Ch#1 - SPE-126446-MS CO2 EOR Industry Application

8/19/2019 Ch#1 - SPE-126446-MS CO2 EOR Industry Application

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SPE 126446

Industry Experience With CO2-Enhanced Oil Recovery TechnologyR.E. Sweatman, Halliburton; M.E. Parker, ExxonMobil; and S.L. Crookshank, American Petroleum Institute

Copyright 2009, Society of Petroleum Engineers

This paper was prepared for presentation at the 2009 SPE International Conference on CO2 Capture, Storage, and Utilization held in San Diego, California, USA, 2–4 November 2009.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not beenreviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, itsofficers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission toreproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment o f SPE copyright.

Abstract

This paper provides substantial and compelling evidence from API (American Petroleum Institute) CCS (Carbon Capture &Storage) Work Group and other studies of CO2 EOR (enhanced oil recovery) and CCS projects showing that CO2 capture,transport, and (GS) geologic-sequestration can be a safe and effective method to reduce GHG (greenhouse gas) emissions andmitigate climate change. The paper summarizes how the oil and gas (O&G) industry has achieved great success inengineering the process to capture, transport, and inject CO2 in EOR projects. This success is seen in over 37 years of safeand environmentally friendly large-scale operations, lessons learned, technical advancements, and millions of tons of CO2 injected. Third party investigations to evaluate this successful record are discussed, including some completed ones that have published statements validating the O&G industry’s success. Now that CCS is being widely considered and a few countrieshave begun to implement commercial-scale CCS projects, technology transfer efforts such as this paper are needed to sharethe experience of the oil and gas industry and the major contribution it can make as part of the solution for climate change.

Introduction

H istori cal Overview.Since the first patent for CO2 EOR was granted in 1952 (Whorton), the O&G industry has spent many tens of billions of

dollars developing and implementing CO2 EOR technologies, asset development, and operational experience. As new sourcesof CO2 have become available, field testing and demonstration or pilot project activities have been conducted. Thesedevelopment and improvement efforts have been continuous since the first project in 1964. The first large-scale, commercialCO2 EOR project began operations in 1972 at the SACROC field in West Texas, which continues in operation today. Manymore have started since then and by 2008 had reached a total of 112 projects, as reported in the EOR Survey by the Oil andGas Journal (O&GJ, 2008). Since 1952, numerous patents, best practices, equipment, and products have been developed forCO2 EOR well construction and injection/production operations. Innovative, cost-effective materials, equipment, andmethods continue to be developed and implemented such as the recent introduction of real-time, smart-well operations atSACROC. Much of this knowledge has been documented in hundreds of technical papers and several books that have been published on the subject including many applicable API standards and specifications.

CO 2 EOR Technology for CCS Deployment.

Underground geological storage of CO2 is a promising technology for reducing greenhouse gas (GHG) emissions becausemuch of the technology developed by the oil and gas industry associated with natural gas processing and CO2 EOR cansupport the sound implementation of CCS and huge storage capacity exists in deep saline formations, depleted oil and gasreservoirs, and unmineable coal seams. According to a major report by the Intergovernmental Panel on Climate Change(IPCC, 2005), as much as 55 percent of a worldwide GHG mitigation effort thru 2100 could be achieved through carboncapture and storage. The IPCC also expresses confidence that CO2 can be stored safely over very long periods of time andcites several studies as evidence that the potential for leakage decreases the longer the CO2 is underground.

The IPCC clearly considers CO2 EOR as a form of underground CO2 storage. In CO2 EOR, storage occurs as CO2 displaces hydrocarbons from reservoir pore spaces and the injected CO2 is trapped within the reservoir’s pore spaces throughcapillary forces and other mechanisms. CO2 EOR projects can also be easily converted to CCS projects at the end of their


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operating lifetimes. Accordingly, the petroleum industry, with a long history of successful CO 2 EOR operations, can makesubstantial contributions to improve and accelerate the deployment of CCS projects.

The petroleum industry processes and experiences relevant to CCS include separating (or capturing) CO2 from oil ornatural gas production, pipeline transportation to EOR projects, and design and operation of surface and subsurface systemsfor injection of CO2. Figure 1 shows a map of the 3,500+ mile network of CO2 pipelines in the United States and Canada.The yellow shaded areas represent many of the sources of CO2 from both underground reservoirs and from above-ground

sources such as plants processing ammonia, treating natural gas, and gasifying coal.

Figure 1. CO2 pipeline network from Figure 5 in SPE 113975 by Mohan et al

Recent estimates by Kinder Morgan show that 655 million tons of CO2 have been injected in EOR projects over the past37 years, which is an average of 17.7 million tons per year. This amount is equivalent to the total CO 2 emissions of four tofive 500 MW capacity coal-fired, electric power plants. Currently, the O&GJ EOR Survey reports that 15,373 wells (94% ofall CO2 EOR wells) including 9,144 producing and 6,229 injectors are operating in 105 CO2 EOR projects in the UnitedStates and 975 wells (6% of all CO2 EOR wells) in 7 projects in other countries. Figure 2 is a photograph of portion of a CO2

EOR surface facility owned by PEMEX in Carmito, Mexico that has been safely and effectively recovering CO2 for over tenyears from nearby fields’ hydrocarbon producing wells and compressing it for pipeline distribution to CO 2 EOR project wellsin the area.

Figure 2. PEMEX’s CO2 EOR facility was commissioned in 1998 with compressors, membrane separators, and distribution viamanifolds for pipelines and well flowlines in Carmito, Mexico.


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Industry CCS Activities

Oil and gas industry companies participate in research consortiums and fund research at major universities to answer thetechnical and policy questions surrounding GHG management, including carbon capture and storage. The Carbon DioxideCapture Projects (CCP & CCP2), Gulf Coast Carbon Center (GCCC), CO 2Remove, Carbon Mitigation Initiative, and theGlobal Climate and Energy Project (GCEP) are prominent examples of such consortia. API is continually developingrecommended practices, standards, and other information to ensure the ongoing safe and environmentally sound operation of

CO2 EOR operations. These same standards and practices, based on extensive industry experience should help anygovernment agencies or regulators prepare sound rules for CO2 injection facilities and wells. Additionally, API and IPIECA(International Petroleum Industry Environmental Conservation Association) have developed guidance on accounting for CO 2 emission reductions associated with CO2 storage projects.

Industry has years of experience injecting CO2 in quantities

comparable to that produced from a large coal-fired power plant.

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EOR; Geologically Sourced CO2

500 MW Coal-fired Electric Power Plant Emissions

FIGURE 3. CO2 injection by large commercial scale CO2 EOR projects compared to CO2 sequestration needed for a large powerplant

CCS and CO2 EOR Studies

API Studies of CO2 EOR Operations in the United States.

Some groups have voiced concerns about embracing geologic storage of CO2 without a thorough understanding of the potential for impacting Underground Sources of Drinking Water (USDW). Although sufficient evidence exists to argue thatCO2 injection and storage over long time frames can be accomplished with very low risk to USDWs, the API recognized theneed for a comprehensive publication to document CO2 EOR best practices and technologies, and to substantiate the case forsustained well integrity and CO2 containment within oil and gas and other reservoirs. Key arguments supporting this case

include: 1) oil and natural gas (including CO2) have been trapped in geologic structure over geologic time frames, 2)numerous other gas storage projects (e.g. sour gas injection, natural gas storage) have been successfully accomplishedwithout adverse impact to USDWs and 3) years of enhanced oil recovery (EOR) experiences have produced technologies,expertise and procedures for safe and environmentally sound CO2 handling, and injection well construction, operation, andmaintenance.

In 2007 the API completed a study to compile CO2 EOR injection well technologies representing the state of the art. Asurvey of operators, representing most of the projects in the United States, was conducted to better document best practicesand to review records of successful performance. The API published the study’s findings in a report titled “Summary ofCarbon Dioxide Enhanced Oil Recovery (CO2 EOR) Injection Well Technology,” (API, 2007). The report can bedownloaded from the API website and contains detailed information on how the O&G industry has successfully constructed


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and operated CO2 EOR projects. Subsequent work by the API CCS Workgroup and other API committees, such as the RP 65Task Group, discovered even more information to help explain the successful history of CO2 EOR operations.

In conducing the API study the contractor surveyed CO2 EOR project operators with a number of questions designed tocapture best practices and operational performance. Specific questions regarding performance are listed below: Injection Well Performance/Integrity

o Workovers (nature/frequency)?

o Typically encountered problems and failure rate, that is, out of X wells, Y problems are encountered?o Unique (non-standard problems) that have been identified and resolved?

Safety Practices and Performanceo Monitoring practices for tubing and casing including: standardized or mandated tests, as well as site specific tests

(open valve on casing, PSH, etc.)?o Incidents that have occurred?o Workover “kill” practices?o Contingency plans?

CO2 Confinement in the Reservoiro Any CO2 leakage observed (injectors, abandoned wells, seepage, etc)?

Survey results included many findings that had not been clearly presented before, particularly in the context of theconcerns around CCS. For example, to cement wells, CO2 EOR operators have used Portland cement-based well cementsystems almost without exception and significantly, without adverse loss of CO

2 containment. These cost-effective,

conventional cements were designed to have sealing and structural support properties suitable for the CO 2 EOR application. No evidence of chronic leaks into USDW zones or into the atmosphere were found. CO2 well operators gave testimonialsclaiming no USDW contamination and reported that their well design and construction practices prevented the endangermentof USDW and the atmosphere. Ongoing work by the U.S. Department of Energy (DOE) and the Gulf Coast Carbon Center isfurther validating these claims.

It is generally accepted that injected CO2 will react with the in-situ formation water to create a weak carbonic acidsolution, which is the basis for much of the concerns raised regarding CCS. Following the formation of the weak acidsolution, several potential chemical reactions are possible, many of which could occur concurrently. Some investigatorsclaim that CO2 EOR and CCS storage reservoirs have corrosion conditions represented by the chemical equations below:

CO2 (aq) + H2O H2CO3 (Carbonic acid) Equation (1)

H2CO3 + C-S-H (*) amorphous silica gel + CaCO3↓

H2CO3 + Ca(OH)2 (**) CaCO3↓ + 2 H2O

aq = aqueous solution of CO2 in pure water * C-S-H (calcium-silica-hydrate) compounds are major components in Portland cements.** Calcium hydroxide in set Portland cement.

The double arrow indicates that the first equation is reversible and the amount of carbonic acid formed can decreasedepending on conditions such as temperature and pressure. The amount of carbonic acid formed from injected CO2 maytypically be less than 1% by volume and often only 0.2% of the total volume of CO2 (Ho et al). Another representation of thechemical reactions involving CO2 in pure water is presented below by Ho et al at Yale University and includes the respectiveionization constants:

H+ HCO3-

H2O CO2+

+ H2CO3

k 23 k 32k 13 k 31

k 12

k 21


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However, geochemists and others have found that the above equations don’t fully represent the complexity of thegeochemical reactions that occur within geologic storage reservoirs. The reactions depicted in the equations below occurwhen CO2 contacts the dissolved ions (mineral salts, etc) present in the formation brine waters and the mineral surfaces of therock inside the formation porosity and permeability.) Subsurface mineralization work (Hangx , 2005) included the followingseries of possible geochemical reactions of subsurface brine waters where the bicarbonate from carbonic acid reacts withcations present in the reservoir water to form stable carbonates in the mineralization process with the following examples:

The in-situ formation water's salinity and mineral content can substantially effect the amount of carbonic acid formed because CO2 molecules have difficulty hydrating and are easily buffered compared to those mixed in fresh water in metal orglass lab containers or testing devices. For example, the carbonic-acid-induced pH of CO2 mixed in pure or other inert watersolutions in laboratories is lower (more acidic) than would actually be present in underground formations primarily due to thelower CO2-induced carbonic acid content from buffering action by materials found in formation fluids and the reservoir rocksurfaces. Cations from mineral salts and combinations of them present in reservoirs can limit decreases in the brine water’s

pH from CO2 injection through mineral buffering and sustain much less corrosive environments than some researchers haveclaimed (Duguid, 2004).

Actual pH values of fluids in contact with well cements and pipe may average between 4.5 and 5.5, which are consideredweakly acidic conditions compared to the much more acidic conditions created in lab tests by some researchers and byunrealistically-low calculated values by some software models that attempt to predict pH conditions. In 2008 at theInternational Energy Association (IEA) GHG R&D Program’s Joint Network meeting, Czernichowski-Lauriol et al presentedthe IEA Modeling Network’s progress in peer reviewing various software models. This presentation included work done byAudigane et al for the Sleipner CCS project offshore Norway which predicted the maximum decrease in pH by supercriticalCO2 injection into the Utsira saline aquifer would be to a value no lower than 5.13 over 10,000 years.

Smyth et al and Lu et al worked on the same CO 2 geochemical laboratory testing project at the Gulf Coast Carbon Center,Bureau of Economic Geology, Jackson School of Geosciences, The University of Texas at Austin (BEG/UT). Both report

that under simulated geochemical conditions pH values can drop rapidly when CO2 is introduced, and then rebound to highervalues as shown in Figure 4a. Regarding R1 (Smyth et al and Lu et al) in Figure 4a, Smyth et al states that: “In Reactor 1, forexample, pH (initially) dropped from over 7.9 to 4.8 within hours after introduction of CO 2, then rebounded and remained at~5.4. The pH rebound is probably due to mineral buffering, in this case dissolution of dolomite and, to a lesser extent, potassium feldspar.” Lu et al refined the pH vs time data presentation in the paper by Smyth et al to report it as Figure 4a in asecond paper. Some of the refinements include deleting R5 and renumbering the reactors presented in the paper by Smyth etal. For example, R8 and R9 in the paper by Smyth et al are R6 and R7 in the paper by Lu et al. R7 in Figure 4a is from asample that did not contain buffering minerals. Therefore, pH is low (as low as 3.2) and constant during the experimentwithout buffering minerals. These lab-generated pH values help explain why higher than expected pH values in Figure 4bwere measured in a U-tube device under downhole conditions at the Frio CCS test project (Hovorka et al, 2005). The mineral buffering effect may typically occur in storage and EOR reservoirs and should be simulated in lab testing procedures for wellmaterial (cement, pipe, etc.) selection and in software modeling applications to predict corrosive conditions (pH vs. time)during all phases of the project, i.e., CO2 injection operations, site closure after CO2 injection is finished, and the post-closure

phase for long-term monitoring of CO2 containment. The actual pH will depend on the particular type of formation and theassociated mineralogy. Hence the formation type, formation fluid and rock minerals should be understood in detail toevaluate the downhole pH.


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Figure 4a. Simulated geochemical conditions in laboratory tests of pH values vs time by Lu et al showing the rebound in pH whenCO2 is introduced on day 14. (Courtesy of Gulf Coast Carbon Center, Bureau of Economic Geology, Jackson School of Geosciences,The University of Texas at Austin)

Figure 4b. Frio CCS test project measurements of pH via U-tube device in an observation well showing the higher than expected pHwhen the CO2 plume arrives at the well. (Courtesy of Gulf Coast Carbon Center, Bureau of Economic Geology, Jackson School ofGeosciences, The University of Texas at Austin)

These weak in-situ acidic conditions help explain why operators have successfully used Portland cement-based systems toseal and support wells in CO2 EOR projects. The extreme degradation of cement common in many lab test results is likely


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due to the absence of mineral buffering and not matching other reservoir conditions. Investigators mentioned in the followingsections have found additional reasons why cement and pipe are protected from carbonic acid-induced corrosion.

Zonal Isolation and Well Integrity Studies by API RP 65 Task Group.

During the last nine years, representatives from government, academic, and industry organizations of the API Task Groupon Annular Flow Prevention studied the causes and prevention of annular flow incidents and sustained casing pressure (SCP)in wells, which are recognized indicators of poor well cement integrity. Two API recommended-practice publications (RP-65

Parts 1 and 2) were prepared and approved that describe preventive measures for any potential flow zone in any type of wellincluding those in CO2 zones. Preventative measures include key well planning, drilling, mechanical barrier, and cementing practices designed to help ensure cement integrity and isolation of potential flow zones. SPE 97168 (Bannerman et al, 2009) provides an overview of these best practice documents that may be adopted by regulators to approve well construction permits. RP 65 Part 1 has already been adopted by the MMS and published in its entirety in the U.S. Federal Register.

Achieving cement integrity and zonal isolation in the presence of a potential annular flow of CO2 requires not only themodification of the cement properties to facilitate control of migrating formation fluids and CO 2 but also several other practices including:

• A stable wellbore: no fluid losses or gains prior to, during, and after the cementing process

• Adequate annular circulating flow clearances to prevent abnormal displacement pressures

• Proper mud/hole conditioning prior to cementing to remove cuttings, gelled mud, and excessive filter-cake

• Spacer designs that help remove mud and leave pipe/formation surfaces water-wet for better cement bonds

•

Casing centralization to allow better placement of cement all around the pipe• Proper tripping requirements to prevent negative effects by excessive swab/surge pressures

• Proper drilling techniques to ensure hole quality and minimize washouts, spiraling, and ovality

• Well monitoring to ensure cementing pressures, pump rates, and densities meet designed values

• Waiting on cement (before start of well operations) for a sufficient time period to allow undisturbed cement curing

• Use of mechanical barriers when appropriate to overcome problematic conditions

Application of RP 65 practices can minimize the risk of CO 2 migration as a result of the multiple pressure barriersinstalled in wells in the form of multiple casing strings from the surface of the well to its total depth, mechanical pressure- barrier devices (packers, etc), and the cemented sections around each pipe. For example, each cemented section can createmultiple pressure-barriers. Every few feet in length of cemented annular intervals across competent-sealing formations suchas shales is strong enough to hold hundreds of psi pressure exerted by CO2 from the reservoir. For example, a typical 500-foot long cemented annulus can provide hundreds of short-sealing intervals that work together to prevent catastrophic failures

of well integrity The chances of all of the short-intervals failing to seal are infinitesimal. Note also that RP 65 effectivelydeals with preventing natural gas (NG) migration which is much more difficult to prevent than CO 2 migration. This is because NG is an inert gas with more buoyancy than chemical reactive CO2 molecules which can seal leak pathways by precipitating CaCO3 scale.

Studies Show Pipe Corrosion Minimized by Portland Based Cements.

The O&G industry has more has 60 years of experience in protecting carbon-steel pipe in well tubing and flowlines fromcorrosion by acidic fluids by lining the pipe with Portland-based cement systems. This cement-lined pipe is used to prevent both dry and wet CO2 from contacting the inner surfaces of carbon-steel pipe in both EOR injection and production wells. Inthe 1970s and 80s, cement-lined well tubing and flowlines dominated the “CO2 EOR-service” pipe market for injection and production wells including CO2 EOR wells. One pipe manufacturing company (cement-lined pipe website) in West Texasreports on their website that cement-lined well tubing and flowlines in excess of 80 million feet of pipe have been utilized byoperators since the late 1940s and in the last 12 years more than 24 million feet have been installed. New types of plastic-

linings have been introduced and have a major share of the well pipe market for handling sour fluids. However, severalmillion linear feet of cement-lined pipe continues to be installed each year.

Portland cement-based systems are commonly used to cement casing in CO2 EOR wells. Long standing successfulexperience with Portland based cements in these applications suggests there are mechanisms working to protect both thecement and the tubulars from excessive corrosion. One potential mechanism is autogenous healing, also called self-sealing.The chemical properties of Portland cement based systems lead to reactions that prevent CO 2 contacting the pipe, thus protecting pipe from corrosion. The cement self-seals by reacting with the CO2 to form an impermeable carbonated layer inthe cement lining inside well tubing, surface flowlines, and outside of well casing and liner pipe. The impermeable,carbonated layer prevents carbonic acid attack on the surfaces of the carbon steel pipe. This technology was introduced in the1940s for acidic-service wells for both well construction and production applications. It has been applied in many CO2 EOR projects in the United States during the 37-year history of commercial-scale CO2 EOR operations and in earlier smaller–scaleCO2 “huff-n-puff” treatments. For example in 1964, Runyan reported that "cement-lined tubing is impervious to any normal


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oilfield water, including very sour waters. Erosion due to high flow rates presents no problems." Later in 1969, Beachreported the development of cement/flyash/sand linings for steel pipe that are "uniform, strong and inert." A few years later in1973, Schremp tested cement-lined pipe in water-alternating-gas (WAG) supercritical CO 2 flows and reported "cementlinings showed no evidence of deterioration or separation from the pipe wall. There also was no indication of stratification orspalling of the cement." In 1977, Newton studied cement-lined pipe applications at SACROC and said, "Although the CO2 content of the produced water has increased, no deterioration of the cement lining has been noted." This technology’ssuccessful applications also help explain the O&G industry’s great HSE operational performance record including the

containment of CO2 inside EOR reservoirs. This CO2 EOR well integrity technology and field-proven practices are equallyapplicable for CCS projects. O&G industry experience also challenges the claims of cement degradation when CCS operators properly design Portland-cement based formulations that do not dissolve or erode away when exposed to wet CO2-inducedacidic fluid flows in injection or production wells. Sweatman et al provides more information on this cement designtechnology and experience in paper SPE 126226 and others are outlined in API Report, “Summary of Carbon DioxideEnhanced Oil Recovery (CO2EOR) Injection Well Technology,” (Appendix 2 - Descriptions of API Cements and SpecialtyCements.)

U.S. EPA Funded Studies.

At U.S. Environmental Protection Agency (EPA) and IEA meetings in March 2007, Koplos et al presented a wellintegrity study of Underground Injection Control (UIC) injection wells that included data from EPA studies of Class II (CO 2 EOR) injection well mechanical integrity tests (MIT) and reported “No reported USDW impacts associated with wells withany known internal or external MIT failures in the 1983-1992 period.” MIT are measurements of the pressure sealing performance (max 5% loss in 30 mins) in one part of the well such as “Annulus A” which is the area sealed at the top/bottom by the wellhead/packer and between the injection tubing and the well casing. The Koplos study also conducted an analysis ofthe MIT data in the 1983-2005 time period for all Class II CO2 injection wells in Texas as shown in the table below. This paper’s authors added the data in the last two columns of Table 1 below for a better comparison on a yearly basis. The dataalso shows the number of failed MIT that passed after maintenance repairs were made (avg. 75%) to seal them vs. those thatwere not put back into active service (avg. 25%) and instead were sealed by being plugged and abandoned (P&A).

Table 1 - Texas UIC Program MIT Data - Class II CO2 EOR Wells (1983-2005)Period of Years # of CO2 Injection Wells # of Failed MIT % of Failed MIT # (%) Each Year # Sealed / P&A

1983 - 1995 3324 135 in 12 years 4.1 in 12 years 11 (0.33) 8 / 3

1995 - 1999 3432 46 in 4 years 1.3 in 4 years 12 (0.34) 9 / 3

2000 - 2005 3978 298 in 6 years 7.5 in 6 years 50 (1.26) 38 / 12

The significance of this data is that MIT failures are rare and, where they do occur, effective response or repairtechnologies exist that protect underground water resources. Koplos et al performed other studies for EPA to help prepare thedraft Class VI rules for CO2 injection wells in CCS projects. A recent EPA Notice announced its proposed rules posted in theFederal Register for Class VI wells for geologic storage of CO2 in CCS projects which included the following statement: “There have been no documented cases of leakage from these projects” [since the UIC (Underground Injection Control)Program started in the mid-1980s]. This conclusion supports the O&G industry’s outstanding record of no USDW oratmospheric endangerment by CO2 emissions from CO2 EOR projects.

Other Studies of CO2 Containment.

The IEA GHG R&D Program’s Monitoring Network reported on soil gas sampling measurements at the Rangely fieldCO2 EOR project and concluded that the total amount of CO 2 leakage from the EOR zone was less than 0.01% over 15 yearsof CO2 EOR operations. The IEA report also stated that there is no evidence of CO2 leakage from the storage reservoir atother CCS projects including Weyburn, Frio, and Sleipner. One depleted oil well in the West Pearl Queen Field in NewMexico was found to leak CO2 at less than 0.1% per year as a result of sealing integrity damage caused by an overpressureevent. However, other CO2 well integrity studies summarized by Sweatman et al provides an extensive amount of evidenceof sustained sealing success. Another significant study by Smyth et al at BEG/UT is ongoing to evaluate CO2 containment bythe confining zones surrounding the EOR reservoir at 6,000 to 7,000 ft depth and by the several hundred EOR wells’ sealingintegrity at the SACROC CO2 EOR project. The study involves a water well and groundwater monitoring program of periodically sampling drinking water from USDW zones above the CO2 zone. Smyth et al reported that water sample testingfrom 68 wells and one spring indicate that no CO2 leakage from the EOR zone has occurred into the USDW zones in the fieldafter 35 years of CO2 injection operations..

BEG/UT is also starting a study of UIC Class II CO2 injection well integrity records in Texas to double check that nosignificant well integrity issues or CO2 leakage has occurred during the UIC program’s history. A recent GHGT-9 paper byDuncan et al at BEG/UT, 2008, reported on CO2 leakage risk assessment and blowouts (accidental flows) and concluded thatthe risk is very low and in all 24 of the reported temporary blowouts during the last 37 years, no damage to USDW or life


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threatening asphyxiation had occurred. One of the 24 incidents occurred during the drilling of a new well and the othershappened during workover rig or other well operations in existing wells. This paper’s authors considered the 24 incidentssince 1983 against the total amount of operating CO2 EOR wells and calculated a negligible incident frequency rate at anestimated 0.0087% of wells per year. Duncan et al concluded that “The CO2-EOR industry has an excellent safety record.”

Finally CCP has been studying the effects of CO2 on well integrity via a wellbore sampling and laboratory analysis program underway since 2006. In a GHGT9 paper (Crow, 2008), a comprehensive study was described and conclusions

presented following an investigation of a 30-year old well from a natural CO2 production reservoir. The types of informationcollected in this survey permitted analysis of individual components (casing, cement and reservoir fluid and pressuremeasurements) for comparison to the larger scale system including the interfaces. Effective placement of the Portland-fly ashcement system was a key element in the observed performance of a barrier system confirmed as having provided effectivehydraulic isolation.

The above discussed studies add up to an overwhelming amount of compelling evidence to validate the O&G industry’sgreat HSE performance record in CO2 EOR and CCS operations. This evidence should be broadly disseminated to help public and interested organizations understand the significant contribution the O&G industry can make to the mitigation ofclimate change and enhancement of energy security

API Collaboration can Improve HSE Performance for CCS Projects

The API welcomes new opportunities to improve industry’s HSE performance and has supported all interested parties in suchefforts. For CCS projects, the API provided valuable information to the U.S. DOE, EPA, and environmental NGOs on CO2 EOR technology and best practices that will help ensure successful HSE performance. The API’s activity in CCS alsoincludes providing comments to government authorities in the legislative and executive branches. Accordingly, theinformation from API and other studies may benefit the decision process for developing and commercializing CCS projectsand GS well construction, operations, and abandonment technology.

Sound Development Practices for CCS.

The O&G industry has a great record in sound development (SD) for operational surface facilities and wells inenvironmentally and politically sensitive site locations. This may usually involves the use of HSE and well integrity standardindustry practices with more oversight by local regulators and community representatives.

Sensitive Sites.

Unlike solar and wind energy equipment and facilities, O&G wells, rigs and other structures can be hidden from public

view in order to satisfy concerns regarding unattractive industrial facilities and the effect on community interests such astourism and residential property values. O&G surface facilities and wells can also avoid environmentally sensitive locationssuch as wildlife habitats in marshes and other wetlands. This is accomplished by drilling many directional wells from a singlelocation that is not near the sensitive area or that can be made to look like an office building or from totally submerged“subsea” structures built offshore on the seafloor. Examples of safe and environmentally sound oil and gas operations beingconducted in sensitive areas can be found in many parts of the world. Similar approaches are equally viable for CCS projects.Extended reach drilling technology can also enable CO2 to be safely injected many miles from a surface location viadirectional wells from hidden facilities along the shore or on nearby islands and injected into storage reservoirs far away from populated shorelines. For example in Figure 5 (Sakhalin-1), Exxon Neftegas Limited (ENL), a subsidiary of ExxonMobil,drilled and completed an extended reach, offshore well at the Sakhalin-1 oil project on Russia’s east coast in the Chayvo fieldwhich set a record distance from shore of nearly 7 miles (11 km). Extended-reach technology allows wells to begin verticallyon land and then curve to horizontally under the seabed to offshore reservoirs. This well was named the Z-12 well with a totalvertical depth of 8,350 ft beneath the Sea of Okhotsk and a rig-to-reservoir distance of 38,322 ft, which is equivalent to 125

US football fields.


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Figure 5. Yastreb drilling rig on the left and subsurface well schematic on the right for the Z-12 well in the Sakhalin-1 oildevelopment project at Sakhalin Island offshore Russia. (Courtesy of ExxonMobil)

Monitoring and Modeling for Long-Term Well and Reservoir Integrity Assurance

The O&G industry has developed a highly sophisticated suite of technologies for petroleum operations that can be applied toCO2 storage integrity monitoring applications. These intermittent and long-term monitoring methods include: wireline

conveyed logging tools run in production, injection, and monitoring wells; seismic array data imaging; wellbore pressuremonitoring by wellhead and downhole gauges; injection and production volumetric monitoring by flowmeters; subsurface tosurface deformation measurements via tiltmeters and satellite radar; gravity surveys; etc. The applicability of thesetechniques is site-specific and selection thereof requires an understanding of the site’s subsurface characteristics, as well asthe measurement capabilities of the various techniques in order to match the site’s monitoring, verification, and accounting(MVA) objectives. A site’s MVA program should adopt monitoring practices that are consistent with the leakage riskassessment made during the site characterization phase, e.g., tailored to address the purpose of the monitoring and thespecific conditions and potential risks at the storage site. When multiple methodologies are available, selection shouldconsider the most cost-effective methods that meet the MVA objectives and regulatory requirements.

Monitoring, whether direct (e.g. observation wells) or indirect (e.g. seismic), can only evaluate limited geographicalareas/points at a point in time. Computer modeling serves as a proxy for visualization of what cannot be seen and for predicting CO2 plume movements in the future. These models are verified by monitoring techniques and improved by periodic calibration to actual monitoring data. Monitoring confirms and informs the models that ultimately provide the basisfor developing confidence during the injection, closure and post-closure phases of the CCS process.

Example MVA Case History at In Salah (Courtesy of Iain Wright, BP, and Phillip Ringrose, StatoilHydro)

Introduction.

The Krechba field is one of eight gas fields comprising the In Salah Gas project in Algeria which includes an industrial-scale CO2 storage project that has been in operation since 2004 (InSalah, 2009). CO2 from several gas fields, which have aCO2 content of 5-10%, is removed from the production stream to meet the sales gas export specification of 0.3% CO 2. Ratherthan vent that separated CO2 to atmosphere (as was normal industry practice for such gas plants), BP and its Joint Venture(JV) partner, Sonatrach, invested an incremental $100 million in a project to compress, dehydrate, transport and inject thatCO2 into a deep saline formation down-dip of the producing gas horizon. StatoilHydro then joined the JV at production start-up in August 2004. The investors derive no commercial benefit from the CO2 storage at In Salah, so it is being used as an

experimental and demonstration project – to learn about CO2 geological storage in deep saline formations.The injection formation (Figure 6) is a 20-metre thick Carboniferous sandstone, 1900m below ground with around 15% porosity and 10mD permeability. Three state-of-the-art horizontal CO2 injection wells were drilled perpendicular to the stressfield, and therefore the dominant fracture orientation, to maximize the injection capacity. By the end of 2008, over 2.5million tonnes of CO2 had been stored underground. A Joint Industry Project (JIP) was set up to monitor the CO2 storageusing a variety of geochemical, geophysical and production techniques over an initial 5-year period.


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Figure 6. Carbon Dioxide Injection and Storage at Krechba, Algeria.

Monitoring Results to Date.

Monitoring data includes geological, geochemical, geophysical, and satellite data (Figure 7). Standard oil industrygeological characterization data have been acquired, including wireline and LWD well logging suites, core sampling, and 3D

seismic. Geochemical monitoring data collected to date include surface and soil gas monitoring, down-hole gasmeasurements (head gas and isotubes samples), and production monitoring. Different tracer chemicals (perflurocarbons) have been used to “tag” the CO2 injected at each injection well, so that any CO2 detected, can be differentiated from the naturalCO2 in the sub-surface and traced back to an individual injection well. Geophysical monitoring data will gain momentum in2009 with the deployment of a down-hole geophone detector string in a dedicated well to monitor microseismic events, andthe first time-lapse 3D seismic survey to monitor saturation and pressure changes.


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Figure 7.

Perhaps the most valuable, and initially surprising, monitoring method so far has been the use of satellite airborne radarinterferometry to detect subtle ground deformation above the injection wells (Mathieson et al. 2008). Permanent scattererinterferometry is a multi-interferogram approach that draws on the phase changes occurring between a series of radar images


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and is specifically designed to overcome the effects of atmospheric noise and thereby determine surface movement historiesover periods of several years (Vasco & Ferritti, 2005). Permanent scatterer interferometry gives an accuracy of around5mm/year and up to 1mm/year for a longer term average. Another related approach is differential interferometry, whichmeasures changes in a single interferogram developed from two radar images.

Surface uplift has been detected over all three of the In Salah CO2 injection wells (Vasco et al. 2008; Onuma & Ohkawa2008 and Rutqvist, et al. 2008) with corresponding subsidence also observed over the gas production area. Figure 7 showsone of the first permanent scatterer interferometry datasets based on a two year time sequence of data (Vasco et al 2008). The

observed surface uplift rate is around 5mm/year. Forward and inverse modelling (Rutqvist, et al. 2008) of the subsurface pressure increase due to CO2 injection, demonstrates that the surface deformation is consistent with measured geomechanicaldata, and is caused by propagation of the subsurface pressure increase through the overburden rock sequence to the surface.In fact, similar millimeter-scale surface movements can be detected over most onshore oilfields as well as numerous civilengineering projects, such as bridges, causeways and tunnels. Using the satellite observations, we are able to indirectly“image” the subsurface plume propagation which follows the expected elongation along the NE-SW fracture direction(Figure 7). Onuma & Ohkawa (2008) have also derived surface deformation data for this site using differential interferometryand a continuous synthetic aperture radar data acquisition programme is underway.

More information on the MVA project at In Salah can be found in publications cited above and those listed as references below under (In Salah and Wright et al). Note that paper SPE 127096 (Wright, 2009) presented at the same conference as this paper will have more information on In Salah and its MVA project. In addition, an article written by Terry Knott on the InSalah project including the MVA work is presented at BP’s public webpage as listed in the references below under (InSalah).

Conclusions

This paper is based on industry data obtained and studied by the API CCS workgroup. The O&G industry experience with CO2 EOR has lead to the development many technologies and operating practices

that are relevant to CCS. Industry CO2 EOR operations successfully demonstrate large scale injection of CO 2 in volumes necessary for

commercial scale CCS. O&G industry experience in CO2 EOR injection wells demonstrates wellbore performance and integrity equal to or

better than that seen with conventional O&G wells as noted by multiple studies that confirm industry’s success. Evaluations of CO2 EOR operations, including well integrity performance specific to CO2 EOR, have shown these

operations to be fully protective of the environmental medium. Our experience with CO2 EOR demonstrates the effectiveness of conventional (established practices and accepted

standards) oilfield cements in both dry and wet CO2 environments. The available studies show significant buffering of pH occurs from the reactions within underground formation rock

surfaces and in-situ waters which appear to limit corrosive effects of injected CO2 EOR. API RP 65 provides numerous practices to help ensure the successful placement of well cements and long-term sealing

integrity of wells including those for CCS. Example projects (Sakhalin and In Salah) show that when sound operating practices and technology are applied,

environmental concerns regarding risk and site integrity can be addressed.

Acknowledgements

This paper is based on industry data obtained and studied by the API CCS workgroup and the authors thank the workgroupfor their contributions.. The authors thank their respective employers, API, ExxonMobil, and Halliburton, for their support in preparing this paper. Special thanks also goes to Rebecca Smyth and Jiemin Lu at the Gulf Coast Carbon Center, Bureau of

Economic Geology, Jackson School of Geosciences, The University of Texas at Austin for Figures 4a and 4b, to BrianWilliams at BP for permission to add content for the In Salah case history, to Iain Wright (BP) and Philip Ringrose(StatoilHydro) for writing the MVA case history on the In Salah project, to Terry Knott (BP) for content and Figures 6 and 7from his article in the December 2008 issue of BP’s “Frontiers” magazine (see In Salah reference below), to ExxonMobil for permission to use their Sakhalin photo and schematic in Figure 5, and to BP, StatoilHydro and Sonatrach (JIP) for permissionto use their In Salah information and graphics in Figures 6 and 7.

References

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Audigane, P., Gaus, I., Czernichowski, L.I., Pruess, K. and Xu., T.: “Two-dimensional reactive transport modeling of CO 2 injection in asaline aquifer at the sleipner site, north sea,” American Journal of Science, 307(7):974–1008, 2007.

Bannerman, M., Calvert, J., Griffin, T., Levine, J., McCarroll, J., Postler, D., Radford, A. and Sweatman, R.: “New API Practices forIsolating Potential Flow Zones During Drilling and Cementing Operations,” paper SPE 97168 at the SPE Annual TechnicalConference and Exhibition held in Dallas, Texas, U.S.A., 9 – 12 October 2005

Beach, H.J., Frawley, Jr., F.E., EnDean, H.J. and Yates, D.: “Causes and Prevention of Failures in Cement Pipe Linings,” Journal ofPetroleum Technology (paper SPE 2478 in 1969), January 1970, pp. 51-57

Cement-lined pipe website: http://www.permianenterprises.com/content/view/14/33/

Crow, W., Williams, B., Carey, J.W., Celia, M. and Gasda, S.: “Wellbore integrity analysis of a natural CO2 producer,” presented atthe 9th International Conference on Greenhouse Gas Control Technologies (GHGT-9), Washington, D.C., November 16-20,2008.

Czernichowski-Lauriol, I. and Marquette, G.: “Modelling overview for CO2 storage,” presentation at the IEA GHG R&D Joint NetworkMeeting held in New York, NY, USA, 11-13 June 2008.

Duguid, A., M. Radonjic, R. Bruant, T. Mandecki, G. Scherer, and M. Celia, “THE EFFECT OF CO2 SEQUESTRATION ON OIL WELLCEMENTS” presented at Greenhouse Gas Technologies Conference (GHGT-7), Vancouver, Canada, 5-9 September, 2004.Download at: http://www.regulations.gov/fdmspublic/component/main?main=DocumentDetail&o=09000064807b6eb4

Duncan, I.J., Nicot, J.P., Choi, J.W.: “Risk assessment for future CO2

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U.S.,” presented at the 9th International Conference on Greenhouse Gas Control Technologies (GHGT-9), Washington, D.C., November 16-20, 2008. GCCC Digital Publication Series #08-03i

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Hangx, S.J.T.: “Subsurface mineralisation: Rate of CO2 mineralisation and geomechanical effects on host and seal formations,” HPTLaboratory, Department of Earth Sciences, Utrecht University, Submitted to Shell International Exploration and Production (leaderCATO WP 4.1). Work performed in the framework of Shell contract 4600002284, December 2005

Ho, C., and Sturtevant, J.M.: “The Kinetics of the Hydration of Carbon Dioxide at 25º C,” from the Department of Chemistry, YaleUniversity, New Haven, Connecticut and published in THE JOURNAL OF BIOLOGICAL CHEMISTRY, Vol. 238, No. 10, October1963

Hovorka, S.D., Collins, D., Benson, S., Myer, L., Byrer, C. and Cohen, K.: “Update on the Frio Brine Pilot,” presented at the 4 th AnnualConference on Carbon Capture & Sequestration held in Alexandria, Virginia, 2-5 May 2005

In Salah CCS Project – MVA Case History written by Iain Wright (BP) and Philip Ringrose (StatoilHydro), 7 August, 2009.In addition, an article by Terry Knott on the In Salah project including the MVA work is presented at BP’s public webpage:http://www.bp.com/sectiongenericarticle.do?categoryId=9027098&contentId=7049642 The same article was published in issue 23 of the BP magazine “Frontiers” on pages 18-25, December, 2008. Wright et al paper SPE127096 listed below and cited in the MVA section also has relevant information on the In Salah project.

International Energy Association (IEA) GHG R&D Program’s Monitoring Network Workshop Report at the University of California inSanta Cruz, California, 8-9 November, 2004

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New Mexico, 12-13 March, 2007

Lu, J., Partin, J.W., Hovorka, S.D. and Wong, C.: “Potential risks to fresh-water resources as a result of leakage from CO 2 geologicalstorage—a batch-reaction experiment,” manuscript submitted to Environmental Geology and not yet accepted for publication.

Mathieson, A., Wright, I., Roberts, D. and Ringrose, P.: “Satellite imaging to monitor CO2 movement at Krechba, Algeria,” EnergyProcedia, Volume 1, Issue 1, February 2009, Pages 2201-2209 and Greenhouse Gas Control Technologies 9, Proceedings of the 9thInternational Conference on Greenhouse Gas Control Technologies (GHGT-9), 16–20 November 2008, Washington DC, USA. Availablefor download at: http://www.sciencedirect.com


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Mohan, H., Carolus, M. and Biglarbigi, K.: “The Potential for Additional Carbon Dioxide Flooding Projects in the United States,” paperSPE 113975 presented at the 2008 SPE/DOE Improved Oil Recovery Symposium held in Tulsa, Oklahoma, U.S.A., 19-23 April

Newton, Jr., L.E. and McClay, R.A.: “Corrosion and Operation Problems, CO2 Project, Sacroc Unit,” paper SPE 6391 prepared for thePermian Basin 0il and Gas Recovery Conference of the Society of Petroleum Engineers of AIME held in Midland, Texas, March 10-11, 1977

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Onuma, T. and Ohkawa, S.: “Detection of surface deformation related with CO2 injection by DInSAR at In Salah, Algeria," in Proceedingsof the 9th International Conference on Greenhouse Gas Control Technologies, 16–20 November 2008, 2008. Available for download at:http://www.sciencedirect.com

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Rutqvist, J., Birkholzer, J.T. and Chin-Fu Tsang,: “Coupled reservoir–geomechanical analysis of the potential for tensile and shear failureassociated with CO2 injection in multilayered reservoir–caprock systems,” paper in International Journal of Rock Mechanics and MiningSciences, Volume 45, Issue 2, February 2008, Pages 132-143 and doi:10.1016/j.ijrmms.2007.04.006. Available for download at:http://www.sciencedirect.com

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Sakhalin-1, project information provided with permission from ExxonMobil. See more information from the ExxonMobil website at:http://www.exxonmobil.com/Corporate/energy_project_russia.aspxAlso relevant information is in a published document that can be downloaded from ExxonMobil’s public website at:http://www.exxonmobil.com/Corporate/files/news_pub_poc_sakhalin.pdf

Smyth, R.C., Hovorka, S.D., Lu, J., Romanak, K.D., Partin, J.W., Wong, C. and Yang, C.: “Assessing risk to fresh water resources fromlong term CO2 injection – laboratory and field studies,” paper GCCC Digital Publication Series #08-03j, presented at the 9thInternational Conference on Greenhouse Gas Control Technologies (GHGT-9), Washington, D.C., November 16-20, 2008. Downloadfrom BEG/UT website: http://www.beg.utexas.edu/gccc/bookshelf/2008/GHGT9/08-03j-Final.pdf

Sweatman, R., Santra, A., Kulakofsky, D. and Calvert, J.: “Effective Zonal Isolation for CO2 Sequestration Wells,” paper SPE 126226 presented at SPE International Conference on CO2 Capture, Storage and Utilization, San Diego, CA, 2-4 November, 2009

Vasco, D.W., Ferretti, A. and Novali, F., “Reservoir monitoring and characterization using satellite geodetic data: Interferometric SyntheticAperture Radar observations from the Krechba field, Algeria,” paper LBNL-308E, Lawrence Berkeley National Laboratory, 2008. This

paper is posted at the eScholarship Repository, University of California:http://repositories.cdlib.org/cgi/viewcontent.cgi?article=7553&context=lbnl

Vasco, D. W., and Ferretti, A.: “On the use of quasi-static deformation to understand reservoir fluid flow,” Geophysics, 70, O13-O27, 2005

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Wright, I., Mathieson, A. and Ringrose, P.: “An Overview of Active Large-Scale CO2 Storage Projects,” paper SPE 127096 presented atSPE International Conference on CO2 Capture, Storage and Utilization, San Diego, CA, 2-4 November, 2009

Ch#1 - SPE-126446-MS CO2 EOR Industry Application

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