# GENERAL TECHNICAL SUPPORT DOCUMENT

FOR INJECTION AND GEOLOG IC SEQUESTRATION OF CARBON DIOXIDE PROPOSED RULE FOR MANDATORY REPORTING OF GREENHOUSE GASES

Office of Air and Radiation U.S. Environmental Protection Agency March 2010General Technical Support Document for Injection and GeologicSequestration of

Carbon Dioxi de: Proposed Rule for Mandatory Reporting of Greenhouse Gases

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### Table of Contents 1. Source Description ................................ ................................ ................................ ................ 3 2. Overview of Source Category ................................ ................................ .............................. 4 2.1 Geologic Sequestration
................................ ................................ ....................... 4 2.2 Enhanced Oil and Gas Recovery
................................ ................................ ........ 4 2.3 Other Industries that Use CO 2 ................................ ................................ ............. 5 2.4 Types of Data to be Reported
................................ ................................ ............. 5 3. Options for Reporting Threshold ................................ ................................ ........................ 6 3.1 ThresholdAnalysis
................................ ................................ ............................. 6 4. Monitoring Methods Considered ................................ ................................ ....................... 11 4.1 CO 2Injection
................................ ................................ ................................ .... 11 4.2 CO 2Production at ER Operations
................................ ................................ ..... 12 4.3 Fugitive and Vented CO 2Emissions
................................ ................................ . 12 4.4 CO 2Leakage to the Surface
................................ ................................ .............. 14 4.4.1 Reservoir Modeling
................................ ................................ .................. 14 4.4.2 Environmental Baselines
................................ ................................ .......... 15 4.4.3 Monito ring Technologies for CO 2Detection and Quantification
............. 16 4.4.4 Leak Detection and Quantification in the Offshore Environment
............ 28 4.5 Detection Limits and Accuracy of Various Technologies
................................ 31 Attachment A ................................ ................................ ................................ .............................. 34 Attachment B ................................ ................................ ................................ ............................... 37
List of Figures Figure 3

- 1. Total CO 2 used in Enhanced Recovery showing growth since 2004..
............. 8 Figure 4

- 1. Example of a Vertical Radial Plume Mapping Configuration Setup
............ 26
List of Tables Table 3

- 1. Threshold Analysis Based on Amount of CO 2Injected
................................ .. 11 Table 4

- 1. Surface Components as CO 2Emissions Sources at Injection Facilities
.......... 13 Table 4

- 2: M onitoring T echnologies as D eployed at 10 E xisting CCS P rojects
............. 17 Table 4

- 3. Example of Leak Quantification Using Tenting and Known Test Gas Flow
.. 23 Table 4

- 4. Detection Range, Accuracy, and Precision of Various Monitoring Technologies
................................ ................................ ................................ ..................... 32General Technical Support Document for Injection and GeologicSequestration of

Carbon Dioxi de: Proposed Rule for Mandatory Reporting of Greenhouse Gases

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### 1. Source De s cription Preliminary estimates indicate that the amount of carbon dioxide ( CO 2 ) captured from industrial processes , including combustion and chemical manufacturing, and produced from naturally

- occurring subsurface CO 2reservoirs is approximately 40.6 million metric tons carbon dioxide equivalent ( MMTCO 2 e )
. 1 2Currently more than 95% of th is CO 2 supplied to the economy is injected underground for enhance d oil and gas r ecovery (ER). 3 The remaining estimated CO 2 supply is captured and used for non

- E R applications. 4 In addition , captured CO 2 may beinjected underground for the purpose of geologic sequestration (GS), or the long term containment of a gaseous, liquid, or s upercritical CO 2 stream in subsurface geologic formations
. GS is one of a portfolio of options that could play an important role in mitigating CO 2 emissions. Data on captured or produced CO 2 supplied to the economy will be reported to EPA through subpart

PP of the Mandatory Reporting for Greenhouse Gases Rulemaking (MRR) ( 74 FR 56260 ). Subpart PP is applicableto all facilities with CO 2 production wells, facilities with production process units that capture and supply CO 2for commercial applications or that capture and maintain custody of a CO 2stream to sequester or otherwise inject it underground, and to importers and exporters of bulk CO 2 . During the public comment period on the rulein 2009 , EPA received many comments on subpart PP indicating that un dergroundinjection and GS of CO 2 should be considered when estimating emissions from the CO 2 supply industry. R eporting on CO 2injection and GS would p rovide information and transparency on the amount of CO 2 injected and geologically sequestered in theUnited States. In combination with other subparts of the MRR , these data would enable EPA to track the flow of CO 2across carbon dioxide capture and sequestration (CCS) system s , monitor the growth and efficacy of GS (and therefore CCS) as a mitigation te chnology over time , and evaluate relevant policy options. Informationwould b e reconciled with data on CO 2 supplied(reported under subpart PP of the MRR) to better understand the quantity of CO 2 supplied to emissive and non

- emissive end

- uses. Lastly, CO 2injection and GS data would i nform policy decisions under the Clean Air Act related to CCS as a climate mitigation tool. This technical support document (TSD) is focused on outlining options associated with incorporating reporting on CO 2 injection an d GS in the MRR. In addition, EPA

1 U.S. EPA Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks, 1990

- 2007, Report, EPA 430

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- 004. Available at: http://epa.gov/climatechange/emissions/usinventoryreport.html 2The estimated 40.6 million metric tons of CO 2does not include biogenic CO 2. 3 U.S. EPA Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks, 1990

- 2007, Report, EPA 430

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- 004. Available at: http://epa.gov/climatechange/emissions/usinventoryreport.html 4EPA 2008. Inventory of U.S. G HG Emissions and Sinks 1990

- 2006. April 15, 2008. EPA 430

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- 005. Washington D.C.General Technical Support Document for Injection and GeologicSequestration of

Carbon Dioxi de: Proposed Rule for Mandatory Reporting of Greenhouse Gases

4 considered reportingon other end uses of CO 2that could also bepotentially non

emissive. 

### 2. Overview of Source Category Three sectors were considered for inclusion in subpart RR: injection of CO 2 underground for GS, injection of CO 2underground to enhance recovery of oil or gas, and end use s of CO 2 by other indus tries
. 2.1 Geologic Sequestration Carbon capture and sequestration involves capturing CO 2from industrial facilities, combustion source facilities, or waste treatment process facilities, purifying and compressing the CO 2 , transporting it (usually by means of a dedicated CO 2pipeline) to an injection site, and injecting the CO 2into an underground geologic formationfor long

term containment
. Undergroundgeo logic formations that can be used for GS include saline aquifers, depleted or active oil and natural gas reservoirs , and unmineable coal seams
. In addition, CO 2 may be injected into other types of subsurface geologic formations, such as basalt formations. Geologic sequestrationoccurs through a combination of structural and stratigraphic trapping, residual CO 2 trapping, solubility trapping, mineral trapping, and preferential adsorption trapping. These mechanisms are functions of the physical and chemical properties of CO 2 and the geologic formations into which the CO 2is injected. For more background information on GS, s ee the V ulnerability E valuation Framework for Geologic Sequestration of Carbon Dioxide( see docket ID No. EPA

- HQ

- OAR

- 200 9

- 0 926). 2.2 Enhan ced Oil and Gas Recovery Carbon dioxide is currently being injected into subsurface geologic formations in the U.S. for the purposes of CO 2 - based e nhanced oil andnatural gas r ecovery (ER). The CO 2 currently being used in ER is primarilyproduced from n aturally

- occurring underground CO 2 reservoirs but is also captured from natural gas processing plants and ammonia plants
. ERinvolves injecting CO 2into oil or natural gas reservoirs via injection wells for the purposes of increasing crude oil productio nor to enhance recovery of natural gas
. The crude oil and CO 2mixture is produced from production wells and sent to a two phase separator where the crude oil is separatedfrom the gaseous hydrocarbons and CO 2 . The gaseous CO 2 - rich streamthen is typical ly dehydrated , recompressed, and reinjected into the oil or natural gas reservoir to further enhance recovery. If the concentration of hydrocarbons in the CO 2 stream from the dehydrator is significant , thenan acid gas recovery unit is used to separate ou t the hydrocarbons from the CO 2 .General Technical Support Document for Injection and GeologicSequestration of

Carbon Dioxi de: Proposed Rule for Mandatory Reporting of Greenhouse Gases

5 Injection of CO 2 into unmineable coal seams may result in displacement of methane (CH 4 ) from the coal seam and subsequent production of the methane as a product (or enhanced coal bed methane (ECBM )). There are currently80 enhanced oil and natural gas recovery fields operating in the U.S. where CO 2 is being injected for the purposes of enhanced recovery. 5 Enhanced recovery projects operating in the U.S. range from new pilot scale projects with one or two injection wells to CO 2 floods that commenced operation in the 1970s and that have hundreds of injection wells. Approximately 40 million metric tons of CO 2 was injected underground for ERin 2008. Of this amount approximately 80 percent was produced from naturally

- occurring underground CO 2reservoirs and 20 percent was captured from combustion or industrial process sources. 6 2.3 Other Industries that Us e CO2 EPA identified and considered a total of 22 commercial end use sectors 7 that use gaseous, liquid, or solid CO 2 , e xcluding ERand GS
. These e nd use sectors are summarized in Appendix A
. For the purposes of this background document, these sectors were not considered likely candidates for reporting at this time. EPA received comments to subpart PP suggesting that at least one of

these end

- uses
– precipitated calcium carbonate (PCC) production

– may be a non - emissiveuse . EPA does not have enough information at this time to conclude whether PCC production or any other industrial end

- use (other than ER and GS) perman ently sequester s CO 2 . EPA is seeking data and information on how many facilities operate in these industries; how much CO 2 would be sequesteredusing these technologies ; whether sequestration factor s would be reasonable in either case; and what methodolog ies could be applied to verify CO 2 sequestration. 2.4 T ypes of Data to be Reported In a mandatory reporting system, d ata on CO 2 injection could be reconciled with data on CO 2 supplied to better understand the quantity of CO 2supplied to emissive and potentially non - emissive end

- uses. The types of data to be reported from all facilities that inject CO 2 c ould include the quantity of CO 2transferred to the facility from offsite

5 See Appendix B of this technical support document. 6U.S. EPA Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks, 1990

- 2007, Report, EPA 430

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- 004. Availabl e at: http://epa.gov/climatechange/emissions/usinventoryreport.html 7 This count includes the various chemical, pharmaceutical, and other processes that use CO 2as an end product and excludes intermediate CO 2processors.. After carbon dioxide is capturedfrom production process units or produced from natural reservoirs for subsequent commercial application, it is generally purified, compressed, and liquefied before being delivered for a multitude of end use commercial applications. This processing is done so that end users can input the CO 2into their processes in the necessary state, e.g., food grade CO 2used for food and beverage production. Intermediate processors often receive the produced CO 2from the production process units or natural reservoirs, pu rify, compress, and/or liquefy it, and then deliver it to end users. Intermediate processors are not discussed further in this TSD.General Technical Support Document for Injection and GeologicSequestration of

Carbon Dioxi de: Proposed Rule for Mandatory Reporting of Greenhouse Gases

6 locations , the amount of CO 2 that is injected into the subsurface at these facilitie s, and the source of that CO 2 (e.g. industrial process or combustion process ). In addition to basic reportingon CO 2 injection, certain additional data could enable EPA to monitor the growth and efficacy of GS
. This c ould include information to underst and the quantity of injected CO 2that is permanently sequesteredat a GS facility
. M onitoring of the injected CO 2would be necessary to demonstrate that it is remaining sequestered underground, and in the unlikely case that some of the injected CO 2does l eak from the formation , to quantify the amount of the leak
. At an ER operation that is also reporting sequesteredCO 2 , the amount of CO 2 sequestered in a year woul d exclude the quantity of CO 2 that is removed from the reservoir, as well as any leakage fro m the subsurface. Emissions from surface equipment at CO 2injection facilities could result from a variety of sources. These sources couldinclude:
 C ombustion of fuel in the driver for the compressors or pumps and combustion of fuel for heaters and boi lers
 V enting from compressors, pumps, and pipelines; and
 Fugitive emissions from components (such as valves, connectors, etc.) and pipeline leaks. If the CO 2 injection facility is an ER operation(i.e., producing crude oil or natural gas), vent edand fug itive emissions from surface components could more specifically include : V enting from pipeline s and separator s , and V enting of gas dissolved in the crude oil (in cases where gas is used as stimulant) If an acid gas recovery unit is used, emissions could result from venting from the glycol dehydrator vent
. 

### 3. Options for Reporting Threshold To determine the appropriate threshold for reporting under s ubpart RR, EPA considered both a threshold based on the amount of CO 2emitted and a threshold based on the amount of CO 2 injected underground. EPA concluded that an emissions

- based threshold would be problematic because of the lack of data on the incidence and scale of surface emissions and leakage from injection and GS of facilities
. Therefore EPA did not con duct this analysis for the TSD. EPA accordingly analyzed injection facilities based on the quantity of CO 2 injected underground. 3.1 Threshold Analysis EPA analyzed injection facilities based on the quantity of CO 2injected underground and considered wh ether an injection threshold should apply. EPA evaluated a no threshold option (i.e. all facilities that inject CO 2 would be required to report) ; 1,000 metric tons per year, 10,000 metric tons per year, 25,000 metric tons per year, and 100,000 metric tons per year per facility of CO 2 injected. Only facilities expected to be operating in 2011, the first year of reporting under this proposal , were considered in the analysis.General Technical Support Document for Injection and GeologicSequestration of

Carbon Dioxi de: Proposed Rule for Mandatory Reporting of Greenhouse Gases

7 To establish a count of CO 2 injection facilities , EPA relied ondata reported inthe Oil and Gas Journal (O&GJ) Enhanced Oil Recovery Surveypublished in April 2008 8

. These data come from the results of a voluntary survey of oil producers reporting miscible and immiscible CO 2 projects in the U.S. operating as of the end of 2007. TheO&GJ survey asked for the production figures "as of the end of 2007". For projects that were active throughout 2007 the value represents annual production (12 months). Several of the projects started mid year, or had scheduled downtime in 2007 , so the reported annual 2007 production may represent only a partial year of production. Production data was not pro
- rated to come up with an annual estimate. Some projects starting late in the year did not see any increase in crude oil production due to enhancedoil recovery operations, or were unable to measure it. These were noted as "TETT" (Too Early To Tell) in the O&GJ survey. In a few cases companies did not report crude oil production data to the O&GJ. The O&GJ did not specify how the production data wa s to be calculatedby the reporting facilities , so most of it is based on internal oil company reporting which is consistent with state Oil and Gas Commission reporting requirements. The O&GJ left it up to the companies to define a "project" when they rep orted data
. Most “projects” are defined based on production reporting requirements to state Oil and Gas Commissions, based on the unit or pool. Some stateOil and Gas Commission s finely divide the production zones in order to manage resource conservation. In one operation in Michigan, for example, the fields are very small (2

- 5 wells each ) because they target pinnacle reefs which are limited in their extent. The company reported two "projects" separately to the O&GJ even though they are located in the same field because it appears that they target different producing zones within the same formation. A somewhat different situation exists for the Seminole field in West Texas , where several projects are listed. These projects are in different geographic l ocations within the large Seminole field, and target different parts of the reservoir ( i.e., main oil pay or residual oil) using different CO 2 injection technologies. These are identified as “ Pilot tests ” in the O&GJ data, so the company considers them sep arate projects for evaluation purposes. Depending on how "project" or "facility" is defined, they could be separate or combined. The use of CO 2in ERhas increased significantly since 2004 , (Figure 3

- 1) and is expected to increase further in the next fi ve to 10 years. The O&GJ survey is the latest and most complete data set of active enhanced oil recovery projects in the U.S. EPA believes that the 2007 data presented in the O&GJ survey are representative of the type and scope of ERprojects that will b e operating in 2011. For this analysis, EPA compiled all the projects listed for miscible and immiscible CO 2 floods 9 reported in the O&GJ survey. The list of active projects represents a wide cross section of several geologic basins in 10 states, rangin g from relatively recent pilot scale projects with one or two injection wells to CO 2floods started in the 1970s with hundreds

8 Enhanced Oil Recovery Survey , 2008. Oil and Gas Journal, Volume 105, Issue 15. 9 A miscible CO 2flood injects CO 2as a l iquid at high pressure to completely mix with oil and make it flow more easily. An immiscible CO 2flood uses lower pressures of CO 2to swell the oil and provide additional gas pressure to move the oil.General Technical Support Document for Injection and GeologicSequestration of

Carbon Dioxi de: Proposed Rule for Mandatory Reporting of Greenhouse Gases

8 of injection wells. The Wasson Field in the Permian Basin is the largest user of CO 2and has six active CO 2 ERprojects managed by two operators.

0 20 40 60 1972 1975 1978 1981 1984 1987 1990 1993 1996 1999 2002 2005 2008 Million Tonnes

Val Verde Basin LaBarge Dakota Gasification McElmo Dome Bravo Dome Sheep Mtn. Doe Canyon Jackson Dome Figure 3 - 1
. Total CO 2used in Enhanced Recovery showing growth since 2004. Graph based on data from specified anthropogenic and n atural CO 2 sources. Data based on sales. Source: Kinder Morgan CO 2Company, CCS briefing to EPA June 3, 2009 10 A total of 105 active ERprojects operated by 23 different companies were reported in the O&GJ survey. In some cases multiple projects were repo rted by the same company in an oil field, reservoir, or operator unit. For the purposes of this analysis, EPA grouped these reported projects by field and by owner or operator to align with the definition of “injection

- only” facility in this s ubpart. Thi s computation results in 80 ER facilities. EPA further grouped the fields by their source of CO 2as determined from geographic location, U.S. DOE pipeline maps, and operator published information. As of 2008, f our natural sources (Jackson Dome MS; Bravo Dome NM; Sheep Mountain CO; and McElmo Dome CO) and five anthropogenic CO 2 sources (Antrim Gas Plant MI; LaBarge/Shute Creek Gas Plant WY; Enid Fertilizer Plant OK; U.S. Energy Partners Russell KS Plant; and Val Verde Gas Plant TX) supply CO 2for EnhancedRecovery. 11 The O&GJ survey does not provide the specific volume of CO 2used in each of the active ERprojects, but does provide the total oil production attributed to the ERprocess. To calculate the estimated volume of CO 2injected at each ERproject, E PA determined the total amount of CO 2 used daily for ER based on data from the U.S. EPA Draft 1990

– 2007 Inventory of U.S. Greenhouse Gas Emissions and Sinks 12 (Inventory). According

10Note that the CO 2being produced by Dakota Gasifica tion Plant in North Dakota is being injected into an ER project in Canada. 11 U.S. EPA Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks, 1990

- 2007, Report, EPA 430

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- 004 . Available at: http://epa.gov/climatechange/emissions/usinventoryreport. html 12 U.S. EPA Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks, 1990

- 2007,General Technical Support Document for Injection and GeologicSequestration of

Carbon Dioxi de: Proposed Rule for Mandatory Reporting of Greenhouse Gases

9 to the Inventory approximately 2.08 billion cubic feet per day (bcf) CO 2 from natural and anthropogenic sources is used (purchased) for ER . The threshold analysis was performed two ways, one based on total daily CO 2use combined for all fields in the U.S., and one based on the total from each source of CO 2 used in EOR (natural or anthropogenic). The daily average CO 2 production from each source was apportioned among the projects supplied by the source based on an average value for the fractional production of oil attributed to e nhanced recovery as presented in the O&GJ survey and normalized on an annual basis ( see Appendix B ) . The analysis was further complicated because anthropogenic gas from the Val Verde Gas Plant is mixed with natural CO 2in the pipeline carrying the CO 2 to the Permian Basin, therefore the specific project s supplied by the Val Verde Gas Plant could not be determined. To accommodate the mixture of sources in the Permian Basin, the CO 2from the Val Verde Gas Plant was apportioned based on the total crude oil production in the Permian Basin and the known quan tities of CO 2 supplied from natural sources. The CO 2 from the Val Verde Gas Plant represents approximately 5.39% of the CO 2 used in Permian Basin Enhanced Recovery projects. EPA recognizes that this is likely an oversimplification of the actual CO 2 inje ction volumes used at each facility but notes that it follows the principle that higher production is a function of higher CO 2 injection volumes. The volume of CO 2 used in a particular e nhanced recovery project is a function of many factors including:

 Re servoir characteristics

–Heterogeneity is one of the most significant design considerations, along with porosity, permeability, oil gravity, production history, depth, and reservoir pressure.  Flood design

–

The injection design (continuous, simultaneous water and gas, water alternating gas , and number of injector wells are major factors in overall CO 2use. Injection well pattern, miscible or immiscible process es , CO 2 saturation target as a percent of hydrocarbon pore volume, and use of surfactants and additives also influence CO 2 use.  Project age

–

The stage of the project is the largest factor in determining CO 2 use. New CO 2 floods use more purchased CO 2and produce less oil because the CO 2 has not fully penetrated the reservoir. It may take 6 to 12 months to see an increase in oil productionupon initiation of injection
. As the reservoir becomes saturated with CO 2 , the amount of new CO 2 added to the project is reduced, and the majority of the injected CO 2is recycled from producing wells. The calculatio n of CO 2 utilization in the threshold analysis presented in this section is based on the volume of new (purchased) CO 2 for EOR obtained from the Inventory. The value represents the "Net CO 2 Utilization" in mcf/bbl. "Gross CO 2 Utilization" is the total amo unt injected, including purchased and recycled CO 2 . Gross CO 2 Utilization was not analyzed in this threshold analysis because the total injection data were not available. Report, EPA 430

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- 004 . Available at: http://epa.gov/climatechange/emissions/usinventoryreport.htmlGeneral Technical Support Document for Injection and GeologicSequestration of

Carbon Dioxi de: Proposed Rule for Mandatory Reporting of Greenhouse Gases

10 To evaluate the reasonableness of the approach , EPA compared the calculated Net CO 2 Utilization from the threshold analysis to field

- specific values for 12 field

- scale projects published by DOE 13

. Values for individual projects showed variance, however, overall the average values were consistent (7.53 mcf/bbl in the Threshold Analysis, v ersus 6.48 mcf/bbl in DOE report). As a secondary check on the reasonableness of the estimates in the threshold analysis , EPA compared the average age of the projects to the Net CO 2Use. This is because the a ge of the project is one of the most significant factors in determining Net CO 2 Utilization. The threshold analysis evaluated EOR projects by CO 2 source (essentially by producing basin) and resulted in Net CO 2Utilization estimates by basin. The results provided support that the estimates of CO 2 use were reasonable. For example:

 The Permian Basin has the oldest EOR projects (70% started before 2000) and the Threshold Analysis shows the lowest Net CO 2usage (7.2 mcf/bbl) for this Basin.  The Mississippi Interior Salt Basin has the youngest CO 2 EOR pro jects (15% started before 2000) and the Threshold Analysis shows the highest Net CO 2 Utilization (19.2 mcf/bbl) of any basin. The DOE report also indicates that projects in this basin use higher CO 2 volumes (60% hydrocarbon pore volume ( HCPV ) versus 30% H CPV) which further increases the Net CO 2Utilization
. Based on the analysis described above the simplified estimation using production

apportioned injection volumes shows a good correlation with independent data and is an appropriate estimation of CO 2 usa ge. Analysis of the e nhanced recovery injection data showed five fields with no enhanced production, and were correspondingly allocated no CO 2use. One additional field showed near zero production. Two of the six fields reported the projects as “just started”, and four reported projects at the “nearing completion” stage. This demonstrated to EPA that injection activity generally follows a curve that can slowly increase in the beginning as the project moves from a pilot test to a larger scale or slowly de crease towards the end of operations. Development of a full scale CO 2EOR project requires extensive testing and ramping up over many years. Additionally, EPA determined that some e nhanced recovery production operations inject CO 2and water in alternatingpulses rather than continuously over years to maximize production, and the CO 2 injection periods and the corresponding (alternating) water injection periods may last from several months to two years or more. Therefore, the annual snapshot of data compile d for e nhanced recovery does not necessarily represent the typical operating conditions of full scale projects expected in the future, as the number of e nhanced recovery operations increase.

13 Evaluating the Potential for “Game Changer” Improvements in O il Recovery Efficiency from CO 2 - Enhanced Oil Recovery,” Prepared by Advanced Resources International for DOE NETL, February 2006 Available at: http://fossil.energy.gov/programs/oilgas/eor/Game_Changer_Oil_Recovery_Efficiency.htmlGeneral Technical Support Document for Injection and GeologicSequestration of

Carbon Dioxi de: Proposed Rule for Mandatory Reporting of Greenhouse Gases

11 Table 3

- 1 shows that nearly all fields (92.5%) injected greater than 1,000 metric tons CO 2 per year . At

injection reporting thresholds of up to 25,000 metric tons per year essentially all CO 2 (100%) injected is included but not all facilities would report. At an injection reporting threshold of 25,000 tons per year , 65 of the 80 facilities (81%) would report. At a 100,000metric tons per year threshold 97.4% of all CO 2used in e nhanced recovery would be reported from 60% of the facilities. The majority of the 40% of facilities not covered are characterized in the O&G J Survey as pilot projects, projects that have just started, or projects nearing completion. Table 3 - 1 . Threshold Analysis Based on Amount of CO 2Injected Amount of CO 2Injected Number of Facilities Threshold Level (metric ton s/yr of CO 2 injected) Total

National (metric tons/yr of CO 2 injected) Total

Number of U.S. Facilities Metric tons/yr

of CO 2 Injected Percent

Covered Numberof

Facilities Covered Percent

Covered All In 40,111 ,639 80 40,111,639 100.0% 80 100.0% 1,000 40,111,639 80 40,111,115 100.0% 74 92.5% 10,000 40,111,639 80 40,099,065 100.0% 71 88.8% 25,000 40,111,639 80 40,005,238 100.0% 65 81.3% 100,000 40,111,639 80 39,065,039 97.4% 48 60.0% 

### 4. Monitoring Methods Con sidered This section presents monitoring methods for CO 2injection and GS facilities
. 4.1 CO 2 Injection In order to determinethe amount of CO 2 injected , transferred from offsite , or produced with oil and gas (at ER operations) , an injection facility w ould measure the flow rate using either a mass flow meter or a volumetric flow meter. To determine the mass the facility would either multiply the mass flow rate by the concentration of CO 2in that flow or multiply the volumetric flow rateat standard temperature and pressure (STP) by the concentration of CO 2 in the flow and by the density of CO 2at STP . Either a continuous mass flow meter or a continuous volumetric flow meter would most accurately account for the fluctuations over time of flowrate . F aci lities subject to the UIC program for permitting of injection wells would already have flow meters installed to measure the flow rate of the CO 2s tream i njected for purposes of compliance with their UIC permits. It is common industry practice to use volum etric rather than mass flow meters. In general, the CO 2 injected for either ER or GS is not 100 percent CO 2 . Therefore, i n order to determine the portion of the stream that is CO 2 , the injection facility would sample the stream and analyze it for its C O 2 concentration. EPA has not identifiedGeneral Technical Support Document for Injection and GeologicSequestration of

Carbon Dioxi de: Proposed Rule for Mandatory Reporting of Greenhouse Gases

12 specific standards that provide methods to extract samples for analysis
. However, it is common practice in the oil and gas industry to take regular samples of CO 2streams. One method would be to use “bomb sampling ” (a bomb is usually a stainless steel or brass vessel used to extract samples for lab testing). Once the sample has been collected, i t can be sent to a laboratory for compositional analysis using chrom atography
. Using the operating temperature and press ure, the volume of CO 2 can be converted into STP conditions and , usinga STP density value for CO 2 , one can calculatethe CO 2 quantity in metric tons. An injection facility would apply the same method in order to calculate the quantity in metric tons of C O 2 transferred on site from offsite. 4.2 CO 2 P

roduction at ER O

perations For an injection facility conducting ER, several steps would be needed in order to estimatethe quantity of

CO 2 produced with oil or gas . The oil or gas streamof a production well at an ER operation is first separated into liquid phase and gas phase; the liquid phase is further separated into a water fraction and an oil fraction
. CO 2 may be found in the following three streams following the gas

- water
- oil separation phase : 1) CO 2 in oi l, 2) CO 2 in water, and 3) CO 2in gas phase (along with other produced hydrocarbons). The amount of CO 2 in the oil (or water) can beestimated by multiplying the gas - to
- oil (or gas - to
- water) ratio by the volume of oil (or water) produced. The gas

to
- oil (or gas - to
- water) ratio can be determined using any standard test method (the ratio determination as well as chromatography are well understood techniques). A method to determine the amount of CO 2 in gas phase is to use a mass flow meter or volumetric flo w meter to measure mass or volumetric flow rate of the produced gas streamthat contains CO 2 , take a sample of the stream, and analyzethe stream for CO 2 composition , which can be done using chromatography. It is common in centralized production collecti on and processing sites receiving production from dozens of surrounding wells to have a “test trap.” This is a small gas/oil/water separator, outfitted with accurate flow measuring devices on all streams in/out, and manifolded to divert any one well throug h the test trap to gauge gas/oil/water ratio of each well. This is important in balancing the extraction of production between wells. If a well is drawing too much water, it can be slowed down and adjacent wells increased in production. This is where gas/o il/water production would be monitored for each well individually and regularly. Therefore, it is not necessarily the case that the sample point would involve a single CO 2stream from a single well. There may be an aggregate point of monitoring from a col lection of wells. 4.3 Fugitive and Vented CO 2 Emissions Fugitive and vented CO 2 emissions can occur from surface components located between the point of transfer onsite and the injectionwellhead . To measure or estimate these emissions, an injectio n facilitycould use methodologies provided in the proposed Petroleum and Natural Gas Systems Reporting Rule ( subpart W of the MRR). The following table lists the surface CO 2 emission sources at an injection facility that may be located between the point of transfer onsite and the injection wellhead and describes theGeneral Technical Support Document for Injection and GeologicSequestration of

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13 methodologies provided in subpart W. Note that the compressors may or may not be a part of this operation depending on how the individual site configures its recycle stream. Compressors are used to com press the recycle stream, which is eventually converted to critical phase CO 2 that is mixed with the critical phase stream coming from outside facility boundary. Table 4 - 1 . Surface Components a s CO 2Emissions Sources at InjectionFacilities Emissions Source Engineering Estimates 1 Direct

Measurement 2 Equipment Count and Population Factor 3 Natural gas pneumatic high bleed device venting 4 X Natural gas pneumatic low bleed device venting 4 X Natural gas dr iven pneumatic pump venting 4 X Reciprocating compressor rod and packing venting X EOR injection pump X Centrifugal compressor wet seal oil degassing venting X Other fugitive emissions (Valve, Connector, Open ended Line, Pressure Relief Valve ) X Notes: (1) The engineering calculation methods use monitored process operating parameters and either engineering calculations (in the case of EOR injection pumps) or emission factors provided by the equipment manufacturer(in the case of pneu matic device or pneumatic pump). (2) Direct measurement involves use of rotameters, turbine meters, or other meters, as appropriate, for emissions measurement directly from the vent stack. This would be repeated once each year to establish a site

- specific , equipment

- specific emission factor for use between repeat measurements. (3) For the use of population factors, the relevant emission factors would be applied to all components using a count of the sources. (4) ER operations that power pneumatic equipmen t by instrument air rather than natural gas would not have natural gas pneumatic emissions sources. Fugitive and vented CO 2 emissions at an ER operation can also occur from surface components located between the production well and the point of CO 2 measu rement. Between these two points, an injection facility will typically havegathering pipeline, valves, connectors, meters, and headers (which are large pipes that mix the oil stream from multiple wellheads) . The procedures provided in subpart W for determining CO 2 emissions from all of these sources is equipment count and population factor.General Technical Support Document for Injection and GeologicSequestration of

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14 4.4 CO 2 Leakage to the Surface While the science of quantifying CO 2 leakage from GS sites is evolving, it is generally recognized that, when properly planned and impleme nted, monitoring methods will be effective at detecting leakages
. 14 15 16 A wide range of techniques for monitoring GS of CO 2 have been used for a number of years in other applications . These techniques may be used in a GS project to monitor the injected C O 2 , the surrounding geology, and the surface conditions. EPA has concluded that a GS facility would be able to propose a site

specific monitoring plan for leak detection and quantification based on the current availability of monitoring technologies , eventhough the methodologies for detecting and quantifying leakage of CO 2 from GS sites have not been standardized
. In addition, it is expected that site characterization and screening will lead to selection of sites that are suitable for long

- term sequestration and that incidences of leaks to the surface may be infrequent at well

- selected and well

- managed sites. T he purpose of this section is to describe techniques available and under development for monitoring the fate of the injected CO 2 and verifying GS, including brief discussions of reservoir modeling and the importance of establishing pre

- injection environmental baselines. The section describes how the techniques may be used for detection and estimation of CO 2leaks in the subsurface and surface. It is expected that these estimates may include engineering calculations and direct measurement where technically feasible. 4.4.1 Reservoir Modeling Reservoir modeling or simulationis a powerful mathematical tool that is used to evaluate the movement of injected CO 2 in the reservoir and is an integral aspect of project design, planning, site characterization, and monitoring program design. 17 A computational model based on the site characterization and monitoring data can be used to predict the size and location of

the plume. An initial model can be used to forecast how the plume is expected to move and change. After injection begins, the data from the injection well and data from the other types of monitoring can feed into the model, to calibrate and history matc h the model. Reservoir modeling has been in use for decades in the oil and gas industry, and is used to design the development of fields. The model is a three dimensional construct of the subsurface reservoir, and uses a finite

- difference approach in w hich the reservoir is

14Benson, S.M., 2006, “Mon itoring Carbon Dioxide Sequestration in Deep Geological Formations for Inventory Verification and Carbon Credits,” Society of Petroleum Engineers Paper 102833, 14pp. http://www.onepetro.org/mslib/servlet/onepetropreview?id=SPE

- 102833

- MS&soc=SPE(at cost). 15 FutureGen Alliance, 2006, “Mattoon Site Environmental Information Volume,” December, 2006. http://www.futuregenalliance.org/
. 16Note that

this document refers to some non - peer - reviewed documents which are publicly available via the web links provided. 17 DOE/NETL, 2009, “Best Practices for Monitoring, Verification, and Accounting for CO 2Stored in Deep Geo logic Formations,” U.S. Department of Energy, National Energy Technology Laboratory. http://www.netl.doe.gov/technologies/carbon_seq/refshelf/MVA_Document.pdf
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15 divided into a large number of discreet three

- dimensional volumes for analysis. Input data include reservoir thickness, depth, pressure, porosity, permeability, fluid saturations, and other parameters. Each three

- dimensional volume has its own specific characteristics. In the case of CO 2 injection, the model is set up using all available data, and the model is run to estimate future movement of CO 2through the reservoir. The model is then calibrated and updated through time as the injection proceeds. This is accomplished through history matching of actual subsurface data such as pressure or the detection of CO 2 . There are three general types of simulation models used for GS : models that focus on faults and fractures, models that focus on the transport of CO 2 , and geomechanical/flow models. 18 The simulators allow the prediction of the following:

 Temporal and spatial migration of the plume  Geochemical reactions  Cap rock and well bore integrity  Potential leakage pathways and estimates of travel times for these routes  Effects of unplanned hydraulic fracturing  Potential leakage near the injector well  Consequences of wellbore failure The GEO

- SEQ Project Team 19 summarized the effectiveness and uncertainly of reservoir modeling in the fo llowing: Modeling and simulation are an intrinsic part of the design phase of a CO 2 injection project. From capacity assessments to estimating travel times for potential leakage routes, multiphase and multi

- component reservoir simulation provides the basi s for defensible decisions and understanding of the system. However, it is essential that simulation tools are used by competent engineers and scientists who understand the pitfalls and complexities of subsurface reservoir simulation. Furthermore, the pr actice of CO 2injection is immature; there is little field experience in the physical processes involved, and therefore extra scrutiny must be given to simulation results. 4.4.2 E nvironmental B aselines An essential part of any monitoring program is determini ng the pre - injection subsurface and surface environmental baselines against which monitoring results will be compared
.

18 DOE, 2009, “Best Practices for Monitoring, Verification, and Accounting for CO 2Stored in Deep Geologic Formations,” U.S. Department of Energy, National Energy Technology Laboratory. http://www.netl.doe.gov/technologies/carbon_seq/refshelf/MVA_Document.pdf
. 19 GEO

- SEQ Best Practices Manual, Geologic Carbon Dioxide Sequestration: Site Evaluation to Implementation , GEO

- SEQ Project Team: Lawrence Berkeley National L aboratory, Lawrence Livermore National Laboratory, Oak Ridge National Laboratory, Stanford University, University of Texas Bureau of Economic Geology, Alberta Research Council, September 30, 2004, Earth Sciences Division, Ernest Orlando Lawrence Berkeley N ational Laboratory, Berkeley, CA 94720. http://www.netl.doe.gov/technologies/carbon_seq/refshelf/GEO

- SEQ_BestPract_Rev1

- 1.pdf
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16 Applying monitoring technologies to detect CO 2 flux at the surface is a challengedue to the natural variability of background CO 2conce ntrations
. The CO 2 background levels may vary with location, depth, air temperature, soil temperature, rainfall, time of day, and season. It can be important to determine the statistical variations of CO 2background levels and account for these when meas uring anomalies that can indicate leaks. In addition, correlations between CO 2 flux and certain environmental parameters (e.g. , soil temperature and moisture, atmospheric temperature, pressure, and wind speed and direction), can help predict the backgroun d CO 2 fluxes expected under a given set of environmental conditions. A leak may be presumed when the monitored CO 2 concentrations are significantly higher than the range of natural CO 2 concentration expected under the sampling conditions. T he background CO 2data can be collected both before and during injection operations and comparisons made among widely scattered sensors sampled at the same time as well as comparisons of samples over time at any one location. O bservations of CO 2concentration gradients with depth, surface CO 2fluxes, atmospheric CO 2 measurements, carbon isotopic compositions and tracers can be used together to determine if CO 2has escaped the injectionzone . 20 21 4.4.3 Monitoring Technologies for CO 2Detection and Quantification This section d escribes monitoring technologies for CO 2 leak detection and quantification, in particular, m onitoring of i njection v olumes and p ressures , the injection well, s ubsurface CO 2 p lume , vadose zone, soil zone and vegetation, and atmosphere. 22 Table 4

- 2 provide s a list of monitoring methods that are being used at CCS projects. 23 This section summarizes these technologies and how they may be applied to detect and quantify leakage, with a focus on detecting and quantifying CO 2 movement to the surface. Monitorin g of Injection Volumes and Pressures During the injection phase, the volume of CO 2injected and the injection pressure are commonly continuously measured at injection wells. There can also be monitoring of the

20 GEO

- SEQ Best Practice s Manual, Geologic Carbon Dioxide Sequestration: Site Evaluation to Implementation , GEO

- SEQ Project Team: Lawrence Berkeley National Laboratory, Lawrence Livermore National Laboratory, Oak Ridge National Laboratory, Stanford University, University of Tex as Bureau of Economic Geology, Alberta Research Council, September 30, 2004, Earth Sciences Division, Ernest Orlando Lawrence Berkeley National Laboratory, Berkeley, CA 94720. http://www.netl.doe.gov/technologies/carbon_seq/refshelf/GEO

- SEQ_BestPract_Rev1

- 1.pdf
. 21 Oldenberg, C.M., Jennifer L. Lewicki, and Robert P. Hepple, 2003, "Near

- Surface Monitoring Strategies for Carbon Dioxide Storage Verification ," Earth Sciences Division, Lawrence Berkeley National Laboratory, publication LBNL

- 54089. http://www.osti.gov/bridge/servlets/purl/840984

- dTw752/native/840984.pdf
. 22The vadose zone is the relatively shallow zone beneath the surface that is not saturated with groundwater. 23 JJ Dooley, CL Davidson and RT Dahowski. 2009. "An Assessment of the Commercial Availability of Carbon Dioxide Capture and Storage Technologi es as of June 2009." Joint Global Change Research Institute. Pacific Northwest National Laboratory. June 2009. PNNL

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17 injection well annulus between the tubing andthe long string casing. The annulus in this diagram is shown in white and the CO 2 flow and plume are shown in purple. Table 4 - 2: M onitoringT echnologies as D eployed at 10 E xisting CCS P rojects

(S ource: JJ Dooley, CL Davidson and RT Dahowski. 2009. "An Assessment of the Commercial Availability of Carbon Dioxide Capture and Storage Technologies as of June 2009." Joint Global Change Research Institute. Pacific Northwest National Laboratory. June 2009. PNNL

- 18520) Monitoring of the Injection Well On e of the greatest risks for leakage at a GS site is from inadequate wellbore integrity, especially with the injection well. Mechanical Integrity Testing (MIT) is commonly used at permitted UIC injection wells to demonstrate that the injection wells can re sist the high pressures of injection, as well as the potentially corrosive nature of the injected CO 2 . Periodic external MIT

checks the area between the cement and the formation in the long string casing to detect gaps or fluid flow. 24 Should there be a b reak in the bond between the cement and the rock of the wellbore, the injected CO 2 can make its way vertically to

24Koplos, Jonathan, et al, 2006, “UIC Program Mechanical Integrity Testing: Lessons for Carbon Capture and Storage,” Fifth Annual C onference on Carbon Capture and Sequestration, May 8

- 11, DOE/NETL, 2006. http://www.netl.doe.gov/publications/proceedings/06/carbon

- seq/Tech%20Session% 20139.pdf
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18 access shallow formations, and possibly escape to the surface. External MIT is a reliable and effective method commonly carried out using wir eline logs or pressure tests. Wireline logs are subsurface measurements of the wellbore taken by lowering an instrument on a wire into the well, and recording the log response continuously as the tool is pulled upward. This generates a detailed pictureof the borehole and nearby rock. There are numerous types of wireline logs used in theoil industry, and the primary focus is on determination of reservoir properties such as lithology, porosity, and fluid content (oil, gas or water). Other types of too ls are used to evaluate the integrity of the casing and cement in a cased well. Wireline logs can be run in the open hole of a newly drilled well, and may be used to evaluate conditions in injection wells or monitoring wells. Common wireline logs used fo r external MIT are the cement bond log, the temperature log and the noise log. The cement bond log is a sonic (sound

- wave) based tool that is used to evaluate the bond between the casing and cement, and between the cement and the formation. 25 26 The temper ature log helps identify hot spots due to flow from deeper formations, while the noise log detects the sound of CO 2 flow behind the pipe. To some extent, the log response might be used as a qualitative measure of the amount of leakage. Other external int egrity tests include the oxygen activation log and radioactive tracer surveys, which indicate lack of fluid migration behind the casing. Internal MIT

of the injector well checks the integrity of the well materials: the tubing, packers, and long stringcasing. During injection operations, therecan be continuous monitoring of the annulus fluid pressure, which is typically maintained at a higher pressure than that of the injected CO 2 . A drop in the annulus pressure may indicate cracks or holes in the l ong string casing or may also indicate a leak in the tubing or packers. This would not necessarily be an indication of a CO 2leak to the atmosphere. In addition to continuous pressure monitoringin the annulus , internal well damage can be monitored with periodic wireline logs, including caliper tools, radioactive tracer tests, and downhole video. Logs can detect corroded or damaged tubing or casing even before a leak occurs. All of these methods are commonly used in the oil and gas industry. Monitori ng of Subsurface CO 2 Plume The location and size (extent) of the injected CO 2plume can be evaluated using several approaches. These include the acquisition of active seismic data, passive seismic data, information from monitoring wells, and reservoir mod eling. The active seismicgeophysical technique involves the generation of sound waves which propagate downward or laterally through the subsurface, are reflected off of geological layers, and are subsequently detected and analyzed at the surface by advan ced instrumentation. The method is used to evaluate the structural or spatial configuration of

25 Duguid, Andrew, and John Tombari, 2007, “Technologies for Measuring Well Integrity in a CO 2Field,” Sixth Annual Conference on Carbon Capture and Sequestration, DOE/NETL, May 2007. http://www.netl.doe.gov/publications/proceedings/07/carbon

- seq/data/papers/tue_064.pdf
. 26DOE/NETL, 2009, “Best Practices for Monitoring, Verification, and Accounting for CO 2Stored in Deep Geologic Formatio ns,” U.S. Department of Energy, National Energy Technology Laboratory. http://www.netl.doe.gov/technologies/carbon_seq/refshelf/MVA_Document.pdf
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19 the subsurface, and can also be used in some cases to determine reservoir properties and fluid content, including the presence of free

- phase (but not dissolved) CO 2 . In conventional active seismic, both sound sources and detectors are located on the surface. In vertical seismic profiling , the source is on the surface and the detector is down hole. In another arrangement called cross - well seismic , both source and detector are down hole in different wells Periodic acquisition of active seismicdata can in some cases be used to detect subsurface CO 2 movement within and outside of the intended reservoir. This may include leakage from/around the injection well, f rom around older pre

- existing wells, or through geological zones of weakness in the caprock ( confining zone). A variety of active seismicmethods are in use today in the oil and gas industry, and can be used for CO 2 plume monitoring. These include 2

- D seismic, 3

- D/4

- D seismic , vertical seismic profiling , and cross - wellseismic. Surface seismic data may be either two

dimensional (2

- D) or three

- dimensional (3

- D). Two

- dimensional seismic is obtained with a linear surface arrangement of receivers. The acoustic energy source is from small explosive charges or from “vibro

- seis” trucks. Three

- dimensional seismic may provide better resolution, accuracy, and tracking of the CO 2if it migrates from the storage reservoir into the overburden
. Three

- dimension al (3

- D) seismicevaluates a large volume of the subsurface, has high resolution, and is more complex and more costly to obtain and analyze. Surface receivers are laid in a grid pattern, and large amounts of data are simultaneously recorded and subsequently processed. Sophisticated software allows the conversion of this raw information into a detailed subsurface representation. Three

- dimensional data are increasingly used in the oil industry, as they allow the mapping of structural details, small faults, rock properties, and fluid properties. Four

- dimensional seismicis time

- sequenced 3

- D. The technique is the same as 3

- D, but it is acquired over time. In this way, one can evaluate fluid movement over time. Vertical seismic profiling uses sensors depl oyed in a borehole to measure sound propagation in the immediate vicinity of the well. 27 It is a high resolution method that evaluates a small volume of the subsurface adjacent to a single well. A variation of vertical seismic profiling is “walk

- away” pro filing, in which the source is sequentially moved away from the well. This creates a mini

- 2

- D seismic line away from the injection well. Cross

- well seismic , as mentioned above, involves the transmission of acoustic waves between wellbores, and also evalu ates a small rock volume. Vertical seismic profiling and cross - well seismicmethods are used to develop a very high resolution image of conditions relatively near the injector or monitoring wells. This is because of the short distance between seismic sou rces and receivers. These methods can also be used to calibrate the acoustic signature of the CO 2plume under very controlled

27 DOE/NETL, 2009 , “Best Practices for Monitoring, Verification, and Accounting for CO 2Stored in Deep Geologic Formations,” U.S. Department of Energy, National Energy Technology Laboratory. http://www.netl.doe.gov/technologies/carbon_seq/refshelf/MVA_Document.pdf
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20 conditions. This calibration can then be used to better interpret the 2

- D and 3

- D seismic, which covers a much larger area. All these types of active seismic methods can be used to image the free

- phase portion of a CO 2 plume under certain subsurface conditions. This method is known to be effective in many cases where CO 2 is injected into a saline reservoir and has a good density contrast with the saline fluid. The ability to image and track a CO 2plume depends upon factors such as lithology (sandstone, limestone, coal or shale), porosity (pore space), fluid content, and depth. 28 Seismic detection of a CO 2plume in a carbonate (li mestone or dolomite) reservoir may be a challenge due to low porosity and other factors. Seismic detection of CO 2 in a depleted oil reservoir may be more challenging than monitoring a saline reservoir, due to lower average fluid density contrast ( b oth oil and free

- phase CO 2 are less dense than saline water). Studies have been undertaken to evaluate seismic plume monitoring in coal beds. 29 Active seismic methods including 2

- D, 3

- D/4

- D, and cross

- well seismic can achieve high plume detection resolution, and therefore can be used to develop a first

- order estimate of plume dimensions for leakage quantification; but a drawback is that seismic methods only image free

- phase CO 2in the reservoir and not the dissolved CO 2 component. In addition, the amplitude of the seismic signal (which is used to detect the CO 2 ) is only partially related to the concentration and therefore cannot fully quantify even the free

phase part of the CO 2 . However, amplitude anomalies have been observed in CO 2 sequestration monitoring that have been related to CO 2 concentration. Such amplitude effects have been observed at the Sleipner gas field and the Weyburn ER project. 30To be detectable, the CO 2 accumulation must have lateral and vertical dimensions sufficient to produce a discerni ble seismic response. One study based on theoretical resolution considerations 31 has suggested that CO 2buildups as small as 10,000 to 20,000 tonnes may be detectable, but amounts would be difficult to quantify, as saturation would remain a key uncertainty . In practice, results from the Sleipner time

- lapse surveys suggest that repeatability noise (which depends on the accuracy with which successive surveys can be matched), rather than resolution may be the key parameter in limiting the detection of small c hanges of seismic signature due to leakage. Under favorable conditions, less than 1,000 tonnes of CO 2 should be detectable at depths less than 1,000 m. Passive seismicmethods, which use only receivers (no active acoustic sources) monitor the sound waves that are emitted from high pressure injection sites with sophisticated

28 IPCC, 2005, “Carbon Dioxide Capture and Storage,” Intergovernmental Panel on Climate Change, pg. 237. http://www.ipcc.ch/
. 29 La wton, Don, 2002, ‘A 3C

- 4D Surface Seismic and VSP Program for a Coalbed Methane and CO 2 Sequestration Pilot

–Red Deer, Alberta,” CREWES Research Report 14. http://www.c rewes.org/ForOurSponsors/ResearchReports/2002/2002

- 64.pdf
. 30DOE, 2009, “Best Practices for Monitoring, Verification, and Accounting for CO 2Stored in Deep Geologic Formations,” U.S. Department of Energy, National Energy Technology Laboratory. http://www.netl.doe.gov/technologies/carbon_seq/refshelf/MVA_Document.pdf
. 31 Myer, L. R., Hoversten, G. M., and Gasperikova, E., 2002. Sensitivity and Cost of Monitoring Geologic Sequestration Using Geophysics . In: Gale, J. & Kaya, I. (eds.) Greenhouse Gas Control Technologies. Elsevier, 377

–382. http://www.sciencedirect.com/science/book/9780080442 761
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21 instrumentation and decipher the results using computational methods. As the pressurized CO 2 moves through the reservoir, it creates microfractures which release acoustic energy that is detected in three

- dimensional space. Passive seismic methods can be used to track the subsurface plume and the areas of high pressure . They can also be used to detect where fractures are occurring that might signal breaks inthe caprock or activation of old faults
. Downhole instrumentation is used in monitoring wells to measure temperature, pressure, conductivity/salinity, and fluid characteristics. The individual measurements are quite reliable and accurate, but their limitation is that they repre sent a single point in time and space. As discussed in the introduction to this section, baseline CO 2 levels must be determined to detect an anomaly. The monitoring wells can be logged periodically with wireline logs that can be used to detect the presen ce and depth of CO 2 . Certain wireline tools may be used to collect a fluid sample under reservoir pressure and temperature conditions, and retrieve the sample to the surface for laboratory analysis. 32 They can also be used for cross - well seismicdata acqu isition, in which seismic signals are broadcast from one well and detected in an adjacent well to characterize the formation between the wells. Monitoring wells can be designed to allow testing of the CO 2 reservoir, or of units above the reservoir. U

- tub e devices can be used to retrieve pressurized samples for laboratory testing. Based on the specific (electric) conductance and the pH of the pressurized samples, the concentration of dissolved inorganic carbon (DIC) can be determined using complex algorithms. DIC includes aqueous CO 2 , carbonic acid ( H 2 CO 3 ) , bicarbonate ( HCO 3 - ) , and carbonate ( CO 3 - - ) . CO 2 leakage from the reservoir can be detected long before the CO 2can escape to shallower zones or to the surface. Geochemical sampling of the fluid from monitoring wells can also be used to detect natural or artificial “tracers” in the injected CO 2 . Monitoring to gather additional data may be necessary if the instrumentation indicates a significant anomaly relative to background levels. Intermediate m onitoring wells can be used to test zones within a depth range of approximately 200 to 2,000 feet below the surface. As with the deeper wells, downhole instruments can measure pressure, temperature, and conductivity/salinity. Further monitoring may be implemented when readings depart from background levels , for example, a

3

- D seismic survey may be undertaken if the anomaly is within an appropriate depth range. Vadose Zone Testing The vadose zone is the relatively shallow zone beneath the surface that i s not saturated with groundwater. Due to absence of water, monitoring in this zone therefore is limited to testing the chemistry of the air contained within the pore space. The CO 2 concentration of air samples taken in this zone can be measured using commercially available infrared gas analyzers(IRGAs), which measure the absorption of specific

32FutureGenAlliance, 2006, “MatoonMattoon Site Environmental Information Volume.” http://www.futuregenalliance.org/
. http://www.futuregenalliance.org/
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22 portions of the infrared spectrum to determine the concentration of CO 2 (or other gases) in the air sample. As discussed earlier inthis section, background level s must first be measured to determine the statistical variations of CO 2 concentration accounting for sample temperature, seasonal variations, diurnal variations, and the like. Later, a presumptive leak is detected if the monitored CO 2 concentration exceed s a value corresponding to a very high (e.g., exceeds the 99 percentile) prediction for the natural CO 2 concentration accounting for sample temperature, seasonal variations, diurnal variations, etc. Should significant anomalies be detected, an expanded so il or atmospheric testing program may provide additional information. In addition to the use of IRGAs for CO 2 concentration, vadose zone sampling can include testing for tracers, should they be used, and for sampling for carbon and oxygen isotopes, to determine whether the CO 2 is that which is being injected or naturally occurring CO 2 . 33 As with data collected in monitoring wells, these individual measurements are quite reliable and accurate, but their limitation is that they represent a single point in ti me and space. Soil Zone and Vegetation Testing The soil zone is generally present within the first few inches to possibly tens of feet beneath the surface, the uppermost layer of the vadose zone. The soil zone is the fertile portion that can retain wat er (i.e., topsoil). A monitoring program in the soil zone can detect the vertical CO 2 flux. It is especially important in the soil zone that b ackground levels (which vary with time of day and season) be determined to provide a well

characterized baselineagainst which statistically significant anomalies can be detected and estimated
. Accumulation chamberscan be used to estimate CO 2flux from the ground surface to the atmosphereand be used to directly detect and quantify the mass of CO2 leaking from th e subsurface. 34 Th e approach may consist of a grid of accumulation chambers in which the CO 2 flux is periodicallymeasured. 35 Commercially available accumulation chamber instrument packages are currently being used to track seasonal variations in CO 2flux as part of climate changestudies . The accumulation chamber is a method of measuring soil CO 2 flux that involves the placement of a collection chamber directly on or into the soil surface, with the rate of CO 2accumulation measured periodically with an I RGA. The rate of change in CO 2 concentration defines the rate of flux. The calculated rate of flux can be used as a standalone quantification method if CO 2leakage is detected. This type of measurement c ould be used to quantify leakage that is moving up through the soil zone across a wide area, as opposed to point sources such as a leaking injection well. To account for local variations in the underlying geologic, soil characteristics, and soil moisture levels, several accumulation chambers would have t o be distributed over the

33 FutureGenAlliance, 2006, “ MatoonMattoo nSiteEnvironmental Information Volume.” http://www.futuregenalliance.org/ 34FutureGenAlliance, 2006, “ MatoonMattoonSiteEnvironmental Information Volume.” http://www.futuregenalliance.org/
. 35 Oldenberg, C.M., Jennifer L. Lewicki, and Robert P. Hepple, 2003, “Near

- Surface Monitoring Strategies for Carbon Dioxide Storage Verification,” Earth Sciences Division, Lawrence Berkeley National Laboratory, publi cation LBNL

- 54089. http://www.osti.gov/bridge/servlets/purl/840984

- dTw752/native/840984.pdf
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23 area to quantify the leakage rate. CO 2flux measurement systems based on accumulation chambers are commercially available and can provide a measurement of anomalous CO 2 flux at a point, with a precision less than 5 micrograms per square meter per second. That point measurement precision corresponds to a leak rate of 25,000 metric tons per year distributed across an area of 150 square kilometers. Surface leaks detected in the soil zone may also be quantified through tenting methods, in which large tents (made of impermeable material) are used to capture and accurately measure the CO 2 leakage from a much larger soil surface area. Tenting methods have been used to detect methane leaks from natural gas pipelines and could also be used for CO 2 quantification. Variations of this method are commonly used in measuring methane flow rates from equipment leaks. 36 A tent or bag is constructed above a known leakage site. An inert gas such as nitrogen is conveyed through the bag at a knownflow rate. Once the carrier gas attains equilibrium, a gas sample is obtained from the bag and the methane content of the sample is determined. The leak flow rate is calculated from the purge flow rate through the enclosure and the concentration of meth ane in the outlet stream. Table 4

- 3 illustrates the general approach to quantify the leak. Table 4 - 3 . Example Leak Quantification Using Tenting and Known Test Gas Flow Inlet Flow of Conveyed Test Gas (cu. ft./minute) Measured CO 2 Conce ntration at Outlet

(%) Calculated Outlet Flow Rate (cu. ft./minute) Calculated CO 2 Leak Rate (cu. ft./minute) 10 50% 20 10 10 10% 11.1 1.1 This approach is limited to sampling a point source or small area of leakage. However, if the site of the leakage can be mapped by airborne methods such as are described below, it should be possible to set up a number of tent measurement locations such that the leaks over a large area can be quantified using statistical sampling. However, the cost and time to se t up a large number of tents and/or accumulation chambers might favor the development and use of innovative mobile quantification methods (e.g., radial plume mapping with path

- integrated optical remote sensing). CO 2 in the shallow subsurface can also b e detected through shallow wells drilled to sample the groundwater. Such wells may be on the order of only several hundred feet deep. As with soil testing, background levels must first be established in order to detect changes that may indicate CO 2 leaka ge. Vegetative stress can also be a leakage indicator. Vegetative stress can be detected through tower

- mounted or airborne imaging instruments such as digital color infrared orthoimagery (CIR) or hyperspectral imaging to detect changes to vegetation colo ration in the visible, infrared, and ultraviolet spectrum. These are relatively new technologies with significant uncertainty in the interpretation of the results . Recent work has shown

36Envirotech Engineering, 2007, “Review and Update of Methods Used for A ir Emissions Leak Detection and Quantification,” February 5 th , 2007. http://www.envirotecheng.com/General Technical Support Document for Injection and GeologicSequestration of

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24 that vegetation in the vicinity of a leak may be negatively impacted , but vegetation farther from a leak may be positively impacted. 37 Atmospheric Monitoring The atmosphere above a GS site may be monitored with an array of CO 2detectors (closed

- path point measurements and open

- path line measurements), tracer gas and CO 2 isotopic measurements , e ddy c ovariance methods, Raman LIDAR (Light Detection and Ranging), or Differential Absorption LIDAR (DIAL). In all methods, CO 2concentration data are integrated with data on wind speed and direction to determine the vertical CO 2 f lux and locate the CO 2 leakage footprint. An additional challenge is to distinguish between natural CO 2 fluxes and CO 2flux due to leakage from geologic storage
. 38 CO 2 detectors are commercially available for short closed

- path and short open

- path (point ) measurements and long open

- path (radial line) measurements. Similar detectors have been integrated into s tationary , m obile , and airborne monitoring packages that are commonly used in combination with high

- resolution global positioning system (GPS) to de tect and quantify methane leaks in areas with road access . W hile the se packages have not been widely tested for CO 2 , various types of CO 2monitors are commercially available , generally relatively low cost, reliable, and could be used in these applications
. The technologies include infrared gas analyzers(IRGAs , including Fourier transform infrared (FTIR) and non

- dispersive infrared (NDIR) analyzers ), tunable diode lasers (TDLs), cavity ring downtechniques, and others. The sample path can range from 10 c m to 1 km, by reflecting a laser beam off retro
- reflecting mirrors. These devices measure the gas concentration, and, when packaged with measurements of wind speed and wind direction, they measure the total gas flow
. The method is described in detail in EPA Other Test Method 10 (OTM 10)

-- Optical Remote Sensing for Emission Characterization from Non

- Point Sources
. 39 The protocol describes three methodologies, each for a specific use:

 Horizontal radial plume mapping (for locating the source of emission s or hot spots)  Vertical radial plume mapping (for estimating the rate of gaseous emissions from an area fugitive emission source)  One

- dimensional radial plume mapping (for profiling pollutant concentrations along a line

- of

- sight which is downwind of an em ission source). These methodologies use an open

- path path

- integrated optical remote sensing system in multiple beam configurations to measure path

- integrated concentration data. The protocol suggests four scanning systems:

37 Montana State University , 2008 http://etd.lib.montana.edu/etd/2008/rouse/RouseJ1208.pdf 38 Atmospheric monitoring and verification technologies for CO2 s torage at geosequestration sites in Australia , David Etheridge, Ray Leuning, Donald de Vries, Kevin Dodds, Cathy Trudinger, Colin Allison, Paul Fraser, Fred Prata, Cirilo Bernardo, Mick Meyer, Bronwyn Dunse and Ashok Luhar, October 2005 CO2CRC Report No: RPT05

- 0134, Prepared by CSIRO Marine and Atmospheric Research for CANSYD Australia and the CRC for Greenhouse Gas Technologies (CO2CRC). http://www.co2crc.com.au
. 39 http://www.epa.gov/ttn/emc/prelim.htmlGeneral Technical Support Document for Injection and GeologicSequestration of

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25  Open

- Path Fourier Transform Infrared Spectroscopy  Ultra

- Violet Differential Optical Absorption Spectroscopy  Open

- Path Tunable Diode Laser Absorption Spectroscopy  Path

- Integrated Differential Absorption LIDAR Figure 4

- 1 illustrates vertical radial plume mapping using path

- integrate d optical remote sensing (PI

- ORS). EPA is also testing mobile versions of these systems for methane leak detection in which the detectors are integrated onto ground or airborne vehicles with high

- resolution global positioning systems (GPS) to aim the lasers at the retro

- reflectors and correctly locate the methane leak. Other atmospheric monitoring for leakage detection and quantification approaches include tracer gas es and CO 2 isotopic measurements . After adding a tracer gas to the CO 2 prior to injecti on, detectors focused on those tracer gases accomplish leak detection. Examples of tracer gases include methane (CH 4 ) , CO 2with radioactive carbon 14, 40 and CO 2 with carbon 13 and oxygen 17. On the downside, the cost of the tracer gas in volumes required for GS might be prohibitive. Alternatively, CO 2isotopic measurements might be able to distinguish between CO 2derived from fossil fuels and naturally occurring atmospheric and underground CO 2 . Researchers in Australia note that even relatively large leaks at the well could dissipate rapidly away from the source and be indistinguishable from background concentrations of CO 2 . They suggest that the use of radioactive tracers or natural carbon isotope ratios in the sequestered fluids will improve detection s ensitivity. 41 Field studies of carbon ratios in injected and recovered CO 2 have been conducted at Weyburn

- Midale CO 2Monitoring and Storage Project (Saskatchewan) the Pembina Cardium CO 2Monitoring Project (Alberta) and the Lost Hills oil field California
.

40 Potential method for measurement of CO 2leakage from underground sequestration fields using radioactive tracers , P. P. Bachelor, J. I. McIntyre, J. E. Amonette, J. C. Hayes, B. D. Milbrath, P. Saripalli, Pac ific Northwest National Laboratory, P. O. Box 999, Richland, WA, Journal of Radioanalytical and Nuclear Chemistry , Vol. 277, No.1 (2008) 85

– 89
. 41 Continuous Greenhouse Gas and Isotopic CO 2 Measurements via WS

- CRDS

- based Analyzers: Investigations in Real Time Monitoring at CO 2 Geological Storage Sites , Paul Steele, Zoë Loh, David Etheridge, Ray Leuning, Paul Krummel, Aaron Van Pelt, Centre for Australian Weather & Climate Research/CSIRO Marine & Atmospheric Research, Energy Transformed Flagship. www.cmar.csiro.au
.General Technical Support Document for Injection and GeologicSequestration of

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26 Figure 4

- 1 . Example of a Vertical Radial Plume Mapping Configuration Setup (Pathlength

- defining component (pdc) is used to denote the component on the other end of the optical path from the PI

- ORS ins trument. Depending on the instrument selected, this could be a source, detector, mirror, or other reflecting object.)

Source: EPA Other Test Method 10. http://www.epa.gov/ttn/emc/prelim.html
. EddyCovariance systems canmeasure the vertical CO 2flux in the atmosphere. They combine an open path IRGA on a tower alongside a sensitive, high

- speed, three

dimensional anemometer, a device used for measuring instantaneous wind speed and direction. Time s eries data are recorded and evaluated using computer methods. The size and shape of the sampling footprint (the surface area that is sampled by the instrument) is derived mathematically from the anemometer data. A typical station consists of sensors mounted on a tower from several meters to 30 meters or more high. The stations can be operated with solar power and can be set up for data telemetry for transmission to a central facility. Deployment of a grid of such detectors over an area provides information regardless of wind direction. CO 2 concentration data are integrated with meteorological data including wind speed and direction, relative humidity, and temperature.General Technical Support Document for Injection and GeologicSequestration of

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27 Such methods have the ability to measure CO 2 concentration in the atmosphere over relatively large areas. A limitation of the method is that it assumes a horizontal and homogeneous surfaceto interpret the data . Variation s in plant cover, land use, and topography may create challenges . As with soil sampling, the rate of leakage of CO 2 from the site must be a statistically significant anomaly above the background variability. Therefore, to provide the required precision, eddy covariance towers would have to collect data over an appropriate time periodto provide a baseline which includ es diurnal and seasonal variations. With careful installation and the collection of baseline data, the eddy covariance method can potentially provide a preciseaverage of CO 2 flux over a large surface area
. Although eddy covariance systems are currently research tools assembled from a variety of commercially available components, the eddy covariance method may eventually provide the anomalous CO 2flux averaged over a large surface area, with an precision less than 50 micrograms per square meter per second , which corresponds to a leak rate of 25,000 metric tons per year distributed across an area of 17 square kilometers. A nother potential technology for measurement of CO 2 in air is Raman LIDAR . LIDAR is the optical analog of radar, and it is based upon the use of laser radiation to measure various compounds in the air, including CO 2 . The Raman LIDAR method involves transmitting laser light into the atmosphere and then detecting the scattered laser radiation that has been shifted in wavelength due to int eraction with the target scattering molecules (e.g., CO 2 ) along the resolved path length. By comparing the Raman signal of the CO 2to the Raman signal of nitrogen or oxygen , a direct measurement of CO 2concentration can be obtained. A similar method, DIAL , w ould use two wavelengths of laser light to measure the CO 2 concentration in the atmosphere. The wavelengths used are specific to CO 2 . One wavelength is selected to correspond to a CO 2 spectral absorption line, while the other is a non - absorbing wav elength. The average CO 2concentration over the path length can be determined from the ratio of the backscatter signals for the two laser wavelengths. The instrumentation for both methods (Raman LIDAR and DIAL) can be ground, truck , helicopter , or airplane mounted and can provide similar precision at similar cost. Truck methods can cover up to tens of square kilometers per day. Helicopter and air p lane mounted platforms can cover a much larger area. Airborne DIAL methods are currently in use for methane leakage detection along natural gas pipelines. 42 Instrumentation includes the LIDAR, a digital mapping camera, a color video system, and an optical guidance system. The airplane flies a survey over the pipeline at an altitude of about 1,000 feet, appro ximately perpendicular to the wind direction. The LIDAR instrumentation measures the concentration of methane by measuring how much of the reflected laser pulse has been absorbed. These data could be integrated with real time wind direction and velocity to define the leakage footprint and estimate a leakage rate.

42IIT Space Systems Division http://www.ssd.itt.com/angel/General Technical Support Document for Injection and GeologicSequestration of

Carbon Dioxi de: Proposed Rule for Mandatory Reporting of Greenhouse Gases

28 While DIAL

is commercially available for methane, Raman LIDAR and DIAL are currently under development for commercial CO 2applications. Oldenburg 43 reports that
“ the advantages of Raman LIDAR and DIAL are that these are rapidly developing technologies with potential applications over multiple spatial scales. The main disadvantages are that they are expensive and measure average concentration over a path length, which means that a large localize d perturbation cannot be distinguished from a small change in the bulk mean concentration.” Airborne methods may also be integrated with ground methods to provide the best approach for quantification. Airborne methods could be used to map out the surfaceleakage area, and ground methods (such as accumulation chambers and tents) could be installed on the surface leakage area to measure the combined background and anomaly CO 2 flux and outside the surface leakage area to measure just the background CO 2 flux. 4.4.4 Leak Detection and Quantification in the Offshore E nvironment Reservoir modeling and m onitoring techniques, such as seismic and monitoring wells can also be applied to the detect leakage in subsurface geologic formations and shallow subsurfacelocated o ffshore. However, the fate of the CO 2entering the ocean from an offshore geologic formation is dependent on the temperature, pressure, and CO 2 flux, and may result in the form ation of CO 2 - hydrates, may dissolve into the seawater, or may be released into the atmosphere. Shallow monitoring systems aim to detect and quantify CO 2 which has migrated into the shallow overburden (e.g., potable aquifers), into the soil or seabed and, ultimately, into the seawater or atmosphere. Shallow monitoring includes thosemethods that detect and measure CO 2in the subsurface (e.g., potable aquifers, soil, sub

- seabed) and those that actually measure CO 2in the water column or atmosphere. Monitoring Near the Seafloor 44 Sparker surveys detect reflections of acoustic signals p roduced from electro

- capacitive sources which penetrate several hundred meters beneath the seafloor. Boomer surveys detect reflections of acoustic signals produced from electromagnetic sources which penetrate about 100 meters beneath the seafloor. Both m ethods can potentially resolve bed thickness of a meter or less and would likely have considerable potential for resolving small amounts of gas. However sparker and boomer data are acquired along 2D profiles, which render them less effective for systemati c areal detection of undiscovered leaks. Their main use may lie in high resolution imaging of shallow features previously detected on 3D conventional data. Shallow sedimentary deposits can also be examined using high

- resolution acoustic imaging . The tec hnique should reveal anomalous features in the top 100 meters beneath

43 Oldenberg, C.M., Jennifer L. Lewicki, and Robert P. Hepple, 2003, “Near

- Surface Monitoring Strategies for Carbon Dioxide Storage Verificatio n,” Earth Sciences Division, Lawrence Berkeley National Laboratory, publication LBNL

- 54089. http://www.osti.gov/bridge/servlets/purl/840984

- dTw752/native/840984.pdf
. 44 Monitoring Technologies for the Geological Storage of CO 2 , Technology Status Report, DTI/Pub URN 05/1032, Cleaner Fossil Fuels Programme, Didcot, Oxfordshire, UK, March 2005. http://www. co2net.eu/public/reports/tsr025abc.pdf
.General Technical Support Document for Injection and GeologicSequestration of

Carbon Dioxi de: Proposed Rule for Mandatory Reporting of Greenhouse Gases

29 the seafloor as well as direct imaging of rising ga s bubbles in the water column. Transducers such as Compressed High Intensity Radar PulseSonar s, operating at frequencies between 2 an d 8 kHz, have been widely employed on the continental margins, and have also been used to map glacial and other sedimentary deposits in shallow water. These techniques are potentially very useful for shallow storage monitoring. They offer high resolutionprofiling of seabed morphology but also have sufficient depth penetration to identify anomalous features in the subsurface, for example zones of acoustic blanking interpreted as signifying high gas saturations. The techniques can also permit direct imagi ng of gas plumes in seawater. Several acoustic sonar bathymetric systemshave been developed to provide area mapping of sea bed bathymetry, resolving features as small as 1 cm, such as pockmarks on the seafloor and free gas in the water column. Naturally occurring pockmarks and shallow gas chimneys may act as potential pathways for CO 2leakage. Two principal types are available: sidescan sonar using piezoelectric transducers mounted on towfish, 45 and multibeam echo sounding using magneto

- restrictive transducers from ships. Sidescan sonar

is one of the most accurate systems for imaging large areas of the ocean. It is a towed system that normally functions when it is moving in a straight line. Somewhat similar to side looking airborne radar (SLAR), side sc an transmits a specially shaped acoustic beam 90 degrees from the support craft's path, and out to each side. This beam propagates into the water and across the seabed. The roughness of the floor of the ocean and any objects lying upon it, reflect some of the incident sound energy back in the direction of the sonar. The sonar is sensitive enough to receive these reflections, amplify them and send them to a sonar data processor and display. Images produced by quality sonar systems are highly accurate, oft en photograph

- like in quality, and can be used to delineate even very small (<1 cm) objects, perhaps resolving features an order of magnitude or more smaller than conventional seismic reflection data, and offering the chance to image gas escape structures (pockmarks) and even free gas in the water column. Naturally occurring pockmarks and shallow gas chimneys may act as potential pathways for future CO 2 seepage. The shape of the beam in side scan is crucial to the formation of the final image. Typically, a side scan acoustic beam is very narrow in the horizontal dimension (~ 0.1 degree) and much wider (40

- 60 degrees) in the vertical dimension. Multibeam echo soundersintegrate bathymetric and backscatter information and can provide a highly efficient wayof obtaining very useful views of the sea floor. A multi

beam echo sounder may be considered as a series of around 100 single

- beam echo sounders, mounted in a fan shaped array on either side of a ship collecting echoes from the entire swath width as the ship advances. The fan is narrow in the fore and aft direction, typically 1.5 degrees, and wide in the port and starboard direction

– around 120 degrees. For each beam, the system reports depth and also the echo maximum amplitude

45 A towfish is an underwater equipment package towed a few hundred feet above the seafloor using an umbilical cable connected to a support craft.General Technical Support Document for Injection and GeologicSequestration of

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30 over time. This allows the detailed mapping of the seafloor bathymetry and inferences about the nature of the sediment. Electrical and electromagnetic (EM) methods offer the theoretical potential for low resolution, low

- cost, site monitoring. The techniques utilize the propagation of electrical or electromagnetic fields within the earth to map subsurface variations in electrical conductivity. A distinction can be made between electric methods which use zero frequency (DC) or very low frequency methods where no EM induction occ urs and EM techniques that utilize frequencies where time

- variant source fields induce secondary electrical and magnetic fields that carry information about subsurface electrical structure. CO 2 is resistive, so electrical/EM methods are likely to be suitab le for monitoring storage in saline formations where CO 2 is displacing more conductive formation waters. Placing the electrical sources or receivers (or both) in the subsurface, within or around the storage reservoir, radically increases spatial resolutio n, while reducing power requirements. Downhole configurations seem to offer the greatest potential for useful offshore application. Recent developments of sea floor EM systems , previously used (typically) for deep

- water tectonic studies, have led to ‘d irect

- detection

- of

- hydrocarbons’ systems. Two of the most advanced systems are referred to as SeaBed Logging (SBL) and Offshore Hydrocarbon Mapping (OHM). The systems consist of towed Controlled Source (CS) transmitters and static sea

- bed receiver arrays . The source is a horizontal electric dipole (HED), towed behind an instrumented towfish on a neutral buoyant streamer. During a survey the source is towed around and through the array of receivers which each measure 2 or 3 orthogonal components of the e lectric field. The technique is sensitive to thin resistive anomalies at depths between several tens of meters and several kilometers. Recent surveys have successfully determined the presence and absence of hydrocarbons within reservoirs. Direct detecti on of resistive CO 2 zones within more conductive lithologies would, theoretically, be possible. Technologies to monitor surface seawater geochemistry , coupled to hydrographic and meteorological conditions advanced significantly in the 1990s in an effort t o understand the role oceans play in global carbon budgets and the relative size and directions of carbon (mainly CO 2 ) fluxes between the sea, the atmosphere and the sediment. These technologies are relatively well tested and are deployed extensively acro ss the world, often routinely on ships regularly crossing oceans. A sensitive pH sensor for marine studies has recently been developed in the UK and would be useful to monitor changes in seawater pH resulting from CO 2 leaks. Four parameters are typicallymeasured that, together with ancillary information, such as temperature, pH and salinity etc, can be used to describe the CO 2system in a given sample. These parameters are: total dissolved inorganic carbon (a measure of the concentrations of CO 2(aq), H 2 CO 3 (aq), HCO 3 - and CO 3 2

- .), total alkalinity (a form of mass

- conservation relationship for the hydrogen ion), fugacity of CO 2 in equilibrium with seawater (a measure of the partial pressure of CO 2 ), and total hydrogen ion, primarily controlled by total sulfate concentration.General Technical Support Document for Injection and GeologicSequestration of

Carbon Dioxi de: Proposed Rule for Mandatory Reporting of Greenhouse Gases

31 Seawater samples obtained at depth, which are more appropriate to the needs of monitoring for CO 2 escape, require that the pressure needs to be maintained to ensure degassing does not occur. One such gas

- tight sampling device has been developed to obtain fluids samples (both waters and gases) at elevated temperatures and pressures. A key feature is that fluid within the chamber is maintained at seafloor pressures during sampling, allowing fluid aliquots to be withdrawn for an alm ost unlimited number of analytical techniques without degassing the remaining fluid. 4.5 Detection Limits and Accuracy of Various Technologies Each of the monitoring methods discussed above involves the application of technolog ies to detect and potentially quantify CO 2 movement or leaks in the subsurface or atmosphere. Monitoring is effective in detecting the presence of both subsurface and atmospheric leakage. However, methods of leak quantification at a site are generally at an earlier stage of evaluatio n, and this is an area needing additional study. As discussed above, leak quantification can be carried out through tenting methods if the surface area or location of the leak is known. Other quantitative methods potentially include wireline log analys is, well pressure analysis, 3

- D or cross

- well seismic analysis and modeling, and plume dimension analysis. The ability to detect or quantify a plume or leak is dependent upon factors such as the rate of leakage, its depth and location, the atmospheric bac kground CO 2 variability, the number and distribution of sampling stations, and the limits of the technology itself. Each technology typically has strengths and weaknesses, and only a combination of approaches is expected to ensure reliable monitoring and leak detection. To evaluate the capabilities of monitoring technologies, one must look at the theoretical limits of CO 2 detection, the size of anomaly that can be detected, and the precision and accuracy of the method. Table 4

- 4 presents this informati on for a number of technologies that can potentially be used for leak quantification. 46 47 48 49 The terminology in the table is as follows:

 Sampling rate . The frequency of sampling.  Detection range . The instrument detection limit or a range of instrument detection limits in appropriate units for the instrument.

46Benson, S.M., 2006, “Monitoring Carbon Dioxide Sequestration i n Deep Geological Formations for Inventory Verification and Carbon Credits,” Society of Petroleum Engineers Paper 102833, 14pp. http://www.onepetro.org/mslib/se rvlet/onepetropreview?id=SPE

- 102833

- MS&soc=SPE 47 Oldenberg, C.M., J.L. Lewicki, and R.P. Hepple, 2003, “Near

- Surface Monitoring Strategies for Geologic Carbon Dioxide Storage Verification,” Report #LBNL 54089, Lawrence Berkeley National Laboratory, Berkel ey, CA, October 30, 2003. http://www.osti.gov/bridge/servlets/purl/840984

- dTw752/native/840984.pdf 48 IPCC, 2006, “2006 IPCC Guidelines for Greenhouse Gas Inventories , “ Intergovernmental Panel on Climate Change, Simon Eggleston, ed. http://www.ipcc

- nggip.iges.or.jp/public/2006gl/index.html
. 49 DOE, 2009, “Best Practices for Monitoring, Verification, and Accounting for CO 2Stored in Deep Geologic Formations,” U.S. De partment of Energy, National Energy Technology Laboratory. http://www.netl.doe.gov/technologies/carbon_seq/refshelf/MVA_Document.pdfGeneral Technical Support Document for Injection and GeologicSequestration of

Carbon Dioxi de: Proposed Rule for Mandatory Reporting of Greenhouse Gases

32  Anomaly detection threshold. The size of the CO 2anomaly that can be detected under typical background conditions.  Precision. The degree of mutual agreement among a series of individual measureme nts.  Accuracy . The degree of conformity of a measured quantity to its actual value. Table 4 - 4 . Detection Range, Accuracy, and Precision of Various Monitoring Technologies Technology Reference Sampling rate Detection

Range Anomaly

Detec tion Threshold Precision Accuracy Comments Pressure gauges in monitoring wells 1, 4 Continuous NA 0.1 psi change NA NA Established and reliable.

3 - D seismic 1, 4 Periodic surveys NA 1,000 to 10,000 metric ton accumulations NA +/ - 20% of plume vol. Establi shed

technology; expensive, resolution decreases with depth. Cannot image dissolved CO 2 . Eddy Covariance 1, 2, 4 Continuous >10 microgram/ m 2/ sec >45

microgram/sq. m/sec 5 - 30% of

the CO 2 flux NA Commercially available technology used in other fields; s ignal to noise challenges CO 2 Detectors (closed path and open path) 2 1 - 10 Hz during sampling 0 - 3,000

ppmv NA 0.2 ppm at 350 ppm CO 2 concentration NA Established technology; Portable and inexpensive.

Accumulation Chamber 2, 3, 4 Continuous >0.46 micr ograms/ m 2/ sec NA 10% of the CO 2 flux 12.5% of

the CO 2 flux Commercially

available technology; Many sampling stations needed; average data from multiple chambers; samples small area; signal to noise challenge.General Technical Support Document for Injection and GeologicSequestration of

Carbon Dioxi de: Proposed Rule for Mandatory Reporting of Greenhouse Gases

33 Raman LIDAR and DIAL 2, 4 Continuous or peri odic <1ppmv to

several % CO 2 NA 1 - 5% of the CO 2 concentration NA Technology available for methane; CO 2 technology under development; Very large sampling area; long range; Precision of 3 - 27 ppm at 1 km path length References: 1. Benson, S.M., 2006, Mo nitoring Carbon Dioxide Sequestration in Deep Geological Formations for Inventory Verification and Carbon Credits , Society of Petroleum Engineers Paper 102833, 14pp. http://www.onepetro.org/mslib/servlet/onepetropreview?id=SPE

- 102833

- MS&soc=SPE 2. Oldenberg, C.M., J.L. Lewicki, and R.P. Hepple, 2003, Near

- Surface Monitoring Strategies for Geologic Carbon Dioxide Storage Verification , Report #LBNL 54089, Lawrenc e Berkeley National Laboratory, Berkeley, CA, October 30, 2003. http://www.osti.gov/bridge/servlets/purl/840984

- dTw752/native/840984.pdf 3. IPCC, 2006, 2006 IPCC Gu idelines for Greenhouse Gas Inventories , Intergovernmental Panel on Climate Change, Simon Eggleston, ed. http://www.ipcc

- nggip.iges.or.jp/public/2006gl/index.html
. 4. DOE, 2009, Best Practices for Monitoring, Verification, and Accounting for CO 2 Stored in Deep Geologic Formations , U.S. Department of Energy, National Energy Technology Laboratory. http://www.netl.doe.gov/technologies/carbon_seq/refshelf/MVA_Document. pdfGeneral Technical Support Document for Injection and GeologicSequestration of

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34 

### A ttachment A The following is a summary of end uses of captured or produced CO 2 (with the exception of ERand GS ). Cement
. While not a common practice in the cement industry, some companies are currently working to employ a cement manufacturing proc ess that uses captured CO 2 . 50 The process will convert CO 2 into carbonic acid, which will be made into carbonate. The carbonate will be combined with calcium and magnesium from seawater to make calcium carbonate and magnesium carbonate for the cement. 51 EP A does not have enough information to conclude whether cement production using this CO 2capture method permanently sequester s CO 2
. P recipitated Calcium Carbonate (P CC )
. PCC is produced through a chemical reaction process that utilizes calcium oxide (quic klime), water, and CO 2 . The CO 2 used to manufacture the PCC is in some cases captured from lime kilns operated at pulp and paper manufacturers. The PCC is available in numerous crystal morphologies and sizes, which can be tailored to optimize performancein specific applications. EPA does not have enough information to conclude whether PCC production using this CO 2 capture method permanently sequester s CO 2
. Food and Beverage Manufacturing. The food and beverage industry is one of the largest consumers of manufactured and captured CO 2 in the United States. Carbon dioxide is used widely throughout the food and beverage industry for a variety of applications including:

– Carbonation of soft drinks

– Beer and wine production

– Decaffeination of coffee and tea

– p H adjustment and shelf life lengthener for dairy products

– Frozen food production

– Canning Pulp and Paper Manufacturing. CO 2 is used in the pulp and paper industry in production processes to control pH, decrease calcium levels, increase de

- watering, buffer the paper making system, and recover chemicals in the mill process
. 52 53

50 Engineering News

- Record, New Green

- Concrete Process Combines Seawater, Flue Gas, February 18, 2009, http://www.calera.biz/pdf/ENR.com%2002

- 18

- 09.pdf (accessed July 26, 2009) 51 Biello, David. Cement from CO 2 : A Concrete Cure for Global Warming? , Scientific American, http://www.calera.biz/pdf/scientifc_american%20copy.pdf (accessed July 26, 2009) 52 Linde Gas, AGA and the Pulp and Paper Industry, http://www.aga.fi/international/web/lg/fi/likelgagafi.nsf/repositorybyalias/pulp_paper_industry/$file/AGA_ and_P ulp_Paper_Industry.pdf (accessed July 22, 2009) 53 US Patent 6200416

- Recycled paper production process which incorporates carbon dioxide, March 2001 http://www.patentstorm.us/pate nts/6200416/description.html (accessed July 26, 2009)General Technical Support Document for Injection and GeologicSequestration of

Carbon Dioxi de: Proposed Rule for Mandatory Reporting of Greenhouse Gases

35 Industrial and Municipal Wastewater Treatment
. Industrial and municipal wastewater treatment facilities use CO 2 to control pH levels in the water and treat soft water by dissolving lime. 54 Metal Fabrication
. Carbon dioxide is used for metal fabrication to enhance the hardness of casting molds; CO 2 is also used during welding and cutting of metal as a shielding gas to prevent the molten metal from oxidation. Greenhouse Uses for P lant Growth
. CO 2 is used to increase plant growth in greenhouses that produce flowers to full growth, nursery plants in early developing stages, and some produce (e.g., tomatoes). Fumigants and Herbicides
. CO 2 is used in the agricultural sector as an h erbicide for organic produce that successfully kills insects and increases storage life; and as a fumigant for grain storage to control insects in the storage facility. Medical Treatment
. For medical treatment, CO 2is added to oxygen to stimulate breath ing and balance CO 2/O 2 levels in patients. Construction
. In the construction and manufacture industry, CO 2 is used on a large scale as a shield gas in m etal inert gas (MIG) welding and metal active gas (MAG) welding, where the gas protects the weld pudd le against oxidation by the surrounding air. 55 A mixture of argon and CO 2is commonly used to achieve a higher welding rate and reduce the need for post

- weld treatment. Additionally, dry ice pellets are used to replace sandblasting when removing paint fro m surfaces. Dry ice aids in reducing the cost of disposal and cleanup. Rubber and Plastic Industry
. Carbon dioxidecleaning, also known as dry ice blasting, is a method of cryogenic cleaning. Dry ice is used to remove flash from rubber objects by tumb ling them with crushed dry ice in a rotating drum. Almost all major tire manufacturers use CO 2cleaning in their rubber molds. Shoe companies as well as gasket and other small rubber companies have successfully been using CO 2 cleaning as part of their routine machine maintenance. Additionally, in the production of polymer foams, liquid carbon dioxide is used as a blowing agent instead of environmentally hazardous substances. Carbon dioxide is a physical blowing agent with properties desired for ideal foaming, while simultaneously fulfilling many requirements related to quality, efficiency, and ecology. Fire Suppression. Carbon dioxide fire extinguishers are used for Class B fires (involving flammable and volatile liquids) and Class C fires (involving ele ctrical equipment).

54 BOC Gases, Carbon Dioxide http://www.boc

gases.com/products_and_services/by_product/carbon_dioxide/i ndex.asp (accessed July 27, 2009) 55 Metal inert gas (MIG) welding and metal active gas (MAG) welding are two subtypes of gas metal arc welding (GMAW).General Technical Support Document for Injection and GeologicSequestration of

Carbon Dioxi de: Proposed Rule for Mandatory Reporting of Greenhouse Gases

36 Cleaning and Solvent Use
. Liquid CO 2 is used a solvent for cleaning a variety of products during manufacturing processes, e.g., electronics cleaning and metal cleaning. Liquid CO 2 's solvent potential has been employed in some dry c leaning equipment as a substitute for conventional solvents
. Refrigeration and Cooling
. Liquid and solid CO 2are important refrigerants, especially in the food distribution industry, where they are employed during the transportation and storage of ice cr eam and other frozen foods, primarily in small retail food stores. In those cases, the CO 2may be stored on

- site or be provided by refrigerant technicians at the time of recharging. Transportation and Storage of Explosives
. Carbon dioxideis used in th e transportation and storage of explosives as it reduces the explosion risk. Algae Production
. Algae plantations for the production of biofuel s have recently been under the spotlight primarily with respect to potential capture of CO 2 from electric power and chemical production projects . The biofuel production from captured CO 2 represents a potential greenhouse gas / carbon sink. Also of strong interest is the usage of algae as a source of feedstock material for the production of biodiesel, and perhaps f ermentation. C arbon dioxide is an ingredient used by algae for normal growth, during photosynthesis. The process is being studied at various pilot projects in the U.S. and elsewhere
. Pressurized Gas
. C arbon dioxide is used as an inexpensive, nonflammablepressurized gas. Compressed CO 2 gas is used in life jackets (stored inside canisters), in air guns, in paintball markers, and for inflating bicycle tires. Chemica l processes. Carbon dioxideis currently used for various processes in the chemical indus try, including but not limited to, the production of: • Urea (from ammonia) • Methanol • Ethanol • Sodium Bicarbonate Pharmaceutical Processes
. Pharmaceutical processes may use CO 2 as a less toxic alternative to organochlo rides or more traditional solventsGeneral Technical Support Document for Injection and GeologicSequestration of

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37 

### A ttachment B U.S. Oilfields Using CO 2Injection for Enhanced Oil Recovery *Note that this table is a based on data summarized from the Oil & Gas Journal Enhanced Oil Recovery Survey published in April 2008 with permiss ion of the publisher. Any other use of these data may be subject to copyright restrictions. NR indicates that no production data were reported in the Oil & Gas Journal Survey

Field Operator State Incremental Production (bbl per day) Rangely Weber Sand C hevron CO 11,600 Hall - Gurney Murfin Drilling KS 3 Lockhart Crossing Denbury Resources LA NR Charlton 30 - 31 Core Energy MI 75 Charlton 6 Core Energy MI 10 Dover 33 Core Energy MI 75 Dover 35 Core Energy MI 286 Dover 36 Core Energy MI 195 Brookhaven Denbury Resources MS 3,100 East Mallalieu Denbury Resources MS 1,800 Eucutta Denbury MS 3,000 Lazy Creek Denbury Resources MS 250 Little Creek Denbury Resources MS 1,650 Martinville Denbury MS 830 McComb Denbury Resources MS 1,650 Smithdale Denbury Resources MS 600 Soso Denbury Resources MS 1,700 Tinsley Denbury Resources MS NR West Mallalieu Denbury Resources MS 6,200 North Hobbs Occidental NM 6,300 Vacuum Chevron NM 2,950 Vacuum ConocoPhillips NM 5,200 Bradley Unit Merit Energy OK 600 Camri ck Chaparral Energy OK 1,175 Northeast Purdy Merit Energy OK 1,800 Postle Whiting Petroleum OK 4,500 Postle Expansion Whiting Petroleum OK 1,700 Sho - Vel - Tum Chaparral Energy OK 1,170 Adair San Andres Unit Hess TX 900 Anton Irish Occidental TX 4,000 Cedar Lake Occidental TX 2,860 Central Mallet Unit Occidental TX 2,100 Cogdell Occidental TX 5,900General Technical Support Document for Injection and GeologicSequestration of

Carbon Dioxi de: Proposed Rule for Mandatory Reporting of Greenhouse Gases

38 Cordona Lake XTO Energy Inc. TX 400 Dollarhide (Clearfork "AB") Unit Pure Resources TX 1,970 Dollarhide Devonian Unit Pure Resources TX 124 East Ford O rla Petco TX 128 East Penwell (SA) Unit Energen Resources TX 450 El Mar Occidental TX 270 Frazier Unit Occidental TX 925 Garza George R. Brown TX NR GMK South Occidental TX 375 Goldsmith XTO Energy Inc. TX 20 Hanford Fasken TX 300 Hanford East Fask en TX 45 Hansford Marmaton Stanberry Oil TX 102 Igoe Smith Occidental TX 440 Levelland Occidental TX 950 Mabee Chevron TX 2,000 Means (San Andres) ExxonMobil TX 8,700 Mid Cross - Devonian Unit Occidental TX 296 N. Cross - Devonian Unit Occidental TX 835 North Cowden Demo. Occidental TX 80 North Dollarhide Occidental TX 1,000 North Perryton Chaparral Energy TX 170 North Ward Estes Whiting Petroleum TX 700 Reinecke Pure Resources TX 830 S. Cross - Devonian Unit Occidental TX 5,790 SACROC Kinder Morgan TX 24,227 Salt Creek Occidental TX 6,600 Seminole San Andres Unit - Main Pay and ROZ Hess TX 24,350 Sharon Ridge Occidental TX 400 Slaughter Apache TX 4,580 Slaughter (5 Units) Occidental TX 3,800 Slaughter Sundown Chevron TX 4,747 South Cowden Con ocoPhillips TX 250 South Welch Occidental TX 865 T - Star (Slaughter Abo) Occidental TX 2,100 Twofreds Great Western Drilling TX 170 Wasson (Cornell and Mahoney Units) XTO Energy Inc. TX 2,250 Wasson (4 Units) Occidental TX 44,325 West Welch Occidenta l TX 0 Yates Kinder Morgan TX 6,280 Greater Aneth Resolute Natural Resources UT 400 Greater Aneth Area ExxonMobil UT 3,000General Technical Support Document for Injection and GeologicSequestration of

Carbon Dioxi de: Proposed Rule for Mandatory Reporting of Greenhouse Gases

39 Lost Soldier Merit Energy WY 7,221 Patrick Draw Monell Anadarko WY 3,000 Salt Creek Anadarko WY 6,000 Sussex Anadarko WY NR W ertz Merit Energy WY 4,019