Storing CO2 throughEnhanced Oil Recovery© OECD/IEA, 2012

Combining EOR with CO2 storage (EOR+)
for profit

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 norepresentation or warranty, express or implied, in respect of the paper’s content (including its completeness or accuracy) and shallnot be responsible for any use of, or reliance on, the paper. Comments are welcome, directed to juho.lipponen@iea.org.

© OECD/IEA, 2015

INTERNATIONAL ENERGY AGENCY
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© OECD/IEA 2015

Storing CO2 through Enhanced Oil Recovery

Combining EOR with CO2 storage (EOR+) for profit

Acknowledgements
This publication was prepared by the International Energy Agency (IEA) Carbon Capture andStorage (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. Page | 3
Kamel Ben Naceur, Director of Sustainable Energy Policy and Technology provided comments andguidance.
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 fielddata 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 juho.lipponen@iea.org.

Storing CO2 through Enhanced Oil Recovery
Combining EOR with CO2 storage (EOR+) for profit© OECD/IEA 2015

Table of contents
Executive summary .................................................................................................................6
Introduction ............................................................................................................................8
Page | 4

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
Figure ES1 • Global storage potential for different CO2-EOR practices (GtCO2)............................... 7
Figure 1 • Schematic of CO2-EOR operation ................................................................................... 10
Figure 2 • Core functional activities used in cost analysis .............................................................. 20© OECD/IEA 2015

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Figure 3 • Average CO2 supply prices under three scenarios ......................................................... 21
Figure 4 • Oil price trajectories under three scenarios................................................................... 22
Figure 5 • NPV of illustrative CO2-EOR project for different ETP scenarios and using different
EOR practices................................................................................................................. 22
Figure 6 • Factors contributing to the different NPV results for each CO2-EOR practice underthe 2DS .......................................................................................................................... 23
Figure 7 • Illustrative oil and CO2 price impact on choice of EOR+ practices indifferent scenarios ........................................................................................................ 24
Figure 8 • Global storage potential for different CO2-EOR practices (GtCO2) ................................ 26
Figure 9 • Global incremental oil production potential for various CO2-EOR practices ................. 27
Figure 10 • Storage potential in the top four regions..................................................................... 28
Figure 11 • Impact of Advanced EOR+ on oil demand .................................................................... 31
Figure 12 • Cumulative incremental CO2-EOR oil production, 2013-50 ......................................... 32
Figure 13 • Schematic production profile used for analysis ........................................................... 41
Figure 14 • Elements of capital costs for different CO2-EOR scenarios .......................................... 43
Figure 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
Box 1 • Weyburn-Midale: The front-runner in combining CO2-EOR and CO2 storage ................... 13
Box 2 • Examples of large-scale CO2 capture projects linked with EOR ......................................... 14
Box 3 • CO2 supply prices and potential impacts of price on CO2 emissions.................................. 18
Box 4 • Key actions from the IEA CCS Roadmap ............................................................................. 37

Page | 5

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Executive summary
Injecting carbon dioxide (CO2) into oil reservoirs to enhance oil recovery (EOR) has beencommercially used for several decades in the petroleum sector. As the increasing pressure tocombat climate change has brought carbon capture and storage (CCS) to the forefront as anPage | 6 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 forclimate change mitigation goals, offering commercial opportunities for oil producers while also
ensuring permanent storage of large quantities of CO2 underground. Transforming practices tosupport 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 capabilityof 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 areuseful 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 andverification 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 oflarger 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 ofoil 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 CO2EOR 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 caseprovides 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 potentiallybe stored, exceeding the CO2 storage requirements under the 2DS case. Storage potential underMaximum Storage EOR+ is estimated at 360 GtCO2.

Storing CO2 through Enhanced Oil Recovery© OECD/IEA 2015

Combining EOR with CO2 storage (EOR+) for profit

Figure ES1 • Global storage potential for different CO2-EOR practices (GtCO2)
400

Billion tonnes of CO2

350
300

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250
200
150
100
50
0

Conventional EOR+

Advanced EOR+

Maximum Storage EOR+

2DS cumulative storage(2015-50)

While both the economic and CO2 storage potential seem significant, adding these CO2 storagepractices 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 andverification of stored CO2. The level of additional cost varies widely, depending on the geologicaland 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 toadding 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 andcomplementary 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 amore mature stage of technology deployment.

•

A framework of laws and regulations is needed to ensure the safe and effective designand operation of CO2 storage options. For CO2 stored through EOR+ to qualify as “notemitted” – and thus gain the benefits of climate policy – the operator must comply withregulations to ensure that the CO2 is retained in the reservoir.

Storing CO2 through Enhanced Oil Recovery
Combining EOR with CO2 storage (EOR+) for profit© OECD/IEA 2015

Introduction
Injecting CO2 into oil reservoirs to enhance oil recovery (CO2-EOR) has been practiced on acommercial 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 anPage | 8 emissions mitigation tool, many have looked to CO2-EOR as a means of supporting geologicalstorage of CO2 storage (IEA, 2015).
Four decades of CO2-EOR experience have generated in-depth knowledge about technical aspectsof the process and its economic benefits. Much has been learned about project design andreservoir 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 thepressure 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 throughextensive 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 thepotential economic impact of modifying EOR at the project level to include storage of CO2, andthen 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 thestorage is incidental to conventional EOR (Conventional EOR+); (b) a second level in which boththe 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 thirdlevel 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 toincrease the amount of CO2 stored when producing oil. The fourth chapter considers thecomplicated question of the net impact of increasing CO2 storage through EOR+, and lays out theconditions 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 toaddress to realise the benefits of EOR+ for climate change mitigation.

© OECD/IEA 2015

Storing CO2 through Enhanced Oil Recovery

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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, Page | 9
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 ofenhancing 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 oiland 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 stateof 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 thecharacteristics 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 thesame 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 isre-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 anadditional 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 andsimilar production enhancements are usually not required until well into a reservoir’sStoring CO2 through Enhanced Oil Recovery
Combining EOR with CO2 storage (EOR+) for profit© OECD/IEA 2015

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).
Page | 10

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 toalter its density or viscosity, change the “wettability” of the reservoir rock, or plug highpermeability flow paths in the reservoir.
Main methods include thermal recovery, chemical flooding and, miscible gas injection. The typeof EOR technology suitable depends on the characteristics of a given oil reservoir and its state ofdepletion. 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) thephysical and chemical characteristics of the oil; and iii) the production history, condition andaccessibility 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 effectreducing 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 withoil 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 thiswindow by balancing the injection and withdrawal of fluids from the reservoir. Should it be© OECD/IEA 2015

Storing CO2 through Enhanced Oil Recovery

Combining EOR with CO2 storage (EOR+) for profit

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 somemiscible 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 Page | 11
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 diminishedby 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 andwater produced from the reservoir. The presence of water hinders the movement of CO2 throughthe 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 andpetrophysical 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 – inparticular, 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 withsuitable 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.

Storing CO2 through Enhanced Oil Recovery
Combining EOR with CO2 storage (EOR+) for profit© OECD/IEA 2015

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 inresidual oil and water present in the reservoir.
Page | 12

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 onproperties 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 becompensated 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 portionof this CO2 is trapped in the reservoir through capillary forces and would be very difficult toremove; 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 takemeasures 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 offugitive emissions released to the atmosphere during handling the CO2 at surface facilities. Whilequantitative 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 projectin 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 raisedquestions 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 ofstoring 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 forthe climate nor for the development of CCS. Moreover, in most cases CO2-EOR operations havenot 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.

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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 thefield is operated as a traditional EOR project, it has provided very useful insights into the potentialof 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 otherfluids; 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 Weyburnfield 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 byapproximately 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 thataround 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 increaseoil production (Box 2).

Page | 13

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Combining EOR with CO2 storage (EOR+) for profit© OECD/IEA 2015

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.
Page | 14

The Boundary Dam Unit 3, inaugurated by SaskPower in October 2014 (Saskatchewan, Canada), is theworld’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 withtransforming 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 apioneer 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 iscaptured 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 andlong-term CO2 storage goals do not figure within the rationale for EOR projects in the UnitedStates (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 wayof 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. Suchmonitoring 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 “asnot being emitted” in the framework of climate policy.

•

The laws and regulations that apply to CO2-EOR operations have evolved to address theissues associated with oil and gas operations, not CO2 storage. In the United States, forexample, property law places limits use of the subsurface that, while allowing for
efficient oil recovery, present barriers to CO2-storage (Marston, 2013). Without changes

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Storing CO2 through Enhanced Oil Recovery

Combining EOR with CO2 storage (EOR+) for profit

to the laws and regulations that apply to CO2-EOR, it may not be possible to reconcile thepractice 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
Page | 15
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).

Storing CO2 through Enhanced Oil Recovery
Combining EOR with CO2 storage (EOR+) for profit© OECD/IEA 2015

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.

Page | 16

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 andthat these benefits are, at a minimum, greater than the additional costs associated withstorage. 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, acase in which the amount of CO2 used per barrel of oil is increased in order to recoveradditional 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 alreadyinjecting CO2 into underground reservoirs, with the aim of enhancing the production of oil. In thissection 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 thepotential 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 sothey can withstand the corrosive effects of CO2-water mixtures.

These additional activities represent an additional cost to CO2-EOR operators that would, if notoffset 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

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Storing CO2 through Enhanced Oil Recovery

Combining EOR with CO2 storage (EOR+) for profit

storage requires a link between the regulatory framework for oil production and that for tacklingclimate change. The challenge for jurisdictions that already have CO2-EOR activities is to makethis transition, which can introduce additional new business risks, sufficiently attractive tooperators who are comfortable with the status quo. This could be done for example throughcarbon pricing or a regulatory mandate.
In this new context, generators of CO2 would choose to capture rather than emit CO2 and Page | 17
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. CO2EOR 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 andcompression), 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 ofidentifying 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 andcarbon storage activities interact. All three models assume the additional activities describedabove are undertaken, which would impose costs on the operator above and beyond thosegenerally 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 inthis section. In this sense, none of these models represent a “business-as-usual” approach. The
three typologies are:4•

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 etal., 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 withincremental oil recovery rising to 13% of OOIP. This is consistent with net utilisation insome 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 astrong 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 AdvancedEOR+). This level of storage could be achieved by not re-injecting produced water into

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.

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Combining EOR with CO2 storage (EOR+) for profit

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).

Page | 18

Table 1 summarises the technical assumptions for each of the three scenarios regarding themodes of extraction, all of which cover only miscible CO2 flooding. 5
Table 1 • Specification of EOR+ practices
Scenario

Description

Incremental recovery

Utilisation% OOIP

tCO2/bbl

Conventional EOR+

Miscible WAG flood with vertical injector andproducer 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 andoperated with the explicit goal of increasingstorage. 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 priceand (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 aresult 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 theConventional 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
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 “fewdollars” per thousand standard cubic feet (Mscf). For example, Bliss et al. (2010) state that recent
contracts have been priced CO2 at USD 30/tCO2 (USD 1.6/Mscf) at oil prices of USD 70/bbl. In
addition, several CO2-EOR producers (e.g. Denbury Resource, Kinder Morgan, and Occidental
Petroleum) own large natural geologic accumulations of CO2 (DiPietro et al., 2012). In these cases, thecost of CO2 supplied to their EOR operations is far less, on the order of a few USD per tonne atcomparable oil prices.
At current US CO2 prices, CO2-EOR is clearly profitable, as evidenced by the growing number of
US projects (Kuuskraa and Wallace, 2014). In fact, as recently as 2012 reports and industry
presentations stated that access to CO2 supplies was holding back EOR project development (ARI andMelzer Consulting, 2010; ARI, 2011; NEORI, 2012).

5
As discussed earlier, immiscible flooding is generally less efficient at recovering oil than miscible CO2-EOR and as a result, thisanalysis does not include immiscible flooding.

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Storing CO2 through Enhanced Oil Recovery

Combining EOR with CO2 storage (EOR+) for profit

Box 3 • CO2 supply prices and potential impacts of price on CO2 emissions cont’d.
Consequently, some have argued that the revenues from CO2 sales to EOR can help support capture
projects and, indeed this has been the case (see Boxes 1 and 2). However, others have pointed out that in a
future where emissions of CO2 to the atmosphere are priced (or otherwise limited) the supply of captured
CO2 may grow, depressing CO2 supply prices for CO2-EOR to the point that prices become negative – a boon
for EOR operators, but a negative outcome for those capturing CO2 (Dooley et al., 2010).
In addition to there being the potential for competition between CO2 sources that drives down the priceof CO2 supply, there is also the potential for competition that limits just how low (i.e. negative) the CO2
supply price can go. In this case, the competition for disposal of CO2 could come from saline aquifer
storage. For example, in the United States, Eccles et al. (2012) estimate that 275 GtCO2 of storage could
be available for under USD 5/tCO2, which would set a limit to the price CO2-EOR operators could expect
to receive – transport bottlenecks notwithstanding. Nonetheless, in both the ETP 2 °C Scenario and 4 °C
Scenario considered here (IEA, 2014a), the operator could expect to generate revenues from use of CO2
for EOR by the end of the modelling period and, as the results will show, the choice of NPV maximising
scenario is robust to CO2 disposal price trajectory.
Regardless of the CO2 supply price, however, CO2-EOR project operators will only consider additional
activities required for verifiable storage if they are required to do so through regulation or contract witha CO2 supplier. The corollary to this is that the financial benefit of storing CO2 must be sufficient to offset
the cost of doing so – otherwise, operators will choose to use natural CO2 (where it is available) or not
pursue CO2-EOR at all. The financial benefit could come about through a reduction in supply prices, as
discussed above, or a variety of other mechanisms, such as: government incentives per tonne of CO2
verifiably stored, or a tradable certificate system. Alternatively, a CO2-EOR operator might undertake theadditional activities and move to an EOR+ practice through regulatory measures and mandates imposedby government. In such a scenario, a government would simply “ban” conventional practice.

The economics of increasing CO2 storage through CO2-EOR:
Illustrative cases
In a carbon-constrained world, storing CO2 through EOR can be a positive NPV proposition for
CO2-EOR projects. This is illustrated here by modelling the financial performance of threehypothetical CO2-EOR projects under three different CO2 and oil price scenarios. These threeprojects are identical, save for the EOR+ operational model after which they are patterned: i.e.
Conventional EOR+, Advanced EOR+, and Maximum Storage EOR+. The full set of assumptions isprovided in Annex 1.

Capital and operating costs
To determine the costs of CO2-EOR operations in the illustrative case, this analysis assumes a setof five core functional activities for which aggregated cost data have been developed (Figure 2).
•

CO2 injection includes distribution of CO2 to the injection wells and all technical measures
to maintain necessary pressure and temperature. The costs of CO2 injection include thecapital costs of compression, flow control and measurement, emergency blowdown
equipment but do not include the capital cost of wells. The costs of well workovers, anddrilling and completion for new injection wells as well as surface facilities is reported
separately. The capital cost of CO2 injection primarily depends on peak CO2 handling rates.

•

Oil-gas-water separation relates to activities required to manage produced fluids –i.e. the collection of fluids from the production wells; their transport to production
facilities; the separation of oil, gas and water; the treatment of water for disposal; andthe collection of gases for further processing.

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Storing CO2 through Enhanced Oil Recovery
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Page | 20© OECD/IEA 2015•

CO2-gas separation and clean-up comprises activities to separate hydrocarbons from CO2
and to adjust the composition of hydrocarbon streams to meet commercial specifications
for export.

•

CO2 recycling and compression includes the compression of separated CO2 and its mixing
with new/purchased CO2.

•

Long-term monitoring pertains to measures needed to ensure the injected CO2 remains
contained in the reservoir, with data collection being the main cost item.

Figure 2 • Core functional activities used in cost analysis

The “CO2 supply price”
For the purposes of this analysis we consider the costs of CO2 supply from the perspective of the
EOR operator. The cost of CO2 supplied for EOR is a key price signal for the oilfield owners’
decision making. In reality, price formation for CO2 supplied to EOR is complex. In this paper, thesupply price of CO2 simply means how much the field operator pays (or is paid) to acquire CO2.
The supply price is assumed for simplicity to be equal to the difference between the CO2 emission
penalty imposed by carbon policy (i.e. a carbon price) and the technical cost to the emitter of
capturing CO2. A positive CO2 supply price indicates that it cost more to capture CO2 than to pay
the emissions penalty imposed, in which case the CO2 emitter would sell CO2 to the EOR
operator, as is commonly the case today. In contrast, a negative supply price indicates that theemissions penalty is higher than the cost to capture CO2. This creates incentive for the emitter (or“capturer”) to pay for the CO2 to be verifiably stored, in this case by the operator of an EOR+
project, who will use it for EOR and ultimately store it in the oil reservoir.
The CO2 supply prices are derived from the global average CO2 emissions penalty in the ETP 2014
2 °C Scenario (2DS), 4 °C Scenario (4DS) and 6 °C Scenario (6DS). The average cost of capture isStoring CO2 through Enhanced Oil Recovery© OECD/IEA 2015

Combining EOR with CO2 storage (EOR+) for profit

assumed to be USD 40/tCO2 (in 2013 constant terms) for capture from anthropogenic sources. 6
The resulting CO2 supply price for the different scenarios is set out in Figure 3. As reflected in thisfigure, the resulting CO2 supply price trajectories vary significantly between ETP scenarios(Figure 3). Under the 6DS and 4DS, which have lesser climate mitigation ambitions, the priceremains positive; i.e. as is the case today, the EOR operator pays the supplier for acquisition of CO2.
In contrast, under the 2DS, where emissions are constrained to limit the long-term average Page | 21
temperature rise to 2 °C, CO2 supply price decreases steadily through to 2050 reaching
USD 125/tCO2 – i.e. the EOR operator would be paid by a supplier (e.g. industry) to store the CO2. 7
Figure 3 • Average CO2 supply prices under three scenarios
40

CO2 supply price, USD(2010)/tCO2

20
0
-20
-40

2DS

-60

4DS
6DS

-80
-100
-120
-140
2015

2020

2025

2030

2035

2040

2045

2050

The oil price received by EOR+ operators
Oil price trajectories are taken from the ETP 2014 2DS, 4DS, and 6DS. It is assumed that the EOR+
projects all receive the same price for their produced oil – that is there is no differentiation of
first purchase price on the basis of embedded upstream CO2 emissions. Figure 4 shows theassumed price trajectories.

NPV of the different EOR+ models
NPV is used to compare the economic attractiveness of the three different EOR+ projects
patterned on the models above. It is essential to recall that the NPV is based on not only an
estimation of the costs and revenues related to storing CO2, but also the costs and revenues
related to the oil production activities of the three EOR+ projects. The oil price and CO2 supply
price are based on the three ETP 2014 scenarios (Figures 3 and 4), while capital and non-CO2
operating costs are assumed to be constant across the three scenarios. NPV is calculated on thebasis of a 10% discount rate, but excludes taxes and royalties, as they vary widely among
jurisdictions. Following standard industry practice, the hypothetical projects are ended when
operating costs exceed revenues; this analysis does not consider abandonment costs.

6
The current actual cost of capture varies widely in different applications, from around USD 20/tCO2 for processes that
already generate concentrated CO2 (e.g. natural gas sweetening, ammonia, some biofuels) to as much as USD 70/tCO2 for
capture from combustion flue gas in a power plant. This analysis does not take into account any potential competition
between CO2 suppliers.
7
As mentioned earlier in Box 3, the definition of the supply price ignores any competing CO2 disposal options, which, inreality, would limit the decrease in CO2 supply price where they were available.

Storing CO2 through Enhanced Oil Recovery© OECD/IEA 2015

Combining EOR with CO2 storage (EOR+) for profit

Figure 4 • Oil price trajectories under three scenarios
160.0

140.0
130.0
6DS

120.0

2DS

110.0

4DS

100.0
90.0
80.0
2015

2020

2025

2030

2035

2040

2045

2050

Figure 5 sets out the results and illustrates both how each hypothetical EOR+ project compares tothe others under a particular ETP price scenario. The first observation is that Advanced EOR+ hasa higher NPV than both Conventional EOR+ and Maximum Storage EOR+ practices under all ETP
scenario price trajectories (Figure 5). The primary economic advantage of Advanced EOR+ over
the other practices results from increased oil recovery. This NPV advantage is most pronounced
in the 2DS where Advanced EOR+ increases the NPV by over 60% in relation to Conventional
EOR+. The NPV advantage of Advanced EOR+ relative to Maximum Storage is 30% to 40% in the
4DS and 6DS, but drops to less than 10% under the more aggressive carbon constraints of the 2DS.
Figure 5 • NPV of illustrative CO2-EOR project for different ETP scenarios and using different EOR
practices
2 000
Conventional
EOR+

1 600

USD milliion (2010)

Page | 22

USD (2013) per barrel

150.0

1 200

Advanced
EOR+

800
Maximum
Storage EOR+

400
0

2DS

4DS

6DS

Despite the dominance of Advanced EOR+ across all three scenarios, somewhat surprisingly, theNPV of Advanced EOR+ is smallest in the 4DS compared to both the 2DS (high climate ambition)and the 6DS (lowest climate ambition) cases. This is principally the result of CO2 being a cost to
the project (i.e. a positive supply price) in the 4DS but shifting to a revenue stream in the 2DS;
however, for Conventional EOR+, the changes in oil prices and CO2 supply cost between the 2DS
and 4DS offset one another. The increasing value of the oil recovered does not offset the increasein operating costs in Advanced EOR+ between the 2DS and 4DS, but does make a significant
impact between the 4DS and 6DS.
The results showing the comparative profitability of Advanced EOR+ remain robust against a
broad range of changes in the performance parameters (see Annex 1). There are several

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Combining EOR with CO2 storage (EOR+) for profit

additional salient observations which can be drawn from Figure 6, in which the factors
contributing to the different project NPVs are split out:•

Under the 2DS, increased oil recovery delivers three-quarters of the increased revenuesof Advanced EOR+ relative to Conventional EOR+, despite the operator being paid over
USD 100/tCO2 by the late 2030s. This reflects the fact that even though the 2DS delivers
on ambitious climate change mitigation targets, hydrocarbons are, nonetheless, still Page | 23
highly valued.

•

In addition, the increased costs associated with Advanced EOR+ relative to Conventional
EOR+ are almost fully covered by revenues from CO2 storage – making the increase in oilrevenue effectively free.

•Moving from Advanced EOR+ to Maximum Storage there is no increase in oil production,leaving only revenue from CO2 storage to defray the added costs of increased CO2
injection. Even under the 2DS, the revenue from CO2 storage is insufficient to fully cover
the costs of increased injection.

Figure 6 • Factors contributing to the different NPV results for each CO2-EOR practice under the 2DS
2 000
1 800

Oil
revenue

USD million (2010)

1 600

CAPEX

1 400

OPEX

CO2
revenue

1 200

Other
annualised
costs
CO2
revenue

1 000
800

Other
annualised
costs

CAPEX

600
400
200
0

OPEX
Conventional
EOR+

Advanced
EOR+

Maximum
Storage EOR+

Notes: Other annualised costs include changes to produced water management and CO2 storage monitoring costs. CAPEX = capital
expenditures; OPEX = operational expenditures.

The largest contribution to uncertainty in the NPV for all three EOR practices under the 2DS is theinjection rate per well, and hence the number of new wells required in the hypothetical project(see the technical appendix for further detail). This is followed by the incremental oil recovery
and parameters affecting the oil production profile – namely the time to plateau and decline
rate. Nonetheless, Advanced EOR+ is more attractive than Conventional EOR+ across a wide
range of parameter values under 2DS price trajectories.

Price drivers for Conventional, Advanced and Maximum Storage EOR+In addition to analysing the NPV under the ETP price scenarios for CO2 supply and oil prices,
Figure 7 shows the preferred (i.e. highest NPV) scenario for a wide range of CO2 supply and oil
prices. One of the central insights from this illustrative analysis is that Advanced EOR+ practices
are more attractive than Conventional EOR+ practices not only at lower (and negative) CO2 supply
prices, but also at higher oil prices. The reason for this result is that, as noted above, we assume
additional injection (and related additional storage) allows for increased oil production.

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Combining EOR with CO2 storage (EOR+) for profit

Since Advanced EOR+ and Maximum Storage show the same dependency on oil price, the CO2
supply price alone determines their relative economic attractiveness. Assuming that the oil andCO2 supply prices are fixed over the lifetime of the project, the area in which the NPV of
Advanced EOR+ is higher than that for Maximum Storage is separated by a straight horizontal line
in Figure 7. Average supply prices above USD 50/tCO2 are required for Maximum Storage toPage | 24 become economically attractive, which are only achieved in the 2DS from about 2030 onward.
Figure 7 • Illustrative oil and CO2 price impact on choice of EOR+ practices in different scenarios

CO2 supply price, USD(2010)/tCO2

40
20

50

70

USD(2010) per barrel
90
110

2015

2DS
2020

0

4DS
2020

130
6DS
2020
4DS
2040

150
6DS
2030

6DS
2040

Conventional
EOR+

- 20
- 40

2DS
2030

- 60
- 80
- 100

2DS
2040

Advanced EOR+

Maximum
Storage EOR+

- 120

Note: It is assumed that regulation or other climate policies exclude the possibility of undertaking EOR without the additional
monitoring and verification practices designed to permit CO2 storage tracking for mitigation purposes (i.e. all EOR is “EOR+”).

In summary, the results presented here illustrate that the oil price, rather than the CO2 supply
price, is the bigger determinant of the economic attractiveness in choosing between different
EOR+ practices. The results also indicate that increasing utilisation rate of CO2 above that
required to increase oil recovery is only economically favourable at highly negative supply prices(i.e. above around USD 60/tCO2, i.e. the EOR operator needs to receive significant compensation
for storing CO2). Together, these factors explain why Advanced EOR+ is the NPV maximising
choice under all three price trajectories considered. These findings are consistent with thosefrom previous work by Leach et al. (2011), in which the authors concluded that CO2 use in EOR
projects is relatively insensitive to changes in CO2 prices, but very sensitive to oil prices.
The above results also suggest that at higher oil prices, and assuming relatively modest CO2
supply prices, it would be beneficial to inject more CO2 and extract more oil than historically has
been the case, regardless of the storage benefits. This finding, of course, hinges on theassumption that the marginal recovery rate from injecting an additional barrel of oil is positive –as is assumed in the Conventional EOR+ case. 8
The economic attractiveness of EOR+ illustrated by this analysis, and in particular Advanced
EOR+, mean that CO2-EOR could indeed be an important means of storing CO2. However, theseresults also beg the question of why more CO2-EOR projects are not being implemented globally.
The following sections examine the technical potential for CO2-EOR and the emissions reduction
benefit that might come from CO2-EOR.

8
There is some evidence to support this, as more recently reported utilisation rates are higher than those reported based on
1970s and 1980s practice (Azzolina et al., 2015; Murrell and DiPietro, 2013; DNR, 2014).

© OECD/IEA 2015

Storing CO2 through Enhanced Oil Recovery

Combining EOR with CO2 storage (EOR+) for profit

The global technical potential for EOR+ for CO2
storage and oil production is large
Key points
At the global level, a substantial opportunity for CO2 storage through EOR+ exists,
ranging from 60 GtCO2 to 360 GtCO2 globally in the next 50 years. This level ranges from
50% to more than three times the amount of total CO2 storage required under the IEA
2DS scenario through 2050.
In addition to storing more CO2, Advanced EOR+ could potentially increase oil
production as compared to conventional EOR+ (which uses less CO2) over the next 50
years by up to 375 billion barrels.
While the overall potential to store CO2 via EOR+ is indeed very significant, thisopportunity is not evenly distributed in the world. Middle East, Russia, North Africa andCentral Asia account for about 90% of the global technical potential outside the United
Sates as measured by either oil production or CO2 storage.
To analyse how much CO2 could be stored and how much oil could be produced using EOR+
globally, a field-by-field evaluation of suitability and capacity has been undertaken, using a rich
oil industry dataset. The dataset has been screened applying the CO2 utilisation rates and oil
recovery factors assumed in the three practices presented in the previous section (see Table 1),
effectively creating three scenarios.
It is stressed that this analysis remains on the technical level, i.e. trying to shed light as to how large
the physical opportunity would be around the world. Economic considerations (such as thoseoutlined in the illustrative case study in the previous section) were not part of the screening
process. Thus, the results provide information on the technical potential associated with each typeof EOR+ scenario, which can be viewed as an upper limit to the amount of oil that could berecovered and CO2 stored based on the best available data in 2012. The actual potential that might
be implemented will depend on various other considerations, primarily economic and political.
Table 1, presented earlier, summarises the assumptions for each of the three scenarios, all ofwhich cover only miscible CO2 flooding. As discussed earlier, immiscible flooding is generally lessefficient at recovering oil than miscible CO2-EOR and as a result, this analysis does not include
immiscible flooding. The criteria are used to screen the UCube 9 global upstream database to
identify fields amenable to CO2-EOR flooding. Ultimately, this makes it possible quantify the
global volumes of oil that can be recovered and of CO2 that can be stored for each of these CO2EOR practices.
The screening process for this analysis included all fields that are currently producing, abandonedor planned to start production before 2025. It assumes oil recovery factors and storage volumes
achievable with technologies known today, but it must be noted that the equations will change
9

UCube, compiled by Rystad Energy, is a field-level database with global coverage, containing information on around 65 000
oil and gas fields, as well as licenses and portfolios of 3 200 companies. Assets are characterised by parameters pertaining tolocation, hydrocarbon flow properties (e.g. density, viscosity, composition), geophysical field characteristics (e.g. pressure,porosity, permeability), and the state of production. The data in UCube originate from primary sources such as company andgovernment reports. Where detailed information is not available, completeness of the database is ensured through estimatesor modelling. The modelling is used to forecast future production from fields and to estimate yet-to-find volumes in licenses.

Page | 25

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Combining EOR with CO2 storage (EOR+) for profit

as technology advances. Additionally, the emergence of policies constraining CO2 emissions could
trigger important changes for the economics of CO2-EOR and storage operations, having impacts
on both CO2-EOR technology and practice.
Recognising that the design and operation of a CO2-EOR project can be optimised for a wide
range of conditions, it is necessary to make certain assumptions about how oil recovery
Page | 26 operations might be conducted. Because this study is interested in the potential for CO2 storage,
this assessment is based on three different scenarios that represent different points on thedesign and operational spectrum, which each imply different levels of CO2 consumption.

The aggregate technical potential for storage and oil recovery
There is a substantial opportunity for CO2 storage through EOR+. The technical potential ofConventional EOR+ practices to store CO2 amounts to about 60 GtCO2 globally over the next
50 years (Figure 8), representing more than half of the total CO2 storage needed to keep theworld on the IEA 2DS trajectory. Advanced EOR+ delivers a technical potential of 240 GtCO2,
which exceeds the IEA 2DS requirement for CO2 storage. Maximum Storage totals 360 GtCO2.
These figures do not account for the potential additional miscible CO2-EOR, which might add afurther storage potential of 30 GtCO2.
Figure 8 • Global storage potential for different CO2-EOR practices (GtCO2)
400

Billion tonnes of CO2

350
300
250
200
150
100
50
0

Conventional EOR+

Advanced EOR+

Maximum Storage EOR+

2DS cumulative storage(2015-50)

The corollary to increased CO2 storage is increased oil production. Where the CO2 storage
potential is large, a similarly substantial opportunity exists in terms of the potential of EOR to
produce additional oil. From a technical standpoint, Conventional EOR+ practices could deliver
about 187 billion barrels (Bbbl) of additional oil. Widespread application of the practices impliedin the Advanced EOR+ or Maximum Storage scenarios could increase global oil production overthe next 50 years by up to 375 Bbbl (Figure 9), i.e. corresponding to over ten times the current
yearly oil consumption. As is expected from the scenario specification, CO2-EOR practices aimed
at achieving Maximum Storage do not further increase oil recovery over the Advanced EOR+
option; they do, however, change estimates for CO2 stored. The incremental production resulting
from immiscible CO2-EOR is small at 56 Bbbl over the next 50 years, but if applied could increase
the incremental production up to a total of 431 Bbbl.
Roughly three-quarters of the potential additional oil is likely to be from onshore fields, and theremaining quarter from offshore. It should be emphasised that these estimates are purely basedon technical considerations, and that the actual amount of CO2 stored and oil recovered will likely
be less. Factors that will influence the uptake of CO2-EOR practices include the availability andStoring CO2 through Enhanced Oil Recovery© OECD/IEA 2015

Combining EOR with CO2 storage (EOR+) for profit

price of anthropogenic CO2, oil prices, the cost of applying CO2-EOR in various particular
circumstances, and government policies. Significant differences exist in how this global potential
is distributed geographically.
Figure 9 • Global incremental oil production potential for various CO2-EOR practices
Page | 27

1 400
1 200

Billion barrels

1 000
800
600
400
200
0

Conventional EOR+

Advanced EOR+

Maximum Storage

2DS cumulative demand(2015-50)

4DS cumulative demand(2015-50)

Geographic distribution of technical potential
The opportunity to store CO2 and produce oil through CO2-EOR is not evenly distributed aroundthe world. With geological conditions being so vital to CO2-EOR and CO2 storage, some regions
are simply better endowed with resources than others. In fact, excluding North America, just four
regions account for about 90% of the global technical potential measured by either oil production
or CO2 storage under the Maximum Storage scenario, as outlined below (Figure 10).
•

With over 70 GtCO2, Russia has the largest technical potential, with most of this inWestern Siberia (e.g. Khanty-Mansi) followed by southern Russia.

•

In the Middle East region, Saudi Arabia, the United Arab Emirates, Iraq and Iran eachhave 25 GtCO2 to 30 GtCO2 technical potential. The total technical capacity to store CO2
via EOR in the Middle East could amount to more than 100 GtCO2.

•

Significant potential also exists in North Africa, with Libya (24 GtCO2) and Algeria(8 GtCO2) being the main players.

•

In the Central Asia, the greatest potential is found in Kazakhstan (9 GtCO2) andAzerbaijan (9 GtCO2).

Outside these four regions, this analysis finds about 10 GtCO2 of technical potential in North
America under the Maximum Storage scenario. However, several studies indicate that thepotential in North America may be of the same order as that of countries in the Middle East. 10

10While 10 GtCO2 corresponds to nearly 20 times the estimated amount of CO2 stored in all North American CO2-EOR
operations to date (Hill et al., 2013), it is a much smaller potential than estimated in US-focused studies. For example, themost recent assessment by Advanced Resources International (ARI) for the US National Energy Technology Laboratory
concludes that, depending on the scenario, between 62 and 119 Bbbl are technically recoverable from conventional reservoirs
in the United states, while at the same time storing between 25 and 38 GtCO2 (NETL, 2011). This is similar to a US estimate of
60 Bbbl and 17 GtCO2 in a global assessment by ARI and Melzer Consulting (2009) for IEAGHG. Hence, these studies indicatethat the potential in North America is of the same order of magnitude as that of the top countries in the Middle East. The
discrepancy between this study and past US-focused studies is the result of relatively poor data coverage for US assets in theunderlying database, and does not stem from a difference in views of the underlying geological potential.

Storing CO2 through Enhanced Oil Recovery© OECD/IEA 2015

Combining EOR with CO2 storage (EOR+) for profit

It is noteworthy that while the above four regions show the most significant potential, the only
CO2-EOR project being implemented in the four regions is Saudi Aramco’s Uthmaniyah CO2-EOR
demonstration project in Saudi Arabia, scheduled to start operation in 2015 (see Box 2).
Global incremental oil production potential under Conventional EOR+ is 187 Bbbl. It almost
doubles in the Advanced EOR+ and Maximum Storage scenarios to about 375 Bbbl, with 70% ofPage | 28 this potential coming from onshore fields The same four regions – the Middle East, Russia, North
Africa and Central Asia – account jointly for about 75% of the technical CO2-EOR potential forincremental onshore production.
Figure 10 • Storage potential in the top four regions
Middle East

RussiaSaudi Arabia

Western Siberia

IranSouth Russia

Iraq
UAE

Arctic Russia

Qatar

Barents Sea

Yemen

Far East Russia

Oman

Eastern Siberia

Syria
10

0

20

30

0

40

North Africa

20

40

60

Central Asia

Libya

Kazakhstan

Algeria

Azerbaijan

Egypt

Turkmenistan

Tunisia

Uzbekistan

Sudan

Georgia

Morocco
0

5

10

15

20

0

25

Conventional EOR+

2

4

6

8

10

GtCO2

GtCO2

Advanced EOR+

Maximum Storage

Understanding the global and regional technical potential for CO2-EOR to boost incremental oil
production or support CO2 storage gives indication of where more detailed analysis would be
useful. However, technical potential is ultimately insufficient for assessing whether the scope of
CO2-EOR as a CO2 emission mitigation option is attractive as a new line of business for the oil
industry. For this, it is imperative to calculate the cost and benefits of the technology andevaluate the availability and cost of CO2 for injection. Providing robust answers would require
geographically detailed studies on the potential to match existing and future CO2 sources toavailable reservoirs in relevant regions (e.g. Ambrose et al., 2009), which is beyond the scope of
this analysis but warrants further investigation.

© OECD/IEA 2015

Storing CO2 through Enhanced Oil Recovery

Combining EOR with CO2 storage (EOR+) for profit

Impact of widespread EOR+ on oil markets andglobal CO2 emissions
Key points
CO2-EOR results in storage of CO2. However, CO2-EOR also produces oil, the majority ofwhich is burnt as fuel, generating CO2 emissions. This will temper the net emission
reductions achieved.
Understanding the net CO2 emissions benefit of EOR on both project level and globally is
a complex task. It requires thorough analysis and clear decisions regarding the included
elements (“project boundaries”).
The previous sections have highlighted the economic benefits of CO2-EOR as an emissions
reduction tool. While it is clear that CO2-EOR can be an economic means of storing CO2 (andproducing oil), the emissions reduction benefit of CO2-EOR is tempered by the production of
additional fossil fuels, from which the majority of the carbon is inevitably emitted back to theatmosphere. From this perspective, storing captured CO2 in a saline aquifer is, ceteris paribus, amore effective means of reducing emissions to the atmosphere. The following sections illuminate
some of the key factors in assessing net CO2 emissions for CO2-EOR through a quantitative, lifecycle assessment of emissions for the models described earlier. While the high-level conclusions
are informative, further analysis is required taking into account the varying underpinningassumptions. Hence specific results will vary from project-to-project.

Accounting for carbon at the project level
Each tonne of CO2 delivered to a CO2-EOR project is injected into the oil reservoir where, as
described earlier, it mixes with the oil present in the reservoir making it easier to recover. The
injection rates of CO2 (and water) and production rates of fluids (oil, water and CO2) are managed
to maintain a constant pressure – ideally just above the MMP. Thus, for each barrel of oil
produced, an equivalent volume of CO2 and water (in WAG operations) remains in the reservoir;
however, because some of the injected CO2 mixes with the produced oil or bypasses oil in thereservoir, only a fraction of the CO2 injected in one cycle is stored. That which is not stored isseparated from the produced fluids and recycled to be injected once again.
Hence, over the life of a project each tonne of CO2 delivered to the project is stored in thereservoir. Thus, in the three EOR+ models described here – namely Conventional EOR+, Advanced
EOR+ and Maximum Storage EOR+ – the amount of CO2 stored is approximately equal to their
net utilisation of CO2 (Table 2).
At the project level, the amount of CO2 stored is offset by emissions from the project both
directly (i.e. fuel combustion, flaring, venting, and fugitive emissions) and indirectly due to theelectricity used by the project. In the case of CO2-EOR, the energy requirements – and hence
indirect emissions – can be substantial because due to CO2 recycling and, should it be required,processing of the recycle gas to separate natural gas liquids (NGL's) (Cooney et al., 2015). For atypical US project with NGL separation, Cooney et al. (2015) estimate emissions of 91 to
165 kilogrammes (kg) CO2-eq per barrel of produced crude; without NGL separation, emissions
would be approximately one-third lower.

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Combining EOR with CO2 storage (EOR+) for profit

Table 2 shows the emissions associated with each of the three practices for an example EOR
project on the basis of both one barrel of produced oil and one tonne of CO2 delivered to theproject. 11 These figures show that net utilisation is a key factor in determining the emissions from
CO2-EOR projects and that, for the practices considered here, project-level emissions are negative
where the CO2 comes from an anthropogenic source – and ignoring any emissions that may be
12Page | 30 associated with capture and transport of this CO2. Of course, when CO2 is supplied to theproject from natural sources, no emissions reduction benefit can accrue to the project.
Table 2 • Illustrative project-level carbon balance of three EOR+ practices
Scenario

Conventional EOR+

Advanced EOR+

Maximum Storage EOR+

0.3

0.6

0.9

Net utilisation (tCO2/bbl)
Functional unit

1 tCO2delivered
0.98

1 bbl
produced
0.29

1 tCO2delivered
0.98

1 bbl
produced
0.59

1 tCO2delivered
0.98

1 bbl
produced
0.88

Recycle losses (tCO2)

0.01

0.00

0.01

0.01

0.01

0.01

Storage (tCO2)

0.99

0.30

0.99

0.59

0.99

0.89

Emissions (tCO2-eq)

0.23

0.07

0.16

0.09

0.13

0.12

Net emissions (tCO2-eq)

-0.76

-0.23

-0.83

-0.50

-0.86

-0.77

Recycle (tCO2)

Expanding the boundaries: Emissions from consumption of oil
Each barrel of oil produced from a CO2-EOR project will be sold into the market, transported to arefinery where it is refined into a range of products, predominantly fuels, which are ultimately
burnt to provide energy. The emissions associated with these steps vary with the quality of thecrude oil, the relative location of production and consumption, and the slate of products intowith the crude oil is converted (Gordon et al., 2015). The combustion of fuels produced from one
barrel of conventional crude oil results in approximately 430 kg CO2-eq of greenhouse gas
emissions (EPA, 2014; Gordon et al., 2015). Transport and processing of conventional crude oil toproduce these fuels increases emissions by slightly less than 10%, bringing the total emissions toaround 470 kgCO2-eq per barrel (Gordon et al., 2015).
Table 3 shows that when the downstream emissions from combustion of petroleum products areincluded (assuming that all EOR+ production represents additional oil consumption),
Conventional EOR+ practices result in emissions of CO2. However, even in this analysis in which
no displacement of oil production is assumed (see next section), Advanced EOR+ and Maximum
Storage EOR+ cases generate emissions reductions (albeit small in the former case) because of
the increased amount of CO2 stored per barrel of oil produced. These results are consistent withthose presented by recent studies (e.g. Jaramillo et al., 2009; Wong et al., 2013).

11

Underlying assumptions: CO2 retention (as defined by Azzolina et al., 2015) of 0.5 for all of the operational cases; recycle
losses of 1% of the CO2 produced; recycle electrical energy requirements of 120 kWh/tCO2 recycled; grid electricity emissions
intensity of 611 kgCO2/MWh (Cooney et al., 2015); flaring, venting, and fugitive emissions of 44 kgCO2-eq/bbl, which is theaverage of upstream emissions for “conventional” crudes reported by Gordon et al. (2015). The electricity consumption
assumed here is consistent with a project without NGL separation (Cooney et al. 2015).
12
Expanding the boundaries to include CO2 capture in the assessment requires judgement to be made about allocation of theemissions between a product such as electricity and the captured CO2, greatly increasing the complexity of the analysis. See
Jaramillo et al. (2009) or Cooney et al. (2015) for assessments of CO2-EOR including both emissions associated with CO2 supply
and use of oil products.

Storing CO2 through Enhanced Oil Recovery© OECD/IEA 2015

Combining EOR with CO2 storage (EOR+) for profit

Table 3 • Illustrative carbon balance of three EOR+ practices including combustion of the produced oil
Scenario
Functional unit
Downstream emissions
from oil use (tCO2-eq)
Emissions (tCO2-eq)
Net emissions (tCO2-eq)

Conventional EOR+

Advanced EOR+

Maximum Storage EOR+

1 tCO2delivered

1 bbl
produced

1 tCO2delivered

1 bbl
produced

1 tCO2delivered

1 bbl
produced

1.56

0.47

0.78

0.47

0.52

0.47

1.79

0.54

0.93

0.56

0.65

0.58

0.80

0.24

-0.06

-0.03

-0.34

-0.31

Displacement of oil in global markets: The response of oil
markets to EOR+
The results shown in Table 3 above do not include the impacts of displacement i.e. oil produced
from EOR+ could displace oil that might otherwise have been produced elsewhere. In such acase, the reduction in consumption of a higher carbon intensity crude results in an emissions
reduction.
In order for CO2-EOR to be attractive, a barrel recovered through use of CO2-EOR must have alower cost than that produced from competing options (e.g. unconventional resources, deep
water). Thus, oil brought to market through the application of CO2-EOR will have lower supply
cost than the marginal barrel. Without a corresponding change in oil demand, this would lead toa reduction in oil prices; however, the response of consumers will be to consume more oil,leading to the establishment of a new equilibrium in the market (Figure 11). EOR practices
effectively shift the oil supply cost curve towards to the left: the oil price at which demand andsupply are balanced drops from P0 to P1, and oil consumption at the lower price increases by ΔQ,
clearing the additional available supply. The critical questions are: (1) how much oil production isdisplaced by CO2-EOR; (2) how much additional production reusults from CO2 EOR; and, (3) whatis the resulting net impact on CO2 emissions.
Figure 11 • Impact of Advanced EOR+ on oil demand

To provide some insights into the first and second questions, we constructed global oil supply
curves that incorporate the three CO2-EOR scenarios. These oil supply curves build on country-level
data for resources and costs of the three CO2-EOR oil production scenarios, as well as resourceand economic data for other conventional and unconventional oil categories. They are based on
the commercially available Rystad UCube database, which was the basis for the assessment ofPage | 31

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Combining EOR with CO2 storage (EOR+) for profit

technical potential presented earlier. The resulting global oil supply cost curves were used todetermine a least-cost solution to meet specified oil demand over the time horizon 2013-50.
In this assessment, oil supply is assumed to have to meet annual oil demand as specified in the
6DS for the time period up to 2050. The response of oil demand to price variation is captured
such that price signals affect demand more strongly in the long term than in the short term.
Page | 32 Correspondingly, oil price elasticity of demand increases in absolute value from 0.1 in the shortterm to 0.2 in the long term.
Modelling results for the incremental cumulative oil production obtained with the three CO2-EOR
practices show that Conventional EOR+ could contribute more than 6% of total oil production to2050 whereas Advanced EOR+ could contribute up to 10% (Figure 12). However, because of its
relatively higher cost, Maximum Storage EOR+ contributes only 9% – i.e. less than Advanced
EOR+. Under the above analysis, some 20% of the cumulative oil production realised via
Conventional EOR+ and Advanced EOR+ would be additional production; the vast majority (80%)
would effectively substitute other oil production, which would be displaced from the market.
Figure 12 • Cumulative incremental CO2-EOR oil production, 2013-50
12%

180
160

10%

140

billion barrels

120

8%

100

6%

80
60

EOR
substitution
other oil

4%

40

2%

20
0

EOR
inreased oil
demandConventional EOR+

Advanced EOR+

Maximum Storage EOR+

0%

Share of EOR
in cumulative
oil production

Estimating the CO2 emissions savings from the displaced oil is challenging, as it requires
knowledge of the emissions associated with its production, transportation, refining, andultimately use (i.e. combustion) of the refined products. The emissions profile – that is the“well-to-wheel” emissions per barrel – of oil from different sources varies far more than has been
assumed in the past. Gordon et al. (2015) recently examined the emissions of 30 different typesof crude oil, finding that their associated emissions range from 450 kgCO2-eq/bbl to820 kgCO2-eq/bbl. The model used in Figure 12 does not have sufficient resolution to capture thisvariability; hence, we assume a comparable 13 oil is displaced, and then consider the impacts ofdisplacement of higher and lower carbon intensity oils.
The impact of displacement on the economy-wide emission from undertaking EOR+ are provided
in Table 4. 14 This table shows that when displacement is considered, even Conventional EOR+ can
generate an emissions reduction benefit when displacing low CO2-intensity oil. This emissions
reduction benefit of CO2-EOR persists until the rate of displacement reaches 0.5 (i.e. 1 barrel of oil
13“Conventional” crude oil as in Gordon et al., 2015.
We assume the baseline against which we are making a comparison is one in which the equivalent amount of displaced oil
is being produced from either a low or high intensity source, and the CO2 that would otherwise be used in EOR is being stored
in a saline aquifer. If we were to assume the CO2 was emitted in the absence of CO2-EOR, the benefit accruing to CO2-EOR
would be larger than estimated in Table 4.
14

Storing CO2 through Enhanced Oil Recovery© OECD/IEA 2015

Combining EOR with CO2 storage (EOR+) for profit

from Conventional EOR+ displaces half a barrel of low-CO2 intensity oil). The emissions reduction
benefit of Advanced EOR+ and Maximum Storage EOR+ are relatively large because they result inemissions reductions without considering the benefits of displacement, as shown in Table 3.
Table 4 • Illustrative CO2 emissions resulting from three EOR+ practices including combustion of the
produced oil and price effects in global oil markets
Scenario
Functional unit
Additional emissions
from EOR+ (tCO2-eq)
Displaced emissions fromother oil (tCO2-eq)
Net emissions (tCO2-eq)

Conventional EOR+

Advanced EOR+

Maximum Storage EOR+

1 tCO2delivered

1 bbl
produced

1 tCO2delivered

1 bbl
produced

1 tCO2delivered1bbl
produced

0.13

0.04

-0.01

-0.01

-0.07

-0.06

-0.76

-0.23

-0.72

-0.43

-0.72

-0.65

-0.63

-0.19

-0.73

-0.44

-0.79

-0.71

Varying the life-cycle emissions intensity of the displaced oil has a significant impact on theestimate of the emissions reductions that accrue from EOR+ activities. In a case where an oil withthe lowest emissions intensity reported by Gordon et al. (2015) is displaced, the emissions
reduction benefit of Conventional EOR+ is reduced to -0.47 tCO2/tCO2 delivered; however, in thecase where the highest emissions intensity oil is displaced, the benefit of Conventional EOR+
increases to -1.50 tCO2/tCO2 delivered. The variation in the emissions reduction benefit withdisplaced oil intensity is smaller for the Advanced EOR+ and Maximum Storage EOR+ cases
because they are less efficient from an oil production perspective – i.e. they have larger net
utilisation of CO2.
As demonstrated throughout this section, understanding the net CO2 emissions benefit of EOR on
both project level and globally is a complex task. It requires thorough analysis and clear decisions
regarding the included elements (“project boundaries”). However, the above results clearly showthat EOR+ can generate an emissions reduction benefit.

Page | 33

Storing CO2 through Enhanced Oil Recovery
Combining EOR with CO2 storage (EOR+) for profit© OECD/IEA 2015

Overcoming barriers to EOR+
Key points
CO2-EOR is currently not widely used for storage, as there is no business case forstorage. In absence of a significant carbon price, a business case could, however, becreated through relevant incentive policy frameworks in the short term.

Page | 34

Policies to ensure the permanent retention of CO2 underground and the long-termmonitoring and stewardship must also be implemented.
Despite the large technical potential of CO2-EOR, today it only contributes about 0.35% of global
oil production, mainly from a growing number of US projects. Thus, it is not clear that CO2-EOR is
attractive for oil production outside the United States and, it is safe to say that, unless it becomes
attractive, little CO2 will be stored through CO2-EOR. This is of particular significance because, as
the US experience demonstrates, CO2-EOR can make early, large-scale capture projects viable,
which contributes to reductions in capture costs and benefits CCS in the longer term. Thus,
governments that want to see and harness the potential of EOR+ must, in the first instance,
understand how to drive wider use of CO2-EOR.
If CO2-EOR is an attractive proposition in itself, requirements for storage-focused activities arethen worth considering. Today, CO2-EOR projects do not undertake such activities, because there
is generally no driver to do so. This means that governments need also to establish a framework
to promote effective CO2 storage through CO2-EOR, i.e. EOR+. Once EOR+ is being employed as astorage option, increases in consumption of CO2 at the project level can improve the potential for
CO2-EOR to contribute to emissions reductions.
There are three types of barriers facing greater EOR+:•

expanding the use of EOR in the first place•

subsequently incentivising the adoption of business practices to “store” CO2 consistent
with the requirements of the climate change mitigation objectives•

injecting more CO2 as part of the EOR extraction process.

The following sections examine these issues and discuss potential policies that governments
could explore further.

Barriers to wider use of CO2-EOR
While there is no definitive history of CO2-EOR that explores the combination of factors that led
to the genesis of CO2-EOR in the United States, it is safe to say that these factors have not
combined in a way to drive CO2-EOR development elsewhere. What is clear, however, is that
US research and development into CO2-EOR, beginning in the 1950s, and the subsequent growthof the industry starting in 1970s, was largely undertaken by commercial entities. These
companies were seeking to bolster declining reserves in what were, even then, mature fields in
the Permian basin.
Today, as in the past, the fundamental driver for CO2-EOR clearly remains increasing oil recovery
from mature assets. The historical development of CO2-EOR shows that it can be a profitable
activity at oil prices in the range of USD 40/bbl (in 2015 real dollars) and the growing number of© OECD/IEA 2015

Storing CO2 through Enhanced Oil Recovery

Combining EOR with CO2 storage (EOR+) for profit

projects today shows that it remains an attractive investment option. There appear, however, tobe several reasons why the flow of investment into CO2-EOR projects is not larger:
1. CO2-EOR requires a large capital investment late in the life of a field.
2. While CO2-EOR increases recovery from a field, the increase is captured over a long
period of time and, thus, its NPV is diminished.
Page | 35
3. While CO2-EOR technology is well understood, in principle, its application is reservoir
specific and requires field pilot tests to optimise.
The first factor may further be amplified when offshore cases are considered, as modifications to
production platforms can often be very costly and are difficult to undertake while in service.
Combined, these factors mean that, while an operator may expect a CO2-EOR project to be
profitable, it may not be an attractive investment in comparison to other options in a portfolio(ARI, 2011; IEA, 2012a). In addition, lack of CO2 transport infrastructure may prove a hurdle forstarting or expanding CO2-EOR operation.
Fundamentally, governments have two options to boost the attractiveness of CO2-EOR: provide
incentives for CO2-EOR developments, or implement policies that make competing investment
options less attractive. Practically, the first option – that is, providing incentives – may be more
attractive option than the latter. However, it is important to recognise that climate policy could
accomplish the second option, as it would likely shift oil and gas investment towards projects
with lower upstream emissions. Thus, even without considering the impacts of climate policy on
availability and price of CO2 for use in EOR, CO2-EOR could stand to benefit from climate policy.
The optimal policy to encourage CO2-EOR is likely to be a combination of the two options.
Most commonly, incentives for oil and gas production take the form of reductions in thegovernment take for specified activities. 15 The net impact of such incentives would be to increase
the after-tax present value of project revenues. An option with a similar impact is the provision of
production tax credits. Either of these options could be tied to requirements for storage-focused
activities.
Another approach could be to provide investment tax credits that offset the capital expenditures
required for CO2-EOR projects. As with reductions in government take or production tax credits,they can also be linked to requirements for storage-focused activities. Investment tax credits
could also be used specifically to support pilot projects where the level of risk is relatively high,and the production potential small. Of course, when designing any incentive scheme it isimportant to carefully craft project eligibility criteria, regularly review the scheme to ensure it
remains fit for purpose, and clearly identify limits to the scheme after which it will no longer apply.
In addition to these three factors, relatively limited access to suitable supplies of CO2 presents a
substantial barrier to further CO2-EOR (ARI, 2011). This issue particularly an issue in the regionswith large technical potential identified here. Even in the US, this has been highlighted as abarrier to more rapid expansion of CO2 (e.g. NETL, 2011; NEORI, 2012) – although, in this case, it
might be more precise to say that the current supply of CO2 matches the price that CO2-EOR
operators are willing to pay.
Increasing the supply of CO2 for EOR can be facilitated by support for CO2 capture fromanthropogenic sources, as well as policies to encourage development of pipeline infrastructure.
Support mechanisms for CO2 capture should be tailored to the stage of technology development,

15
For example, the US Federal Government has provided tax incentives for CO2-EOR operators; see, for example,
Dooley et. al., 2010.

Storing CO2 through Enhanced Oil Recovery
Combining EOR with CO2 storage (EOR+) for profit© OECD/IEA 2015

and placed in an adaptive framework so that, over time the incentives remain fit for purpose(IEA, 2012b).
It is critical to recognise that not all capture technologies are at the same stage of development in
all applications: for example, some of the original CO2 sources for EOR projects in the
United States were from gas processing, whereas only in 2014 did the first power plant equipped
Page | 36 with capture come on line. For capture from power generation, the initial technology
development objectives call for economic instruments specifically designed to provide support
for learning and early deployment (IEA, 2012b). Capital subsidies, loan guarantees and operating
subsidies are examples of instruments known to effective at this stage that can be geared
towards funding new capture projects.

Framework to ensure effective storage of CO2 through EOR
Laws and regulations are needed to encourage the safe and effective design and operation of CO2
storage options. For CO2 stored through EOR to qualify as “not emitted” – and thus gain thebenefits of climate policy – the operator must comply with regulations to ensure that the CO2 isretained in the reservoir. Similarly, regulations to ensure CO2 storage is undertaken in a way that
protects human health and the environment should apply equally to CO2-EOR.
As noted earlier, to qualify as CO2 storage, operators will have to adjust the design andoperations of a CO2-EOR project before, during and following CO2-injection:•

Additional site characterisation to collect information on overlying cap-rock andgeological formations, as well as abandoned wellbores, to assess the potential forleakage 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 sothey can withstand the corrosive effects of CO2-water mixtures.
This being said, however, few regulatory frameworks have been developed that explicitly
recognise the important differences between storage through CO2-EOR and in other geologicalreservoirs. These differences are both positive, such as a reduction the area of elevated pressure
and the presence of a demonstrated seal, and negative, as the seal may have geo-mechanicaldamage and there are many existing wellbores (Hill et al., 2013).
•

At a minimum, regulations applied to CO2-EOR should ensure that:•

CO2-EOR operators undertake the necessary up-front site characterisation, modelling,
and risk assessment to satisfy regulatory authorities that the storage project (i.e. thereservoir and wells) will effectively retain stored CO2.

•

Emissions from surface equipment, in particular venting and fugitive emissions, aremonitored, measured, and reported to ensure that the amount of CO2 stored can be
accurately calculated.

•

Monitoring and enhanced field surveillance are undertaken to: assess whether the
reservoir behaves as anticipated and allow risk assessments to be updated; and, identify
and, if necessary, estimate leakage rates from the site to the atmosphere.

© OECD/IEA 2015

Storing CO2 through Enhanced Oil Recovery

Combining EOR with CO2 storage (EOR+) for profit•

Site closure practices support long-term containment of injected CO2, in particular, thoserelating to plugging and abandonment of wells so they can withstand the corrosive
effects of CO2-water mixtures over the long term.

•Long-term monitoring and stewardship are carried out according to the relevant body oflaws and regulations.

•

In addition, governments should establish the relevant processes by which a CO2-EOR
project can transition into a pure storage project upon depletion of the reservoir. For
example, the US Environmental Protection Agency (EPA) has recently issued draft
guidance on the transition of a well permitted for use in CO2-EOR (i.e. Class II) to wellpermit for geologic CO2-storage (i.e. Class VI) (EPA, 2013).

It is also important to recognise that these storage-focused activities may depend on relatively
new technologies and are not commonly undertaken. For example, while CO2-EOR projects in the
United States have created ample experience with CO2 transport and injection, experience withdecommissioning is lacking. Thus, funding research and development, as well as field trials forthese technologies and activities is an appropriate government intervention. Such funding should
support dedicated testing to de-risk and build experience with novel approaches to modelling
and risk assessment, fugitive emissions monitoring technologies, subsurface monitoring and fieldsurveillance, and field decommissioning and closure for long-term storage. Funding in these areas
could have benefits for all types of geologic storage.
Box 4 • Key actions from the IEA CCS Roadmap
In its 2013 CCS Roadmap, the IEA sets out key actions needed to confirm the practicability of CCS as alarge-scale CO2 abatement tool and to set it on the required deployment pathway. Many of the
Roadmap’s recommendations concern the critically important areas of providing financial incentives
and other policy drivers, as well as ensuring the safety and timely development of CO2 storage. Thus,
the seven key actions identified are equally relevant to EOR+:
1. Introduce financial support mechanisms for demonstration and early deployment.
2. Develop laws and regulations that effectively require new-build power capacity to be CCS-ready.
3. Significantly increase efforts to improve understanding among the public and stakeholders of CCS
technology.
4. Implement policies that encourage storage exploration, characterisation and development for CCS
projects.
5. Reduce the cost of electricity from power plants equipped with capture through continued
technology development.
6. Prove capture systems at pilot scale in industrial applications.
7. Encourage efficient development of CO2 transport infrastructure.
In addition, the Roadmap provides one specific action regarding EOR+ (Action 9):
9. Where CO2-EOR is being undertaken as part of long-term geologic storage operations, ensure that
it is conducted under appropriate, storage-specific regulatory regimes.

In addition to the appropriate regulatory requirements for storage through CO2-EOR,
governments may also need to consider other legal issues that could limit the potential forstorage. Generally, these issues stem from the different models of regulation for CO2-storage andPage | 37

Storing CO2 through Enhanced Oil Recovery
Combining EOR with CO2 storage (EOR+) for profit© OECD/IEA 2015

CO2-EOR; the former being focused on disposal of a waste and, the latter, on resource recovery(Marston, 2013). Thus, for example, where hydrocarbon recovery is given primacy the effectivesterilisation of the resource remaining in place after cessation of oil production may cause legal
complications. This situation may be particularly vexing in the US, where onshore mineral andstorage rights are, for the most part, privately held and separate (Marston, 2013). These sorts ofPage | 38 legal issues are inherently jurisdiction-specific, as are the potential solutions.

Barriers to the use of more CO2 per barrel of oil
As the illustrative economic analysis has hopefully demonstrated, declining supply costs of CO2 or– ceteris paribus – increasing prices of oil can lead to increased consumption of CO2 by an EOR
operator and an expanded storage resource base. However, there is a tension between those
who view CO2-EOR as a means of supporting capture technology demonstrations, which would
benefit from high prices for CO2 sold into EOR markets, and those who would like to see
increased use of CO2 for EOR, which would result from lower CO2 prices.
In the United States, recent market prices of CO2 for EOR, while sufficient to drive capture from
relatively high concentration sources, are generally insufficient to cover the first-of-a-kind
capture costs in power generation. Additionally, the volatility of oil-linked CO2 prices, flexibility
provisions, and duration of typical CO2 supply contracts may provide a disincentive for investors
in capture plants. While alternatives to conventional supply contracts are emerging in the
United States (e.g. joint ventures such as Petra Nova), a recent US analysis (NEORI, 2012)
recommended introducing a federal production tax credit for CO2 capture and transport.
The way in which incentives could be structured to both encourage increased use of CO2 for EOR
and capture from anthropogenic sources, particularly outside the US, is an area where additional
assessments are required.

© OECD/IEA 2015

Storing CO2 through Enhanced Oil Recovery

Combining EOR with CO2 storage (EOR+) for profit

Conclusions
Injecting CO2 into oil reservoirs to enhance oil recovery is a well-known commercial practice.
While CO2-EOR is a technically mature technology to enhance oil production, applying it tocontrol CO2 emissions requires a major shift in business practices and government incentives.
Adapting CO2-EOR for CO2 storage in fact represents an early and unique opportunity for kick- Page | 39
starting CCS deployment. Past experience in United States and a few other countries is valuable
to understand the drivers behind conventional EOR, but it provides incomplete guidance forextending CO2-EOR into the field of climate change mitigation.
There are seven policy-relevant conclusions that can be drawn from the analysis presented in thisreport:
1. With novel practices it is possible to turn today’s EOR from a pure petroleum production
tool to a means of storing CO2 in large quantities – namely EOR+. Advancing to a businessmodel in which long-term CO2 storage is a revenue stream requires a fundamental shift
in thinking and operations. It requires that operators re-consider reservoir management
practices and operational choices that explicitly incorporate both increased oil
production and storing of CO2 as joint business objectives. At present, no site is pursuingthis dual objective.
2. Adding storage-related activities to CO2-EOR inherent in EOR+ increases the costs ofundertaking CO2-EOR; the offsetting of these costs must be driven by climate factors suchas a price on carbon or a regulatory or permitting requirement. Hence this requires achange in incentives and support from government – one in which storage of CO2
generates a value for the operator.
3. Co-exploiting CO2-EOR for both CO2 storage and increased oil production could deliver
NPVs that exceed those for conventional CO2-EOR projects. Across a variety of CO2 andoil price trajectories, a scenario that uses more CO2 while recovering more oil (AdvancedEOR+) is preferred over scenarios that recover less oil (Conventional EOR+) or store more
CO2 (Maximum Storage). Hence under realistic oil and carbon price assumptions, fields
that recover more oil AND provide long-term CO2 storage can be more profitable. Allother things being equal, lower cost to acquire CO2 (i.e. lower supply prices) will lead to
additional use of CO2, as will higher oil prices.
4. The technical potential for CO2 storage through EOR+ is large in relation to the potential
demand for CO2 storage, regardless of the scenario considered. The potential ranges
from 60 GtCO2 to 360 GtCO2 globally in the next 50 years, i.e. from 50% to more than
three times the amount of total CO2 storage required under the IEA 2DS scenario through2050. Similarly, the volumes of oil that could be produced are substantial, up to
375 billion barrels over the next 50 years, which could both contribute to government
revenues and impact global oil markets.
5. The technical potential of EOR+ is not evenly distributed: four regions outside the UnitedStates account for 90% of the potential, much of which is located far from CO2 sources. In
addition, one-third of the potential is located offshore.
6. Widespread use of EOR+ appears likely to result in some additional oil consumption.
However, high-level estimated indicate that while a small proportion of oil produced
through EOR+ would be additional, most of EOR+ oil production would substitute oil
produced through other means without CO2 injection and storage. This substitution can
result in net reductions in emissions given the incremental storage being generated
through EOR+ practices. It is however critical that appropriate in-depth life-cycle analyses
be performed to assess both project-level and cumulative net impact.

Storing CO2 through Enhanced Oil Recovery
Combining EOR with CO2 storage (EOR+) for profit

Page | 40© OECD/IEA 2015

7. To stimulate use of CO2-EOR to achieve the benefits of CO2 storage and greater oil
extraction, governments could consider creating supportive policy frameworks to drive
first projects. Equally, a framework of laws and regulations is needed to encourage thesafe and effective design and operation of CO2 storage options. For CO2 stored throughEOR+ to qualify as “not emitted” – and thus gain the benefits of climate policy – theoperator must comply with regulations to ensure that the CO2 is retained in the reservoir.

Storing CO2 through Enhanced Oil Recovery© OECD/IEA 2015

Combining EOR with CO2 storage (EOR+) for profit

Annex 1. Technical aspects of a hypothetical
CO2-EOR+ case study
The hypothetical field used for the evaluation contains 1 Bbbl of OOIP (on a stock-tank basis)prior to the start of production. The economic analysis is based on simplified oil production and Page | 41
CO2 injection profiles that might be representative of different CO2-EOR practices. The costaccounting does not include the initial capital costs of production facilities installed before
starting CO2-EOR, which are assumed to be inherited at zero cost. In this hypothetical case, CO2EOR flooding commences in 2022 when the remaining oil falls to 30% of recoverable reserves.
CO2 recycling is assumed to begin in 2028. This case assumes an emissions pathway consistent
with the ETP 2DS; the evolution of oil and CO2 prices reflect those assumed in ETP 2012.

Production and injection profiles
We assume an oil production profile for the hypothetical project has three distinct phases(Figure 13). In Phase 1, new CO2 injection wells are drilled and put in operation along with thesupporting injection and production infrastructure in stages, which results in increased
production. In Phase 2, incremental oil production reaches and remains at a plateau, the lengthof which is determined by injection rates and the rate of pattern build out in the first phase. By
this time, enough CO2 has been injected to induce “breakthrough” and reach the oil production
wells. This breakthrough occurs earlier for Conventional EOR+ flooding than for the Advanced
EOR+ and Maximum Storage practices as a result of design choices and operating procedures
specific to the latter practices. In Phase 3, incremental oil production declines exponentially withan increasing fraction of CO2 being produced alongside oil.
Figure 13 • Schematic production profile used for analysis

Assessment

Unit

Low

Base

High

1

Time to plateau

years

10

20

30

2

Time at plateau

years

20

30

80

3

Decline rate after plateau

%

375

1125

1875

4

Peak incremental production% of STOOIP

Conventional
EOR +Advanced EOR+ andMaximum Storage EOR+

0.52

1.04

Storing CO2 through Enhanced Oil Recovery© OECD/IEA 2015

Combining EOR with CO2 storage (EOR+) for profit

The oil production profile determines the volume of CO2 that needs to be purchased and stored.
Over time, the need to purchase “new” CO2 decreases in direct proportion to oil production:
more CO2 is available through recycling as oil production declines. The stored volume iscalculated by multiplying incremental oil production with the CO2 utilisation factors
Page | 42 characterising the CO2-EOR scenarios described (see Table 1, p. 16). Thus, the analysis assumes
that CO2 purchase rates follow an exponential decline curve reflecting that of oil production.
Costs for each of these functions are based on the assumption that about half (by value) of theexisting separation equipment is replaced as necessary and new equipment is added to handle
CO2 (Tables 5a and 5b). In practice, the costs for these activities may vary depending on the pasthistory of the oil field and, the level of hydrocarbon recovery desired from the recycle gas, andoptions for produced water disposal. Of course, estimated costs are only approximate, as they
are based on a very low level of project definition.
Table 5a • Key cost assumptions: Capital expenditure
Activity

Unit

Low

Base

High

Notes

CO2 injection

USD/tCO2pa

10

20

30

Injection wells

USD million

20

30

80

Oil / gas /waterseparation

USD/bbl/d

375

1 125

1 875

CO2 / gas
separation

USD/scf/d

0.5

2.25

4.0

Total gas flow (CO2 + gas)

CO2 recycling
compression

USD/W

1

1.5

2

Cost of compression to inlet stream

30-50% of processing equipment replaced at
1.25 original cost as expensive materials
Total liquid flow (oil + water)

Table 5b • Key cost assumptions: Operational expenditure
Activity

Unit

Low

Base

High

Notes

CO2 injection

USD/tCO2

Injection wells

USD million pa

0.8

1.5

2.5

4% of well CAPEX

Oil / gas / water
separation

USD/bbl1

2

3

Based on previous conventional oil
projects. Variable OPEX based on
throughput

CO2 recycling andcompression

USD/tCO220

CO2 recycling andcompression

tCO2/bbl

0.6

Produced water cost

USD/1 000 gal

20

40

70

Monitoring EOR+

USD million pa

1.7

2

2.5

Monitoring EOR

USD paAssumed to be negligible

2 500

Source: US EPA analysis
Source: US EPA analysis

Data in Tables 5a and 5b can then be used to calculate capital and operating costs for the three
CO2-EOR scenarios considered (Figures 14 and 15). Figure 15 also provides information on theincrease in OPEX with time.

© OECD/IEA 2015

Storing CO2 through Enhanced Oil Recovery

Combining EOR with CO2 storage (EOR+) for profit

This analysis finds that injecting more CO2 for storage drives up both capital and operating costs,
even before considering the purchase of CO2. In the hypothetical case, the capital cost increase ofmoving from Conventional EOR+ to Advanced EOR+ is roughly 55%. Moving from Conventional
EOR+ to Maximum Storage, the capital cost doubles. These additional costs are almost
exclusively due to the need for additional wells – or, ceteris paribus, more complex and expensive
wells – and associated maintenance. To a lesser extent, CO2 recycling after CO2 breakthrough also Page | 43
increases capital expenditure.
Figure 14 • Elements of capital costs for different CO2-EOR scenarios

Figure 15 • Change of incremental project operating cost; CO2 recycling as of 2028

Storing CO2 through Enhanced Oil Recovery
Combining EOR with CO2 storage (EOR+) for profit© OECD/IEA 2015

References
Page | 44

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Page | 45

Storing CO2 through Enhanced Oil Recovery
Combining EOR with CO2 storage (EOR+) for profit© OECD/IEA 2015

Acronyms, abbreviations and units of measure
Acronyms and abbreviations
Page | 46

2DS
4DS
6DS
CAPEX
CCS
°C
CO2
CO2-EOREOR
ETP
IEA
IEAGHG
IGCC
LNG
MMP
MMV
NPV
OOIP
OPEX
STOOIP
WAG
USD

2-Degree Scenario (ETP)
4-Degree Scenario (ETP)
6-Degree Scenario (ETP)
capital expenditures
carbon capture and storage
degree Celsius
carbon dioxidecarbon dioxide for enhanced oil recovery
enhanced oil recovery
Energy Technology Perspectives
International Energy Agency
IEA Greenhouse Gas R&D Programme
integrated gasification combined cycleliquefied natural gas
minimum miscibility pressure
monitoring, measuring and verification
net present value
original oil in place
operational expenditures
stock-tank original oil in placewater-alternating-gas (process)United States dollar

Units of measure
/d
/yr
bbl
Bbbl
gal
Gt
GtCO2
kg
Mcf
Mt
MtCO2
MW
pa
t
tCO2
tCO2-eqWper day
per yearbarrels of oil
billion barrels of oil
gallons
gigatonne
gigatonnes of carbon dioxide
kilogramme
thousand standard cubic feetmillion tonnes (megatonne)
million tonnes of carbon dioxide
megawatt
per annum
tonne
tonnes of carbon dioxide
tonnes of carbon dioxide equivalent
watt

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MediumTerm Market Renewable
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MarketReportThis document and any map included herein are without prejudice to the status of or sovereignty
over any territory, to the delimitation of international frontiers and boundaries and to the nameof any territory, city or area.
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