Enhanced oil recovery and the geological sequestration of carbon dioxide: Regulation and carbon crediting

Transcription

1 Enhanced oil recovery and the geological sequestration of carbon dioxide: Regulation and carbon crediting A report prepared for Natural Resources Canada Nigel Bankes and Elizabeth Brennan March 2013

2 Acknowledgments Several people provided documents and helped us with our understanding of the provincial and federal regulatory schemes including Rob Bioletti, Tristan Goodman, Beth Hardy, Robyn Kuhn, Susan MacDonald, Shan Pletcher, James Porter, Christian Roux and Floyd Wist. Disclaimer Considerable portions of this paper deal with the interpretation and application of legislation to CO 2 capture, injection and storage. Statements in this paper about the interpretation or application of legislation are the opinions and conclusions of the authors. They should not be regarded either as legal opinions or as officially sanctioned statements of the government agencies responsible for their administration. ii

3 Table of Contents Acknowledgments... ii Disclaimer... ii 1. Introduction : What is CO 2 Enhanced Oil Recovery and under what circumstances can it provide permanent geological storage? Introduction to CO 2 Enhanced Oil Recovery The Enhanced Oil Recovery Process Types of CO 2 Floods Challenges Associated with Long Term CO 2 Storage from EOR CO 2 Sequestration Process during EOR Carbon Accounting Additional Monitoring of the Reservoir Optimizing for CO 2 sequestration and Stacking Conclusion : Crediting CO 2 Sequestered as a result of CO 2 EOR Net CO 2 sequestered from CO 2 EOR processes CO 2 EOR May Result in Net CO 2 Emissions CO 2 EOR May Result in Net CO 2 Sequestration Additionality and the Determination of a Baseline Existing Protocols for Determining the Amount of CO 2 Sequestered Overview of Greenhouse Gas Accounting and/or Offset Protocols The General Format of Quantification Protocols Addressing Specific GHG Accounting Challenges with a Quantification Protocol Monitoring, Verification and Accounting Technical Concerns regarding CO 2 leakage during and after operations MVA Activities Occur Concurrently with EOR Processes MVA Methodologies Duration of Carbon Crediting Conclusion Standards for CO 2 storage site selection, monitoring, verification and risk assessment CSA Group, Standard Z741 12, Geological Storage of Carbon Dioxide Z Part 4: Management Systems Z Part 5: Site Screening, Selection, and Characterization Z Part 6: Risk Management Z Part 7: Well Infrastructure development Z Part 8: Monitoring and Verification Z Part 9: Closure Conclusions The current rules for approving and crediting CO 2 EOR projects in Alberta The property basis for CO 2 EOR Schemes CO 2 EOR Project approvals iii

4 5.3 The Crediting Rules for CO 2 EOR Projects Alberta Quantification Protocol For Enhanced Oil Recovery The CO 2 EOR Projects registered in the Alberta Offset Registry Conclusions The current rules for approving and crediting CCS projects in Alberta The property basis for a CCS Scheme CCS Project Approvals Board Directives Crediting for CCS Projects The DRAFT Quantification Protocol for the Capture of CO 2 and Storage in Deep Saline Aquifers Conclusions The current rules for approving and crediting CO 2 EOR projects in Saskatchewan The property basis for CO 2 EOR Schemes CO 2 EOR Project Approval CO 2 EOR scheme approvals in Saskatchewan: The practice Crediting Rules Compliance Mechanisms Offset Credit Performance Credit Pre certified investment Recognition for early action Application of the Compliance Mechanisms to CO 2 Capture and Sequestration The current rules for approving and crediting CCS Projects in Saskatchewan The property basis for CCS projects CCS Project Approval Crediting rules The relationship between provincial carbon crediting rules and the federal Coal Regulations The federal regulations Using a CCS project to meet the performance standard Using CCS to obtain a temporary exemption Using early action on CCS to defer the application of performance standards Reporting and Quantification Requirements Implications of the federal regulations for provincial schemes The prescribed standard The temporary exemption The early action provision Equivalency Agreements The European Union Directives and their Implementation Introduction The Property Basis for CCS and CO 2 EOR Schemes CCS and CO 2 EOR Project Approvals The Crediting Rules for CCS and CO 2 EOR Projects Conclusions iv

5 11. The Current Rules for Approving and Crediting CCS and CO 2 EOR Projects in Texas, USA Introduction The Property Basis for CCS and CO 2 EOR Schemes CCS and CO 2 EOR Project Approvals The TRC s CO 2 Geologic Storage Rules The TRC s Certification Rules The Crediting Rules for CCS and CO 2 EOR Projects Quantification Protocols for CO 2 EOR Projects in Texas Conclusion References Cited Appendix A Appendix B Appendix C: Carbon Dioxide Disposal, Approval No [Quest Project] Appendix D: Carbon Sequestration Lease: Shell Canada v

6 1. Introduction This report examines the issue of carbon crediting and other recognition of avoided greenhouse gas (GHG) emissions for the geological sequestration 1 of carbon dioxide (CO 2 ) that may occur as a result of enhanced oil recovery (EOR) operations using CO 2 as the flooding agent to enhance recovery. In doing so, the paper identifies differences in the regulations for project review and crediting that apply to CO 2 -EOR operations and to carbon capture and storage (CCS) projects (eg saline projects) that do not involve enhanced recovery. Part two of the paper reviews the literature on CO 2 -EOR technology, and discusses the CO 2 -EOR processes and types of floods, and then proceeds to identify some challenges associated with the long-term storage of CO 2, including trapping and sequestration mechanisms, carbon accounting, the additional monitoring required, and optimizing a reservoir for sequestration. Part three of the paper surveys the literature dealing with carbon crediting for emissions reductions that may be obtained in CO 2 -EOR projects, including studies that use a Life Cycle Assessment methodology. It also examines the concept of additionality, and shows how that concept influences the determination of a baseline for CO 2 -EOR processes. Existing CO 2 quantification protocols are highlighted to show how these protocols address challenges associated with carbon accounting. Monitoring, Verification, and Accounting protocols and tools are identified. Finally, the duration of carbon crediting for CO 2 -EOR projects is discussed. Part four of the paper discusses the development of standards for CO 2 storage site selection, monitoring, verification and risk assessment to aid proponents and regulators in the development of permitting procedures for CCS and CO 2 -EOR projects. Specifically, 1 We use the terms sequestration and storage interchangeably in this report in order to be consistent with references cited. We generally prefer the term geological although we note that the regulatory documents in the state of Texas use the term geologic. 1

7 this section focuses on the new CSA Group Standard Z741-12, Geological Storage of carbon dioxide adopted October Part five of the paper is the first of several parts dealing with the approval and crediting of CO 2 -EOR projects and CCS saline projects in different jurisdictions. Each of these parts follows a similar format, beginning with a discussion of the property or ownership framework for the project. Subsequent sections deal with the main regulatory approval process and then examine the crediting rules in that jurisdiction including discussion of any relevant Quantification Protocols or draft Protocols. Thus part five of the paper deals with the current rules for approving CO 2 -EOR projects in Alberta while part six covers CCS projects. Parts seven and eight deal with the property, regulation and crediting rules for CO 2 -EOR and CCS projects in Saskatchewan. Part nine of the paper examines the treatment of CO 2 -EOR and CCS projects within the context of the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulation (the federal Coal Regulations) and considers the relationship between these regulations and provincial crediting rules. Parts ten and eleven of the report examine the regulatory and carbon crediting rules for CO 2 -EOR projects in one EU member state (the United Kingdom) and one US state (Texas). 2

8 2: What is CO2 Enhanced Oil Recovery and under what circumstances can it provide permanent geological storage? 2.1 Introduction to CO2 Enhanced Oil Recovery This section provides an introduction to the history and use of Enhanced Oil Recovery (EOR) with carbon dioxide (CO 2 ). CO 2 -EOR refers to the subsurface injection of CO 2 in a liquid or supercritical state 2 for the purpose of producing commercially significant quantities of oil (Hovorka, 2010). CO 2 -EOR also has the side effect of sequestering some of the process CO 2, laying the groundwork for studies examining the feasibility of EOR as a carbon sequestration technique. Because the technology has been implemented (primarily in the United States) for more than 50 years, high confidence exists with respect to the effectiveness of CO 2 injection techniques. Several authors call for the use of CO 2 -EOR as a near-term solution for the geological sequestration of anthropogenic CO 2, while industrial-scale CCS techniques are still under development (Bennion and Bachu, 2005; Hovorka, 2010; Leach et al, 2011). The injection of CO 2 for the purposes of EOR is undertaken in an oil reservoir in the tertiary phase of production. In the primary phase of production, oil will be produced from a formation under the combined pressures of the oil itself, as well as expanding gases dissolved in the oil (Blunt et al, 1993). The reservoir pressure must be maintained in the secondary phase of production, and this is often accomplished by the injection of a fluid, such as water. Further oil can be extracted in the tertiary phase, with the use of an effective solvent, such as supercritical CO 2. Miscibility can be defined as the solubility of the CO 2 in into the oil and of the oil into the CO 2 (Hovorka, 2010, pp. 5). Miscibility depends on reservoir conditions, the temperature and pressure of the fluids as they contact one another, and the density of the oil (lower density oils will reach miscibility at lower temperatures and pressures). 2 Supercritical refers to higher temperatures and pressures beyond a substance s critical point, meaning the distinct characteristics of gas or liquid phases no longer exist. 3

9 Supercritical CO 2 will be miscible with light hydrocarbons (typically alkanes of 13 carbon atoms or fewer) and this phase will be less viscous than the crude oil, and thus will flow through the reservoir, contacting more and more remaining oil (Blunt et al, 1993). With increasing CO 2 injection (resulting in increased pressure), an oil-co 2 mixture will eventually form that is completely miscible with reservoir oil. This pressure is called the Minimum Miscibility Pressure (MMP). The tertiary production of oil is most efficient at the MMP. Supercritical CO 2 proves to be a more effective solvent than water because the density of supercritical CO 2 is approximately half that of water, and CO 2 is able to interact with the ganglia of oil that are held in place in the formation pores by water-oil surface tension (Blunt et al, 1993). While secondary production may recover between 40 50% of the original oil in place, tertiary production with CO 2 can recover an additional 25 40% of the remaining oil. There are several geological factors affecting the efficiency of tertiary recovery (such as permeability and heterogeneity), as well as the density and viscosity differences of the fluids. CO 2 -EOR is not necessarily applicable to all reservoirs, although it is an efficient technique for reservoirs with crude oils of a specific gravity greater than 22 API (Aycaguer et al, 2001). Advances in EOR technology, coupled with better modeling tools with which to understand oil producing formations, may result in even higher fractions of oil being produced (Blunt et al, 1993; Hovorka, 2010). Many non-geological factors also play critical roles in the application of EOR technologies. Economic considerations, such as the price of oil and the price and availability of CO 2, play a large role in the development of EOR projects (Leach et al, 2011). The lack of regulatory experience can also pose a challenge: many jurisdictions have regulatory experience with injection wells; however, EOR infrastructure for the copurpose of CO 2 sequestration requires further considerations. The benefits of using EOR as a carbon storage technology are discussed in the literature. These include: 4

10 CO 2 -EOR can result in the re-pressurization of a producing formation, which would avoid ground collapse (this may be more of a concern in some regions than others) (Aycaguer et al, 2001). The capture and sale of CO 2 provides a revenue stream to those involved (Kuuskraa, 2010). Carbon sequestration in EOR projects, compared to deep saline carbon capture and sequestration projects, utilize more of the geologically available storage (deep saline aquifers are projected to utilize 1 4% of geologically available storage, compared to the use of approximately 40% of the geologically available storage that is achieved in oilfields). The result of this is that the sequestration of a given amount of CO 2 results in a plume 10 times smaller in an oilfield compared to a saline aquifer (Kuuskraa, 2010). Sequestration activities in an oilfield benefit from a proven reservoir caprock (or seal) that has confined the hydrocarbons over geologic time, the existing subsurface data, the existing subsurface infrastructure (in some cases), and the established mineral or pore-space rights (Kuuskraa, 2010). However, several challenges exist with respect to utilizing EOR processes for the purposes of CO 2 sequestration. Babadagli (2006) argues that the use of CO 2 for EOR purposes compared to the use of CO 2 for sequestration are two technically different challenges. Dooley et al (2010) agree, and emphasize that current EOR techniques are designed around a different purpose (increased oil production) than carbon sequestration, and therefore the use of EOR for carbon sequestration leads to several intricacies not well discussed in the literature. Dooley and colleagues arguments are highlighted below, and some are further expanded upon in subsequent sections of this paper: Although depleted oilfields may be ideal for the lateral and vertical confinement of CO 2 due to their proven trap (or seal), these fields carry additional risks due to the multiple well-bore penetrations. Operators must account carefully for carbon balances with quantitative methods such as lifecycle analysis tools: the gap between simply injecting CO 2 to increase oil recovery and injecting it to ensure it will not enter the atmosphere is 5

11 not trivial and cannot be addressed by a simple mass balance of [CO 2 volumes] (pp.10). Instead, operators need to undertake a careful analysis of fugitive and vented emissions at different stages of the operation, track and manage produced CO 2 emissions, and employ sophisticated methods to track the fate of injected CO 2. If an EOR project is to be considered for carbon sequestration, more costs are incurred throughout the project during pre-injection, co-injection, and postinjection activities are required in addition to standard EOR project operation. In some cases, CO 2 -EOR is unlikely to appreciably offset the cost of CO 2 emissions mitigation. Dooley and colleagues (2010) appreciate that the body of knowledge offered by CO 2 - EOR projects may prove useful in the development of CCS technologies, but indicate that CO 2 -EOR is not necessarily a fundamental step in the development of the long-term sequestration industry. 2.2 The Enhanced Oil Recovery Process The CO 2 -EOR process begins with the injection of CO 2 into an injection well by applying pumping pressure (Hovorka, 2010). The liquid or supercritical CO 2 is forced into the producing formation through well perforations, typically at depths of 800m to 3,000m below the surface. The CO 2 moves away from the injection well and interacts with the oil in the manner described above. The region of CO 2 saturated oil is called the oil bank, and it is in that region of decreased viscosity oil that production wells are placed. An EOR operation will consist of a pattern of injection and production wells. These patterns are developed with advanced analytical and geological models, which are also essential for estimating production rates and volumes (and thereby contributing to the financial viability of the project). Some CO 2 and water or brine are produced along with the oil in the production wells (Aycaguer et al, 2001; Hovorka, 2010). Separation facilities must be used to capture the 6

12 CO 2 that flashes out of solution to a gas at the production well. The separation facilities consist of retention vessels, and rely on phase change, heat, and some other chemical processes to completely separate the gases, oil, and water. The crude oil is separated for sale. In a Water-Alternating Gas process (WAG), where the CO 2 flood alternates with a water flood, the water is recycled for re-use in the injection process. In other cases it may be separated for disposal. The gas processing stage may be more complex, as hydrogen sulfide (H 2 S), methane, butane, or other light hydrocarbons may be produced along with the CO 2. The CO 2 and H 2 S are separated from the methane and other valuable gases, and then the CO 2 is recycled for re-use in the injection phase of the EOR process. The recovery and reuse of CO 2 is more economical than purchasing fresh CO 2 and venting the produced CO 2 to the atmosphere (Aycaguer et al, 2001). The lifetime of a CO 2 -EOR project can be in the order of magnitude of a few decades (Hovorka, 2010). Some basins in Texas have sustained injection since 1972, and by all indications, will continue to sustain injection into the future. The long lifetimes of these EOR projects provide extensive opportunities for carbon sequestration. However, the long lifetimes provide challenges in the context of awarding carbon credits, as offsets may be awarded on timeframes of 5 20 years. EOR project lifetimes may extend through several iterations of protocols and policies addressing CO 2 emissions reductions, or carbon offset regimes and accounting protocols. In the case of the Permian Basin project in West Texas, Aycaguer et al (2001) estimate that optimal production over a 40-year project life will require the injection of 5.5 kg of CO 2 per recovered kg of oil. Approximately 2.6 kg of CO 2 are produced with each kg of produced oil; over the 40-year project life, the re-use of this CO 2 can supply 43% of the cumulative CO 2 needed. The specific quantities of CO 2 needed and produced per kg of oil produced vary by reservoir and also by operation techniques. Furthermore, the efficiency of the CO 2 recycle depends on the handling losses of CO 2 associated with separation, equipment maintenance, connection points, or from equipment malfunctions 7

13 (Hovorka, 2010). In an EOR project designed purely for the production of additional oil, these CO 2 losses would not necessarily be accounted for. Therefore, Hovorka (2010, pp. 5) stipulates that if CO 2 -EOR is to be part of a sequestration operation, additional inventory process losses of CO 2 during handling from the point of sale through the whole system would be needed. 2.3 Types of CO2 Floods CO 2 -EOR flooding is developed in stages, by selectively injecting only certain wells in a pattern (Hovorka, 2010). The pattern of injections may depend upon information provided by geophysical models, the availability and/or price of CO 2, or the availability of investment capital. An EOR project can be adjusted operationally to optimize oil recovery, minimize costs, or even optimize CO 2 sequestration. Hovorka (2010) speculates that the availability of anthropogenically derived CO 2 may have an impact on CO 2 availability and price, and therefore indirectly have an effect on how EOR projects are staged. EOR floods can be described based on the mechanism of oil displacement; that is to say, as miscible floods or immiscible floods (Hovorka, 2010). As indicated above, minimum miscibility pressure (MMP) is the injection pressure at which the CO 2 in the reservoir will form a single phase with the contacted oil (to enable its production) (Anderson, 2010). Flooding at pressures below the MMP is referred to as immiscible flooding and flooding at pressures above the MMP is referred to as miscible flooding. The majority of industry experience exists with miscible flooding, even though it requires more CO 2. Miscible flooding requires the injection of CO 2 at pressures to meet the MMP plus a little bit (Anderson, 2010). Miscible flooding can be described as a multiple contact process, because the light oil fractions vaporize into the injected CO 2, and the CO 2 condenses into the oil phase. The low interfacial tension, low viscosity, and enhanced mobility of the resulting miscible fluid are what enable the production of further hydrocarbon resources (Godec, 2011). 8

14 Immiscible processes involve several mechanisms, including oil phase swelling (as the oil becomes saturated with CO 2 ), viscosity reduction of the swollen oil, extraction of lighter hydrocarbons into the CO 2 phase, and fluid drive plus pressure (Godec, 2011, pp.6). Immiscible processes result in less production than miscible processes (as only a portion of the reservoir fluids can be produced), although it is still a financially viable process in many instances (Godec, 2011). As indicated above, a variation of the CO 2 -EOR process is a technique called Water- Alternating-Gas (WAG), which is described in depth by Aycaguer et al (2001) in their discussion of the application of this method in the Permian Basin of West Texas. In essence, this method involves injecting water alternately with CO 2, in order to divert CO 2 to different areas, sweep additional oil, and contribute to the maintenance of reservoir pressure. 2.4 Challenges Associated with Long Term CO2 Storage from EOR CO 2 Sequestration Process during EOR Of interest in the context of this study is the extent to which the EOR process can be used for CO 2 sequestration, and by what mechanisms CO 2 is sequestered. This section outlines some of the studies examining the operational parameters favoring CO 2 sequestration during EOR, the mechanisms by which CO 2 is entrapped, and some examples from the Permian Basin in West Texas. Several authors have described the results of laboratory or modeling exercises aimed at optimizing the sequestration of CO 2 during EOR processes. Ghoodjani and Bolouri (2012) for example enumerate several variables that affect the amount of CO 2 sequestered: Location of the injection wells within the producing reservoir: injection into the lower regions of a formation resulted in higher rates of CO 2 sequestration and 9

15 delayed breakthrough time (the time until injected CO 2 is produced along with the oil). Injection pressure: increasing injection pressure, up to approximately the MMP, resulted in both higher volumes of oil production and higher volumes of CO 2 storage. Ghoodjani and Bolouri concluded that optimum injection pressure is near miscible pressure for both oil recovery and CO 2 sequestration (pp. 749). Babadagli (2006) also agrees that miscible injection is desirable for storage and recovery if the required pressure is practically applicable (pp. 266). Reservoir temperature: in a higher temperature reservoir, oil viscosity will be lower and therefore oil recovery will increase. However, in a simplistic sense, a higher temperature results in a lower density of CO 2, leading to lower amounts of CO 2 sequestered. Timing of flooding: in terms of the production life of a particular reservoir, earlier implementation of CO 2 flooding (relative to water flooding) leads to higher rates of CO 2 storage, although the authors also concluded that WAG techniques contribute to higher oil recovery. Ghoodjani and Bolouri (2012) also identified other operational factors that may play a role in determining the amount of CO 2 sequestered, including: the ratio of horizontal to vertical permeability of a reservoir; pore size distribution; the addition of nitrogen into the injection mix; the fraction of heavy oil remaining in the reservoir; and the configuration of production and injection wells in the formation. These factors did not affect their results as significantly as the above-described factors. It is possible that different results would be obtained in different geological formations and reservoirs, and that different factors would play a more critical role. The optimization of CO 2 -EOR for CO 2 sequestration, or the co-optimization of EOR processes for both sequestration and oil production, is a complex issue. Significant variability in appropriate operating conditions can be expected for different reservoirs. The mechanisms by which CO 2 is actually trapped underground are well known (Bennion and Bachu, 2005; Ghoodjani and Bolouri, 2012; Hovorka, 2010; Metz et al, 2005). The 10

16 first and most important mechanism is physical trapping, provided by the geological formation and the caprock. Geochemical trapping, or solubility trapping, involves some of the injected CO 2 dissolving in the un-produced oil or naturally occurring water in the formation. Another significant trapping mechanism in the context of EOR projects is the nonwetting-phase capillary trapping, which results from the interaction of CO 2 with other liquids and their binding solids within the reservoir s pore space. Physical trapping also occurs when the CO 2 is retained at depth as a supercritical fluid; extreme CO 2 densities of 800 kg m -3 result in the decrease of buoyant forces that would cause it to rise within the sequestration zone. CO 2 can also be injected into an aquifer through which it migrates very slowly over time; this is referred to as hydrodynamic trapping. Finally, injected CO 2 may undergo the in-situ formation of carbonates, which is referred to as mineral trapping. Mineral trapping is considered the most stable of all mechanisms, but only occurs after significant periods of time. The IPCC is optimistic with respect to the permanence of geologic sequestration of CO 2, indicating that it is likely 99% is likely to remain over 1,000 years in a properly selected and managed geological reservoir. Aycaguer et al (2001) have obtained data on the sequestration of CO 2 in the Permian Basin of West Texas based on continuous monitoring activities. They describe sequestered CO 2 as the difference between the amount of CO 2 injected and the amount of CO 2 produced. These authors are optimistic about the storage capacity of the reservoir, estimating that the reservoir could sequester 3 kg of CO 2 per 1 kg of oil produced. Therefore, if the reservoir had an average production of 7000 bbl/day (1.4 x kg over the reservoir lifetime), then the final CO 2 storage would be 4.2 x kg CO 2. Taking into account the emissions associated with the energy-intensive engines and compressors used in the EOR process, the flaring emissions, and fugitive emissions, the authors still estimate the net storage of CO 2 in the reservoir at 2.6 kg CO 2 per 1 kg of oil produced. As noted above, Aycaguer et al (2001) estimated the need for the injection of 5.5 kg of CO 2 per 1 kg of oil produced. This means that in this formation, the net sequestration works out to be approximately 47% of what is injected. This figure is consistent with approximate ranges presented by other authors (Dooley et al, 2010), although Hovorka (2010) cautions that sequestration potential is very site specific. 11

17 2.4.2 Carbon Accounting One of the most obvious challenges associated with enhanced oil recovery for the purpose of CO 2 sequestration is that of accounting for how much CO 2 has actually been sequestered. As discussed above, 50 67% of the CO 2 that is injected is produced along with the oil (Dooley et al, 2010), most or all of which is recycled into the injection well again. If the aim of the EOR is to sequester CO 2 for the benefit of the atmosphere, then there must be careful monitoring of the aboveground CO 2 handling facilities (from the gas separation plant back to the injection well) for CO 2 losses. Furthermore, assumptions about the ability of the reservoir to sequester CO 2 must be tested over time (Hovorka, 2010). Methods currently used for research must be evaluated for their applicability to EOR projects, such as above-zone, groundwater or soil-gas monitoring. Hovorka (2010) indicates that monitoring very slow leaks from a reservoir may pose a challenge, if the leaks are at rates below detection of currently employed methods. Another carbon accounting consideration is the lifecycle emissions of the project, such as emissions associated with the pumping technology and separation technology, and energy associated with the use of cement and steel for EOR projects. These lifecycle CO 2 issues are addressed in Part 3 of this report Additional Monitoring of the Reservoir The integrity of the caprock, or seal, of the storage reservoir should not be taken for granted, despite its proven ability to hold hydrocarbon resources over time; indeed, Smith et al (2009) identify certifying the integrity of the caprock to be a critical research area. Risks stem from the high injection pressures needed for effective EOR processes, as well as from abandoned or legacy wells that penetrate the producing formation. Anderson 12

18 (2010) discusses risks associated with injecting CO 2 at pressures high enough to reach MMP. High enough pressures may eventually lead to the tensile failure (fracturing), or shear failure, of the confining rock. Project developers should have reasonable confidence in the integrity of the caprock to withstand the injection of fluids at specific pressures to ensure the long-term safety of the operation. The integrity of abandoned wells within the formation is a much more immediate and likely concern for many producing reservoirs (Hovorka, 2010). Currently, uncertainties exist with respect to the long-term performance of abandoned or old wells, so a research priority is the development of risk assessment tools to address these site-specific challenges. Leakage risks from historically abandoned wells arise in several circumstances: well design may have been inadequate to control fluid flow (such as in older wells); construction could have failed to meet design specifications; well maintenance and/or management could have failed; the well could have been improperly abandoned; or finally, in some jurisdictions, there could be a risk of improperly abandoned wells for which documentation is lost (Hovorka, 2010). The extent to which old wells can be retrofitted for the purposes of retaining CO 2 is unknown. However, the high completion standards that apply to new wells significantly reduce leakage risks. Operators can implement surveillance protocols to monitor for potential leaks as EOR processes are underway (Hovorka, 2010). Monitoring the casing pressures at specific wells can be useful for detecting leaks. In addition, geological and hydrogeological monitoring techniques, as well as above-ground methods, can be employed together to provide as complete a picture as possible regarding the ability of a geological formation to retain CO 2. These topics are expanded upon in Part 3 of this report Optimizing for CO 2 sequestration and Stacking Enhanced oil recovery techniques are currently tuned to optimize the production of oil, and much of the new research in the past decade (as discussed above) has explored the optimization of EOR for the sequestration of CO 2, or the co-optimization of the process 13

19 for both sequestration and oil recovery. This would primarily involve a shift from minimizing the injection of CO 2 to maximizing the injection of CO 2 (Hovorka, 2010). This transition may also include changes in operational procedures, such as well spacing, injection rates, gravity displacement, or the speed of development of particular field. One major factor affecting the practicality of CO 2 -EOR using anthropogenic CO 2 is the availability and price of the CO 2. It is unknown how widespread availability of anthropogenic CO 2 would impact the ability to move forward on EOR projects resulting in sequestration (Hovorka, 2010). This is because EOR projects require CO 2 periodically, as they are developed in phases, or stages, whereas sources of CO 2 are producing the gas at a nearly constant rate. Provided that anthropogenic CO 2 is available for sequestration, EOR processes could be modified to enhance sequestration potential of certain reservoirs by making use of stacked storage. Stacked storage makes use of the brine-filled pore space laterally adjacent (the water leg) or below the reservoir. In some fields, higher rates of injection will allow stacked pore volumes to be accessed, as the plume of CO 2 moves outward from the injection pattern. In other formations, the re-completion of injection wells into the water leg, or non-productive strata, may be required to enhance CO 2 sequestration. When CO 2 is available in excess of what is required for enhancing production from the producing formation, there is a potential to use the water legs or stacked volumes to accept the excess of CO 2. In this manner, the CO 2 demand peaks of a CO 2 -EOR project could be moderated. 2.5 Conclusion Enhanced oil recovery processes provide a significant opportunity to store CO 2 underground, and could provide a near-term solution to the geologic storage of anthropogenically derived CO 2, if it were readily available and at an appropriate price. The North American Carbon Storage Atlas indicates that in Canada, oil and gas reservoirs could provide storage capacity for 16 gigatonnes (GT) of CO 2, unmineable 14

20 coal could provide capacity for 6 GT of CO 2, and saline formations could provide capacity for 110 GT CO 2, for a Canadian total of 132 GT CO 2 stored (NACSA, 2011). To give a sense of magnitude, the 16 GT CO 2 storage capacity in oil and gas reservoirs in Canada would provide 70 years of storage if all of the regional CO 2 emissions were captured and stored. Although this is considerable, it is substantially less than the 500 years of storage potential provided by the 110 GT CO 2 storage capacity to be found in saline aquifers. In sum, both oil and gas reservoirs, as well as saline aquifers, provide significant CO 2 storage opportunities in Canada. Challenges still exist with respect to ensuring that the injected carbon is appropriately accounted for, ensuring that the producing formation is appropriate for CO 2 storage, and optimizing the EOR process for CO 2 storage. Although decades of experience with EOR (particularly in Texas) provide a baseline of information on injection techniques and materials handling, further research is needed on historic well remediation, and the modification of the EOR process to prioritize CO 2 sequestration. The literature emphasizes that site-specific geological and geophysical characteristics, as well as the historical use, of the reservoir play significant roles in determining the capacity for sequestration, the operating conditions for EOR processes, and necessary monitoring techniques. 15

21 3: Crediting CO2 Sequestered as a result of CO2 EOR As shown in Part 2, decades of industry experience with CO 2 -EOR have demonstrated the capacity for EOR processes to sequester CO 2 in the producing formation. But several challenges exist when trying to quantify the resulting emissions reductions for carbon crediting purposes. This Part of the paper identifies those challenges based upon a review of the literature and highlights several protocols for calculating net carbon sequestered. This Part also discusses the monitoring, verification, and accounting protocols that could accompany a crediting scheme. 3.1 Net CO2 sequestered from CO2 EOR processes Some of the issues in crediting carbon capture and storage technologies, including EOR processes, involve defining the project boundary, reducing the energy penalty associated with carbon capture, dealing with leaks or fugitive emissions associated with capture, transport and storage processes, ensuring long-term sequestration, and monitoring and verification of the permanence of storage (Lokey, 2009). The literature identifies two important areas of concern in determining whether there are net emissions reductions associated with CO 2 -EOR processes. One concern relates to the energy penalty incurred at the capture site and in subsequent operations. The energy penalty refers to the energy required to separate CO 2 from the power plant stack and compress it for transportation. More fuel must be consumed by the power plant if it is equipped with carbon capture technologies per MWh of electricity delivered to the grid than a power plant without carbon capture technologies (Lokey, 2009). A second concern relates to the emissions associated with the combustion of the incremental hydrocarbons produced as a result of CO 2 -EOR processes. A common methodology for addressing these questions is life-cycle assessment. 16

22 Life-cycle assessment (LCA) methodology has been applied to address a wide range of environmental concerns, and several examples exist in the literature of the application of LCA to carbon capture and sequestration projects (Condor et al, 2010; Corsten et al, 2013; Hertwich et al, 2008). LCA has been standardized in ISO 14040, and generally comprises the four phases of goal and scope definition, life-cycle inventory analysis, lifecycle impact assessment, and interpretation (Condor et al, 2010). In considering the goal and scope definition, several important parameters are defined (Corsten et al, 2013). For example, is the LCA analysis conducted relative to a reference system or baseline, or does it report absolute terms? Does the LCA base analysis on a functional unit (such as kwh of net electricity delivered to the grid)? Finally, what are the system boundaries, or processes that are included or excluded from the LCA? The definition of the system boundaries also determines whether a full or partial LCA is being performed. The life-cycle inventory phase typically includes emissions and resource use from the resource extraction, production, use and disposal phases (Hertwich et al, 2008, pp. 343). In the Impact Analysis stage, the two main assessment methodologies are either problemoriented or damage-oriented, but according to Corsten et al (2013), both methodologies give a similar result when considering the global warming potential of a project. Most of the LCA literature available on the environmental impacts of CCS focuses on projects combining CCS with electrical power generation (Corsten et al, 2013). Because these studies examine CCS technologies from a holistic environmental standpoint, upstream and downstream processes in the CCS chain are also included. Some of these major processes include coal mining, electrical generation and hydrocarbon upgraders (in the case of sequestration via CO 2 -EOR) (Condor et al, 2010). In their review of LCA literature dealing with CCS technologies, Corsten et al (2013) noted that methodological differences resulted in a range of outcomes. The definition of system boundaries, or the inclusion or exclusion of certain processes, proves critical in the outcome of an LCA study. The authors also noted that the applicability of LCA as a tool is limited when there is a lack of transparency regarding data or assumptions used. An understanding of the processes involved (especially with novel technologies) is critical for producing an applicable LCA. The use of different system boundaries is likely one of the primary 17

23 reasons that different studies in the literature report different results when considering CO 2 sequestered during CO 2 -EOR processes. The next section examines studies that conclude that CO 2 -EOR processes may result in net CO 2 emissions CO 2 EOR May Result in Net CO 2 Emissions Certain studies examining the life-cycle emissions from CCS projects that sequester anthropogenic CO 2 (usually from coal-fired power plants) assert that a precise estimate of net GHG emissions must include upstream and downstream activities (McCoy et al, 2011). McCoy et al (2011) indicate that CO 2 -EOR can only be said to reduce GHG emissions if the energy produced (upstream of carbon capture) and incremental hydrocarbons produced replace more GHG intensive fuels. The idea of replaced fuel production is referred to as displacement, which means that the energy or fuels provided by EOR processes do not represent truly incremental production but simply displace other energy that would otherwise be produced. McCoy et al (2011) indicate that it is plausible for fuels produced by EOR to displace other fuels, as the quantity produced is still very small compared to total world oil production. According to McCoy and colleagues (2011), the types of fuel and electricity displaced by the products of CO 2 -EOR determine whether or not there is an emissions reduction associated with CO 2 -EOR processes. If the oil and electricity displaced have high emissions intensity, then the emissions reduction potential of the EOR project is greater than the amount of CO 2 purchased by the project. However, if the EOR-produced fuels are displacing light crude, then the EOR project will result in an emissions increase. The system boundaries were crucial for Jaramillo et al (2009), who examined the GHG emissions associated with using CO 2 captured from power plants for CO 2 -EOR. In accordance with guidelines set out by ISO 14040, their LCA includes emissions associated with the life cycle of the electricity generated within the power plant for CO 2 capture; transport of CO 2 from the power plant to the field; oil extraction; transport of crude oil produced in the field; crude oil refining; and, combustion of the refined 18

24 petroleum products (pp. 8027). This methodology was applied to five CO 2 -EOR projects within the United States and Canada, including the SACROC Unit in the Kelly Snyder Field, as well as the Weyburn Unit, and found that the net GHG emissions for each plant were positive (meaning more CO 2 was emitted than sequestered). Figure 3.1 below shows the relative contributions to life cycle emissions of the different procedures included in the life cycle inventory for the SACROC and Weyburn fields. From Figure 3.1 below, it is clear that the two units (SACROC and Weyburn) have a similar emissions profile but differ in magnitude, and Jaramillo and colleagues (2009) indicate that this is also the case for the other three units studied. The combustion of petroleum products and the coal power plant emissions are the two largest contributors to the CO 2 emission in the LCA, both of which are larger in magnitude than the CO 2 sequestered during EOR. EOR operations and refinery operations combined do not equal the magnitude of CO 2 sequestered in either case. Emissions generated upstream of the coal plant, CO 2 transport, and crude oil transport are all relatively small in both cases. Jaramillo and colleagues (2009) calculated that for every tonne of CO 2 injected, between 3.7 and 4.7 tonnes of CO 2 are emitted. The authors suggest that in order for a CO 2 -EOR project to be net zero, a sequestration project could be operated concurrently to the EOR project, by injecting produced CO 2 into an adjacent water leg or other appropriate formation. By taking into account all life cycle stages, Jaramillo and colleagues (2009) demonstrate that CO 2 -EOR results in significant net emissions. They assert that a thorough understanding of ultimate displacement is necessary before anyone can suggest that CO 2 - EOR is a sequestration technique (pp. 8032). McCoy et al (2011) suggest that if efforts are to be spent on sequestration activities for the benefit of the climate, deep saline sequestration would be much more worthwhile than geologic sequestration through CO 2 - EOR. 19

25 Figure 3.1: Relative contributions of the components of Life Cycle GHG Emissions for the SACROC and Weyburn EOR projects (from Jaramillo et al, 2009). The key question raised in studies such as Jaramillo et al (2009) and McCoy et al (2011) is whether a full life cycle assessment of CO 2 -EOR is an appropriate way of determining CO 2 sequestered from EOR processes for the purposes of carbon crediting, and in particular, whether such LCAs should include the incremental oil consumption produced as a result of the EOR operation CO 2 EOR May Result in Net CO 2 Sequestration There are several studies that indicate that including downstream oil refining and consumption is inappropriate when considering CO 2 -EOR for sequestration. Faltinson and Gunter (2011) discuss a ring fence (analogous to project scope) when considering project life cycle emissions. They believe that downstream emissions common to all oil supplies should be excluded. Burdening CO 2 -EOR projects with downstream refining and consumption emissions would suggest that CO 2 -EOR oil is incremental to total world oil supply from all other sources, and CO 2 -EOR oil consumption emissions would increase world aggregate oil-consumption emissions. World oil supply is determined by 20

26 world oil demand, and CO 2 -EOR oil will simply displace other oil from other higher-cost sources (i.e. not be produced in addition to it) (pp. 59). Condor et al (2010) describe this as the oil industry view, and from this perspective emissions from consumption should be seen as the responsibility of the consumer. Studies that exclude upstream coal mining and downstream oil refining from their life cycle inventory, or ring fence, conclude that CO 2 -EOR does sequester CO 2 in the subsurface, even when considering project emissions (Faltinson and Gunter, 2011). Emissions associated with CO 2 -EOR processes may include the burning of fossil fuels on location to power equipment used (such as compressors), on-site consumption of off-site generated electricity, and fugitive or vented emissions (planned or accidental). Hertwich and colleagues (2008) prepared a hybrid LCA to address environmental concerns associated with a natural gas fired power plant combined-cycle power plant with post-combustion capture, pipeline transport, and injection into a North Sea oil field for EOR. They determined that the proposed power plant with carbon capture would have substantially lower greenhouse gas emissions than a similar power plant without carbon capture technologies. They also determined that EOR processes that use CO 2 from the power plant result in reduced GHG emissions per barrel of oil produced. In this manner, Hertwich et al (2008) demonstrate that CO 2 -EOR not only results in sequestration, but also the efficient use of already producing reservoirs. Faltinson and Gunter (2011) agree: from a climate-change-mitigation viewpoint, the more CO 2 -EOR oil supply sources in the mix of total world oil supply, the better (pp. 60). In summary, a fundamental disagreement exists within the literature as to whether CO 2 - EOR can or should be considered a sequestration technique. Full life cycle assessment techniques that take a broad view of the entire project chain demonstrate that there are net project emissions, due in large part to downstream oil consumption. Studies that exclude downstream oil refining processes and consumption (common to all sources of oil), and upstream emissions associated with the business-as-usual electrical generation, find that CO 2 -EOR processes sequester more CO 2 than that which is emitted due to project energy 21

27 usage. From a policy standpoint, a clear decision about the appropriate project assessment boundaries is critical for carbon accounting purposes. This decision must inform the development of specific protocols which can be used to quantify net emission reductions (or increases). 3.2 Additionality and the Determination of a Baseline In addition to determining whether CO 2 -EOR processes deliver a net benefit to the atmosphere, it is also important for carbon crediting purposes to determine net sequestration relative to a baseline or business-as-usual (BAU). A baseline must be drawn temporally as well as with respect to emissions levels and sequestration targets. A baseline is determined based on a reasonable prediction of anthropogenic greenhouse gas emissions that would occur without a greenhouse gas emissions reduction project (Baker & McKenzie, n.d.). Sequestration above and beyond such a baseline may count as additional in multiple senses: Emissions reduction additionality occurs when anthropogenic greenhouse gas emissions reductions exceed what could be expected without the emissions reduction project (Baker & McKenzie, n.d.). Financial additionality occurs when the revenues from carbon credits or offsets are necessary to make the project financially viable. If the project would not have existed in a BAU setting, then the project fulfills the criterion of financial additionality (Lokey, 2009). Regulatory additionality means that the project and its associated emissions reductions are not required by law. A project that is mandated by law would be considered BAU and would have existed regardless of whether it could earn offset revenues (Lokey, 2009). The determination of a baseline (and the subsequent determination of additionality) is a policy question as much as a technical question. Jurisdictions can and do choose to deal with baseline determination in different ways; for example, one can designate emissions reductions as carbon offsets, or simply designate them as tonnes of greenhouse gases not 22