number: 2006/TR1, 26 pp.
Khattri
, S. K., Hellevang, H., Fladmark, G. E.,
Kvamme, B, 2006: Numerical modelling of reactive
transport at the Utsira. 8
th
Greenhouse Gas Control
20
Technologies conference (GHGT-8), Trondheim, June
2006.
Kirby
, G. A.., Chadwick , R. A. & Holloway, S . 2001.
Depth mapping and characterisation of the Utsira Sand
Saline Aquifer, Northern North Sea.
British Geological
Survey Commissioned Report
, CR/01/218. 26pp.
Korbol,
R. and A. Kaddour, 1994: Sleipner West CO2
disposal: injection of removed CO
2
into the Utsira
formation.
Energy Conversion and Management
,
36
(6–
9), 509–512.
Kovscek,
A.R., 2002: Screening criteria for CO2
storage in oil reservoirs.
Petroleum Science and
Technology
,
20
(7–8), 841–866.
Lippmann,
M.J. and S.M. Benson, 2003: Relevance of
underground
natural
gas
storage
to
geologic
sequestration of carbon dioxide. Department of
Energy’s
Information
Bridge,
http://www.osti.gov/
dublincore/ecd/servlets/purl/813565-m7Ve/native/
813565
. pdf, U.S. Government Printing Office (GPO).
Magoon,
L.B. and W.G. Dow, 1994: The petroleum
system. American Association of Petroleum Geologists,
Memoir
60
, 3–24.
Pearce,
J.M., S. Holloway, H. Wacker, M.K. Nelis, C.
Rochelle and K. Bateman, 1996: Natural occurrences as
analogues for the geological disposal of carbon dioxide.
Energy Conversion and Management
,
37
(6–8), 1123–
1128.
Perry,
K.F., 2005: Natural gas storage industry
experience and technology: Potential application to CO
2
geological storage, Carbon Dioxide Capture for Storage
in Deep Geologic Formations—Results from the CO
2
Capture Project, v. 2: Geologic Storage of Carbon
Dioxide with Monitoring and Verification, S.M. Benson
(ed.), Elsevier Science, London, pp. 815–826.
Salvi,
S., F. Quattrocchi, M. Angelone, C.A. Brunori,
A. Billi, F. Buongiorno, F. Doumaz, R. Funiciello, M.
Guerra, S. Lombardi, G. Mele, L. Pizzino and F.
Salvini, 2000: A multidisciplinary approach to
earthquake research: implementation of a Geochemical
Geographic Information System for the Gargano site,
Southern Italy. Natural Hazard, 20(1), 255–278.
Springer,
N. and Lindgren, H., 2006: Caprock
properties of the Nordland Shale recovered from the
15/9-A11 well, the Sleipner area.. 8
th
Greenhouse Gas
Control Technologies conference (GHGT-8),
Trondheim, June 2006.
Steefel
C. I., 2001: CRUNCH. Lawrence Livermore
National Laboratory, Livermore, CA. 76 pp.
Stangeland
, A., Kristiansen, B. and Solli, A. 2006:
How to close the gap between global energy demand
and renewable energy production. Bellona paper, The
Bellona Foundation,
Oslo, Norway
Stangeland
, A. 2006: CO
2
Capture and Storage – A
Strategy to Combat Climate Changes. Bellona paper,
The Bellona Foundation,
Oslo, Norway
Streit
, J., A. Siggins and B. Evans, 2005: Predicting and
monitoring geomechanical effects of CO
2
injection,
Carbon Dioxide Capture for Storage in Deep Geologic
Formations—Results from the CO
2
Capture Project, v.
2: Geologic Storage of Carbon Dioxide with Monitoring
and Verification, S.M. Benson (ed.), Elsevier Science,
London, pp. 751–766.
Studlick
, J.R.J., R.D. Shew, G.L. Basye and J.R. Ray,
1990: A giant carbon dioxide accumulation in the
Norphlet Formation, Pisgah Anticline, Mississippi. In:
Sandstone Petroleum Reservoirs, J.H. Barwis, J.G.
McPherson and J.R.J. Studlick (eds.), Springer Verlag,
New York, 181–203.
Torp
, T.A, Gale J. 2004. Demonstrating storage of
CO2 in geological reservoirs: The Sleipner and SACS
Projects.
Energy
, 29:1361-1369.
Watson
, M.N., C.J. Boreham and P.R. Tingate, 2004:
Carbon dioxide and carbonate elements in the Otway
Basin: implications for geological storage of carbon
dioxide.
The APPEA Journal
,
44
(1), 703–720.
White
, M.D. and M. Oostrom, 1997: STOMP,
Subsurface Transport Over Multiple Phases. Pacific
Northwest National Laboratory Report PNNL-11218,
Richland, WA, October 1997.
Xu
, T., J.A. Apps and K. Pruess, 2003: Reactive
geochemical transport simulation to study mineral
trapping for CO
2
disposal in deep arenaceous
formations.
Journal of Geophysical Research,
108
(B2),
2071–2084.
Zweigel
, P. & Lindeberg, E. 2000: 4D seismikk løser
gåten.
GEO 6 - 2000
, 16-18.