This paper was prepared by Dr Steve Whittaker and Dr Ernie Per

This paper was prepared by Dr Steve Whittaker and Dr Ernie
Perkins, respectively Principal
Manager–Carbon Storage and Consultant–Projects, during their
time at the Institute.
October 2013
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1.1 Background
The injection of carbon dioxide into oil fields is one method of
enhancing oil recovery that has been used
commercially for more than 40 years. For enhanced oil recovery
(EOR), carbon dioxide gas (CO2) is
compressed at surface and injected as a liquid into the oil
reservoir at depth where it effectively acts as a
solvent to increase the amount of oil that can be produced from
the field. Typically, CO2 EOR is a tertiary
method applied to reservoirs that have declining oil production
and that have progressed through primary
and secondary production stages.
Primary production uses the reservoirs’ natural pressure to drive

the oil to surface whereas secondary
production typically involves pumping the oil to surface and
injection of water to restore or increase reservoir
pressure to drive oil production. The reason CO2 is used in a
tertiary method is because water does not mix
with the oil (they are immiscible) whereas CO2 and oil can mix
(they are miscible) at reservoir conditions.
This results in the oil becoming less viscous so that it flows
more easily. Very generally, if a secondary water
injection program is successful, it bodes well for a CO2 EOR
program being successful. It must be noted that
not all oil fields are suitable for CO2 injection as oil
composition, depth, temperature and other reservoir
characteristics significantly influence the effectiveness of this
method (Melzer, 2012).
The amount of oil that can be recovered during the different
production stages is again highly dependent on
the nature of the geological reservoir and oil composition, but
in very general terms fields typically targeted
for CO2 EOR have had primary recovery of about 10–20 per
cent of the original oil in place, secondary
recovery of an additional 10–20 per cent, and expectations from
CO2 EOR of another 10–20 per cent. Thus
CO2 EOR provides an opportunity to improve the efficiency of

resource extraction and clearly can lead to
significant economic benefits through sales from additional oil
production and through extending the
productive life of suitable oil fields by decades. An additional
noteworthy benefit of this method is that when
the CO2 mixed with the oil is produced it can be separated and
re-injected and ultimately retained in the
reservoir so that incidental geological storage of CO2 is an
intrinsic part of the overall process.
A number of excellent overview papers on the geological and
engineering aspects CO2 EOR, including
potential for storage, have been released recently (such as Hill
et al, 2013; National EOR Initiative, 2012;
Melzer, 2012; Berenblyum et al. 2011; Kuuskraa et al. 2011;
and Hovorka and Tinker, 2010).
Currently, about 130 commercial CO2 EOR operations, also
called CO2 floods, have been deployed around
the world, although the vast majority are in the United States.
Roughly half of the American projects are
within a geologic setting known as the Permian Basin located in
west Texas where commercial CO2 EOR
operations were first attempted in Scurry County at the Scurry
Area Canyon Reef Operators Committee
(SACROC) site in 1972. It is notable that SACROC initially

used an anthropogenic source of CO2 (A-CO2)
from capture at natural gas plants as most of the subsequent
development of CO2 EOR sites in the Permian
Basin and surrounding regions was driven by the availability of
relatively inexpensive CO2 produced from
reservoirs that contained geologically (i.e. naturally) sourced
CO2 (N-CO2).
Geological structures such as the McElmo Dome in Colorado
and Bravo Dome in New Mexico are features
that contain enormous quantities of naturally occurring CO2
(Allis et al., 2001). The McElmo Dome alone
contained more than 280 billion m3 of high purity CO2 and
together with the Bravo Dome these natural
sources supply more than 40 million m3/d of CO2 to oil fields
in Texas, Utah and Oklahoma (DiPietro and
Balash, 2012). Today, about 7,000 km of CO2 pipelines (Dooley
et al., 2009) transport about 70Mt CO2 per
year for use in North American CO2 EOR operations of which
about 75 per cent originates from natural
geological sources and the remainder from anthropogenic
sources such as gas plants and fertiliser plants.
Two commercial-scale capture projects to supply anthropogenic
CO2 for EOR from coal-fired power plants
are in construction at the Boundary Dam Power Plant in

Saskatchewan, Canada and in Kemper County,
Mississippi, USA.
Technical aspects of CO2 EOR and associated carbon storage
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Most, if not all, CO2 EOR operators do not implement
procedures to optimise opportunities for storage of CO2
in association with their floods because there is no present
financial or regulatory impetus to consider
storage as a component of their business. Rather, the cost of
purchasing CO2 leads companies to minimise
the amount of CO2 required to produce a barrel of oil, and
operators continuously attempt to optimise

economic return based around the price of oil and cost of CO2.
For operators to consider carbon storage a
part of the business some form of price, tax or policy on carbon
will need to be implemented. In the instance
that regulatory or economic drivers do arise, transitioning CO2
EOR operations to more actively include
storage and ultimately become dedicated carbon storage sites
will involve some operational modifications
and likely require additional monitoring and verification
activities than typically implemented for oilfield,
including EOR, operations at present.
1.2 How CO2 EOR works
Enhanced, or tertiary, oil recovery methods involve techniques
that alter the original properties of the oil
allowing it to be more easily produced. Injection of CO2, other
solvents, or steam (heat) are among the most
common forms of EOR. CO2 EOR can be applied to a range of
reservoir settings including sandstones,
limestones and dolostones; in structural or stratigraphic tr aps;
in small isolated buildups or giant fields; and
onshore or offshore (although no commercial offshore CO2
EOR has yet been performed). Limitations to
deployment are largely influenced by depth (temperature) of

reservoir, oil composition, previous oil recovery
practices and internal reservoir features that may hinder
effective distribution of the injected CO2. Access
and proximity to a relatively pure and consistent stream of low -
cost CO2, however, is among the more critical
factors limiting wider deployment of CO2 EOR.
The cost of initiating a CO2 flood is significant and a large
anchor field is often needed to develop the
infrastructure to deliver CO2 before smaller nearby fields are
able to access a supply. In the southern United
States the availability of relatively low-cost CO2 from naturally
occurring geological sources in proximity to
suitable oil fields is a primary reason for the early development
and extensive use of CO2 EOR in this region.
Either geologically sourced CO2 or anthropogenic CO2 can be
used in CO2 EOR, although a requirement for
CO2 purity of greater than 95 per cent is a rule-of-thumb.
Whereas some A-CO2 can be obtained quite pure
relatively easily (from natural gas processing for example) other
captured sources such as from coal-fired
power plants must go to greater effort and expense to purify
CO2 to the required specification. Other
components in the CO2-stream may reduce (or enhance)
miscibility so most operators prefer to work with

relatively pure CO2.
After capture the CO2 is compressed and usually pipelined to
the field although trains and trucks have also
been used to deliver CO2 for pilots and smaller-scale
operations. Ships have also been proposed to move
large quantities of CO2 for offshore use or to areas without
other natural-source or capture options (Chiyoda,
2013). In North America an extensive network of pipelines has
been transporting compressed CO2 for
decades using well-established protocols, standards and safety
procedures. Once delivered to the field the
CO2 is further distributed to the injection well(s) and injected
into the reservoir.
The compression of CO2 for transportation and injection
converts the CO2 from a gas into a denser phase –
either to liquid or to a supercritical fluid. Supercritical fluids
are physically similar to, but not strictly, liquids or
gases, and supercritical CO2 has a density similar to a liquid
and mobility similar to a gas. Many common
materials such as water and carbon dioxide become supercritical
above specific pressures and
temperatures; for CO2 this is a temperature greater than 31.1°C
and a pressure greater than 7.38 Mpa

(Bachu, 2008). These conditions are reached naturally in the
subsurface generally below about 800 m depth
and most CO2 EOR operations (and saline formation storage
projects), therefore, will target reservoirs of this
depth or greater. This is to ensure that the injected CO2 will
remain in a dense state and to minimise its
buoyancy in the reservoir. Figure 1 depicts the pressure and
temperature influence on the density of CO2.
This is an important concept for enhanced oil recovery as
supercritical CO2 has properties that make it an
effective solvent for many oils.
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When injected CO2 contacts reservoir oil, the dense CO2 will
begin to dissolve into the oil, and the oil will
begin to dissolve into the dense CO2. This mixing does not
occur instantaneously, but with time and repeated
contact between the fluids the oil and CO2 can mix to become a
single phase. In the instance where CO2 and
oil mix completely it is termed miscible and CO2 floods are
often referred to as miscible floods. The effect of
this miscibility is to cause the oil to swell slightly and become

less viscous so that it flows within and through
the reservoir pores more easily. The majority of CO2 EOR
projects operate in fully miscible conditions;
however incomplete mixing or partially to completely
immiscible CO2 floods may also be operated and can
be effective at increasing oil production.
Figure 1: Relation of the density of carbon dioxide to
temperature and pressure (Bachu, 2003).
A key parameter for an effective CO2 EOR project is
maintaining oil-CO2 miscibility which is primarily a
function of reservoir pressure. The minimum miscibility
pressure (MMP) is the lowest pressure at which an oil
and CO2 are completely miscible. The MMP is specific for
individual oil compositions and must be
determined by performing laboratory analyses such as using a
slim tube apparatus or through a rising
bubble experiment (Figure 2). Although numerical models and
correlations also exist to estimate MMP for
most oils, MMP should be confirmed experimentally for any
particular oil reservoir. Oil recovery operations
are usually designed to maintain reservoir pressure above the
MMP. If the pressure during oil recovery is
less than the MMP the lighter hydrocarbon components in the
oil (lower molecular weight and generally

lower viscosity) may be preferentially produced. This leads to
the residual oil becoming progressively more
viscous and more difficult to recover, and increases the
potential for asphaltenes and waxes (components
common in many crude oils) to precipitate and become lodged
in pores and small channels connecting pores
thereby plugging or reducing flow within parts of the reservoir.
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Figure 2: Miscible and immiscible zones during experimental
oil recovery as a function of CO2
(reservoir) pressure. HCPV = hydrocarbon pore volume. Shelton
and Yarborough (1977).
One of the aims of CO2 EOR is to have a relatively smooth
front of CO2 ‘sweeping’ oil not previously
recovered into the producing wells. The density of supercritical
CO2 is slightly less than water and oil so
injected CO2 will tend to be buoyant in the reservoir providing
the potential to sweep higher and potentially
unswept portions of the reservoir, but also with the possibility
of over-riding and thereby bypassing the oil.
Variations in physical characteristics of the reservoir such as

porosity and permeability play a critical role in
influencing the effectiveness of the distribution of the injected
CO2.
Porosity is the void spaces between grains or minerals, and
permeability is a measure of the ability of a rock
to allow fluids to flow through it. Small scale heterogeneities
effectively disperse the CO2 and expand the
contact region between CO2 and oil, whereas larger scale
heterogeneities may channel the injected CO2
thereby reducing reservoir sweep (often referred to as viscous
fingering). The affinity of mineral surfaces for
water or other fluids is known as wettability and this also
influences the movement of water, oil and CO2
within the reservoir. For example, if the reservoir rock is water -
wet, this indicates a thin film of water is
present on all mineral surfaces and oil does not touch the
surfaces (Melzer 2012). Moreover, each fluid may
have a different permeability within the reservoir depending on
fluid proportions (saturation) and
compositions.
Determining the relative permeability of CO2, oil and water is
an important parameter for modeling the long-
term performance of the flood. The influences of the reservoir
heterogeneities, relative permeability and

wettability all must be considered in the design of the CO2
flood, which in turn encompasses well placement,
CO2 injection rates, water injection rates, and reservoir
pressure management.
1.3 Recovery Methods and Processes
There are several strategies for injecting CO2 and recovering oil
in CO2 EOR operations. Most
straightforward is to inject CO2 into a single well over a finite
time, leave the CO2 in the reservoir for days,
weeks or even months (soak period), and then produce reservoir
fluids using the same well. This is called
cyclic stimulation or the ‘huff n puff’ method (Figure 3) and is
generally used only in small fields or in a pilot
test to establish suitability or potential for CO2 EOR. More
usually, fields targeted for CO2 EOR are relatively
large involving tens to hundreds of existing wells and which
have already undergone a secondary process
for oil recovery (Edwards et al., 2002). Often the wells are
configured in patterns; a single injector well
surrounded by several producing wells, or several injector wells
surrounding a central producer. The style of
the patterns can be highly variable depending on reservoir and
operator preference and may include both

horizontal wells and vertical wells. The operator may need to
drill new wells and decommission others to
prepare the field for the flood and several years may be needed
to implement the required changes to the
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existing field infrastructure. Usual facility upgrades include gas
separation facilities such as recompression
and dehydration, the drilling of new wells, upgrading existing
valves and fittings, installing additional
pipelining and gathering system.
Figure 3. Diagram of cyclic CO2 EOR recovery methods. The
CO2 is injected into the reservoir and
allowed to ‘soak’ to enable the CO2 to mix with the oil and then
produced. This cycle can be repeated.
US Department of Energy, NETL.
A fundamental consideration in production design is whether
the CO2 flood will be miscible or immiscible as
determined by reservoir pressure and which can be influenced
by operating parameters (Stalkup 1983). An
immiscible flood is basically a drive process; the injected CO2
effectively pushes the oil towards the
production well but this process also suffers from the large

viscosity contrast between the injected CO2 and
the reservoir oil. Whereas a miscible CO2 flood does entail
some component of ‘push’, its strength is in the
resulting decreases in oil viscosity and density (oil swelling)
that results in a more efficient sweep of oil.
Figure 4 illustrates idealised behaviour in a miscible flood
showing the development of compositional zones
within the reservoir along the path of oil displacement by the
injected CO2.
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Figure 4: Illustration of the zones that develop in miscible CO2
flooding.
The CO2 being more buoyant and less viscous than oil,
however, may potentially channel or finger through
the upper reservoir thereby bypassing oil and breaking through
at a producing well. To reduce the chance of
early breakthrough and improve sweep, operators will often
inject alternating slugs of water and CO2 in what
is known as a WAG (Water Alternating Gas) process (Figure 5).
Water has a viscosity more similar to the
dominant reservoir fluids (brine and oil) than CO2, and can

provide a more uniform sweep. Water is also
heavier than oil so that it may tend toward the lower portion of
the reservoir complementing the less dense
CO2 that may rise to the upper portion of the reservoir. Most
current CO2 floods implement some form of
WAG within their operations. A version of this strategy is to
simultaneously but separately inject water and
CO2 (SS-WAG) shown in Figure 6 as deployed at the Weyburn
Field in Saskatchewan, Canada (Monea and
Wilson, 2004).
In this example vertical wells are used to inject water lower in
the sequence to provide pressure support and
maintain a more efficient sweep by the CO2 that is injected
using horizontal injection wells in the upper part of
the reservoir. Alternatively, some operators implement
continuous CO2 injection without using water.
Continuous CO2 injection is suitable for gravity driven
processes where the CO2 is injected at the top of the
reservoir and pushes reservoir fluids downward to a deeper
production well (or, where injected below the
production well, quickly moves upward and overrides).
Continuous injection can also be used in thinner
reservoirs where the effect of CO2 over-riding oil because of
lower density is minimal. Continuous CO2

injection may also be used in more conventional settings and
also uses the most CO2 of all EOR methods; a
significant aspect of alternating water injection with CO2 is that
water, when available, is much less
expensive than CO2.
In practice, a combination of recovery processes can be used
within a single reservoir and the design and
operation of the recovery process is rarely static. If CO2
breakthrough occurs at a production well, or
reservoir monitoring suggests that the sweep is missing a
portion of the zone, additional wells may be drilled.
Production and monitoring data and reservoir simulation results
may suggest turning wells off or back on,
and perhaps switching injectors to producers or visa-versa. In a
large field such as the Weyburn Field at
various times WAG, SS-WAG and continuous injection patterns
have all been in operation simultaneously
(Monea and Wilson, 2004).
Injected
CO
2
CO
2

with Oil
Components
Oil with condensed
CO
2
Oil
Miscibility
Zone
``Single Phase``
Displacement Direction
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Figure 5: Depiction of CO2 EOR WAG operations with the
various miscible zones identified. Figure
from Advanced Resources International and Melzer Consul ting
(2010).
Figure 6: Simultaneous but separate WAG as deployed at the
Weyburn Field in Saskatchewan,
Canada. CO2 is injected into the upper reservoir zone using a
horizontal well and water is injected
simultaneously into the lower reservoir zone using a vertical
well. Production wells are both
horizontal and vertical in this instance. (Wilson and Monea,
2004).

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1.4 Response, Recycle and Incidental Storage
An example of reservoir response to a large-scale CO2 flood is
shown in the production graph of the
Weyburn Field in Figure 7. CO2 injection commenced in
October 2000 and ten years later oil production had
increased to daily volumes not recovered since the 1970s wi th
20,000 barrels of oil/day incremental
production, or two-thirds of the total field production, due to
the CO2 EOR process. At the onset of a CO2-
flood only a subset of the total patterns within a large oil field
may receive CO2 and with time the flood is
rolled-out in stages more broadly across the field. CO2-floods
are long-lived operations spanning decades;
parts of a large field subjected to early CO2 injection may be
suspended once production drops prior to other
areas even being started to be flooded. Operators will
continually monitor injection rates, production volumes
and downhole pressures to tweak operating parameters and
adjust recovery strategies. Some operations

may also include surveillance wells, repeat seismic surveys and
other monitoring techniques (such as
saturation logging or fluid sampling) within their program to
assess CO2 distribution and field performance.
Figure 7: Production history over 55 years at the Weyburn Unit,
Saskatchewan, Canada, showing
stages from Primary production, Secondary water-flooding,
infill drilling (both vertical and then more
dominantly horizontal wells) and implementation of Tertiary
CO2 EOR. (Hitchon, 2012)
Operators try to be as efficient with the use of CO2 as possible
as it is one of the more expensive
components of the project. Recovery efficiencies can be
expressed by the number of tonnes CO2 injected to
recover a cubic metre of oil (or some equivalent form of
utilisation factor such as mcf/bbl). As the oil is
brought toward the surface within the production well, the
pressure decreases and the once miscible CO2
begins to unmix with the oil. At surface the CO2 can be
separated, collected, dehydrated, compressed and
re-injected into the reservoir. This recycling reduces the need to
purchase additional CO2 and effectively
establishes a closed-loop use of CO2. It also avoids emitting
this CO2 to atmosphere. There can be small-
scale losses of CO2 to atmosphere during surface equipment
maintenance or power outages, and also in

some circumstances such as during well workovers (general
well maintenance) when, for a restricted period,
the volume of recycle is more than can be injected and some
recycle CO2 may be emitted or vented.
A major influence on recovery efficiencies is the retention of
CO2 within the reservoir. A large portion of a
given volume of CO2 injected into a reservoir, generally
considered to be 30 to 40 per cent but variable for
different reservoirs, will not return to the surface with oil as it
gets trapped at the end of pore channels or
stuck on mineral surfaces. This ‘loss’ of CO2 to the oil
production cycle is actually a form of geologic storage
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as the CO2 will be contained within the reservoir indefinitely
and is an unavoidable mechanism associated
with CO2 EOR that is sometimes referred to as incidental
storage. Moreover, as the 60 per cent or so of the
injected CO2 that does come out with oil is captured and re-
injected, a similar proportion of the CO2 from this
cycle of injection will be stored incidentally.

As the recycled CO2 is re-injected in numerous cycles, more of
it will be progressively retained by incidental
storage so that through this process essentially all the purchased
CO2 will eventually reside within the
geologic reservoir. Melzer (2012) provides a clear discussion of
this mechanism and indicates that almost all
of the purchased CO2 for a CO2 EOR project will eventually be
securely trapped in the subsurface and that
loses are very minor and mainly related to surface activities as
mentioned above.
During the course of the CO2 EOR operation the amount of CO2
purchased will remain somewhat constant
to partially offset that lost through incidental storage and also
maintain expansion of the flood. Because of
the growing cumulative injection of purchased CO2, the amount
of recycled CO2 will correspondingly
increase so that the daily rate of total CO2 injected (recycled
plus newly purchased) will also increase during
the initial to mid-stages of the flood. At some point, the amount
of recycle may surpass that of the fresh CO2
and eventually the flood will begin to taper off purchase of new
CO2 and rely increasingly on recycled CO2
(Figure 8).
Figure 8. Stylised forecast injection rates for an oil field based

on cumulative CO2 retention. CO2
supply from a capture source may remain constant, but total
injection increases as CO2 recycle
increases. Eventually purchase of CO2 is reduced and only
recycle is used in the latter stages of the
flood.
1.5 Storage Capacity
Individual oil fields will have greater capacity to store CO2
than results from an EOR operation. EOR
operators will try to minimise use of CO2 to minimize costs, but
alternative operational scenarios can result in
additional carbon storage. An extensive study was performed at
the Weyburn Field to evaluate the merits of
different strategies for storage and incremental oil production
(Law, 2004). In this work the base-case
scenario representing the operation as planned by the operator
was simulated until the expected end of EOR
in 2033. (Note the present operators have now expanded the
extent and duration of the flood, but these
simulation studies still serve to highlight storage potential).
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Under this base-case scenario, over 23MT CO2 would be stored

from 2000–2033. By purchasing and
injecting more CO2 during operations (increasing the utilisation
ratio), up to 30MT could be stored to year
2033 at end of commercial EOR operations. Scenarios were
also evaluated for storage optimization post –
EOR. By simply continuing to inject CO2 until a pressure limit
in the reservoir was reached and then
systematically shutting in wells (stopping injection) an
incremental storage of 6 to 7 MT CO2 could be added
to the above scenarios. As the Weyburn Field is a low
permeability reservoir pressure limits would be
reached within two to three years; more permeable reservoirs
would take longer to reach a threshold
pressure. Alternatively, by maintaining CO2 injection post-EOR
but with continued production of fluids from
wells at gas to oil ratios much higher than would be typically
produced (i.e. non-economic), an additional
30MT CO2, or about double the base-case, can be stored
without significant change to infrastructure (Wilson
and Monea, 2004).
Storage potential in oil reservoirs can also be increased by
targeting portions of the reservoir not usually
accessed by EOR strategies. Near the base of reservoirs there is
often a zone that is transitional between oil

saturation and water saturation and is generally considered non-
economic. This part of the reservoir is also
called the residual oil zone (ROZ) and is gaining interest for
increasing storage capacity and also for the
possibility of recovering oil previously considered
unrecoverable. Brine-filled formations also can occur
beneath, adjacent or above oil reservoirs but with their use
prevented from ownership or access rights, or
lack of economic benefit. If these saline reservoirs are assessed
to be appropriate for storage they can
potentially be more easily accessed using the existing
infrastructure associated with the CO2 EOR operation.
These situations are examples of stacked storage potential.
Storage estimates associated with CO2 EOR in North America
are over 20 billion metric tonnes CO2 and by
including ROZ potential this could increase by more than 50 per
cent (Carpenter 2012). Globally Carpenter
(2012) has suggested storage potential of several hundreds of
billion tonnes. Although these numbers are
very preliminary, they do indicate that there is significant
storage potential associated with CO2 EOR and that
it can be important for future CCS development. Figure 9
indicates the potential mass of CO2 stored in

projects at various stages of advancement as determined during
the Global CCS Institute’s 2013 survey of
Large-Scale Integrated CCS Projects (LSIPs). For the 65 LSIPs
identified in the 2013 survey the storage
potential associated with CO2 EOR is much greater than for any
form of geologic storage.
Figure 9. The potential mass of CO2 that is being considered in
different storage options in large-
scale CCS projects. CO2 EOR currently stores more CO2 than
any other method of geological
sequestration. (Global CCS Institute, 2013)
1.6 Issues on Implementing Storage in conjunction with EOR
There are many challenges involving technical, business, legal
and regulatory issues in the implementation
or transition to storage as part of existing oil and gas
operations. Technical challenges in the transition from
CO2 EOR to CCS include determining whether the reservoir is
suitable for storage; establishing monitoring
and accounting requirements for CCS; and considering
operational issues associated with implementing or
transitioning to storage.
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In general, reservoirs suitable for CO2 EOR are proven
containers for retaining fluids as they have
demonstrated sealing capabilities and relatively well -known
storage capacities. Prior operational activities
would also have identified injectivity characteristics as well as
potentially defining numerous operational
parameters including fracture gradients and pressure thresholds.
Thus characterising the storage facility for
an existing CO2 EOR operation is generally more readily
performed than for a greenfield saline formation
storage project.
The goal of the monitoring requirements for geologic storage is
to establish that the injected CO2 remains in
the target storage formation (or storage complex) and that none
has migrated laterally or vertically out of this
zone, potentially impacting other resources or the surface. The
existence of numerous wells, pipelines,
treatment and separation facilities and prior oil field activities
in a CO2 EOR operation makes it challenging to
establish baselines for many monitoring parameters prior to the
transition to a storage facility. In addition,
where a large number of wells exist (abandoned, suspended and
active) this may contribute to increased risk

of potential leakage. In such instances, that risk must be
assessed and mitigated as necessary through
added monitoring or re-abandonment (reworking), as and if
appropriate. This could be an expensive
undertaking depending on the extent of mitigation. Finally, the
CO2 EOR operation or previous water
injection or other field operations may have either modified
portions of the reservoir or cap-rock through
pressure cycling and final depressurisation.
An aspect often discussed regarding storage associated with
CO2 EOR is the monitoring requirement to
account for the injected CO2. While specific requirements may
be established by individual jurisdictions or on
a project basis, it is worth repeating that many current
operations do conduct ongoing monitoring activities
such as pressure monitoring, but also may use dedicated
surveillance wells, repeat seismic surveys,
geophysical logging and fluid sampling to provide data for
maintaining or improving flood performance. The
routine evaluation of gas/oil ratios from numerous production
wells also provides much data regarding the
distribution of CO2 within the reservoir. What may evolve
different to routine operations may be monitoring
above the reservoir, including at surface.

From the specific standpoint of identifying operational
considerations that can increase storage potential,
options may include increasing purchase amounts of CO2,
decreasing WAG cycles and possibly injecting
into deeper zones or less productive regions of the field (subject
to appropriate incentives being in place
aimed at maximization of storage potential). Aspects involving
post-EOR activities may include continuing
injection past economic oil recovery and development of a
closure and post-closure operational plan (again
subject to appropriate incentives being in place aimed at
maximizing storage potential).
1.7 Summary
Injection of carbon dioxide into mature oil reservoirs is a
proven effective method for improving oil production
that can be applied to a variety of oil reservoirs in different
geological settings. Retention of the injected
carbon dioxide within the reservoir is an intrinsic part of the
CO2 EOR process, and effectively all CO2
purchased for injection will ultimately remain stored within the
oil field at the end of EOR operations. This
storage aspect has driven interest in CO2 EOR as a potential
method of CCS that has a supportive business

component.
The storage opportunities within CO2 EOR floods are generally
not maximised, although there are no over-
riding technical impediments preventing using more of the pore
space for storage. Transitional, or residual oil
zones, and stacked reservoirs all pose significant opportunities
to increase storage amounts well beyond that
used strictly for EOR. While deploying monitoring equipment
and determining suitable baselines may present
challenges to some existing operations, technical solutions can
be found to address most of these issues.
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References
Advanced Resources International and Melzer Consulting
(2010), Optimization of CO2 storage in CO2
Enhanced Oil Recovery Projects, Prepared for the Department
of Energy & Climate Change (DECC), Office
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Overview
In the highly competitive automotive market, it is critical to
keep up with current technology to stay in or get ahead in the
marketplace. To remain competitive, companies must innovate
and integrate new technologies within their product lines and
services.
Scenario
You work as a middle manager for one of the top U.S. producers
of luxury and mass-market automobiles and trucks.

The chief technology officer (CTO) of the company from the
course scenario has been monitoring new technology
developments that the company could integrate into its vehicles
to enhance the usefulness of and improve access to the data
acquired by the many digital sensors integrated into vehicle
subsystems over the past 20 to 30 years. The technology trend
of particular interest is the internet of things (IoT)—the
interconnection of embedded devices, such as sensors and
computers, over the internet. By taking advantage of this trend,
the CTO believes the company can seize an opportunity to
provide better service and predictive maintenance to its
customers, improving customer satisfaction and adding
additional revenue streams.
Based on briefings by the CTO and your Module One memo,
senior management has decided to implement IoT into its
product line. Your CTO has asked you to lead a cross-functional
team to take this initiative forward. Your first task is to create a
presentation that will include your recommendation for how the
company should approach this business problem: should you use
incremental or discontinuous innovation?
Specifically, should the company:
A. Design a completely new product line, based on the new
technology (discontinuous innovation)
or
B. Add new technology features first into one model and then

incrementally into the broader product line (incremental
innovation)
The recommendation you and your team will make is an
important first step in pursuing this new technology. Your
presentation and recommendations will be reviewed by senior
management. Until senior management approves your approach
to this innovation, your cross-functional team will not have a
budget and will not be able to start work on the innovation. You
should utilize your work from the Module Two presentation and
data analysis when making and justifying your recommendation
in this first milestone.In Milestone Two, you will subsequently
develop a go-to-market strategy. For your project in Module
Nine, you will compile your work from Milestones One and
Two, and include a proposed organizational structure to best
integrate, produce, and market the new technology.
Assignment Details:
Create a PowerPoint presentation to make a recommendation for
how the company should pursue the IoT technology to remain
competitive: either by discontinuous or incremental innovation.
To make your recommendation, you will need to identify how
the evolving IoT (sensor) technology fits into the company’s
products and services and determine potential risks and
benefits. You will also need to look at your competitors to see
what they are doing. Finally, you need to analyze the company’s
capability (resources) for pursuing the innovation. Use the

information and data from the CTO Brief, Comparative Growth
Data, Comparative Operating Statistics, and Comparative
Product Plans to complete this milestone.
1. Explain potential risks and benefits for options A and B.
· Overview (1 slide): Present the business problem and options
A and B.
· Option A (1–2 slides): Explain at least two potential risks and
benefits for option A.
· Option B (1–2 slides): Explain at least two potential risks and
benefits for option B.
2. Compare your competition’s products and services.
· Competitors (3–4 slides): Evaluate the competitors’ current
products and services.
· What are your competitors' current products and services?
· Are your competitors expanding in the current market?
Explain how this impacts their market strength.
3. Analyze your company’s capability to pursue the innovation.
· Complete a partial gap analysis (2 slides):
· Does your company own the technology, or does it need to be
purchased?
· How is the technology currently being used in today’s
products and services?
· What type of technology is available to purchase?
4. Recommend the innovation approach your company should
pursue.

· Innovation approach (2 slides): Explain which innovation
approach you are recommending and why.
· Consider the different stakeholders—research and
development (R&D), marketing, finance—when communicating
your recommendations.
1. Include a description of the incremental or discontinuous
product that you are recommending for R&D.
2. Include the sales forecasts for marketing.
3. Include a financial snapshot for finance.
Submission
Submit a 10- to 13-slide PowerPoint presentation with detailed
speaker notes that highlight the important points you want to
emphasize to senior management. If you include references,
they should be cited according to APA style.
Reading:
Textbook: Managing Innovation: Integrating Technological,
Market and Organizational Change (Tidd), Sections 3.8, 3:10,
7:1, 7:7, and 10:3
Video:The Age of Fragmentation opens in new window

The views expressed in this paper do not necessarily reflect the
views or policy of the International Energy Agency (IEA)
Secretariat
or of its individual member countries. The paper does not
constitute advice on any specific issue or situation. The IEA
makes no
representation or warranty, express or implied, in respect of the
paper’s content (including its completeness or accuracy) and
shall
not be responsible for any use of, or reliance on, the paper.
Comments are welcome, directed to [email protected]
© OECD/IEA, 2015 ©
O
EC
D
/I
EA
20
12
Storing CO2 through
Enhanced Oil Recovery

Combining EOR with CO2 storage (EOR+)
for profit
INTERNATIONAL ENERGY AGENCY
The International Energy Agency (IEA), an autonomous agency,
was established in November 1974.
Its primary mandate was – and is – two-fold: to promote energy
security amongst its member
countries through collective response to physical disruptions in
oil supply, and provide authoritative
research and analysis on ways to ensure reliable, affordable and
clean energy for its 29 member
countries and beyond. The IEA carries out a comprehensive
programme of energy co-operation among

its member countries, each of which is obliged to hold oil
stocks equivalent to 90 days of its net imports.
The Agency’s aims include the following objectives:
Secure member countries’ access to reliable and ample
supplies of all forms of energy; in particular,
through maintaining effective emergency response capabilities
in case of oil supply disruptions.
Promote sustainable energy policies that spur economic growth
and environmental protection
in a global context – particularly in terms of reducing
greenhouse-gas emissions that contribute
to climate change.
Improve transparency of international markets through
collection and analysis of
energy data.
Support global collaboration on energy technology to secure

future energy supplies
and mitigate their environmental impact, including through
improved energy
efficiency and development and deployment of low -carbon
technologies.
Find solutions to global energy challenges through engagement
and
dialogue with non-member countries, industry, international
organisations and other stakeholders.
IEA member countries:
Australia
Austria
Belgium
Canada
Czech Republic
Denmark

Estonia
Finland
France
Germany
Greece
Hungary
Ireland
Italy
Japan
Korea
Luxembourg
Netherlands
New Zealand
Norway
Poland
Portugal
Slovak Republic
Spain
Sweden
Switzerland

Turkey
United Kingdom
United States
The European Commission
also participates in
the work of the IEA.
© OECD/IEA, 2015
International Energy Agency
9 rue de la Fédération
75739 Paris Cedex 15, France
www.iea.org
Please note that this publication
is subject to specific restrictions
that limit its use and distribution.
The terms and conditions are
available online at www.iea.org/t&c/

© OECD/IEA 2015 Storing CO2 through Enhanced Oil
Recovery
Combining EOR with CO2 storage (EOR+) for profit
Page | 3
Acknowledgements
This publication was prepared by the International Energy
Agency (IEA) Carbon Capture and
Storage (CCS) Unit. Dr Wolf Heidug,1 Juho Lipponen, Sean
McCoy and Philippe Benoit, Head of
the Energy Efficiency and Environment (EED) Division, were
the principal authors of this report.
Substantial input was provided by IEA analysts Simon Bennett,
Tristan Stanley and Ellina Levina.
Kamel Ben Naceur, Director of Sustainable Energy Policy and
Technology provided comments and
guidance.
Several other IEA colleagues contributed to the work, in
particular Uwe Remme, Christian Besson
and Capella Festa.

Rystad Energy provided a database of oil field assets, upon
which the analysis is based. Thorsten
Clemens of OMV, Malcolm Wilson of PTRC, Lawrence Pekot
of Schlumberger, and Sean Brennan
and Peter Warwick of USGS provided significant input in
developing criteria to screen the oil field
data and to categorise it.
Jan Paul van Driel and Chris Jones of Strategic Fit provided
economic analysis of illustrative EOR
cases and further guidance. Editing services were provided by
Marilyn Smith.
1 Dr. Wolf Heidug has since left the IEA. Comments and
feedback should be directed to [email protected]
Storing CO2 through Enhanced Oil Recovery © OECD/IEA
2015

Page | 4
Table of contents
Executive summary
...............................................................................................
.................. 6
Introduction
...............................................................................................
............................. 8
CO2-EOR today: An oil production tool
..................................................................................... 9
What is CO2-EOR?
...............................................................................................
....................... 9
What happens to the injected CO2?
........................................................................................ 11
Has CO2-EOR been used to store CO2?
.................................................................................... 12
Towards storing CO2: “EOR+” as a climate tool
....................................................................... 16

Adding storage to CO2-EOR: Minimum requirements for EOR+
............................................. 16
EOR+: Three models – Conventional, Advanced, Maximum
Storage ...................................... 17
The economics of increasing CO2 storage through CO2-EOR:
Illustrative cases .............. 19
Capital and operating costs
.............................................................................................
19
The “CO2 supply price”
...............................................................................................
...... 20
The oil price received by EOR+
operators............................................... ......................... 21
NPV of the different EOR+ models
.................................................................................. 21
Price drivers for Conventional, Advanced and Maximum
Storage EOR+ ........................ 23
The global technical potential for EOR+ for CO2 storage and oil
production is large ................. 25
The aggregate technical potential for storage and oil recovery

............................................. 26
Geographic distribution of technical potential
................................................................ 27
Impact of widespread EOR+ on oil markets and global CO2
emissions ..................................... 29
Accounting for carbon at the project level
.............................................................................. 29
Expanding the boundaries: Emissions from consumption of oil
............................................. 30
Displacement of oil in global markets: The response of oil
markets to EOR+ ........................ 31
Overcoming barriers to EOR+
...............................................................................................
.. 34
Barriers to wider use of CO2-EOR
............................................................................................
34
Framework to ensure effective storage of CO2 through EOR
................................................. 36
Barriers to the use of more CO2 per barrel of oil
.................................................................... 38

Conclusions
...............................................................................................
............................ 39
Annex 1. Technical aspects of a hypothetical CO2-EOR+ case
study ......................................... 41
Production and injection profiles
............................................................................................
41
References
...............................................................................................
............................. 44
Acronyms, abbreviations and units of measure
...................................................................... 46
List of figures
igure ES1 Global storage potential for different CO2-EOR
practices (GtCO2)............................... 7
igure 1 Schematic of CO2-EOR operation
................................................................................... 10

igure 2 Core functional activities used in cost analysis
.............................................................. 20
Recovery
Page | 5
igure 3 Average CO2 supply prices under three scenarios
......................................................... 21
igure 4 Oil price trajectories under three scenarios
................................................................... 22
igure 5 NPV of illustrative CO2-EOR project for different ETP
scenarios and using different
EOR
practices.................................... .............................................
................................ 22
igure 6 Factors contributing to the different NPV results for
each CO2-EOR practice under

the 2DS
...............................................................................................
........................... 23
igure Illustrative oil and CO2 price impact on choice of EOR+
practices in
different scenarios
...............................................................................................
......... 24
igure 8 Global storage potential for different CO2-EOR
practices (GtCO2) ................................ 26
igure 9 Global incremental oil production potential for various
CO2-EOR practices ................. 27
igure 1 Storage potential in the top four regions
..................................................................... 28
igure 11 Impact of Advanced EOR+ on oil demand
.................................................................... 31
igure 12 Cumulative incremental CO2-EOR oil production,
2013-50 ......................................... 32
igure 13 Schematic production profile used for analysis
........................................................... 41
igure 14 Elements of capital costs for different CO2-EOR
scenarios .......................................... 43
igure 15 Change of incremental project operating cost; CO2
recycling as of 2028 .................... 43

List of tables
Table 1 Specification of EOR+ practices
....................................................................................... 18
Table 2 Illustrative project-level carbon balance of three EOR+
practices .................................. 30
Table 3 Illustrative carbon balance of three EOR+ practices
including combustion of the
produced oil
...............................................................................................
................... 31
Table 4 Illustrative CO2 emissions resulting from three EOR+
practices including combustion of
the produced oil and price effects in global oil markets
............................................... 33
Table 5a Key cost assumptions: Capital expenditure
.................................................................. 42
Table 5b Key cost assumptions: Operational expenditure
.......................................................... 42

List of boxes
ox 1 Weyburn-Midale: The front-runner in combining CO2-
EOR and CO2 storage ................... 13
ox 2 Examples of large-scale CO2 capture projects linked with
EOR ......................................... 14
ox 3 CO2 supply prices and potential impacts of price on CO2
emissions .................................. 18
ox 4 Key actions from the IEA CCS Roadmap
............................................................................. 37
2015
Page | 6
Executive summary
Injecting carbon dioxide (CO2) into oil reservoirs to enhance oil

recovery (EOR) has been
commercially used for several decades in the petroleum sector.
As the increasing pressure to
combat climate change has brought carbon capture and storage
(CCS) to the forefront as an
emissions mitigation tool, greater attention is being paid to the
potential for CO2-EOR to support
geological CO2 storage for climate change mitigation.
Novel ways of conducting CO2-EOR could help achieve a win-
win solution for business and for
climate change mitigation goals, offering commercial
opportunities for oil producers while also
ensuring permanent storage of large quantities of CO2
underground. Transforming practices to
support climate change carbon storage objectives in addition to
oil extraction, i.e. moving from
simple EOR to “EOR+”, represents a potentially attractive and
cost-effective way to spur greater
CCS action.
CO2-EOR practices can be modified to deliver significant
capacity for long-term CO2 storage.
Extending EOR to qualify as CO2 storage can be achieved
through a minimum of four main

activities: i) additional site characterisation and risk assessment
to evaluate the storage capability
of a site; ii) additional monitoring of vented and fugitive
emissions; iii) additional subsurface
monitoring; and iv) changes to field abandonment practices.
CO2-EOR can be used for CO2 storage in a manner that is
economically interesting for industry.
This analysis develops three distinct models combining oil
extraction with CO2 storage, which are
useful to illustrate the technical and economic options:
Conventional EOR+: current CO2-EOR practices, which aim to
maximise oil production
with a minimal amount of CO2, are adjusted to provide for
additional monitoring and
verification practices designed to permit CO2 storage tracking
for mitigation purposes.
Advanced EOR+: a second option is to “co-exploit” two
business activities, namely both
(a) oil recovery and (b) CO2 storage for profit. This approach
involves the injection of
larger amounts of CO2 than under Conventional EOR+, as well
as greater additional oil

recovery.
Maximum Storage EOR+: CO2-EOR operations are undertaken
with a strong focus on
maximising long-term storage of CO2 in the oil reservoir while
achieving the same level of
oil production as under the Advanced EOR+ scenario.
Analysis of a hypothetical, representative field clearly
demonstrates that, in a carbon-constrained
world, “co-exploiting” the storage of CO2 with oil extraction to
generate more profits using two
different revenue streams is feasible. A key insight is that for
the oil and carbon prices assumed in
the 2-Degree Celsius (2 °C), 4-Degree Celsius (4 °C) and 6-
Degree (6 °C) Scenarios (2DS, 4DS and
6DS respectively) modelled in the IEA publication, Energy
Technology Perspectives (ETP), a CO2-
EOR practice that aims at co-exploiting both recovery and
storage, i.e. Advanced EOR +, leads to
net present values (NPVs) that are consistently larger than those
achieved with
Conventional EOR+. While the business case is ultimately
project-specific, the hypothetical case
provides valuable insights.

At an aggregate global level, estimates indicate that by 2050, a
cumulative 60 gigatonnes of CO2
(GtCO2) could be stored in declining oil reservoirs with
Conventional EOR+ practice,
corresponding to half of the IEA 2DS requirements outlined in
ETP (see Figure ES1 below; also
Figure 8, p. 25 [to which it is identical]). With Advanced
EOR+, some 240 GtCO2 could potentially
be stored, exceeding the CO2 storage requirements under the
2DS case. Storage potential under
Maximum Storage EOR+ is estimated at 360 GtCO2.
Recovery
Page | 7
Figure ES1 Global storage potential for different CO2-EOR
practices (GtCO2)

While both the economic and CO2 storage potential seem
significant, adding these CO2 storage
practices to EOR (the “+” in EOR+) requires a clear paradigm
shift from current practices. At
present, no CO2-EOR site is pursuing this dual objective: today
EOR operations are carried out
with the aim of maximising oil output with the minimum CO2
input. Extending CO2-EOR projects
to include CO2 storage as an end goal requires taking on
activities associated with monitoring and
verification of stored CO2. The level of additional cost varies
widely, depending on the geological
and geophysical features of individual reservoirs
“Co-exploiting” CO2 storage and EOR is unlikely to happen in
the short to medium term without
additional incentives, as applying novel practices increases cost
and carries additional risk. Key to
adding CO2 storage to EOR activities is a carbon price or some
regulatory mandate as in all cases,
the storage for mitigation purposes will entail additional costs
to conventional CO2-EOR projects.
Governments may need to step in by creating a policy
framework comprising multiple and

complementary economic instruments, of the type being used to
stimulate CCS deployment
more generally:
EOR+ pilot projects are needed to help to de-risk the
technology and generate learning.
In the longer term, increasing the capacity to extract oil needs
to be tempered with
policies that optimise CO2 storage and ensures its
environmental effectiveness. Early
projects can also be beneficial for the creation of a CO2
transport infrastructure.
Specific incentives may be required to kick-start deployment.
For example tax incentives
could be considered. Carbon pricing could serve as an
appropriate policy instrument at a
more mature stage of technology deployment.
A framework of laws and regulations is needed to ensure the
safe and effective design
and operation of CO2 storage options. For CO2 stored through
EOR+ to qualify as “not
emitted” – and thus gain the benefits of climate policy – the
operator must comply with

regulations to ensure that the CO2 is retained in the reservoir.
0
50
100
150
200
250
300
350
400
Conventional EOR+ Advanced EOR+ Maximum Storage EOR+
2DS cumulative storage
(2015-50)

B
ill
io
n
to
nn
es
o
f C
O
2
2015
Page | 8

Introduction
Injecting CO2 into oil reservoirs to enhance oil recovery (CO2-
EOR) has been practiced on a
commercial scale for nearly 50 years. Most of this practice has
been developed in North America.
As increasing pressure to combat climate change has brought
CCS to the forefront as an
emissions mitigation tool, many have looked to CO2-EOR as a
means of supporting geological
storage of CO2 storage (IEA, 2015).
Four decades of CO2-EOR experience have generated in-depth
knowledge about technical aspects
of the process and its economic benefits. Much has been learned
about project design and
reservoir management for CO2-EOR, reducing the risk and costs
associated with developing
projects. Today, there is little doubt that CO2-EOR can be a
cost-effective way to prolong the
lifetime of a conventional oil field, enabling the extraction of
more of a valuable commodity
wherever the right conditions exist. Improving recovery from
existing fields can also reduce the
pressure to develop new oilfields, thus avoiding the associated

cost and environmental impacts,
which can be an attractive factor for governments and
companies. As a result, CO2-EOR has
turned CO2 into a bulk commodity in North America placing a
market value on its supply through
extensive pipeline networks.
Yet a number of questions remain in relation to potential for
CO2-EOR to generate climate
mitigation benefits resulting from CO2 storage. While previous
studies have largely focused on
the potential for an expanded CO2 supply to expand oil
production via CO2-EOR, and therefore
store more CO2 as part of the process, this IEA study takes a
different perspective: it looks at the
potential economic impact of modifying EOR at the project
level to include storage of CO2, and
then quantifies the global potentials for CO2 storage and
additional oil production in aggregate.
The first chapter describes conventional CO2-EOR operations,
as undertaken today. The second
chapter then describes how traditional CO2-EOR practices,
designed to maximise oil production
with little attention to the ultimate disposition of CO2, can be

modified to provide verifiable CO2
storage consistent with the requirements of climate change
mitigation objectives. Projects that go
beyond traditional CO2-EOR practices to provide CO2-storage
are referred to as “EOR+” projects.
The second chapter then considers alternative cases in which
EOR+ practices are further modified
to increase the amount of CO2 stored, while continuing to
support oil extraction operations.
Three different levels of CO2 storage activities are presented:
(a) an initial level in which the
storage is incidental to conventional EOR (Conventional
EOR+); (b) a second level in which both
the amounts of CO2 stored and oil produced are increased above
the conventional case, resulting
in increased revenues from both CO2 storage and oil production
(Advanced EOR+); and (c) a third
level at which the amount of CO2 stored is increased
substantially, consistent with the underlying
oil production activities (Maximum Storage EOR+).
The third chapter analyses the potential magnitude of these
sequestration actions through EOR+
at a global level. A rich dataset of oilfields has been examined

to assess the potential scale of CO2
storage through EOR+ operations at a global level if there were
incentives for operators to
increase the amount of CO2 stored when producing oil. The
fourth chapter considers the
complicated question of the net impact of increasing CO2
storage through EOR+, and lays out the
conditions under which EOR+ could raise oil demand at the
margins while still providing a net
reduction of emissions. The final chapter considers various
issues that policymakers will need to
address to realise the benefits of EOR+ for climate change
mitigation.
Recovery
Page | 9
CO2-EOR today: An oil production tool
Key points

CO2-EOR is one of many technologies that can be used to
enhance oil recovery. Today,
the main concentration of CO2-EOR projects is in North
America, mostly in the Permian
Basin of the United States. So far CO2-EOR has been
undertaken with the primary aim of
enhancing oil recovery. Climate change mitigation and long-
term CO2 storage goals are
not principal drivers for EOR projects.
Oil fields typically have various production phases. In the
primary production phase,
natural pressure drives oil to the production wells. In the
secondary phase, pressure in
the reservoir is increased by injecting fluids, pushing more oil
to the production wells. In
the tertiary phase, techniques are used not only to maintain
pressure in the reservoir,
but to also alter properties of the oil or reservoir, improving
recovery of the existing oil.
CO2-EOR is a tertiary technique, based on injection of CO2 and
usually, but not always,
water into the oil reservoir. CO2 mixes with oil, improving its

ability to flow towards
production wells. Injected CO2 is produced with the oil; this
CO2 is separated from the oil
and re-injected for further oil recovery.
Injecting CO2 into oil reservoirs to enhance oil recovery has
been practiced on a commercial scale
for nearly 50 years, with the first successful pilot tests
conducted in the early 1960s in the state
of Texas (Holm, 1987). Experience in the United States shows
that CO2-EOR can boost recovery by
5% to 15% of the original oil in place (IEA, 2013b).
What is CO2-EOR?
Oil fields typically have several production phases. While
specifics will vary according to the
characteristics of each field, they are often grouped in three
main phases. In the first, primary
production phase of an oil reservoir, oil flows to the production
well as a result of pressure
gradients within the reservoir. Initially this occurs naturally, but
over time the oil production rate
tends to decrease as ongoing production of fluids leads to a
decline in reservoir pressure (at the

same time rates of water production increase). At this point,
producers may apply a range of
secondary and tertiary techniques to enhance oil recovery and
compensate for declining production.
Secondary recovery involves increasing pressure in the
reservoir by injecting (through wells) a
fluid, such as water or natural gas. The injected substance
usually does not mix with the reservoir
oil (i.e. it is “immiscible” with the existing oil), and has the
effect pressurising the reservoir.
Usually the injection strategy is designed to drive oil towards
the production wells. In gas
re-injection, a common variant of secondary recovery, natural
gas produced during extraction is
re-injected into the reservoir’s gas cap, which overlies the oil,
driving the oil downwards to the
producers. Water flooding is usually targeted at the margins of
the reservoir, to push (or sweep)
the oil towards the wellbore.
A successful secondary recovery programme may boost the total
recoverable oil by an
additional 5% to 20% of the original oil in place. Such pressure
maintenance programmes may

begin during the primary oil production phase of an oil field,
although water flooding and
similar production enhancements are usually not required until
well into a reservoir’s
2015
Page | 10
productive life. As pressure maintenance with water is less
costly than other techniques, it
tends to be the secondary process of choice.
Tertiary recovery is the third level of production enhancement,
one option for which is CO2-EOR
(a schematic explanation of the CO2-EOR process is shown in
Figure 1).
Figure 1 Schematic of CO2-EOR operation

Source: Global CCS Institute (2015), website,
www.globalccsinstitute.com/content/information-resources.
In addition to maintaining pressure and sweeping oil to the
production wellbore (as in secondary
recovery), tertiary techniques aim to change the properties of
the oil of reservoir rock, or alter
flow patterns in the reservoir. This implies the need for
substance that will interact with oil to
alter its density or viscosity, change the “wettability” of the
reservoir rock, or plug high-
permeability flow paths in the reservoir.
Main methods include thermal recovery, chemical flooding and,
miscible gas injection. The type
of EOR technology suitable depends on the characteristics of a
given oil reservoir and its state of
depletion. Whether or not CO2-EOR can be effectively applied
to a given reservoir depends on
three main factors: i) the geological and petrophysical
characteristics of the reservoir; ii) the
physical and chemical characteristics of the oil; and iii) the
production history, condition and
accessibility of the field.

CO2, nitrogen and hydrocarbon gases (e.g. propane, butane)
have been employed as injectants in
tertiary recovery projects. In a miscible CO2 displacement
process relatively pure CO2 (i.e. typically
95% by volume or greater) is injected into the reservoir and
mixes with the oil. This has the effect
reducing the capillary forces that trap the oil in the reservoir
rock and creates more favourable flow
properties. Compared with injection of nitrogen and
hydrocarbon gas, CO2 achieves miscibility with
oil at lower pressure and can therefore be applied in relatively
shallow reservoirs.
Pressure balance is critical to CO2-EOR: to achieve miscibility,
the reservoir pressure must be
maintained above the so-called minimum miscibility pressure
(MMP) while the maximum
reservoir pressure is limited by the reservoir fracture pressure.
Pressure can be maintained in this
window by balancing the injection and withdrawal of fluids
from the reservoir. Should it be

Recovery
Page | 11
impossible to reach the MMP, for instance in shallow
reservoirs, CO2-EOR can still be applied, but
operated as an immiscible flood in which the injected CO2
physically pushes the oil towards the
production wells (as described under secondary recovery).
Operating the CO2 flood above the
MMP is preferable as the miscible process leads to more
efficient oil recovery (although some
miscible benefits may be achieved even where full miscibility is
not achievable).
One impediment to CO2 flooding arises from the fact that the
viscosity
2 of CO2 under injection
conditions is low compared to that of the oil; this creates a
tendency for the CO2 to channel or
“finger” through to the production well without mixing with the

oil to a significant degree. As CO2
also tends to be less dense than the reservoir, it rises towards
the top (referred to as gravity
override) and does not evenly contact the reservoir. These
effects can be amplified or diminished
by the geology of the reservoir (Green and Willhite, 1998). One
approach to overcome this
impediment and to achieve relatively even mixing of the CO2
through the reservoir is known as
the "water-alternating-gas" (WAG) process, which involves
injecting alternating slugs of CO2 and
water produced from the reservoir. The presence of water
hinders the movement of CO2 through
the rock, thereby enhancing mixing. WAG decreases the CO2
demand per barrel of oil recovered,
which is advantageous in a situation where CO2 must be
purchased and represents a cost factor.
When CO2 reaches the production well, it is typically separated
from the produced hydrocarbon
so that it can be re-injected (i.e. recycled). In commercial
projects, CO2 typically “breaks through”
at production wells relatively rapidly following the start of
injection. This recycling is done for
economic reasons, as the purchased CO2 comes at a cost to the

operator. Over the life cycle of
the EOR project, the CO2 injection and recovery cycles are
repeated many times, with smaller
amounts of new CO2 added to the project in each cycle.
The role of CO2-EOR in global oil production is currently
limited: more than 140 projects globally
produce around 300 000 barrels per day (bbl/d) of oil (Kuuskraa
and Wallace, 2014) – i.e. only
0.35% of global daily oil consumption. Almost all operating
CO2-EOR projects are concentrated in
the mid-west United States, not all that far from where the
technology was first developed.
The viability of CO2-EOR projects in the United States depends
largely on three factors:
The existence of oil reservoirs in late stages of production with
geological and
petrophysical characteristics conducive to CO2 flooding.
The availability of inexpensive CO2 sources and an extensive,
built-for-purpose CO2
pipeline system to deliver this CO2 to projects. Most CO2 used
in EOR projects today

comes from naturally occurring volcanic accumulations.
The combination of a fiscal regime that supports EOR
deployment to enhance energy
security and a legal framework that facilitates development of
EOR projects.
While the way in which these factors have emerged is very
specific to the United States – in
particular, the evolution of the CO2 pipeline network and
supply business – there is no reason
that similarly supportive conditions for CO2-EOR could not be
created in other regions with
suitable oil reservoirs.
What happens to the injected CO2?
Not all of the injected CO2 is recovered at the production wells.
To maintain pressure above the
MMP, operators must carefully balance the volume of fluids
produced and injected: as oil is being
2 How resistant a fluid is to flow under an applied pressure.

2015
Page | 12
produced and removed from the system, roughly equal volumes
of CO2 and water must be
injected (in WAG operations).3 A significant portion the CO2 in
the reservoir remains trapped due
to capillary forces that act to immobilise its movement within
pores and through dissolution in
residual oil and water present in the reservoir.
With each recovery cycle, more of the injected CO2 is
progressively retained until a significant
volume is securely trapped. The volume of CO2 that can be
stored in this way depends on
properties of the reservoir and the oil it contains, and on
operational factors of oil production,
including the duration of the WAG and the water/oil ratio used,
well spacing, and the relative
position of injection and producing wells.

To maintain pressure and production, the CO2 retained (stored)
in the reservoir must be
compensated through injection of additional CO2 (or water).
The “recovery efficiency” quantifies
how many tonnes of CO2 are injected to recover an additional
barrel of oil, with low efficiencies
indicating more CO2 storage. The Weyburn-Midale EOR project
in 2012 was producing about
18 000 incremental barrels per day (bbl/d) with an injection rate
of 13 000 tCO2/d – or about
1.5 barrels per tonne. This injected CO2 represents 6 500 t
purchased and 6 500 tonnes recycled,
or approximately 3 barrels per purchased tonne of CO2 (IEA,
2014b; see also Box 1).
At the end of the CO2 flood, the volume of CO2 that remains in
the reservoir has been
“incidentally stored” over the course of numerous CO2 recovery
and re-injection cycles. A portion
of this CO2 is trapped in the reservoir through capillary forces
and would be very difficult to
remove; however, much of the CO2 exists either in the form of
free phase CO2 or is dissolved
within the mobile oil and could be recovered. This leaves the

operator with the choice to either
produce the CO2 so that it can be re-used elsewhere in the field
or resold, or alternatively to take
measures aimed at long-term CO2 storage in the abandoned
reservoir. In larger projects,
operators usually choose to recover and re-use the CO2 injected
in early phases for later phases.
This recycling effectively establishes a closed-loop for use of
CO2 with only a very small amount of
fugitive emissions released to the atmosphere during handling
the CO2 at surface facilities. While
quantitative data on fugitive CO2 emissions from CO2-EOR
projects is limited, the literature
indicates losses of less than 0.3 % of the total volume of CO2
injected for the Elk Hills CO2 project
in the United States (Hill et al., 2013).
Has CO2-EOR been used to store CO2?
The increasing urgency to combat climate change has sharpened
the focus on CCS and raised
questions about the role that CO2-EOR is currently playing in
supporting CCS and the role it could
play in geological CO2 storage. There is growing recognition
that CO2-EOR can be a means of

storing CO2 and, thus, can indeed play a role in combating
climate change.
However, most of the CO2-EOR projects operating today use
naturally occurring CO2 that is
extracted from underground specifically for EOR purposes.
Such practice is neither beneficial for
the climate nor for the development of CCS. Moreover, in most
cases CO2-EOR operations have
not been designed with long-term CO2 storage in mind and,
hence, storage-focused activities that
support the demonstration of long-term CO2 storage have not
been undertaken (e.g. risk
assessment, monitoring and verification).
3 To a first approximation, the reservoir can be considered a
closed volume initially saturated with a mixture of oil and
water:
if oil is removed, another fluid must be injected to maintain a
constant pressure. In reality, the presence of natural gas or the
influx of water can complicate the calculation, but the principle
remains the same.

Recovery
Page | 13
The IEAGHG Weyburn-Midale CO2 Monitoring and Storage
Project has been an early exception,
as it included an extensive pilot programme to monitor and
verify the storage of CO2, between
2000 and 2012 (Hitchon, 2012). Although the project no longer
monitors the stored CO2 and the
field is operated as a traditional EOR project, it has provided
very useful insights into the potential
of combining two activities.
Box 1 Weyburn-Midale: The front-runner in combining CO2-
EOR and CO2 storage
The Weyburn and Midale oil fields, located in southeast
Saskatchewan, Canada, were brought into primary
production in 1954. As is common, oil was initially produced

from the reservoir without injection of other
fluids; however, over time, production has been maintained in
both fields through the use of water flooding
coupled with the drilling of additional (infill) wells to reach
parts of the reservoir that had not been previously
accessed. In October 2000, Cenovus (formerly PanCanadian or
EnCana) began injecting CO2 into the Weyburn
field in order to boost oil production. There are now over 100
injection wells. Apache followed suit in 2005,
injecting CO2 into the Midale field.
The Weyburn and Midale fields combined are expected to
produce at least 220 million barrels of incremental
oil through miscible or near-miscible displacement with CO2.
EOR will extend the life of the fields by
approximately two to three decades.
Source: Cenovus,
http://en.wikipedia.org/wiki/File:Cenovus_Unit_Oil_Production
.jpg.
What makes the Weyburn-Midale project unique among CO2-
based EOR operations is the comprehensive
monitoring and verification pilot program undertaken between

2000 and 2012. Overall, it is anticipated that
around 40 MtCO2 will be permanently sequestered over the
project's lifespan – 30 Mt at Weyburn and 10 Mt
at Midale.
The key finding from this project relates to the successful
coupling of EOR operations and CO2 storage.
Experience of the 12 years of operation clearly demonstrates
that the two approaches can be complementary,
that accurate CO2 accounting is possible and that permanent
storage of CO2 can be achieved.
Knowledge and experience from both CO2 capture and EOR are
set to grow in the near future, as
new projects are pursuing the dual ambition of using CO2-EOR
to reduce emissions and increase
oil production (Box 2).
2015

Page | 14
Box 2 Examples of large-scale CO2 capture projects linked
with EOR
A number of new CO2 capture projects in early operation or in
construction are linked to conventional
CO2-EOR as practiced today. These projects will improve
experience in large-scale capture of CO2 from various
sources, and EOR will provide necessary partial economic
drivers and business models for the projects.
The Boundary Dam Unit 3, inaugurated by SaskPower in
October 2014 (Saskatchewan, Canada), is the
world’s first large-scale power unit equipped with post-
combustion CO2 capture. This rebuild of an aging
generator operates on continuous mode (producing 110 MW of
power to the grid) and captures 95% of
the CO2 emissions (and 100% of the SO2) of the lignite-fired
power unit – reducing direct CO2 emissions
by 1 million tonnes per year (Mt/yr). The captured CO2 is

transported to nearby oil fields for EOR and a
proportion is also stored in the associated Aquistore Project.
In the first half of 2016, the Kemper Project gasifier and
capture unit, owned and operated by Mississippi
Power (a subsidiary of Southern Company), is scheduled to
come online in Mississippi, United States.
This large-scale (582 MW) integrated gasification combined
cycle (IGCC) plant will incorporate CCS
technologies with the aim of significantly reducing the high
emissions normally associated with
transforming lignite coal into natural gas. The company intends
to capture 65% of the plant’s CO2
emissions and hence deliver 3 MtCO2 per year for EOR use in
nearby fields.
Construction recently began on the NRG Petra Nova project in
Texas (United States), a joint capture
project by NRG Energy and JX Nippon Oil and Gas Exploration
(with transport and storage held by Texas
Coastal Ventures, a joint venture between Petra Nova Parish
Holdings and Hilcorp Energy Company).
This combined coal- (247 MW) and gas-fired (127 MW) plant is
being retrofitted with post-combustion
technology to capture 90% of emissions (1.4 Mt/yr), which

would be fed into the West Ranch oil field
(operational since 1938). Over the 20-year project span, the site
may develop as many as 130 injection
wells and 130 production wells.
Petrobras, BG Brasil and Petrogal Brasil are partners in the Lula
oil field CO2-EOR project located in the
Santos Basin, some 300 kilometres off the coast of Rio de
Janeiro, Brazil. The Lula project separates
0.7MtCO2 per annum from natural gas production and injects
the CO2 for EOR in a pre-salt carbonate
reservoir, some 5 000-7 000 metres below the sea level. The
Lula project, in operation since 2013, is a
pioneer in ultra-deep water CO2-EOR, operating currently the
deepest CO2 injection well in the world.
In Saudi Arabia, Saudi Aramco is implementing the Uthmaniyah
CO2-EOR project. In this project, CO2 is
captured from the existing Hawiyah natural gas processing plant
and some 800 000 tCO2/yr will be
injected in the Uthmaniyah production unit (part of the super-
giant Ghawar oil field) for EOR. The
project will pilot new technologies in order to monitor and
verify the behaviour of CO2 underground.

Operation of existing projects demonstrates that, to date,
climate change mitigation and
long-term CO2 storage goals do not figure within the rationale
for EOR projects in the United
States (Dooley et al., 2010). This is not a surprise given the
lack of a focus on climate mitigation
during the development of the industry. Two main impediments
appear to be standing in the way
of using CO2-EOR as a mitigation option:
There are few incentives, commercial or otherwise, that would
lead the operator of a
CO2-EOR project to focus on CO2 storage. Hence, most
projects do not undertake
dedicated activities to demonstrate that CO2 remains contained
in the reservoir. Such
monitoring activities are generally agreed to be a critical
component of geologic CO2
storage (e.g. see IPCC, 2006); thus, CO2 injected in EOR
projects cannot be considered “as
not being emitted” in the framework of climate policy.
The laws and regulations that apply to CO2-EOR operations
have evolved to address the

issues associated with oil and gas operations, not CO2 storage.
In the United States, for
example, property law places limits use of the subsurface that,
while allowing for
efficient oil recovery, present barriers to CO2-storage (Marston,
2013). Without changes
Recovery
Page | 15
to the laws and regulations that apply to CO2-EOR, it may not
be possible to reconcile the
practice of CO2-storage with that of CO2-EOR.
Despite increasing interest worldwide in the potential for CCS
as a climate change mitigation
technology and the potential role CO2-EOR could play in its
deployment, few, if any, of the more
recently identified opportunities have been developed outside

the United States. In analysis
carried out in the early 2000s, the International Energy Agency
Implementing Agreement on
Greenhouse Gas Research and Development Programme
(IEAGHG) identified 488 CO2-EOR
candidate projects as “early opportunities” for CCS (Lysen,
2002).
2015
Page | 16
Towards storing CO2: “EOR+” as a climate tool
Key points
Extending CO2-EOR practice to qualify as CO2 storage can be
achieved with adjustments
to the design and operations of a CO2-EOR project. At a

minimum, these would include
four main activities: i) additional site characterisation and risk
assessment; ii) additional
monitoring of vented and fugitive emissions; iii) additional
subsurface monitoring; and,
iv) changes to field abandonment practices.
Costs of undertaking CO2-EOR for storage, i.e. EOR+, will be
higher than for traditional
CO2-EOR due to additional monitoring, measuring and
verification (MMV) and closure
activities and could also increase as a result of changes to flood
design and operations.
Storing CO2 through EOR operations could be profitable,
provided that the CO2-EOR
operators see the economic benefits of reducing emissions from
large point sources and
that these benefits are, at a minimum, greater than the
additional costs associated with
storage. As the benefits of reducing emissions grow, the profits
from carbon storage
activities lead to higher levels of CO2 storage, particularly at
higher oil prices. In fact, a
case in which the amount of CO2 used per barrel of oil is

increased in order to recover
additional oil, delivers greater overall profitability than
traditional EOR across a wide
range of future price scenarios.
However, oil price is the single most important driver for CO2-
EOR project economics,
with higher prices catalysing higher levels of carbon injection.
Adding storage to CO2-EOR: Minimum requirements for EOR+
The previous chapter described how CO2-EOR is undertaken
today. Oil producers are already
injecting CO2 into underground reservoirs, with the aim of
enhancing the production of oil. In this
section we will look at how CO2-EOR could be used for climate
change mitigation purposes.
Extending today’s practice to qualify as CO2 storage requires
additional activities to be undertaken
before, during and following CO2-injection. At a minimum,
these would include four main activities,
the first two being pre-operational, the third and fourth during
and following storage:
Additional site characterisation and risk assessment to collect

information on overlying
cap-rock and geological formations, as well as abandoned
wellbores, to assess the
potential for leakage of CO2 from the reservoir.
Additional measurement of venting and fugitive emissions from
surface processing
equipment.
Monitoring and enhanced field surveillance aimed at
identifying and, if necessary,
estimating leakage rates from the site to assess whether the
reservoir behaves as
anticipated.
Changes to abandonment processes that help guarantee long-
term containment of
injected CO2, such as plugging and removal of the uppermost
components of wells so
they can withstand the corrosive effects of CO2-water mixtures.
These additional activities represent an additional cost to CO2-
EOR operators that would, if not
offset by compensatory measures or revenue, negatively impact
project economics. Thus,

ensuring that operators take the steps of managing oil fields for
both oil recovery and CO2
Recovery
Page | 17
storage requires a link between the regulatory framework for oil
production and that for tackling
climate change. The challenge for jurisdictions that already
have CO2-EOR activities is to make
this transition, which can introduce additional new business
risks, sufficiently attractive to
operators who are comfortable with the status quo. This could
be done for example through
carbon pricing or a regulatory mandate.
In this new context, generators of CO2 would choose to capture
rather than emit CO2 and
subsequently look to verifiably store the CO2, potentially

through a third party such as an EOR
operator. This would create a demand for verifiable storage
from which CO2-EOR operators could
benefit through, for example, reduced supply prices or revenues
from offsets or certificates. CO2-
EOR operators could seize the opportunity by undertaking
activities to demonstrate long-term
storage and optimising flood design for lower CO2 prices or
CO2-storage revenues, which would
result in additional oil recovery and CO2 use. The feasibility of
such a shift in operations depends
on the relative prices of oil, the price of CO2 supplied for EOR,
energy costs (for processing and
compression), and the cost of design and operation of EOR (e.g.
additional wells, fluids
separation and compression capacity).
EOR+: Three models – Conventional, Advanced, Maximum
Storage
For the purposes of illustrating the needed changes in practices
(and for the later purposes of
identifying the associated global potential as discussed in the
next chapter), we outline below
three operational models, with significant differences in the way
CO2-EOR oil extraction and

carbon storage activities interact. All three models assume the
additional activities described
above are undertaken, which would impose costs on the operator
above and beyond those
generally incurred today (i.e. the “Conventional EOR+” practice
is distinct from CO2-EOR as
typically practiced today). The impact of the additional cost is
examined in greater detail later in
this section. In this sense, none of these models represent a
“business-as-usual” approach. The
three typologies are:
Conventional EOR+: As its name suggests, this model is based
on CO2-EOR operations as
documented in the literature for historical and current US
projects (e.g. EPRI, 1999; Jarell et
al., 2002; Azzolina et al., 2015; Brock and Bryan, 1989). It
assumes representative values for
net utilisation of 0.3 tCO2/bbl of oil produced and incremental
oil recovery corresponding
to 6.5% of the original oil in place (OOIP).4 It is furthermore
assumed that operators
undertake all additional activities as outlined above, including
monitoring and verification.

Advanced EOR+: In this model an operator chooses to use and
store more CO2 to recover
more oil. In this scenario, the projects have a net CO2
utilisation of 0.6 tCO2/bbl with
incremental oil recovery rising to 13% of OOIP. This is
consistent with net utilisation in
some recent projects. These levels of utilisation and recovery
could be reached in several
ways including well control schemes (Kovscek and Cakici,
2005) and some
“next-generation” practices (ARI and Melzer Consulting, 2010).
Maximum Storage EOR+: Under this scenario CO2-EOR
operations are undertaken with a
strong focus on CO2 storage. Consequently, net CO2 utilisation
rises to 0.9 tCO2/bbl while
incremental oil recovery stays at 13% OOIP (i.e. the level
achieved in the Advanced
EOR+). This level of storage could be achieved by not re-
injecting produced water into
4 Net utilisation refers to the volume of CO2 purchased per
barrel of oil recovered. Gross utilisation, which is also
sometimes

quoted as a performance metric, is the volume of CO2 injected
(including recycle volumes) per barrel of oil recovered. Because
it includes recycle volumes, gross utilisation is higher than net
utilisation.
2015
Page | 18
the oil reservoir or by using CO2 in a once-through system
where, instead of being
recycled, produced CO2 is injected into a saline aquifer –
similar to “stacked storage”
concepts (Hovorka, 2013).
Table 1 summarises the technical assumptions for each of the
three scenarios regarding the
modes of extraction, all of which cover only miscible CO2
flooding.

5
Table 1 Specification of EOR+ practices
Scenario Description Incremental recovery
% OOIP
Utilisation
tCO2/bbl
Conventional EOR+ Miscible WAG flood with vertical injector
and
producer wells in a “five spot” or similar pattern.
Operational practices seek to minimise CO2 use.
6.5 0.3
Advanced EOR+ Miscible flooding following current best
practices
optimised for oil recovery. May also involve some
“second-generation” approaches that boost
utilisation and recovery.

13 0.6
Maximum Storage
EOR+
Miscible flooding where injection is designed and
operated with the explicit goal of increasing
storage. Could include approaches in which water
is removed from reservoir to increase available
pore volume.
13 0.9
The different behaviour of project developers in these three
models is presumed to be driven by
(1) a requirement to undertake the additional storage-related
activities, (2) changes in oil price
and (3) CO2 supply prices. Operations in the Conventional
EOR+ scenario are broadly
representative of historic CO2 and oil prices – that is prices
below USD 50/bbl with corresponding
CO2 supply prices of around USD 20 per tonne. The Advanced
EOR+ scenario could emerge as a
result of declining CO2 acquisition prices, for example,

resulting from an increasing cost to
industry producers to dispose of their CO2, (see Box 3) and
increasing oil prices relative to the
Conventional EOR+ case, which would drive the operator to use
more CO2 to recover more oil.
Finally, the Maximum Storage EOR+ case could emerge if,
instead of paying for CO2, the operator
was paid to store CO2 at oil prices comparable to those in the
Advanced EOR+ case.
Box 3 CO2 supply prices and potential impacts of price on CO2
emissions
5 As discussed earlier, immiscible flooding is generally less
efficient at recovering oil than miscible CO2-EOR and as a
result, this
analysis does not include immiscible flooding.
In the United States, CO2 supply prices for EOR have
traditionally been tied to oil prices and are
generally not public information. However, they are generally
understood to be in the range of a “few
dollars” per thousand standard cubic feet (Mscf). For example,
Bliss et al. (2010) state that recent

This paper was prepared by Dr Steve Whittaker and Dr Ernie Per

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