ISO/TR 27926:2024

Technical
Report
ISO/TR 27926
First edition
Carbon dioxide capture,
2024-12
transportation and geological
storage — Carbon dioxide
enhanced oil recovery (CO -EOR) —
Transitioning from EOR to storage
Captage du dioxyde de carbone, transport et stockage
géologique — Récupération assistée du pétrole par le dioxyde de
carbone (RAP-CO2) — Transition de la RAP au stockage
Reference number
© ISO 2024
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ii
Contents Page
Foreword .v
Introduction .vi
1 Scope . 1
2 Normative references . 1
3 Terms and definitions . 1
4 Abbreviated terms and symbols . 3
4.1 Abbreviated terms .3
4.2 Symbols .4
5 Overview . 4
6 CO operational scenarios addressed . 5
7 Technical and operational aspects of transition . 6
7.1 General considerations.6
7.1.1 Storage volume assessment and estimation of pore volume .6
7.1.2 Current fluid saturations, including CO , in the reservoir/storage zone at the
time of transition .7
7.2 Mechanisms for additional storage .8
7.3 A ssessing containment assurance in modified operations .8
7.4 Reservoir management .9
7.4.1 General .9
7.4.2 New CO volumes — Increase of supply .9
7.4.3 Management of displaced water .9
7.4.4 Redesign of patterns .9
7.5 Well operations .10
7.5.1 General .10
7.5.2 Creating a well inventory.10
7.5.3 Repurposing wellbores for storage injection.10
7.6 Application of operational modifications — Illustrative analysis .11
7.6.1 Containment assurance assessment in base case — Typical EOR .11
7.6.2 Assessing containment assurance in modified operations . 12
7.6.3 Project IWR exceeds 1 (case 2) . 12
7.6.4 Change in storage assurance assessment related to long term stabilization
change during transition (case 3) . 13
7.7 Wells . . 13
7.7.1 Re-use . 13
7.7.2 Abandonment .14
7.8 Facility operations .14
7.8.1 Design assessment .14
7.8.2 Facility integrity testing .14
7.8.3 Measurement . 15
7.8.4 Projects that are not currently CO -EOR projects . 15
7.8.5 Recycle compression capacity . 15
7.9 Monitoring .16
7.9.1 M onitoring design .16
7.9.2 Role of baseline .17
7.9.3 Development of model(s) prior to storage .17
7.10 Quantification . . .17
7.10.1 Existing quantification practices .17
7.10.2 Application to transitioning CO storage scenarios .18
8 Case studies .18
8.1 General .18
8.2 Case study no. 1: Optimization of CO storage in an actively producing CO -EOR project .19
2 2
8.2.1 General .19

iii
8.2.2 Storage phase 1: Discontinuation of WAG and implementation of continuous
CO injection . 20
8.2.3 Storage phase 2: Additional pattern development . 20
8.2.4 Storage phase 3: Reservoir operating pressure .21
8.2.5 Wells during the additional storage phases . 23
8.2.6 Other facilities during the additional storage phases . 23
8.3 Case study no. 2: Engineered CO storage following termination of CO -EOR
2 2
hydrocarbon recovery operations .24
8.3.1 General .24
8.3.2 Points to consider in using existing CO -EOR infrastructure . 25
8.3.3 Areas of the oil field considered for transition to engineered CO storage . 26
8.3.4 Analysis of case study no. 2 . 28
8.4 Case study no. 3: Conversion of an off-shore gas field to CO storage with associated
hydrocarbon recovery . 30
8.4.1 General . 30
8.4.2 Initial phase: CO capture and injection .31
9 Comparison of ISO 27914 and ISO 27916 .31
9.1 Purpose .31
9.2 Scope and coverage of ISO 27914 and ISO 27916 .32
9.3 Application of ISO 27916 . 33
9.4 Application of ISO 27914 . . 33
9.5 Conclusion . 34
10 L egal, regulatory and permitting issues .34
10.1 General . 34
10.2 Pre-existing legal and regulatory paradigm . 34
10.2.1 General . 34
10.2.2 Comparison of legal and regulatory frameworks for mineral recovery versus
frameworks for managing geological injections for storage . 35
10.2.3 Pore space ownership and access .42
10.3 L egal and regulatory aspects of reuse of existing infrastructure .45
10.3.1 R eview of property instruments and contractual agreements .45
10.3.2 R egulatory compliance review . 46
10.4 R eview of case study scenarios . 48
10.4.1 Case study variations in 8.1: Maximization or optimization of CO storage in an
actively producing CO -EOR project . 48
10.4.2 Case study variations in 8.2 . 49
10.4.3 Case study variations in 8.3 .51
Annex A (informative) Transition scenarios and comparison of ISO 27914 and ISO 27916 .53
Bibliography .62

iv
Foreword
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This document was prepared by Technical Committee ISO/TC 265, Carbon dioxide capture, transportation,
and geological storage.
Any feedback or questions on this document should be directed to the user’s national standards body. A
complete listing of these bodies can be found at www.iso.org/members.html.

v
Introduction
Across the globe, interest in and development of projects for the geological storage of captured
anthropogenic CO continues to increase. One subset of these projects consists of those that would find some
way to increase CO storage through the use of existing hydrocarbon fields and infrastructure. There is a
continuum of projects from hydrocarbon fields near the end of their lives that start CO injection before
the end of production, thereby accelerating transition to storage and potentially reducing costs, to full-
fledged carbon dioxide enhanced oil recovery (CO -EOR) projects that can be optimized to maximize CO
2 2
storage while still producing oil. Alternatively, operators of a producing field can decide to begin storage
operations in that field before ceasing production. Such operations would instead be designed to achieve
storage simultaneously with production.
Due to the availability of existing infrastructure for CO transport, handling, injection and storage, modifying
CO -EOR projects nearing maturity to increase CO storage can be a particularly cost-effective way to reduce
2 2
atmospheric emissions of CO . Some such modified projects can also defer project decommissioning, again
helping to expand commercial carbon capture and sequestration (CCS) as an emissions-reduction option.
CO transport and injection infrastructure, as well as the generally well-characterized geologic formations
where CO -EOR operation are already undertaken or where operations at CO -bearing geological formations
2 2
occur, can be modified too for CO storage.
Similarly, for producing oil and gas fields, starting CO injection before cessation of production (i.e. having
overlapping storage and production licenses) can have significant economic benefits. The CCS project can
have certainty in timing and can potentially avoid having to compensate the hydrocarbon operator for “lost
production”. There is also no gap between production and storage leading to no challenging questions over
who pays for mothballed infrastructure.
There is considerable overlap in technology and infrastructure between standard CO -EOR, other
hydrocarbon recovery processes and dedicated geological storage of CO . Each of the processes – and
many of the operational variations discussed in this document – can present different advantages or
disadvantages. For example, a number of the operational techniques for maximizing CO storage would
tend to increase reservoir pressures affecting the containment risk assessment, CO movement through the
storage complex or certain subsurface-engineered facilities. The technical and operational portion of this
document examines these issues.
Similarly, the legal, regulatory and even consensus standards framework developed for typical CO -EOR
operations can no longer be applicable to a modified operation. A given framework can be appropriate for
some operational changes, but not for others. Clause 10 provides an overview of these issues.
This document does not address the quantification of greenhouse gases (GHGs) other than CO for carbon
dioxide storage projects. CCS projects can address quantifying, monitoring, reporting, and validating or
verifying other GHG emissions reductions or removals through the application of ISO 14064-2 or other
documents in the ISO 14064 series.

vi
Technical Report ISO/TR 27926:2024(en)
Carbon dioxide capture, transportation and geological
storage — Carbon dioxide enhanced oil recovery (CO -EOR)
— Transitioning from EOR to storage
1 Scope
This document examines various CO injection operations that involve modifications to CO -EOR or other
2 2
complementary hydrocarbon recovery operations that can be conducted in conjunction with CO storage.
The document also examines potential policy, regulatory or standards development issues that can arise in
evaluating such operational changes.
2 Normative references
There are no normative references in this document.
3 Terms and definitions
For the purposes of this document, the following terms and definitions apply.
ISO and IEC maintain terminology databases for use in standardization at the following addresses:
— ISO Online browsing platform: available at https:// www .iso .org/ obp
— IEC Electropedia: available at https:// www .electropedia .org/
3.1
anthropogenic CO
anthropogenic carbon dioxide
carbon dioxide that is initially produced as a by-product of a combustion, chemical or separation process
(including separation of hydrocarbon-bearing fluids or gases) where it would otherwise be emitted to the
atmosphere (excluding the recycling of non-anthropogenic CO )
[SOURCE: ISO 27916:2019, 3.1, modified — Notes 1 and 2 to entry have been deleted.]
3.2
area of review
AOR
geographical area(s) of a carbon capture and sequestration (CCS) project, or part of it, designated for
the assessment of the extent to which a CCS project, or part of it, can affect life and human health, the
environment, competitive development of other resources, or infrastructure
Note 1 to entry: The delineation of an area of review defines the outer perimeters on the land surface or seabed and
water surface within which assessments will be conducted.
[SOURCE: ISO 27917:2017, 3.3.10, modified — "may be required by regulatory authorities" has been deleted
from Note 1 to entry.]
3.3
enhanced oil recovery complex
EOR complex
project reservoir, trap and such additional surrounding volume in the subsurface as defined by the operator
within which injected CO will remain in safe, long-term containment
[SOURCE: ISO 27916:2019, 3.10]
3.4
injection/withdrawal ratio
IWR
relationship, during a defined period, of the volume of all fluids and gases injected into the project reservoir
to the volume of all fluids and gases produced from the project reservoir as determined using consistent
temperature and pressure conditions
[SOURCE: ISO 27916:2019, 3.11]
3.5
natural-sourced CO
gaseous accumulations of CO found in geological settings, such as sedimentary basins, intra-plate volcanic
regions, faulted areas or quiescent volcanic structures
3.6
plug and abandon
P&A
permanently close a well or wellbore to prevent inter-formational movement of fluids into strata, into
freshwater aquifers, and out of the well
Note 1 to entry: In most cases, a series of cement plugs is set in the wellbore, with an inflow or integrity test made at
each stage to confirm hydraulic isolation.
[SOURCE: ISO 27916:2019, 3.17]
3.7
produced water
naturally occurring water in the reservoir that is extracted as part of oil and gas production operations
3.8
produced water cut
ratio of water to total fluids that are produced at the well during oil and gas production operations
3.9
purchased CO
CO injected in a formation that is not attributable to recycling of CO previously injected at that site,
2 2
regardless of whether the supply is acquired through a purchase and sale transaction
Note 1 to entry: Other terms include “incremental”, “new”, “off-site” and “acquired” CO . Accounting protocols to
preclude double-counting of CO storage are presented in ISO 27916:2019, 8.2, 8.7 and Clause A.14 b).
3.10
spill point
structurally lowest part of a reservoir that can contain buoyant fluids within the trap
3.11
thief zone
geological formation to which fluids used or produced during CO enhanced oil recovery drilling or
production operations are lost

3.12
water-alternating gas
WAG
enhanced oil recovery production technique in which injections of water are alternated with injections of
CO (as opposed to continuous injections of CO )
2 2
3.13
water out
point in time beyond which the proportion of water in a production stream is so great that recovery of the
remaining hydrocarbons in the stream is no longer economically justified
4 Abbreviated terms and symbols
4.1 Abbreviated terms
AOR area of review
API American Petroleum Institute
BIO LLC Brilliant Idea Oil LLC
CCI continuous CO injection (i.e. not alternating with water injections)
CCS carbon capture and sequestration
CCUS carbon capture utilization and storage
CO -EOR carbon dioxide enhanced oil and gas recovery
FPSO floating production storage and offloading vessel
GOR gas/oil ratio
HC hydrocarbon
HCPV hydrocarbon pore volume
IPL injection profile logging
IWR injection/withdrawal ratio
LACT lease automatic custody transfer
LNG liquid natural gas
M one thousand
MDF mature and depleted field
MIT mechanical integrity testing
MM one million
MMRb one million reservoir barrels
OOIP original oil in place
PDO plan for development and operation
P&A plug and abandon
psi pounds per square inch
Rm reservoir cubic meter (i.e. cubic meter at reservoir temperature and pressure)
ROZ residual oil zone
STB standard barrel (i.e. barrel of liquid at standard temperature and pressure)
Tcf trillion cubic feet
USDW underground source of drinking water
WAG water alternating gas
4.2 Symbols
T initial temperature
i
B oil formation volume factor at initial reservoir pressure
OI
P bubble point pressure
BP
P initial reservoir pressure
i
R solution gas/oil ratio
s
R reservoir barrel
b
5 Overview
During CO -based enhanced oil or gas recovery operations (CO -EOR), CO is injected into a hydrocarbon-
2 2 2
bearing geological formation to restore reservoir pressure and to mobilize oil that is trapped in the pore
spaces of the rock. As explained in ISO 27916:2019, Clause A.3:
"Once injected, the CO contacts and swells the oil in the reservoir. At certain pressure and temperature
conditions, the CO becomes miscible (mixing in all phases) with the oil, creating a more mobile oil that
is more easily displaced through the reservoir. Oil, CO , and brine are then produced to the surface at
production wells. This mixture of produced fluids is delivered to a separation plant in which pressure is
dropped, and oil, water, and CO and other gases are separated from one another. […] Oil is sent to market
and brine is reinjected for flooding as part of the operation or injected in permitted disposal wells."
ISO 27916:2019, Clause A.4 states that, as a natural part of CO -EOR operations, CO is “effectively stored
2 2
in the subsurface and securely isolated from the atmosphere, underground sources of drinking water, and
other subsurface resources.” Furthermore, ISO 27916:2019, Clause A.4 explains that:
"a significant fraction of injected CO becomes trapped in place and is physically unrecoverable.
Modelling and core plug studies illuminate the trapping that occurs; it includes CO trapped by capillary
processes and in dead end pores, dissolved in immobile oil, dissolved in brine, or moved into 'attic' areas
and outside of the active flow paths. Some discussions of CO -EOR operations characterize only this
[1]
non-recyclable CO as 'stored' (e.g. Whittaker and Perkins, 2013). However, others follow the same
approach as is used in accounting for saline formation storage projects, where all forms of effective
trapping in the reservoir are counted as stored (including CO trapped as a mobile phase beneath the
confining system)."
Adsorption counts as another trapping mechanism. A dense layer of CO forms at the solid surface increasing
the storage capacity of a reservoir on one hand and reducing the possibility of CO leakage through
overpressure on the other. However, residual water or oil films adhering to the surface can prevent the
formation of closed adsorption layers.

The first commercial CO -EOR projects began over 50 years ago. The vast majority of the 140 or more
projects worldwide are still operational today. Until recently, there has generally been no economic value
to be derived from the associated storage of CO that occurs in a CO -EOR operation. As a result, in seeking
2 2
to maximize the ultimate recovery of the hydrocarbon mineral resource (as typically required by the
applicable law, permit or commercial agreement), operators have generally sought to economically optimize
(i.e. minimize) the quantity of CO injected and stored during the operation. The economic incentives change;
however, when a legal or regulatory framework or a commercial agreement creates an economic value for
the long-term secure containment of the stored CO , in effect, creating a dual revenue stream for a project:
revenue from hydrocarbon sales plus revenue from CO emission reduction or avoidance incentives.
In these circumstances, the operator can explore various operational changes to maximize the total
economic recovery of the project. While some operational changes can alter spatial distribution and spread
of the injected CO , others cannot. Increasing the amount of CO that is stored can also affect operating
2 2
pressures, particularly in the subsurface. These, and related changes, can affect the area of review (AOR)
for assessing potential leakage pathways and other aspects of the containment assurance. In addition, legal,
regulatory, contractual or mineral property leases or permits can need revising as well. Clauses 6, 7 and
8 examine various potential operational modifications that can be pursued to achieve higher levels of CO
storage while Clause 10 addresses related legal, regulatory and property management issues.
6 CO operational scenarios addressed
Operations and facility prerequisites for each field operation, whether oil and gas recovery or CO storage
are site specific, depending upon the circumstances for that project. Operations are designed, conducted and
modified in accordance with multiple factors, including, for example, geology, infrastructure availability,
input costs and availability, projected market prices and costs over time, potential changes in government
regulation and public perceptions, and a host of other factors. Accordingly, the operational scenarios
discussed in this document are intended to illustrate the range of scenarios that can be considered by
different operators; they are not real-world projects.
Transitioning from hydrocarbon recovery to storage can necessitate additional or upgraded infrastructure,
depending upon the nature of the project and the regulatory regime in which the project resides.
There are three broad categories of operational changes discussed, together with potential variations. The
categories define the facility considerations and operational considerations for the project. The three broad
categories (see Figure 1) are:
— Scenario category 1: Maximizing or optimizing CO storage quantities in an actively producing CO -EOR
2 2
project. This set of operational changes consists of actions aimed at increasing the amount of CO injected
and stored in CO -EOR operation either by increasing the amount of pore space in a defined containment
that is filled with CO or by extending the previously defined containment either laterally or vertically.
These project variations will generally have existing facilities that can be sufficient for the immediate
needs of CO storage, but over time can necessitate upgrades for injection system operating pressures,
recycle rates and field distribution and gathering. These projects can be termed “CO maximization/
optimization” projects.
— Scenario category 2: Projects that do not envision continued hydrocarbon recovery, meaning that no
additional production facilities be required. However, if additional saline water production is necessary
to provide accommodating pore space for CO storage, some production facilities can be necessary. In
addition, the prerequisites for CO injection can necessitate additional injection pressure capability and
possibly rate capacity as well. These variations are sometimes referred to as “top off the tank” operations
where CO injections continue after hydrocarbon production is terminated.
— Scenario category 3: Projects that are hydrocarbon-recovery related projects that have not previously
undergone CO flooding. These projects have hydrocarbon production related facilities, but no existing
CO injection capability at all. Such projects need CO injection and compression facilities. In addition,
2 2
the continued production capability can need adapting to capture CO extracted from the hydrocarbon
production stream as well as the capability for handling increased CO concentrations. Field injection
infrastructure are needed and upgrades to gathering infrastructure is likely to be necessary.

Figure 1 — Operational scenario categories
Although an operator can pursue these operational strategies at any stage, the most likely cases for their
implementation are projects in the mature stage of hydrocarbon operations when operators will be looking
to either abandon their operations or extend the economic life of the asset. The economic life can be extended
through continued or new enhanced recovery processes or in combination with storage incentives, if
applicable. However, extending operations in this manner can present questions as to the use of the original
equipment. Wellbores and surface facilities that are no longer new can be reviewed vis-à-vis their remaining
operating life. Certain equipment will have been maintained but other equipment can be nearing the end
of its useful life. Operators will forecast end-of-life relative to expenditure outlays many years in advance
and plan and conduct maintenance operations accordingly. Maintenance can well be reduced, allowing the
mechanical integrity of wellbores and surface facilities to decline from optimum manufacturer-specified
rates or pressures. Replacements or remediation costs most likely will need to be figured for the go-forward
storage option.
7 Technical and operational aspects of transition
7.1 General considerations
7.1.1 Storage volume assessment and estimation of pore volume
One of the key parameters for determining the maximum amount of CO that can be stored in a defined
formation is the pore volume available for CO storage within that interval. That pore volume is a function of
area, thickness and porosity of the formation. Hence, to calculate the pore volume (V ) within the CO -EOR’s
pi 2
producing intervals (i) of the petroleum reservoir, some form of the following volumetric formula is needed:
V = A × h × φ
where
V is the pore volume;
A is the area;
h is the thickness;
φ is the average porosity of the producing intervals.
The inputs for these estimates will come from well and petrophysical data. The locations of the production
and injection wells can be used to define the A . The thickness from which fluid flows into or out from wells
i
can be calculated by identifying original depth of oil-water contact, as defined by well log measurements,
minus the depth to the top of the reservoir. These thickness values calculated for all of the production and
injection wells within the CO project area can then be used to estimate the h . Porosity values derived from
2 i
well log estimates or physical measurements can be used to estimate the average φ across the h of each well.
i i
To estimate the pore volume of an entire geological trap that contains the producing intervals, the volumetric
formula can be used with different input values. The area and the thickness of the trap can be defined by
locating the spill point of the reservoir, which is defined as the structurally lowest part of a reservoir that
can contain buoyant fluids within the trap. As CO is generally less dense than other in situ formation fluids
(except CH or light hydrocarbons), it is buoyant relative to those fluids and therefore tends to move upwards
in the subsurface. Once the cumulative CO injected “fills” the trap, any additional CO injected into the trap
2 2
can then “spill” outside of the trap and buoyantly move upwards into the adjacent strata. The spill point can
be identified using seismic data if available, or cross-sections based on well log interpretations, or structural
maps of the reservoir. The trap as defined by the spill point gives a maximum CO column thickness, and a
maximum area of the trap. The bulk volume (A × h ) can be estimated from the spill point, typically using
i i
stratigraphic software. If the spill points are not known, the area defined by the location of active and
previously active production wells can serve as a proxy for A , but the potential CO column thickness will
i 2
need to be estimated. The well logs, core and well-based measurements used in the volumetric formula, can
also be used to calculate the φ and the maximum CO column thickness for the h within the defined area of
i 2 i
the trap.
Due to the density difference between CO and other in situ fluids, the CO column thickness used in the
2 2
volumetric method is subject to limitations. If CO immediately underlies the seal to the trap, the pressure
of the CO can be excessive, depending on the thickness of the vertically continuous CO column. As the CO
2 2 2
column thickness increases, there is a corresponding increase in the pressure at the top of the column and
hence the vertically continuous CO column must be compared to the thickness of the trap. The maximum
CO column thickness is determined by using the minimum of the seal’s fracture pressure and capillary
entrance pressure and the average CO density in the column. If the calculated maximum CO column is
2 2
greater than the thickness of the trap, the entire trap can be used to store CO . If the calculated maximum
CO column is lesser than the thickness of the trap, the entire trap cannot be used to store CO , and the
2 2
thickness used in the volumetric formula equals the maximum CO column thickness.
7.1.2 Current fluid saturations, including CO , in the reservoir/storage zone at the time of
transition
To facilitate the transition from CO -EOR to CO storage, the distribution of fluids within the pore volume
2 2
of the intervals defined by the CO -EOR well patterns at the time the transition begins is important in
determining the predominant storage mechanisms and thereby quantify CO storage for each mechanism.
The challenge is to determine which of the remaining fluids will be displaced from the CO -EOR patterns to
accommodate storage of the injected CO , and hence identify the storage mechanisms.
The possible fluids present are hydrocarbon gas, non-hydrocarbon gases such as nitrogen or H S,
hydrocarbon liquid (oil), formation fluid or injected water (brine), and CO . If the CO -EOR project was a
2 2
miscible flood, it is less likely that hydrocarbon gas is present. Furthermore, due to the vaporization/
condensation process of CO -EOR, the oil will be enriched with CO , and the CO will be enriched with
2 2 2
hydrocarbons; therefore, there can be minimal native oil or pure CO in the subsurface. The distribution
of the fluids at the end of CO -EOR operations can be assumed using material balance calculations, which
provides average estimates for the system and numerical flow modelling methods, which can provide more
granular insight into the fluid distribution.
7.2 Mechanisms for additional storage
When evaluating the storage available within the volume of the intervals defined by the CO -EOR well
patterns, using the operating practices at the time of the transition to storage, additional storage can be
available via:
— an increase in CO saturation within the CO -EOR patterns;
2 2
— an increase in storage pressure above CO -EOR operating pressure;
— an expansion of the storage area beyond the volume defined by the CO -EOR patterns or in different
geological formations; or
— a change in operating practices to improve CO sweep efficiency (e.g. change in pattern shape or size)
...