1
Enhanced Oil Recovery and CO2 Storage Potential Outside North America: An Economic Assessment
Enhanced Oil Recovery
and CO2 Storage Potential
Outside North America:
An Economic Assessment
Colin Ward, Wolfgang Heidug and
Nils-Henrik Bjurstrøm
January 2018/KS--2018-DP27
doi: 10.30573/KS--2018-DP27
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Enhanced Oil Recovery and CO2 Storage Potential Outside North America: An Economic Assessment
About KAPSARC
Legal Notice
The King Abdullah Petroleum Studies and Research Center (KAPSARC) is a
non-prot global institution dedicated to independent research into energy economics,
policy, technology and the environment, across all types of energy. KAPSARC’s
mandate is to advance the understanding of energy challenges and opportunities
facing the world today and tomorrow, through unbiased, independent, and high-caliber
research for the benet of society. KAPSARC is located in Riyadh, Saudi Arabia.
© Copyright 2018 King Abdullah Petroleum Studies and Research Center (KAPSARC).
No portion of this document may be reproduced or utilized without the proper attribution
to KAPSARC.
3
Enhanced Oil Recovery and CO2 Storage Potential Outside North America: An Economic Assessment
Storing carbon dioxide (CO2) in oil reservoirs as part of CO2-based enhanced oil recovery (CO2-EOR)
can be a cost-effective solution to reduce emissions into the atmosphere. In this paper, we analyze
the economics of this option in order to estimate the amount of CO2 that could be protably stored in
different regions of the world. We consider situations in which the CO2-EOR operator either purchases the
CO2 supplied or is paid for its storage. Building upon extensive datasets concerning the characteristics and
location of oil reservoirs and emission sources, the paper focuses on opportunities outside North America.
Using net present value (NPV) as an indicator for protability, we conduct a break-even analysis to relate
CO2 supply prices (positive or negative) to economically viable storage potential. The main insights of our
ndings include:
A total of about 40 gigatonnes of CO2 (GtCO2) from currently operating emission sources could be
economically stored via CO2-EOR in our focus area. For reference, China currently emits about 10
GtCO2 per year.
Storage potential is dependent on CO2 prices, but only over a narrow range. At an oil price of $50 per
barrel (bbl), storage increases in proportion to the CO2 price — up until about $20 per tonne of CO2
(tCO2). Higher CO2 prices show diminishing returns for storage.
Approximately 6 GtCO2, mainly in Russia, China, Indonesia and Oman, could be protably stored at a
negative or zero CO2 supply price, assuming an oil price of $50/bbl. This corresponds to the situation
where the operator receives no revenue for providing storage services.
Current scal regimes create a disincentive for storage. By taxing the CO2-EOR oil produced at the
same rate as regular oil production, they reduce overall protability of CO2-EOR projects and thus the
economically available storage potential.
At present, there is a shortage of CO2 to satisfy potential demand created by CO2-EOR. If supply were
logistically available, Saudi Arabia alone could technically store a total of about 25 GtCO2 via CO2-
EOR. For perspective, achieving the 2-Degree Scenario (2DS) of the International Energy Agency (IEA)
requires storing 6.8 GtCO2 per year by 2060 (IEA 2016).
Key Points
4
Enhanced Oil Recovery and CO2 Storage Potential Outside North America: An Economic Assessment
Summary for Policymakers
Despite signicant interest in using carbon
pricing to stimulate the application of CO2
-based enhanced oil recovery (CO2-EOR) to
cost-effectively reduce CO2 emissions, to date there is
only limited information available on how carbon prices
inuence the economic viability of CO2 storage — and
hence the total amount that could be economically
stored. This study uses a bottom-up approach to shed
light on the issue, combining data on oil elds and
emission sources. As analyses of storage potential in
North America are widely available, our study focuses
on situations in other regions.
The methodology rst involves screening to identify
elds amenable for CO2-EOR. In a second step,
we seek to connect emission sources with CO2-
EOR opportunities, allowing for CO2 transportation
distances of up to 500 km. Additionally, we stipulate
that sources must produce sufcient CO2 to meet
peak demand of the CO2 ood.
In a nal step, we estimate cost and revenue of a
CO2-EOR project to assess the protability and cost-
effectiveness of CO2-EOR in terms of net present
value (NPV) for the operator, considering potential
source and storage combinations. This calculation
considers both situations in which the CO2-EOR
operator pays for the CO2 used or is paid for the CO2
stored. The former arrangement reects the present
U.S. situation; the latter corresponds to a scenario
in which carbon price policies are implemented to
reduce CO2 emissions into the atmosphere.
Results of our analysis are most effectively
assessed in terms of the combinations of CO2 value
and amount of CO2 stored that deliver a break-even
NPV (discounted at 10 percent) for specied oil
prices. This criterion marks the onset of protability
and cost-effectiveness. For a xed oil price, an
increasingly positive CO2 supply price makes it
protable to store more CO2. However, after a
certain point, this effect tapers off. For instance,
outside of North America, at an oil price of $50 per
barrel (bbl), irrespective of the CO2 supply price,
the potential for storage caps at 40 gigatonnes of
CO2 (GtCO2) because all potential has been utilized.
In this case, 40 GtCO2 can be interpreted as the
economic potential for CO2 storage by CO2-EOR.
Since the storage potential of CO2-EOR is sensitive
to CO2 supply prices, minor policy adjustments can
signicantly impact the amount stored. We show
that even at an oil price of $50/bbl, a CO2 supply
price of $20/tCO2 is sufcient to exhaust virtually all
of the protable storage capacity outside of North
America. Moreover, for the same oil price, about 6.1
GtCO2 could be stored when the CO2 supply price is
negative (i.e., the CO2-EOR operator pays to acquire
CO2). The calculation assumes a net utilization of
0.6 tCO2/bbl, which exceeds the typical utilization
factor of about 0.3 tCO2/bbl for business-as-usual
EOR operations. This increased CO2 utilization
corresponds to a situation in which the operator
increases CO2 consumption to produce more oil,
leading to increased storage.
The economically viable storage potential of 40
GtCO2 is contingent upon cost-effective access to
the CO2 supply from currently operating and emitting
CO2 sources. If CO2 supply considerations are
relaxed, the storage potential of CO2-EOR increases
vastly. Under the relaxed conditions, the technical
CO2-EOR storage potential in Saudi Arabia is
about 25 GtCO2, making it a top contender for this
technology globally. In real-world circumstances,
however, limited access to CO2 could become the
main factor constraining the development of CO2-
EOR projects.
5
Enhanced Oil Recovery and CO2 Storage Potential Outside North America: An Economic Assessment
Introduction
CO2-EOR (enhanced oil recovery using
CO2) is a technology used by commercial
oil producers: to extract additional oil from
depleting elds, they inject CO2 and water directly
into the reservoir. The injected CO2 chemically
interacts with the in situ oil facilitating its ow to
the production wells. Current commercial CO2-
EOR practices focus solely on optimizing oil
production and maximizing prot; as the CO2 must
be purchased, operators seek to control costs
by injecting the minimum amount necessary.
The benet of CO2-EOR derives entirely from
the additional revenue of enhanced oil extraction
offsetting the cost of CO2.
From a climate change perspective, a growing
concern for governments and industry, this
technology is interesting because of its capability to
provide long-term storage of the injected CO2. The
amount of CO2 stored depends to a large degree
on how a particular CO2-EOR project is operated
and managed (Kovsek and Cakici 2005; Dai et al.
2013; Saini 2017). Taking account of the additional
oil revenues, the net storage costs of CO2-EOR are
substantially lower than those associated with other
forms of carbon capture and storage (CCS). As a
result of this cost advantage, CO2-EOR could be a
stepping stone for the development of a large-scale
CO2 storage infrastructure (ARI 2010).
The incentives for EOR-based storage could be
strengthened by setting policy that puts a price on
CO2 emissions into the atmosphere and/or offers
payment for initiatives that store CO2 to avert such
emissions. This creates potential for a CO2-EOR
project to generate two revenue streams: one from
the increased oil extraction and the other from
storing CO2. Under such a policy regime, it becomes
advantageous for operators to specically design
and manage CO2-EOR projects to optimize the
revenues from both oil production and CO2 storage
(van’t Veld et al. 2012).
This analysis focuses on an EOR scenario that
maximizes oil production and CO2 storage on the
assumption that both goals are desirable and should
be encouraged through public policy (IEA 2015).
As assessments of the storage potential in North
America are already available (NETL 2011; IEAGHG
2009), this paper contributes to the assessment
of CO2-EOR potential by estimating the amount
of CO2 that can be economically stored outside of
North America. An emphasis on the sourcing of CO2
supply — or indeed matching supplies and sinks
— is a key feature of our analysis. In this way, our
analysis extends earlier work by the International
Energy Agency (IEA 2015) on the technical potential
of CO2-EOR, which did not cover economic aspects,
and in particular the geographical matching of oil
demand to CO2 supply.
How CO2-EOR works
EOR is usually implemented after primary (natural
production) and secondary (involving pressure
regulation) production methods have been
exhausted in a given oil eld, but may technically
begin at any time. Enhanced production methods
aim to ‘unlock’ some of the oil remaining in the
reservoir by reducing its viscosity, thus making it
easier to produce. These EOR methods typically
rely on heat or a chemical process to increase the
mobility of the oil in the reservoir.
In the case of CO2-EOR, CO2 gas is injected into
the reservoir and interacts with the oil in two ways
depending on the temperature and pressure. If
the pressure is high enough to reach the so-called
minimum miscibility pressure (MMP), CO2 will
dissolve into the oil and ‘loosen’ it from the
formation. The CO2 gas injection phase is then
often followed by a water injection phase, in which
the water sweeps the newly freed oil toward the
production wells. Gas and water injection phases
6
Enhanced Oil Recovery and CO2 Storage Potential Outside North America: An Economic Assessment
then continue in a process called water alternating
with gas (WAG) until the oil production falls below
economically viable levels. Should the reservoir
pressure stay below the MMP after injection, the
injected CO2 will not mix with the oil but push it
toward the production well in a piston-like manner
in what is called an immiscible ood.
The CO2 dissolved in the produced oil is then
recovered and recycled for re-injection. This
means that virtually all CO2 delivered and injected
over the lifetime of the project should remain in
the reservoir once production has halted, apart
from minor leakage through fugitive emissions. To
be of benet from a climate policy perspective, the
CO2 stored as part of CO2-EOR needs to remain
effectively contained in the subsurface. To ensure
this, the operator must undertake appropriate
measurement and verication activities, as
specied in relevant regulatory guidelines
(IEAGHG 2016). As most currently operating CO2-
EOR projects do not carry out these monitoring
activities, there is no certainty regarding the
amount of CO2 that is effectively stored.
Current business-as-usual practices focus on
optimizing oil extraction with the minimum amount
of CO2. These practices typically use around 0.3
tCO2/bbl to produce an additional 6.5 percent
of the original oil in place (OOIP). However, a
more innovative approach that seeks to optimize
CO2 utilization and oil production may yield
signicantly better outcomes. With a miscible
CO2 ood, the IEA (2015) suggests a storage-
focused CO2 utilization of 0.6 tCO2/bbl, allowing
incremental recovery of 13 percent of the OOIP.
The corresponding numbers for EOR operations
using immiscible ooding are 0.65 tCO2/bbl with
an incremental recovery of 4 percent of the OOIP.
Immiscible ooding is typically less effective for
enhancing oil production than miscible ooding
(Jarell et al. 2002).
A simplied picture of a CO2-EOR project is shown
in Figure 1. After arriving at the project site, the
CO2 enters the surface facilities and is compressed
for injection into the reservoir through an injection
well. In the reservoir, the CO2 either dissolves
into the oil or physically pushes the oil toward a
production well where a slurry of oil, water and
gas then exits the reservoir. The recycling facilities
separate the CO2 from the oil (a simple settling
drum is often sufcient, with gas exiting the top and
liquids exiting the bottom). The recovered CO2 is
reinjected while the oil is processed and exported
through the existing production facilities.
Introduction
7
Enhanced Oil Recovery and CO2 Storage Potential Outside North America: An Economic Assessment
Introduction
Figure 1. Main elements of CO2-EOR facilities and boundaries for economic analysis.
Source: KAPSARC.
8
Enhanced Oil Recovery and CO2 Storage Potential Outside North America: An Economic Assessment
Screening Methodology to Select
Candidate Fields for CO2-EOR
To identify elds with economic potential (rather
than straight technical potential) for CO2-
EOR, we carried out a three-step process of
mining databases and available information. The
rst step involved setting specic criteria against the
total population of available elds. We then identied
existing sources of CO2 supply and nally assessed
the geographical ‘match’ of demand and supply.
Assessing available elds for
CO2-EOR
A rst step to estimate global CO2 storage potential
under an approach that seeks to optimize EOR and
CO2 storage (hereafter referred to as storage-focused),
is to assess available elds. For this, we used UCube,
the global eld-level database compiled by Rystad
Energy, which has information on reservoirs and the
production status for approximately 35,000 oil and gas
elds. To select CO2-EOR candidate elds, we applied
the following criteria against the data in UCube:
Field status: only on-shore oil elds that are
currently producing, abandoned or assumed to
start production before 2025 are considered.
Flood type: the type may be either miscible or
immiscible, depending on the MMP, which was
estimated based on the oil mass density (API)
and reservoir temperature for each reservoir
examined. Broadly, if the MMP is greater than
the reservoir pressure (Pr), then the CO2 is not
miscible (dissolvable) into the oil, indicating an
immiscible ood.
Gas/oil ratio (GOR): a large volume of existing
gas in a reservoir undermines the effectiveness
of CO2-EOR operations for several reasons.
More gas indicates a saturated oil with dissolved
gases already present, reducing the ability of
the CO2 to interact directly with the crude. The
compressibility of the gas cap also makes it
difcult to push the oil to the production wells.
For this reason, reservoirs with little or no gas
cap were selected, as determined by the GOR.
Specically, we required the GOR to be less
than 25 percent.
Breakthrough potential: the uids injected into
a reservoir, whether gas or liquid, tend to be much
more mobile than the in-situ crude. Breakthrough
occurs when these injection uids enter the
production stream. A low resistance path for the
injection uids between injection and production
wells can signicantly reduce their ability to drive
the oil, as they bypass most of the reserves.
The mobility of the oil, a primary determinant of
when breakthrough will occur, is correlated to its
viscosity. Fields with very low viscosity (<10 cP)
have been excluded from the sample.
Additional factors: some characteristics warrant
omitting elds from the candidate list. Offshore
reservoirs were excluded entirely, as they are
a tiny fraction of the total CO2-EOR potential
outside of North America, and are technically very
challenging to develop. Additionally, we excluded
existing onshore projects that have already
produced more than 80 percent of their reserves
(dened as being well into tertiary production).
As this is close to the highest technical recovery
factor possible for most EOR methods, it leaves
little oil for the EOR process to recover. Similarly,
onshore reservoirs with less than 10 million
barrels (MMbbl) of incremental production
remaining were determined to be uneconomic as
stand-alone projects. Finally, smaller elds (with a
minimum 0.7 million incremental barrels available)
were considered only if located within 20 km of a
stand-alone project and able to operate as a tie-in.
9
Enhanced Oil Recovery and CO2 Storage Potential Outside North America: An Economic Assessment
Screening Methodology to Select Candidate Fields for CO2-EOR
This initial ltering process identied a population of
reservoirs that show strong potential for CO2 storage
if enough supply is present. The next step was to
assess the CO2 supply available for these elds.
Locating CO2 supply
To develop a technically feasible CO2-EOR
project, a producer must secure sufcient local
supply of CO2. To nd potential CO2 sources for
each candidate CO2-EOR project, we accessed
the European Emission Database for Global
Atmospheric Research (EDGAR 2017), which tracks
historical CO2 emissions from stationary sources
worldwide and categorizes them according to the
type of source (Figure 2).
While EDGAR delivers high-resolution information,
its handling is computationally intensive. To make the
process of source-sink matching more manageable,
we decreased the data resolution to a 1 x 1-degree
grid (corresponding to a cell size of approximately
111 km x 111 km), covering the entire globe (Figure
3). The center of each pixel was used to determine
distances between CO2 supplies and potential CO2-
EOR projects. To ensure sufcient CO2 supply, we
stipulated that supply must meet peak demand of the
CO2-EOR project.
After determining the sources and CO2 demanded
for each potential CO2-EOR candidate, viable supply/
demand pairs were identied by selecting the closest
source with sufcient supply for each project. CO2
supply and demand were also considered from the
perspective that supply typically remains constant
over several years while CO2 demand drops following
peak oil production: thus, a single CO2 source could
consecutively supply multiple EOR projects. Our
analysis assumes that the most economically attractive
source-sink combination is developed rst until demand
drops; then the next project may proceed. Based
on existing projects and economic considerations,
we set 500 km as the maximum distance for CO2
delivery from source to sink. Over this distance,
pipeline is the preferred way of transporting the high
volumes of CO2 required for EOR projects. Existing
CO2-EOR projects suggest that the pipeline must be
sized to deliver, in a single year, a peak CO2 supply of
roughly 15 percent of the lifetime CO2 demand.
A total of 2,355 CO2-EOR opportunities in 30 countries
were identied using the methodology described.
Figure 2. EDGAR database results for stationary emissions.
Source: EDGAR.
10
Enhanced Oil Recovery and CO2 Storage Potential Outside North America: An Economic Assessment
Geographic distribution of
CO2 sinks and sources
Figure 4 shows the countries outside of North
America with the largest CO2 storage potential
with sufcient supply. Russia tops the list in terms
of currently available CO2-EOR opportunities
(11.900 GtCO2), followed by China (5.381 GtCO2)
and Iran (2.932 GtCO2). For comparison, the
chart also indicates technical storage potential,
i.e., unconstrained by the availability of CO2 from
anthropogenic sources. The orange bars in the
gure show that EOR-based storage opportunities
vastly exceed the amount of CO2 currently available
(blue bars) from local sources, particularly in Russia,
Saudi Arabia and Iraq.
Another interesting nding is that most of the
candidate projects can be arranged in clusters. In
fact, 1,990 of the 2,355 projects considered can be
grouped into 32 clusters (Figure 5). Often, these
clusters comprise several reservoirs within the
same geological formations, with a CO2 source in
the vicinity. Clusters allow for a stable CO2 supply
and shared CO2 transportation infrastructure, which
could translate into reducing overall capital and
operational expenses (CAPEX and OPEX).
About 40 GtCO2 from currently operating
stationary sources in our focus area could be
stored through CO2-EOR, with an approximate
incremental production of 66 billion barrels of oil.
Validating the prior ltering methodology, almost
all of the potential opportunities are onshore, with
offshore storage representing a mere 2 GtCO2.
Miscible ooding holds the majority (35 Gt) of the
onshore storage potential, with most of it coming
from currently producing elds in the Middle East,
China and Russia.
Figure 3. EDGAR data for Europe converted into 1 x 1-degree grid of stationary emissions.
Note: Darker colors indicate higher concentrations of emissions.
Source: EDGAR.
Screening Methodology to Select Candidate Fields for CO2-EOR
11
Enhanced Oil Recovery and CO2 Storage Potential Outside North America: An Economic Assessment
0
10
20
30
40
50
60
Russia
China
Iran
Iraq
Indonesia
UAE
Nigeria
Oman
Saudi Arabia
Syria
Egypt
India
Ecuador
Libya
Venezuela
Colombia
Algeria
Mexico
Ukraine
Germany
Italy
Kazakhstan
Argentina
Romania
Turkey
Peru
Belarus
Yemen
Kuwait
Croatia
Gt Co2
Onshore potential CO2 storage
Strict criteria Full potential
Figure 4. CO2-EOR storage potential with strict criteria (sufcient CO2 supply) versus technical potential.
Source: KAPSARC.
Figure 5. Potential clusters for CO2-EOR development outside of North America.
Source: Rystad.
Screening Methodology to Select Candidate Fields for CO2-EOR
12
Enhanced Oil Recovery and CO2 Storage Potential Outside North America: An Economic Assessment
Economics
Unless a reasonable return on investment
(ROI) can be assured, no oil producer will
ever invest in a CO2-EOR project. To assess
economic tness of a project, CAPEX and OPEX
costs, along with potential revenues, must be
determined.
Costing CO2-EOR projects
The total amount of CO2 that is stored via
commercial CO2-EOR projects crucially depends
on individual project protability. We thus sought
to estimate the protablilty of the 2,355 CO2-EOR
opportunities identied through our methodology.
Performing a detailed cash ow analysis for this
many projects was impractical, not only because of
the large number of elds but also due to the lack
of essential data required to quantify oil production
and CO2 storage curves for each reservoir. These
data are commercially sensitive, and generally not
available to the public.
To work around this challenge, we assumed that
all elds exhibit similar incremental oil production
and CO2 storage performance. We determined
some standard production and injection curves, and
scaled them (both annually and temporally) to match
the size of the reservoirs. Given the constraints on
data mentioned above, an assumption of this type
might be considered ‘courageous’ but is necessary
for estimating the economics of CO2-EOR.
Costing of CO2-EOR projects depends on the
components included in the calculation (Figure 1).
For this analysis, which examines only the behavior
of the oil producer in response to the experienced
CO2 supply price, we consider that all cost items
pertaining to CO2 delivery are outside our scope.
The challenges of capture and transport are
deliberately avoided, and assumed to be included
in the supply price incurred by the EOR operator.
Similarly, the emission price of CO2 as set by climate
policy is exogenous to these considerations.
Costs and revenues for a CO2-EOR project are
relatively simple. The main CAPEX components are
related to the drilling and completion of injection and
production wells, and the installation of recycling
facilities. In the operation phase, OPEX comprises
the purchase of CO2, worker salaries and the
cost of energy. When the project reaches the end
of its lifetime, decommissioning (DECOM) costs
are incurred for shutting down operations and
making the site safe (details of the cost estimation
process are given in Appendix A). For revenues, oil
production and potential CO2 storage income are
considered as the only sources.
Other factors that signicantly affect the economics
of CO2-EOR projects are the percentage of revenue
collected by governments in the form of taxes,
royalty payments and other charges. To evaluate
the impact of the government’s take on NPV in each
country, we used the scal information collected
in the proprietary IHS Markit Vantage database.
These data cover details of the scal terms between
governments and oil companies, together with the
type of contractual arrangement (e.g., concessions
or production sharing agreements). To keep the
calculation simple and avoid the need to consider
carryforwards, we assumed that EOR projects are
not scally ring-fenced. This enables operators
to consolidate all cash ows over a portfolio of
projects, thereby gaining the full value of any tax
benets in the year in which they occur.
Storage potential as a function
of breakeven CO2 price
The net present value (NPV) of a project is a
nancial indicator that compares expenditures and
revenues occurring over the lifetime of a project
13
Enhanced Oil Recovery and CO2 Storage Potential Outside North America: An Economic Assessment
Economics
in terms of today’s money. It is calculated by
discounting future cash ows by a set rate for each
year in which they occur. The discount rate is a
key assumption for this calculation, and is crucially
dependent on the perceived risk of the project. High
risk projects command a high discount rate. The
economics of CO2-EOR is particularly sensitive to
the choice of the discount rate because of the large
CAPEX expenditure occurring early in the life of a
project. The OPEX, as well as net revenues from
oil production and potentially from CO2 storage,
will materialize over many years and are reduced
signicantly through discounting, especially at
higher rates. For the purposes of this analysis, we
have selected a at 10 percent discount rate.
To identify the price of CO2 at which EOR becomes
an economically viable option for storage, the NPV
breakeven point is the appropriate indicator. At this
price the project’s NPV is zero and the operator
neither earns nor loses money.
Figure 6 shows the estimated break-even CO2
supply price for all projects in our sample and the
corresponding amount of CO2 stored. The CO2
supply price is taken as negative if acquiring CO2
represents a cost for the CO2-EOR project (as in
current practice) and positive if the EOR operator
receives revenue from providing storage services
(the desired practice). As noted earlier, we do not
explicitly take into account supply-side economics
such as the CO2 emission price or the cost of
capture and transportation, as we assume these
will be factored into the nal CO2 supply price for
the EOR operator. For example, assuming a cost
of $50/tCO2 for capture and transport, a $10/tCO2
supply price would be consistent with an emissions
value of $60/tCO2.
5
10
15
20
25
30
35
40
($30) ($20) ($10) $0 $10 $20 $30 $40 $50
Gt of CO2 stored
Pre-tax/royalty NPV Post-tax/royalty NPV
Breakeven cost or value of CO2 /tonne
Figure 6. Impact of tax and royalty on NPV break-even value for CO2 @ $50/bbl.
Source: KAPSARC.
14
Enhanced Oil Recovery and CO2 Storage Potential Outside North America: An Economic Assessment
The plots in Figure 6 show the amount of CO2 that is
stored for varying break-even CO2 prices and for a
xed oil price of $50/bbl. Since petroleum taxation is
known to have a signicant effect on the protability
of EOR projects, we plotted the curves both for the
pre- and post-tax situations using country-specic
tax rates collected from the IHS Markit Vantage
system. Comparing the two curves quanties
the extent to which petroleum taxes and charges
affect the economics of storage-focused CO2-EOR
projects. The median of CO2 break-even value in
our model is about $6/tCO2 of revenue received by
the operator pre-tax and increases to about $12/
tCO2 post-tax, showing that petroleum taxes and
charges have the potential to signicantly erode
the nancial feasibility of these projects. The shape
of the curve, with an almost linear middle section
from $0/tCO2 to 20/tCO2, indicates that the supply
price is a signicant factor driving the total storage
of CO2. Within this price range, for projects seeking
to optimize oil production and storage, each dollar
of additional revenue could prompt an additional 1
billion tCO2 stored outside of North America. Beyond
$20/tCO2, the technical costs become much higher
and the pool of economically viable projects begins
to shrink.
The results presented so far, linked to a xed oil
price assumption of $50/bbl, show approximately
6.1 GtCO2 of economic storage potential under
commercial schemes in which the operator receives
no revenue from storage (i.e., without the need for
any additional subsidies). In contrast to the strictly
technical potential highlighted earlier, an economic
analysis shows the largest potentials to be in China,
Russia, Indonesia, Oman and Iran. Additionally, it
becomes clear that several of the largest projects
could pay for CO2 to enhance oil production as their
break-even prices are negative (Table 1).
Testing the sensitivity of break-even CO2 prices to
changes in the oil price has a predictable result, with
higher oil prices driving lower break-evens (Figure
7). Clearly, this indicates that under higher oil prices,
producers nd more value in injecting CO2 and will
do so even if they are paid less for CO2 storage.
Country Project Post-tax break-even ($/tCO2) CO2 stored (Mt)
China Jiangsu (2.75) 275
China Henan (2.74) 250
Oman Lekhwair ( 7.77) 187
Russia Arlanskoye (0.29) 141
Indonesia Rantau (1.92) 135
Russia Chutyrsko-Kiyengoskoye (1.45) 118
Oman Al Huwaisah (1.11) 115
Russia Igrovkoye (0.94) 108
Iran Naft-I-Shahr (10.15) 101
Table 1. Large CO2-EOR projects with negative post-tax CO2 break-even supply prices.
Source: KAPSARC.
Economics
15
Enhanced Oil Recovery and CO2 Storage Potential Outside North America: An Economic Assessment
0
5
10
15
20
25
30
35
40
$30 $20 $10 $0 $10 $20 $30 $40 $50 $60
Gt of CO2 stored
Breakeven cost or value of CO2 /tonne
$70/bbl $50/bbl $30/bbl
Figure 7. Effect of oil price on storage potential and CO2 break-even prices.
Source: KAPSARC.
Figure 7 demonstrates that changes in the oil price
have a net effect of shifting the entire storage
curve. The shape of the curve remains unchanged,
indicating that the behavior of the CO2 supply price
is relatively stable assuming a xed injection rate.
More interesting is the nding that most of the
change in storage potential occurs only over a small
range of CO2 supply prices (~$20). This indicates
that the general engineering and nancial hurdles of
these projects, while varied, have similar outcomes.
The steep and linear slope implies that setting the
CO2 supply price at an appropriate level could act
as a lever for increasing storage.
It is notable that the horizontal shift in the curves is
almost $1 of CO2 price substituting $1 of oil price.
This is because the CAPEX and OPEX are xed
with only the oil and CO2 cash ows as variable.
When the oil price drops, the CO2 cash ow must
rise to offset the lost revenue and maintain the
breakeven point. The CO2 consumption is a xed
ratio of 0.6 tCO2 per barrel, and the aggregate
discount rates for oil and CO2 are 36 percent and 54
percent, respectively (see Appendix A). Multiplying
these values ($/bbl * 1 bbl * 36 percent = 0.36, $/
tonne *0.6 tCO2 * 54 percent = 0.34) yields a ratio
of 93 percent of the oil price movement to the CO2
price offset.
As mentioned earlier, oil producers’ application of
CO2 injection may vary signicantly depending on
the positive or negative price of the CO2 supply
available to them. If the CO2 was an expense
instead of a revenue, the operators would likely
revert to the traditional injection rate of 0.3 tCO2/
bbl to reduce costs. At the lower injection rate,
the incremental recovery is also half the factor for
storage-focused EOR (6.5 percent of OOIP instead
of 13 percent) which implies:
The number of CO2-EOR projects increases, as
they are not ruled out for having insufcient supply.
Economics
16
Enhanced Oil Recovery and CO2 Storage Potential Outside North America: An Economic Assessment
When CO2-supply prices are negative, the
operator incurs lower costs and more projects
are protable.
Essentially, the real-world behavior of an operator
changes at the point where the CO2 supply price
switches from positive to negative. Under negative
CO2 supply prices, more CO2 is protably stored
through conventional CO2-EOR practices than
through storage-focused CO2-EOR (Figure 8). For
positive prices, the additional revenues from storage-
focused projects raises the total CO2 sequestered.
The impact of relaxing supply
constraints
Applying the methodology described above, in
which CO2 supply is constrained in various ways,
yields a total economically viable CO2-EOR storage
capacity of 40 GtCO2. This is signicantly less than
the technical potential for global storage capacity
(including North America) of 240 GtCO2, as estimated
by the IEA, for storage-focused CO2-EOR (IEA 2015).
With this consideration in mind, we extended our
analysis to remove the constraint of CO2 supply
limitations such that project protability becomes the
determining factor for viability. Using the methodology
described above to calculate CO2 supply prices
against potential storage, we nd a total technical
potential for onshore storage capacity of 190 GtCO2,
almost vefold more than the previously calculated
economic storage potential of 40 GtCO2 (Figure 9).
This changes the curve in relation to CO2 supply
price increases: in contrast to the smooth initial curve,
the new curve appears jagged due to the inclusion
of a few very large elds that have outsized impacts
on the results. The vertical portion to the right is a
cluster of very big elds in Saudi Arabia, for instance.
The gure also shows that taxation appears to have a
smaller impact at this scale, due to the larger volume
of projects in the sample.
Gt of CO2 stored
Breakeven cost or value of CO2 /tonne
-
5
10
15
20
25
30
35
40
($60) ($40) ($20) $0 $20 $40 $60
0.3 t/bbl CO2 utilization 0.6 t/bbl CO2 utilization
Figure 8. Effect of CO2 utilization factor on economic storage potential @ $50/bbl.
Note: EOR refers to 0.3 t/bbl CO2 injection rates. EOR+ is 0.6 t/bbl CO2 injection, leading to more storage.
Source: KAPSARC.
Economics
17
Enhanced Oil Recovery and CO2 Storage Potential Outside North America: An Economic Assessment
Figure 9. Pre- versus post-tax unconstrained break-even CO2 values @ $50/bbl.
Source: KAPSARC.
Economics
Gt of CO2 stored
Breakeven cost or value of CO2 /tonne
Pre-tax Post-tax
-
20
40
60
80
100
120
140
160
180
200
($20) ($10) $0 $10 $20 $30 $40 $50
Under this extended analysis, the range of prices
that affect storage potential is very similar to the
rst results (Figure 6); the median supply price is
still somewhere around the $15/tCO2 paid to the
operator for storage. The difference is that total
storage is much bigger.
Examining data for Saudi Arabia highlights the
difference between technical and economic
potential. Under the methodology that includes
the initial constraints, the economic storage
potential of Saudi Arabia is estimated as 788
million tonnes of CO2 (MtCO2), which is less than
one-tenth of the economic storage potential of
Russia (9.925 GtCO2). As noted, this estimate
is predicated on several assumptions, the most
important of which are:
CO2 demand assumes that the entire eld is
developed at once.
CO2 supply from a single source is sufcient to
meet the maximum volume of CO2 demanded
by the EOR project.
The distance of a pipeline (or network of
pipelines) is constrained to less than 500 km.
Emission sources are xed and do not change
with future developments.
In reality, the storage potential in some Saudi elds
is so vast that supplying sufcient CO2 for a full
EOR project from a single source is practically
impossible. A realistic implementation of CO2-EOR
in such situations would be phased, with small
sections of the eld developed sequentially as the
CO2 supply can support it. Without these limiting
criteria, the total possible storage of Saudi Arabia
climbs to 25 Gt, more than half of the total in our
primary analysis.
18
Enhanced Oil Recovery and CO2 Storage Potential Outside North America: An Economic Assessment
Globally, a phased construction approach for larger
projects could expand the CO2 supply. Where this
approach is not possible or economically viable,
an alternative could be front-loading with aquifer
storage. A CO2 producer lacking sufcient supply
to cover the maximum demand of an EOR project
could pre-charge an aquifer to support the initial
phases of the WAG injection, when huge volumes
of CO2 are needed. Large pipeline networks to
collect and distribute CO2 among multiple sources
and sinks may also help address constraints
caused by CO2 shortages.
As estimates in this analysis are made on current
conditions and CO2 emissions data, it should be
noted that some key assumptions may change
in the future. With rising CO2 demand from EOR
elds it may become advantageous to locate
emissions sources close to potential storage sites.
In addition, in the largest elds, economies of
scale can make supply options such as a longer
pipeline, or a network connecting multiple sources
economically advantageous. Such developments
would substantially change the results of the
present analysis.
Economics
19
Enhanced Oil Recovery and CO2 Storage Potential Outside North America: An Economic Assessment
Conclusion
With a specic focus on regions outside
North America, we examined the
economic potential to apply CO2-EOR
technologies to CO2 storage, and the relationship
between the supply price of CO2 and the storage
capacity in oil elds. Our analysis shows that
storage-focused CO2-EOR projects outside of
North America have the potential to store up to 40
GtCO2 from existing large-scale stationary sources.
In some regions, storage potential vastly exceeds
currently available CO2 supply from such sources.
The amount of CO2 stored depends on the protability
of CO2-EOR, which in turn is inuenced by the value
of CO2 to an EOR operator. Two key elements can
change the value equation substantially:
When the price of oil increases, the value of CO2
as an input to enhance production increases.
Alternatively, implementation of a carbon
pricing policy by governments creates value
for CO2 storage.
Regardless of whether governments create the
latter value through subsidies, tax credits, emissions
trading or tax on the emitters, concrete nancial
benets arise from encouraging additional CO2
storage in oil elds.
For the CO2 injection rates assumed in the
analysis, we nd that independent of the oil price,
even moderate changes in CO2 supply prices can
signicantly affect the economics of CO2 storage.
For an oil price of $50/bbl and a CO2 supply price
in the range $10/tCO2 to $15/tCO2, with CO2 supply
constraints taken into account, we nd at the
aggregate level an economically viable storage
capacity of 20 GtCO2. Without these supply
constraints, accessible storage space increases as
much as vefold at these pricing levels.
Our study delivers three key policy-relevant
insights. First, it suggests an optimal range of CO2
supply prices to encourage an increase in the
storage component of CO2-EOR projects. For a
given oil price, the range over which the CO2 supply
price can affect storage potential is quite narrowly
dened in the interval of $10 to $30/tCO2 for an oil
price of $50/tCO2.
Second, we show that petroleum taxation has a
detrimental effect on the availability of economic
storage by lowering the protability of individual
projects. The policy implication is that oil producing
countries seeking to implement CO2-focused
storage projects may wish to revisit their petroleum
scal regimes to avoid negative interaction with CO2
storage policies.
Third, our results show that economically viable
storage is limited by current CO2 supply. Large CO2
transportation infrastructure could unlock additional
CO2-EOR storage opportunities and allow for
oil producers to engage in decarbonization on a
meaningful scale.
20
Enhanced Oil Recovery and CO2 Storage Potential Outside North America: An Economic Assessment
References
ARI, 2010. “U.S. Oil Production Potential from
Accelerated Deployment of Carbon Capture and
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Dai, Zhenxue, Richard Middleton, Hari Viswanathan,
Julianna Fessenden-Rahn, Jacob Bauman, Rajresh
Pawar, Si-Yong Lee and Brian McPherson.” An Integrated
Framework for Optimizing CO2 Sequestration and
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Godec, Michael, Vello A. Kuuskraa, and Phil Dipietro.
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oil recovery and CO2 storage.” Energy Fuels 27 (2013):
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IEAGHG 2009. “CO2 Storage in Depleted Oilelds:
Global Application Criteria for Carbon Dioxide Enhanced
Oil Recovery.” IEA Greenhouse Gas R&D Programme,
Cheltenham. www.ieaghg.org/docs/General_Docs/
Reports/2009-12.pdf
IEAGHG 2016. “Emissions accounting for CO2-EOR” IEA
Greenhouse Gas R&D Programme, Cheltenham.
IHS Markit Vantage Database. Last accessed October
2017: http://vantage.ihsenergy.com/
IHS Markit QUE$TOR Cost Estimation Tool. Last
accessed October 2017: https://ihsmarkit.com/products/
questor-oil-gas-project-cost-estimation-software.html
Kovscek, A.R. and M.D. Cakici 2015. “Geologic
storage of carbon dioxide and enhanced oil recovery
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Leach, Andrew, Charles F. Mason, and Klaas van‘t Veld
2011. “Co-optimisation of enhanced oil recovery and
carbon sequestration.” Resource and Energy Economics
33:893-912.
Jarrel, Perry M., Charles E. Fox, Michael H. Stein
and Steven L. Webb 2002.” Practical Aspects of CO2
Flooding.” SPE Monograph Series, vol. 22.
NETL 2011. “Improving Domestic Energy Security and
Lowering CO2 Emissions with “Next Generation” CO2-
Enhanced Oil Recovery (CO2-EOR).” National Energy
Technology Laboratory and U.S. Department of Energy
(2011).
NETL 2014. “Acquisition and Development of Selected
Cost Data for Saline and Enhanced Oil Recovery (EOR)
Operations.” National Energy Technology Laboratory and
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Saini, Dayanand 2015. “CO2-Prophet model based
evaluation of CO2-EOR and storage potential in mature
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21
Enhanced Oil Recovery and CO2 Storage Potential Outside North America: An Economic Assessment
Appendix A: Cost Analysis
The economic analysis carried out for this report
takes into account the main cost elements
and sources of revenue for a typical CO2-EOR
operation, based on a simplied representation of oil
production and CO2 injection proles.
Injection and production
proles
With a sole focus on estimating CO2-EOR project
protability, we use a simplied approach that relies
on a set of dimensionless oil production and CO2
injection curves (Figure A1). These curves relate
incremental oil production (expressed as a fraction of
maximum production) to the percentage of injectants
required to ll the hydrocarbon pore volume (HCPV).
These curves were generated using the CO2-
Prophet model, a CO2-EOR estimation software
developed by Texaco for the U.S. Department of
Energy (Saini, 2006), and reect a CO2-EOR project
in which pure CO2 is injected (lling 10 percent of
the HCPV) followed by a WAG phase implementing
a CO2-to-water ratio of 1:1. The curves capture the
main characteristics of a CO2-EOR ood, including
the absence of a production plateau and a steep
production decline. In reality, individual projects may
show considerable variation from the performance
characteristics assumed in this calculation.
Figure A1. Variation of incremental oil production and CO2 demand with injected HCPV.
Note: Oil production and CO2 demand are quantied as fractions of their corresponding maximum values.
Source: KAPSARC.
22
Enhanced Oil Recovery and CO2 Storage Potential Outside North America: An Economic Assessment
Appendix A: Cost Analysis
The usefulness of the gures is that they can be
scaled to t larger or smaller developments. For
example, we may apply a 10 percent NPV to these
values, and determine the present value of future
revenues (or potential costs in the case of CO2) in
relation to the total volumes. In this case, the CO2
NPV is 54 percent of the total value, while oil NPV
is 36 percent. This is due to the majority of CO2
use occurring early in the project, with a sharp
reduction afterward. Oil production occurs after an
initial delay and declines at a gentle rate, leading to
a larger reduction of the total value once NPV has
been applied.
Production and injection wells
Number of wells
EOR wells are much less productive than regular
wells, and as such many more are required than in
a normal upstream development. This means that
production is much more localized, with a nearby
injector ‘pushing’ oil toward a producer. In a normal
upstream project, a net productivity of 8 MMbbl per
well is normal; for EOR projects, a value closer to
600,000 barrels is more usual.
First, we solve for the number of existing producers
and injectors of the upstream project. Multiplying
the OOIP by the ultimate recovery factor (the
percentage of recoverable reserves) determines the
total volume of oil that would have been produced
without EOR. This value is then divided by the
typical 8 MMbbl per producer. Based on analyzed
projects, existing injection wells are equal to about
40 percent of the existing producers.
∗% =
8 =
∗40% =
We now solve for the number of new producers
and injectors. Rystad provides data on the
incremental oil from the reservoir; we merely divide
this value by the expected productivity of 600,000
barrels. Note that this calculation is for the total
number of producers, as existing wells will also
benet from the EOR process. The number of new
producers is the difference between the total wells
and the existing ones.
600,000 =
− =
Due to the use of drilling patterns, the total
number of injection wells in an EOR project
matches the total number of production wells.
Typically, four injection wells surround a single
producer, driving the oil toward the middle (Figure
A2), with this pattern repeated in a giant grid over
the reservoir. Across a large enough pattern, the
number of injectors and producers is ultimately
the same.
Carrying on, we solve the number of new injectors
as follows:
Total production wells = Total injection wells
Total injection wells – Existing injection wells =
New injection wells
Surface costs
For each well, whether existing or new, new
surface equipment will need to be installed, ranging
from a collection of valves and/or regulators to
the wellhead itself. As CO2 is a highly corrosive
substance, this equipment must be upgraded
or replaced even on existing wells. Based on
some sample projects built in IHS QUE$TOR,
the cost of new equipment was determined to be
approximately $200 k/producer and $250 k/injector.
600,000 =
− =
600,000 =
− =
23
Enhanced Oil Recovery and CO2 Storage Potential Outside North America: An Economic Assessment
Appendix A: Cost Analysis
Cost per well
Depending on reservoir characteristics, the cost
of a single well can vary widely. Reservoir depth is
the major determinant. We derived an equation to
solve for the cost per foot of drilling, completion and
rework by running multiple QUE$TOR examples (the
equation itself cannot be shared due to intellectual
property rights).
CO2 recycle system (separator
and compressors)
In line with the Kinder Morgan model used as a guide
for this analysis, the separators and compressors
that comprise the recycle system are priced together.
However, as the original cost was quoted in 2000,
we applied the IHS Capital Cost Index (used to
track change in costs over time for upstream
developments) to estimate current values. The
original cost, quoted as a function of system capacity
and using million standard cubic feet (MMscf), was
approximately $1,200/MMscf/year; it revises to a
current cost of about $2,170/MMscf/year.
Operations cost
As proposed in NETL (2014), we assume that the
OPEX (expressed in $/Mcf [thousand cubic feet])
for projects analyzed is set at 1 percent of the oil
price per barrel; ergo, for an oil price of $50/bbl,
OPEX is $0.50/Mcf.
CO2CO2
CO2
CO2
Oil
Figure A2. A Five-spot EOR well pattern.
Source: KAPSARC.
24
Enhanced Oil Recovery and CO2 Storage Potential Outside North America: An Economic Assessment
Appendix A: Cost Analysis
Figure A3. IHS Markit upstream capital cost index, used to update recycle system costs.
Source: IHS Markit.
Decommissioning
Using benchmarks generated from QUE$TOR, we
estimated the DECOM cost by examining various
portions of each project. We based our calculations
on the extra costs associated with CO2-EOR only,
as existing elements (such as wells) should be
accounted for in the decommissioning of the original
project. As such, the recycle system was treated as
a new facility/equipment and the decommissioning
costs were estimated to be about 27 percent of
CAPEX. Costs to decommission new wells are
much lower, with only 6 percent of CAPEX allocated.
25
Enhanced Oil Recovery and CO2 Storage Potential Outside North America: An Economic Assessment
Nils-Henrik Bjurstrøm
Nils-Henrik is a product portfolio manager at Rystad Energy with overall
responsibility for the management of its commercial products. He was a
senior project manager within Rystad Energy consulting for three years.
Nils-Henrik previously worked at Roxar Software Solutions as a manager
and developer of software products within petroleum geology, geophysics
and reservoir engineering. He holds an M.S. in Applied Mathematics from
the Norwegian University of Technology and Science and an Executive MBA
in Strategic Management from the Norwegian School of Economics.
Wolfgang Heidug
Colin Ward
Wolfgang is an expert on low-carbon energy technology policy with in-depth
knowledge of the science and technology of CO2 capture and storage. Prior
to joining KAPSARC he was a senior adviser at the International Energy
Agency in Paris. Wolfgang has over 20 years’ experience working with Shell
International. He obtained his Ph.D. in Engineering from the U.S. and holds
a M.S. in Physics and Economics from Germany.
Colin is a research fellow in KAPSARC’s Markets and Industrial
Development program. He has worked in the energy industry for 10 years
in various capacities including seismic eld work, renery design and
consulting for major international and national oil companies worldwide. Colin
plays a major role in several KAPSARC projects, primarily focusing on cost
estimation for energy projects and environmental impacts of the global energy
industry. He holds an MBA (University of Texas), B.S. Electrical Engineering
(University of Houston), and a B.A. Philosophy (Tulane University).
About the Authors
About the Project
Pathways to Low Carbon Oil is a project that will examine the global challenges and opportunities
for oil in a carbon constrained world. With a focus on Saudi Arabia’s competitiveness in this
emerging market, we examine the existing carbon intensity of upstream operations and the
opportunities to reduce that intensity through management strategies and technology, as well as
the economic impacts. Understanding the market and player behaviors will provide insights to
policy options along with the legal, regulatory and commercial issues that must be addressed.
26
Enhanced Oil Recovery and CO2 Storage Potential Outside North America: An Economic Assessment
www.kapsarc.org
