## GENERAL TECHNICAL SUPPORT DOCUMENT
FOR INJECTION AND GEOLOGIC SEQUESTRATION OF CARBON DIOXIDE:
SUBPARTS RR AND UU

GREENHOUSE GAS
REPORTING PROGRAM

Office of Air and Radiation
U.S. Environmental Protection Agency
November 2010

## Disclaimer

The Environmental Protection Agency (EPA) re gulations cited in th is technical support document (TSD) contain legally-binding requ irements. In several chapters this TSD offers illustrative examples for complying w ith the minimum requirements indicated by the regulations. This is done to provide in formation that may be helpful for reporters’ implementation efforts. Such recommendations are prefaced by the words “may” or
“should” and are to be considered advisor y. They are not required elements of the regulations cited in this TSD. Therefore, this document does not substitute for the regulations cited in this TSD, nor is it a re gulation itself, so it does not impose legallybinding requirements on EPA or the regulat ed community. It may not apply to a particular situation based upon the circum stances. Mention of trade names or commercial products does not constitute endorsement or recommendation for use.

While EPA has made every effort to ensure the accuracy of the discussion in this document, the obligations of the regulate d community are determined by statutes, regulations or other legally bi nding requirements. In the ev ent of a conflict between the discussion in this document and any statute or regulation, this document would not be controlling.

Note that this document only addresses i ssues covered by 49 CFR part 98, subpart RR and subpart UU, which are be ing promulgated under EPA’s authorities under the Clean Air Act (CAA). Other statutor y and regulatory requirements, such as compliance with Safe Drinking Water Act (SDWA) and Unde rground Injection Cont rol (UIC) Program requirements 1 , are not within the scope of this TSD. Please see section I.D. of the preamble to the final rule for more inform ation on the relationship between subpart UU, subpart RR and the UIC Program.

1 Please refer to EPA’s UIC Web site for more information: http://water.epa.gov/type/groundwat er/uic/wells_sequestration.cfm

.

2

### Table of Contents

Disclaimer

........................................................................................................................... 2
Table of Contents

............................................................................................................... 3 Acronyms and Abbreviations

........................................................................................... 6
1. Source Description

..................................................................................................... 8

1.1 Overview of Source Categories

............................................................................ 8
1.1.1 Geologic Sequestration

................................................................................. 8
1.1.2 Enhanced Oil and Gas Recovery

.................................................................. 8
1.1.3 Other Industries That Use CO 2

..................................................................... 9
1.2 Delineation of Facility

........................................................................................ 10
2. Reporting Threshold Analysis

................................................................................ 16
3. Monitoring Methods for CO 2 Received and CO 2 Injected

................................... 23
3.1 Determining the Amount of CO 2 Received Using Data from Sales, Contracts, Invoices, or Manifests Associated with Commercial Transactions

.............................. 23
3.2 Determining the Amount of CO 2 Received, Injected, or Produced Using Mass
Flow Meters or Volumetric Flow Meters

..................................................................... 24
4. Overview of Monitoring Technologies for CO 2 Leakage Detection and Quantification

................................................................................................................... 30
4.1 Monitoring of the Injection Well

....................................................................... 31
4.2 Monitoring of Subsurface CO 2 Plume

............................................................... 32
4.3 Vadose Zone Testing

.......................................................................................... 36
4.4 Soil Zone and Vegetation Testing

...................................................................... 36
4.5 Atmospheric Monitoring

.................................................................................... 39
4.6 Leakage Detection and Quantification in the Offshore Environment

................ 44
4.7 Detection Range, Accuracy and Precisi on of Various Monitoring Technologies .

............................................................................................................................ 46
5. Monitoring, Reporting, and Verification Plans

.................................................... 49
5.1 Delineation of the MMA and AMA

................................................................... 50
5.1.1 Maximum Monitoring Area (MMA)

.......................................................... 52
5.1.2 Active Monitoring Area (AMA)

................................................................. 53
5.2 Assessment of the Risk of Potential Leakage of CO 2 to the Surface

................. 54
5.2.1 Assessment of the Risk of Potential Leakage of CO 2 through Wells

......... 55
5.2.2 Assessment of the Risk of Potential Leakage of CO 2 through Fractures, Faults, and Bedding Plane Partings

.......................................................................... 58
5.2.3 Assessment of the Risk of Potential Leakage of CO 2 based on the Competency, Extent, and Dip of the Confining Zone

.............................................. 59
5.3 Strategy for Detecting and Quantifying any CO 2 Leakage to the Surface

......... 60
5.3.1 Detecting Leakage

...................................................................................... 60
5.3.2 Verifying Leakage

...................................................................................... 63
5.3.3 Quantifying Leakage

................................................................................... 64
5.4 Strategy for Establishing the Expected Baselines

.............................................. 67
5.4.1 Approaches for Establishing an Expected Baseline

.................................... 68
5.4.2 Considerations in Establishing Expected Baselines

................................... 70
5.5 Site-Specific Variables for the Mass Balance Equation

..................................... 73
5.6 Quality Assurance and Quality Control

............................................................. 76

35.7 Missing Data

...................................................................................................... 77
6. MRV Plan Approval Process Overview

................................................................. 78
6.1 Suggested Outline for the MRV Plan

................................................................. 78
6.2 Notification of Receipt of MRV Plan

................................................................ 78
6.3 Completeness Check

.......................................................................................... 78
6.4 Technical Review

............................................................................................... 79
6.5 Issuance of EPA Decision

.................................................................................. 80

6.6 Appeals Period

................................................................................................... 80

6.7 Resubmittal of MRV Plans

................................................................................ 80

7. Annual Monitoring Report and Records Retention

............................................. 81

7.1 Narrative History of Annual Monitoring Efforts

............................................... 81
7.2 Report of Non-Material Changes to the MRV Plan

........................................... 81
7.3 Narrative History of Monitoring Anomalies

...................................................... 82
7.4 Description of Surface Leakage

......................................................................... 82
7.5 Records Retention Requirements for MRV Plans

.............................................. 83 Appendix A: Glossary

....................................................................................................... 84 Appendix B: U.S. Oilfields Using CO 2 Injection for Enhanced Oil Recovery

................. 87 Appendix C: Summary of Other End Uses of Captured or Produced CO 2

....................... 90 Appendix D: Suggested Outlines for MRV Plans, MRV Plan Resubmittals, and Annual Monitoring Reports....

....................................................................................................... 93 Appendix E: Sampling Considerations for Designing a Monitoring Strategy

.................. 96

4List of Figures Figure 1-1: Facility Example 1

......................................................................................... 11 Figure 1-2: Facility Example 2

......................................................................................... 12 Figure 1-3: Facility Example 3

......................................................................................... 13 Figure 1-4: Facility Example 4

......................................................................................... 14 Figure 1-5: Facility Example 5

......................................................................................... 14 Figure 1-6: Facility Example 6

......................................................................................... 15 Figure 2-1 Total CO 2 used in ER showing growth since 2004

. ........................................ 17 Figure 5-1: Monitoring Areas as They Relate to UI C Class VI and subpart RR Requirements

.................................................................................................................... 54

List of Tables
Table 2-1: Threshold Anal ysis Based on Amount of CO 2 Received by a Facility

........... 21

Table 4-3: Detection Range, Accurac y, and Precision of Various Monitoring

Table 5-1. Surface Components as Potential CO 2 Emissions Sources at Injection Table 4-1: Monitoring Technologies as Deployed at 10 Existing CCS Projects

.............. 30 Table 4-2: Example Leak Quantification Using Tenting and Known Test Gas Flow

...... 38

Technologies

..................................................................................................................... 47

Facilities

............................................................................................................................ 74 Table 6-1: Completeness Check Criteria for MRV Plan Submittals and Resubmittals

... 79 Table D-1: Suggested Format for Listing of Monitoring Equipment

............................... 95

5

## Acronyms and Abbreviations

2-D Two-Dimensional

3-D Three-Dimensional

4-D Four-Dimensional

ACZ Above Confining Zone

AMA Active Monitoring Area

AMR Annual Monitoring Report

ASTM American Society fo r Testing and Materials
bbl Barrel

CCS Carbon Dioxide Capture and Geologic Sequestration

CFR Code of Federal Regulations

CH 4 Methane

CO 2 Carbon Dioxide

CO 2FI Total annual CO 2 mass emitted (metric tons) as equipment leaks or vented emissions from equipment located on the surface between the flow meter used to measure injection quant ity and the injection wellhead.

CO 2FP Total annual CO 2 mass emitted (metric tons) as equipment leaks or vented emissions from equipment located on the surface between the production wellhead and the flow meter used to measure production quantity.

CO 3 - - Carbonate

CZ Confining Zone

DIAL Differential Absorption Light Detection and Ranging

DIC Dissolved Inorganic Carbon

DOE Department of Energy
e-GGRT Electronic Greenhouse Gas Reporting Tool

EOS Equation of State

EM Electromagnetic

EOR Enhanced Oil Recovery

EPA Environmental Protection Agency

ER Enhanced Oil and Gas Recovery

FTIR Fourier Transform Infrared

GHG Greenhouse Gas

GPA Gas Processors Association

GPS Global Positioning System

GS Geologic Sequestration

H 2 CO 3 Carbonic Acid

H 2 S Hydrogen Sulfide

HCO 3 - Bicarbonate

HCPV Hydrocarbon Pore Volume

He Helium

InSAR Interferometric Synthetic Aperture Radar

IOGCC Interstate Oil and Gas Compact Commission

IRGA Infrared Gas Analyzer

IZ Injection Zone

6km Kilometer LIDAR Light Detection and Ranging
mcf Thousand Cubic Feet MIT Mechanical Integrity Testing MMA Maximum Monitoring Area MRV Monitoring, Reporting, and Verification NIST National Institute of Standards and Technology
O&GJ Oil and Gas Journal
PFC Perfluorocarbons ppm Parts Per Million ppmv Parts Per Million by Volume psi Pounds Per Square Inch SDWA Safe Drinking Water Act STP Standard Temperature and Pressure
TDL Tunable Diode Laser TSD Technical Support Document UIC Underground Injection Control

U.S. United States USDW Underground Source of Drinking Water ZERT Zero Emissions Research and Technology

71. 

### Source Description

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 2 reservoirs is approximately 44 million metric tons carbon dioxide equivalent . 2

, 3 Currently more than 95 percent of this CO 2 supplied to the economy is injected underground fo r enhanced oil and gas recovery (ER). 2 CO 2 may be injected underground for geologic se questration (GS). GS is the long-term
containment of a CO 2 stream in subsurface geologic formations and is a key component of a set of climate change mitigation t echnologies known as carbon dioxide capture and geologic sequestration (CCS). CCS has the potential to enable large emitters of CO 2 such as coal fired power plants to signific antly reduce greenhouse gas (GHG) emissions.

1.1 Overview of Source Categories

Three sectors were considered for incl usion in this rule: injection of CO 2 underground for GS, injection of CO 2 underground for ER, and end uses of CO 2 by other industries.

1.1.1 Geologic Sequestration

Underground geologic formations that can be used for GS include deep saline formations, oil and natural gas reservoirs, and un mineable coal seams. In addition, CO 2 may be injected into other types of subsurface geologi c formations, such as basalt formations. The UIC program, which is authorized by Pa rt C of the SDWA, regulates underground

CO 2 injection.

Geologic sequestration occurs through a combination of st ructural and stratigraphic trapping, residual CO 2 trapping, solubility trapping, mi neral trapping, and preferential adsorption trapping. These mechanisms are f unctions of the physical and chemical properties of CO 2 and the geologic formations into which the CO 2 is injected. For more background information on GS trapping mechan isms, see the Vulnerability Evaluation Framework for Geologic Seque stration of Carbon Dioxide. 4

1.1.2 Enhanced Oil and Gas Recovery

CO 2 is currently being injected into subsurf ace geologic formations in the United States (U.S.) for ER. The CO 2 currently being used in ER is primarily produced from naturally occurring underground CO 2 reservoirs but is also captu red from industrial processes, including combustion and ch emical manufacturing.

2 U.S. EPA. 2010. Inventory of U.S. Greenhouse Gas Emissions and Sinks, 1990-2008, EPA 430-R-10­
006. Available at: http://epa.gov/climatechange/emissions/usinventoryreport.html

. 3 The estimated 44.2 million metric tons of CO 2 does not include biogenic CO 2

. 4 Vulnerability Evaluation Framework for Geologic Se questration of Carbon Dioxide (see docket ID No. EPA-HQ-OAR-2009-0926)

8ER involves injecting CO 2 into oil or natural gas reservoirs via injection wells for the purposes of increasing crude oil production or to enhance recovery of natural gas. The
crude oil and CO 2 mixture is produced from producti on wells and sent to a two-phase separator where the crude oil is separa ted from the gaseous hydrocarbons and CO 2 . The gaseous CO 2 -rich stream then is typi cally dehydrated, recompre ssed, and reinjected into the oil or natural gas reser voir to further enhance recove ry. If the concentration of hydrocarbons in the CO 2 stream from the dehydrator is significant, then an acid gas recovery unit is used to separa te the hydrocarbons from the CO 2

.

Injection of CO 2 into unmineable coal seams may re sult in displacement of methane (CH 4 ) from the coal seam and subsequent pr oduction of the meth ane as a product (or enhanced coal bed methane).

There are currently 80 ER fields ope rating in the United States where CO 2 is being injected for the purposes of ER. 5 ER projects operating in th e United States 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 hundred s of injection wells. Approximately 44
million metric tons of CO 2 was received for injection underground for ER in 2008. Of this amount approximately 80 percent was produced from naturally occurring underground CO 2 reservoirs and 20 percent was cap tured from industrial processes, including combustion and chemical manufacturing. 6

Natural gas processing plants and wellhead treatment units condition incoming natural gas from the wellhead to meet sales and natural gas pipeline sp ecifications. In some fields the natural gas may contain a signi ficant quantity of hydrogen sulfide (H 2 S) or CO 2 , which is separated from the natural gas by the processing plants and treatment units. Because of the highly corrosive nature of this stream, the combination of H 2 S and CO 2 separated from the natural gas is called acid gas. The composition is quite variable and can range from 2 percent H 2 S and 98 percent CO 2 to about 85 percent H 2 S and 15 percent

CO 2

. 7 Most acid gas is disposed of by undergr ound injection under a UIC Class II permit. These permits may allow for disposal of ot her oil and gas production wastes, including brine, well completion and work-over flui ds, and spent dehydration unit fluids, in addition to the acid gas.

1.1.3 Other Industries That Use CO 2

5 See Appendix B of this technical support document.

6 U.S. EPA. 2010. Inventory of U.S. Greenhouse Gas Emissions and Sinks, 1990-2008, EPA 430-R-10­

006. Available at: http://epa.gov/climatechange/emi ssions/usinventoryreport.html

. 7 S. Bachu and W.D. Gunter. 2004. Overview of Acid Gas Operations in Western Canada. In: Proceedings of 7th International Conference on Greenhouse Gas Control Technologies

. Volume 1: Peer-Reviewed Papers and Plenary Presentations

.

9EPA identified and considered a tota l of 22 commercial end use sectors 8 that use gaseous, liquid, or solid CO 2 , excluding ER and GS. These end use sectors are summarized in Appendix C. EPA received comments to subpart PP suggesting that at least one of these end-uses – precipitated calcium carbonate production – may be a non-emissive use. At proposal for this rule, EPA sought comment on whether applications, such as precipitated
calcium carbonate and some cement production, permanently sequester CO 2 and if so, which industries this would include; how ma ny facilities operate in each of these industries; how much of the CO 2 consumed in each industry would be sequestered; whether a sequestration factor would be reas onable in any case; and what methodologies could be used to verify this sequestration. Th ese sectors were not in cluded in this final rule. Please refer to the Response to Co mments document for further information. 9

1.2 Delineation of Facility

For CO 2 received by pipeline, the point of m easurement for reporting the amount of CO 2 received at a facility will of ten be identified by a change in ownership (or custody) of the

CO 2 . The transfer of custody of the CO 2 is the basis of sales contracts and revenue reporting, and is generally measured with mete rs that conform to state oil and gas board regulations and industry standa rds. The question arises of how to delineate a facility when collecting data on CO 2 received. Subparts RR and UU rely on the definition of “facility” in 40 Code of Fede ral Regulations (CFR) 98.6, which states that “a facility means any physical property, plant, building, structure, source, or stationary equipment located on one or more contiguous or adjacen t properties in actual physical contact or separated solely by a public roadway or other public right-of-way and under common ownership or common control...” To illustrate how EPA applies this definition of facility to injection wells under subparts RR and UU, six example scenarios are presented in Figure 1-1 through Figure 1-6

.

8 This count includes the various chemical, pharmaceutical, and other processes that use CO 2 as an end product and excludes intermediate CO 2 processors. After CO 2 is captured from 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 2 into their processes in the necessary state; e.g., food grade CO 2 used for food and beverage production. Interm ediate processors often receive the produced CO 2 from the production process units or natural reservoirs, purify, compress, and/or liquefy it, and then deliver it to end users. Intermediate processors are not discussed further in this TSD.

9 See docket ID No. EPA–HQ–OAR–2009–0926.

10Figure 1-1: Facility Example 1

In the first example (Figure 1-1 ) an operator is conducting CO 2 -ER operations in a field that is fully contained within on e leased area. A large-diameter CO 2 supply pipeline (trunk line) owned by a thir d party supplies all the CO 2 used in the field. The CO 2 is
delivered to the field from the trunk line via a distribution lin e owned by the field operator. The custody of the CO 2 is transferred to the field operator at the meter where the distribution line begins. Once the fi eld operator takes possession of the CO 2 , it is transported over some distance and further dist ributed and injected into the wells in the field. Although not shown on the figure, there would likely be gathering lines from the producing oil wells that lead to facil ities that capture and re-process the CO 2 for reinjection downstream of the custody transfer meter. In this scenar io the field is one facility because it is under common control, and the mete r reading at the custody transfer point is the amount of CO 2 received.

11Figure 1-2: Facility Example 2

In the second example, Figure 1-2 , two fields under common control are fed by a
continuous CO 2 distribution line that passes through Field A and terminates in Field B. The operator has placed a meter at the upstream end of Field B to assist with state oil and gas board reporting requirements and reservoi r management. In this case, whether this scenario is one or two facilities depends on site specific conditions. Reporters should review the definition of facility carefully and decide whether to report as one or two
facilities in their specific situation.

12Figure 1-3: Facility Example 3

An example similar to Figure 1-1 is shown in Figure 1-3 . In this instance, Fields A and B are on different leases and operated by di fferent entities, but fed by a single CO 2 distribution line from the main trunk line. Ownership of the CO 2 is transferred at the
meter between Fields A and B. In this ex ample because Field A and Field B are under different ownership and control, they repres ent two different facilities. The amount of

CO 2 passing through meter A (at the trunk lin e) represents the total amount of CO 2 supplied to both fields; theref ore the owner of Field A shoul d report the total amount at meter A less the amount at meter B (the amount of CO 2 provided to Field B).

13Figure 1-4: Facility Example 4

Figure 1-4 shows a trunk line that splits and supp lies two different fields operated by the same entity, and thus are under co mmon control. Custody of the CO 2 is transferred at the meters that connect the distribution line to the trunk line. This example is similar to the second example, in that the determination of whether this situation represents one or two facilities depends on site-specific conditions. Reporters should revi ew the definition of facility carefully and decide wh ether to report as one or two facilities in their specific
situation.

Figure 1-5: Facility Example 5

14In large ER operations in a single field ope rated by the same entity, the trunk line may pass directly through the field and conn ect to multiple distribution lines ( Figure 1-5 ). Custody of the CO 2 is transferred to the operator at each meter. Even though there are many custody meters, the entire field is under common ownership and would be considered a single facility. To determine the total amount of CO 2 received at the facility, the reporter would sum the CO 2 amounts from all meters within the field.

Figure 1-6: Facility Example 6

In the last example, Figure 1-6 , a CO 2 generator supplies CO 2 to an ER project that it operates. The generation facili ty and ER operation are locat ed on the same property and are connected by a dedicated transmission line. In this example the generating facility, the transmission line, and the ER operation ar e under common ownership and are located on the same property and therefore are consid ered a single facility under subpart RR. The

CO 2 received is the amount passi ng through the meter at the poi nt of generation in this example. A third-party pipeline company th at owns and operates the transmission line, but does not take custody of the gas or operate the injection facility, is not a facility or operator under subpart RR.

152. 

### Reporting Threshold Analysis

To determine the appropriate threshold for reporting, EPA considered a threshold based
on the amount of CO 2 emitted, a threshold based on the amount of CO 2 injected, and a
threshold based on the amount of CO 2 received by the facility. EPA concluded that an emissions-based threshold would be problema tic because of the lack of data on the
incidence and scale of surface emissions and leakage from facilities that conduct GS and all other facilities that inject CO 2 underground. EPA also concluded that the amount of

CO 2 injected one year is not a good indicator of the amount of CO 2 injected the following year, and that injected CO 2 may be produced and recycled at some facilities. EPA accordingly analyzed injection facili ties based on the quantity of CO 2 received by the facility.

EPA conducted the threshold analys is based on the quantity of CO 2 received at the facility (not including CO 2 being recycled onsite) and considered whether a threshold on

CO 2 received should apply. EPA evaluated a no th reshold option (i.e., all facilities that inject CO 2 would be required to report), 1,000 metr ic tons per year, 10,000 metric tons per year, 25,000 metric tons per year, and 100,000 metric tons per year of CO 2 received per facility. Only fac ilities expected to be operating in 2011, the first year of reporting under this proposal, were considered in the anal ysis. For this analysis it was assumed that
all of the CO 2 received by the facility was injected for ER.

To establish a facility count, EPA relied on data reported in the Oil and Gas Journal (O&GJ) Enhanced Oil Recovery Survey published in April 2008. 10 These data come from the results of a voluntary survey of oil pr oducers reporting miscible and immiscible CO 2 projects in the U.S. operating as of the end of 2007. The O&GJ survey asked for the production figures “as of the end of 2007.” Fo r projects that were active throughout 2007 the value represents annual production (12 mont hs). Several of the projects started midyear, or had scheduled downtime in 2007, so the reported annual 2007 production may represent only a partia l year of production. Pr oduction data were not pro-rated to come up with an annual estimate. Some projects starting late in the year did no t see any increase in crude oil production due to ER 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 th e O&GJ. The O&GJ did not specify how the production data were to be calcu lated by the reporting facilities, so most of the data are based on internal oil company reporting, whic h 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 reported data. Most projects are defined based on production re porting requirements to state oil and gas commissions, based on the unit or pool. Some state oil and gas commissions finely divide the production zones in order to manage re source conservation. In one operation in Michigan, for example, the fields are very small (2–5 wells each) because they target pinnacle reefs that are limited in their ex tent. The company reported two “projects” separately to the O&GJ even though they are lo cated in the same field, because it appears

10 Enhanced Oil Recovery Survey. 2008. Oil and Gas Journal , Volume 105, Issue 15.

16that they target different producing zone s 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 locations within the large Seminole field, and target different parts of the reservoir (i.e., main o il pay or residual oil) using
different CO 2 injection technologies. Th ese are identified as “pilot tests” in the O&GJ data, so the company considers them se parate projects for evaluation purposes. Depending on how “project” or “facility” is defi ned, they could be separate or combined.

The use of CO 2 in ER has increased significantly since 2004 ( Figure 2-1 ), and is expected to increase further in the next five to 10 year s. The O&GJ survey is the latest and most complete data set of active ER 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 ER projects that will be operating in 2011.

For this analysis, EPA compiled all the projec ts listed for miscible and immiscible CO 2 floods 11 reported in the O&GJ survey. The list of active projects repres ents a wide crosssection of several geologic basins in 10 stat es, ranging from relative ly recent pilot-scale projects with one or two injection wells to CO 2 floods started in the 1970s with hundreds of injection wells. The Wasson Field in the Permian Basin is the largest user of CO 2 , and
has six active CO 2 ER projects managed by two operators.

Figure 2-1: Total CO 2 used in ER showing growth since 2004. Graph based on data from specified anthropogenic and natural CO 2 sources. Data based on sales. Source: Kinder Morgan CO 2 Company, CCS briefing to EPA June 3, 2009 12

11 A miscible CO 2 flood injects CO 2 as a liquid at high pressure to completely mix with oil and make it flow more easily. An immiscible CO 2 flood uses lower pressures of CO 2 to swell the oil and provide additional gas pressure to move the oil.

12 Note that the CO 2 being produced by Dakota Gasification Plant in North Dakota is being injected into an ER project in Canada.

17A total of 105 active ER proj ects operated by 23 different co mpanies were reported in the O&GJ survey. In some cases multiple projects were reported by the same company in an oil field, reservoir, or operat or unit. For the purposes of th is analysis, EPA grouped these reported projects by field and by owner or operato r to align with the definition of facility at 40 CFR 98.6. This computation results in 80 facilities that conduct ER. EPA further grouped the fields by their source of CO 2 as determined from geographic location, U.S. DOE pipeline maps, and operator-published info rmation. As of 2008, four 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 Plants, TX) supply CO 2 for ER that is conducted in the United States. 13

The O&GJ survey does not provide the specific volume of CO 2 used in each of the active ER projects, but does provide the total oil pr oduction attributed to the ER process. To
calculate the estimated volume of CO 2 received by each ER project, EPA determined the
total amount of CO 2 used daily for ER based on data from the U.S. EPA 1990–2007 Inventory of U.S. Greenhouse Gas Emissions and Sinks 14 (Inventory). According to the Inventory, approximately 2.08 bill ion cubic feet per day of CO 2 from natural and anthropogenic sources is received (purchas ed) for ER. The threshold analysis was performed two ways, one based on total daily CO 2 received combined for all fields in the U.S., and one based on the total from each source of CO 2 received for ER (natural or anthropogenic). The daily average CO 2 production from each source was apportioned among the projects supplied by the source base d on an average value for the fractional production of oil attributed to ER as presente d in the O&GJ survey and normalized on an annual basis (see Appendix B). The anal ysis was further complicated because anthropogenic gas from the Val Verde Gas Plants is mixed with natural CO 2 in the pipeline carrying the CO 2 to the Permian Basin; therefor e the specific projects supplied by the Val Verde Gas Plants could not be de termined. To accommodate the mixture of sources in the Permian Basin, the CO 2 from the Val Verde Gas Plants was apportioned based on the total crude oil production in th e Permian Basin and the known quantities of

CO 2 supplied from natural sources. The CO 2 from the Val Verde Gas Plants represents approximately 5.39 percent of the CO 2 used in Permian Basin Enhanced Recovery projects.

EPA recognizes that this is likely an ove rsimplification of the actual volume of CO 2 received by each facility, but notes that it fo llows the principle that higher production is a function of higher CO 2 injection volumes. The volume of CO 2 received by a particular ER project is a function of many factors, including:

13 DOE/NETL, 2009. Carbon Dioxide Enhanced Oil Recovery, Untapped Domestic Energy Supply and Long Term Carbon Storage Solution. U.S. Department of Energy, National Energy Technology Laboratory, September 2009. page 11. Available at: http://www.netl.doe.gov/technol o gies/oil-gas/publications/EP/small_CO2_eor_primer.pdf

14 U.S. EPA. 2009. Inventory of U.S. Greenhouse Gas Emissions and Sinks, 1990-2007, EPA 430-R-09­

004. Available at: http://epa.gov/climatechange/emissions/downloads09/GHG2007entire_report-508.pdf

.

18 Reservoir characteristics: Heterogeneity is a signifi cant design consideration, along with porosity, permeability, oil gravity, production history, depth, and reservoir pressure.

 Flood design: The injection design (e.g., continuous, simultaneous water and gas, water alternating gas), and number of injector wells are major factors in
overall CO 2 use. Injection well pa ttern, miscible or immi scible processes, CO 2 saturation target as a pe rcent of hydrocarbon pore volume (HCPV), and use of
surfactants and additi ves also influence CO 2 use.

 Project age: The stage of the project is a significant factor in determining CO 2 use. New CO 2 floods use more purchased CO 2 and produce less oil because
the CO 2 has not fully penetrated the reservoi r. It may take 6–12 months to see an increase in oil production upon initiat ion 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 2 is recycled from producing
wells.

The calculation of CO 2 utilization in the threshold analysis presented in this chapter is based on the volume of new (purchased) CO 2 for ER obtained from the Inventory. The value represents the “Net CO 2 Utilization” in thousand cubic feet (mcf)/barrel (bbl).

“Gross CO 2 Utilization” is the tota l amount 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.

To evaluate the reasonableness of the appr oach, EPA compared the calculated Net CO 2 Utilization from the threshold analysis to field-specific values for 12 field-scale projects published by DOE. 15 Values for individual projects showed variance; however, overall the average values were consistent (7.53 mcf/ bbl in the Threshold Analysis, versus 6.48 mcf/bbl in the 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 2 Utilization. EPA performed this comparison because the age of the project is one of the most significant factors in determining Net CO 2 Utilization. The threshold anal ysis evaluated ER projects by CO 2 source (essentially by producing basin) and resulted in Net CO 2 Utilization estimates by basin. The results provi ded support that the estimates of CO 2 use were reasonable. For example:

 The Permian Basin has the oldest EOR projects (70 percent started before 2000) and the Threshold Analysis shows the lowest Net CO 2 Utilization (7.2 mcf/bbl) for this basin.

15 DOE. 2006. Evaluating the Potential for “Game Changer” Improvements in Oil Recovery Efficiency
from CO 2 -Enhanced Oil Recovery, Prepared by Advanc ed Resources International for DOE NETL, February 2006. Available at: http://fossil.energy.gov/programs/oilgas/eor/G am e_Changer_Oil_Recovery_Efficiency.html

.

19 The Mississippi Interior Salt Basin has the youngest CO 2 EOR projects (15 percent started before 2000) and the Threshold Analysis shows the highest

Net CO 2 Utilization (19.2 mcf/bbl) of any basin.

Based on the analysis descri bed above, the simplified estimation using productionapportioned CO 2 volumes shows a good correlation with independent data and is an appropriate estimation of the amount of CO 2 received by the facility.

Analysis of the ER injection data showed fi ve fields with no enhanced production, which were correspondingly allocated to no CO 2 use. One additional field showed near zero production. Two of the six fields reported the projects as ha ving “just started,” and four reported projects at the “neari ng completion” stage. This demonstrated to EPA that injection activity generally follows a curve that can slowly increas e in the beginning, as the project moves from a pilot test to a larger scale, or slowly decrease toward the end of operations. Development of a full-scale CO 2 ER project requires extensive testing and ramping up over many years. Additionally, EPA determined that some ER production operations inject CO 2 and water in alternati ng pulses rather than continuously over years to maximize production, and the CO 2 injection periods and the corresponding (alternating) water injection pe riods may last from several m onths to two years or more. Therefore, the annual snapshot of data compiled for ER does not necessarily represent the typical operating conditions of full-scale projec ts expected in the future, as the number of ER operations increase.

The Interstate Oil and Gas Compact Commission (IOGCC) noted that acid gas is injected at approximately 20 sites in Michigan, New Mexico, North Dakota, Oklahoma, Texas, and Wyoming. 16 Many of the acid gas injection well lo cations are within oil fields that are listed in the O&GJ EOR survey, and inje ct into oil producing zones, suggesting the acid gas is being used for ER and not being in jected solely for the purposes of disposal. Other acid gas injection locations identified by the IOGCC that are not associated with ER include one in Michigan, two in North Dakot a, two in the Palo Duro basin of Texas, one in the Permian Basin in New Mexico, and one in Utah. These si tes generally inject the acid gas for disposal into permeable st rata below the deepest currently producing oil zone. EPA could not find any da ta to estimate quantity of CO 2 received for injection, so
these facilities are not include d in the threshold analysis.

Table 2-1 shows that nearly all facilities (92.5 pe rcent) received grea ter than 1,000 metric
tons of CO 2 per year

. At a reporting threshold of up to 25,000 metric tons of CO 2 received per year, essentially all CO 2 (100 percent) received w ould be included, but not all facilities would repor t. At a reporting threshold of 25,000 tons of CO 2 received per year, 65 of the 80 facilities (81 percent) would report. At a 10 0,000 metric tons of CO 2

16 Interstate Oil and Gas Compact Commission, 2005, Interstate Oil and Gas Compact Commission. 2005. Carbon Capture and Storage: A Regulatory Framework for States – Final Report January 2005. Available

at: http://groundwork.iogcc.org/topics-index/carbon-sequestratio n/executive-white-papers/ccgs-task-forcephase-i-final-report-2005

20received per year thresh old, 97.4 percent of all CO 2 used in ER would be reported from 60 percent of the facilities. The majority of the 40 percent of facil ities not covered are characterized in the O&GJ Survey as pilot pr ojects, projects that have just started, or projects nearing completion.

Table 2-1: Threshold Analysis Based on Amount of CO 2 Received by a Facility

Threshold
Level (metric tons/yr of
CO 2 received) Total
National (metric tons/yr of
CO 2 received) Total
Number of
U.S.
Facilities Amount of CO 2 Received Number of Facilities

Metric tons/yr
of CO 2 Received Percent
Covered Number of
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%

Since the proposed subpart RR rule and March 2010 General TSD 17 were published, a new O&GJ survey of ER projects was publis hed. The 2010 O&GJ Worldwide Survey of Enhanced Oil Recovery projects was c onducted by O&GJ and published on April 19, 2010 (Volume 108 Issue 14). The data were coll ected and presented in the same manner as the 2008 survey that EPA used in the Thre shold Analysis and described in the March
2010 General TSD.

The 2010 survey reflects the status of CO 2 ER projects at the end of 2009, and shows that the popularity of CO 2 ER is growing. There was a 14 pe rcent increase in the number of fields employing CO 2 flooding, a 4 percent increase in the acreage of projects, and a 2 percent increase in the acreag e of the fields. The projec ts included in the 2010 O&GJ survey are generally being operated by the same companies and in the same states as was the case in the 2008 survey. The projects a ppear to be more successful, producing 14 percent more oil per project with only a 3–5 percent increase in th e number of producing and injection wells. This is likely due to the increased volumes of CO 2 being used for flooding. 18

In the threshold analysis described in the March 2010 General TSD, EPA estimated the

CO 2 use for each field identified in the 2008 OG&J survey of ER projects operating as of the end of 2007 using the apportioned amount of CO 2 used daily for ER based on the 2007 data from the 1990–2007 U.S. GHG Inventory. The 2009 data from the 1990–2009

U.S. GHG Inventory is not avai lable at this time; therefore the Threshold Analysis cannot be updated to reflect the new 2010 O&GJ Survey data which identifies ER projects as of the end of 2009. However, producer s of natural sources of CO 2 are increasing

17 U.S. Environmental Protection Agency, General Technical Support Document for Injection and Geologic Sequestration of Carbon Dioxide, Proposed Rule for Mandatory Reporting of Greenhouse Gases, March 2010 (see docket ID No. EPA–HQ–OAR–2009–0926).

18 DOE. 2009. Electricity Use of Enhanced Recovery with Carbon Dioxide (CO 2 –EOR), U.S. Department of Energy, DOE/NETL 2009-1 354, January 26, 2009.

21production 19

, 20

, 21 in response to the growing demand for CO 2 in new and existing ER projects. The 2008 Inventory shows an incr ease from 2007 of approximately 3 million
metric tons of CO 2 production from natural sources. Additionally, as noted above, the
volume of CO 2 used in each field is increasing, as is the Net CO 2 Utilization.

19 Denbury Resources 2009 Annual Report page 20 shows a 7.2 percent increase in production of CO 2 over the previous year, and page 48 reports a production increase of 17 percent over 2009 in February 2010.

20 Kinder-Morgan Analysts Conference, January 28, 2010, Slide 14 showing Permian Basin CO 2 Deliveries increasing 23 percent from 2007 to 2009.

21 The 1990-2008 U.S. GHG Inventory (containing 2008 data) is available at: http://epa.gov/climatechange/emissions/usinventoryreport.html

.

223. 

### Monitoring Methods for CO 2 

### Received and CO 2 

### Injected

This chapter presents monitoring methods for determining the amount of CO 2 received (subparts RR and UU) and the amount of CO 2 injected (subpart RR).

CO 2 is a gas whose volume is typically reporte d at standard temper ature and pressure (STP). The behavior of CO 2 at low pressure and high temperatures can be satisfactorily approximated by the ideal gas law. The ideal ga s law is simple to a pply in practice, but
the behavior of CO 2 deviates from ideal gas with an in crease in pressure or decrease in temperature as the assumptions made in deri ving the ideal gas equation begin to deviate from actual gas behavior. The GHG Reporting Program addresses CO 2 equipment leaks,
vented CO 2 emissions, and combustion CO 2 emissions as well as CO 2 streams, which can be at a wide range of temper atures and pressures. In addi tion, the program also covers
facilities that conduct GS and all other facilities that inject CO 2 underground, which may
use mixtures of several fluids that predominantly contain CO 2 . The ideal gas law is only applicable to fluids in the gas phase; therefor e significant error will occur if it is used to calculate densities for liquids and supercritical fluids.

Measuring CO 2 in gas phase should be performed differently from CO 2 in the supercritical phase. In supercritical phase, CO 2 behaves much like a liquid, and other gases can dissolve into supercritical-phase CO 2 . This means the volumetric reading of supercritical phase CO 2 stream can be misleading if th ere is any significant amount of impurities dissolved in the CO 2 stream. The discussion be low describes different
measurement and calculation methods that may be required to accurately measure the different phases of CO 2

.

3.1 Determining the Amount of CO 2 Received Using Data from Sales, Contracts, Invoices, or Manifests Associated with Commercial Transactions

In order to determine the amount of CO 2 received, a facility woul d measure the flow rate
of the CO 2 at the custody transfer meter at the facility boundary prior to any subsequent processing operations at the faci lity, use flow rate data from the sales contract associated
with CO 2 received from a one-time commercial tr ansaction, use data from invoices or
manifests for CO 2 received from an ongoing commercial transaction, or measure the flow rate at the equivalent of a custody transfer meter, following the provisions of subpart PP,
for CO 2 supplied from a production process that is part of a facility. Also, for commercial
transactions for which the sales contract specifies a range of CO 2 concentration, and if the supplier of the CO 2 sampled the CO 2 stream and measured its concentration per the sales contract terms, the reporter can use the average CO 2 concentration data from the sales
contract or the seller’s measured value.

Information concerning the use of mass or vol umetric flow meters for measurement of
the amount of CO 2 received is included below under Chapter 3.2 concerning the use of data from sales contracts, invoices, or manife sts associated with commercial transactions is discussed in this chapter.

23For a one-time commercial transaction between a CO 2 supplier and a CO 2 recipient (i.e., the reporter) there would generally be a sales receipt indicating the amount of CO 2 that was supplied by the supplier and that was rece ived by the recipient in the commercial
transaction.

For an ongoing commercial tr ansaction between a CO 2 supplier and a CO 2 recipient (i.e., the reporter) involving a series of discrete shipments, there would generally be invoices or manifests indicating the amount of CO 2 that was supplied by the supplier and that was received by the recipient. Each individual invoice or manifest would cover a specific period of time (e.g., one month; one quarter) over which CO 2 was received, or may cover
one individual transaction in the series of discrete shipments.

To minimize errors in reporting data from sales receipts or invoices and manifests associated with one-time and ongoing comme rcial transactions, the sales receipts, invoices, and manife sts provided by the CO 2 supplier should report the amount of CO 2 supplied (and the amount of CO 2 received) in the same physical units (mass units) as are required to be reported under the subpart, a nd using the same standard conditions (STP) and conversion factors as are required to be used under the subpart. This will minimize errors by the reporter in converting the amount of CO 2 received from one set of units (e.g., volumetric units) to the units (i.e., mass units) that are required to be used under the subpart. If the commercial tran saction is actually tied to a different set of measurement units (e.g., volumetric units) the sales receip t, invoice, or manifest should report the
amount of CO 2 supplied in both the units to which th e transaction is tied and the units that are required to be reporte d under the subpart. The units of CO 2 concentration measurements provided by the CO 2 supplier in sales contracts used by the reporter to
determine the CO 2 content should also be in the same units as required to be used under the subpart, and the methodology used by the CO 2 supplier to measure the CO 2 concentration should be consistent with the methodology specified under subpart PP for

CO 2 suppliers.

For ongoing transactions, the reporter should compare invoi ces and manifests received
for CO 2 supply transactions from one period to the next (e.g., monthly, quarterly) or should compare the invoices or manifests from one shipment to the next, to assess the variability of the amount of CO 2 supplied. Unanticipated vari ation in the amount of CO 2 supplied (and received) between one invoice/manifest period and the next could indicate a reporting error on the part of the CO 2 supplier, for example.

3.2 Determining the Amount of CO 2 Received, Injected, or Produced Using Mass
Flow Meters or Volumetric Flow Meters

In order to determine the amount of CO 2 received, injected, or produced (at ER or other fluid production operations), a f acility would measure the flow rate using either a mass
flow meter or a volumetric flow meter. To de termine the mass, the facility would either multiply the mass flow rate by the concentration of CO 2 in that flow or multiply the
volumetric flow rate at ST P by the concentration of CO 2 in the flow and by the density of

24CO 2 at STP. Either a continuous mass flow me ter or a continuous volumetric flow meter would most accurately account for the fl uctuations over time of flow rate.

To minimize the error in calculating the mass from CO 2 volumetric readings, the application of an equation of state 22 (EOS) more accurate than the ideal gas law is recommended. The EOS proposed by Span and Wagner 23 represents the state of science in theoretical predic tion of gas phase CO 2 properties. This EOS predicts density of CO 2 within ± 0.03 percent to ± 0.05 percent for pressures up to 4,350 pounds per square inch (psi) and temperatures up to 482°F. At the sa me time, the Span and Wagner EOS may be too complex to be directly applied by repor ters. Therefore, EPA recommends using the database of thermodynamic properties develo ped by the National Institute of Standards and Technology (NIST). This on line database, available at http://webbook.nist.gov/chemistry/fluid/

, provides density of CO 2 using the Span and Wagner EOS at a wide range of temperature and pressures.

The following generic protocol is recommended to calculate CO 2 mass from volumetric

measurements, with the assumption that the gas stream is predominantly CO 2 :

 Obtain volumetric measurements using consensus standards at operating conditions;

 Determine the density of CO 2 at operating conditions using the Span and Wagner EOS from NIST tables;

 Calculate the mass of CO 2 in the required units by multiplying the density by
the volumetric measurements of CO 2

.

 Obtain species and their mass fraction information by sampling the stream of

CO 2 . The sample can be analyzed using standards from consensus standards organizations for methods such as ch romatography or mass spectroscopy to identify all chemical constituents and their mass fractions. With knowledge of
the mass of CO 2 calculated, the masses of the other individual species present may be evaluated knowing their individual mass fractions in the CO 2 stream.

The density of liquid or supercritical phase 24 CO 2 depends significantly on process conditions as well as mixture composition. Therefore, available theoretical models to calculate density of CO 2 may not be robust enough to span all potential process conditions. Furthermore, theoretical methods, where available, may be too cumbersome for reporters to implement in practice. EPA has not identified standards from consensusbased organizations that are suited for th e purpose of measuri ng the density of CO 2 in liquid or supercritical state. Therefore, EPA recommends the following generic protocol

22 An equation of state is a mathematical expression that describes the relationship between thermodynamic properties of chemical species.

23 Span, R. and W. Wagner. 1996. A New Equation of State for Carbon Dioxide covering the Fluid Region from the Tripe-point Temperature to 1 100 K at Pressures up to 800 MPa, J. Phys. Chem. Ref. Data, Vol 25.

24 Supercritical CO 2 refers to CO 2 with both pressure and temperatur e greater than their critical values. Critical temperature of a gas is the temperature above which the gas can not be liquefied at any pressure. This temperature for CO 2 is 88°F. Critical pressure is the pressure required to liquefy the gas at its critical temperature. Critical pressure for CO 2 is 1072 psi.

25to calculate density of CO 2 in liquid or supercritical st ate at process conditions or conditions at the point of transfer/measurement:

 Collect a representative sample of liquid or supercritical CO 2 mixture from process equipment in a high-pressure sampling container.

 Determine the volume of the sampling container from manufacturer specifications.

 Determine the mass of the sample by weighing the sampling container before and after taking the sample.

 Send the sampling container to an anal ytical laboratory for compositional analysis. The laboratory may expand the contents in sampling container to testing conditions. A sub-sample is anal yzed using standards from consensus standards organizations for methods such as chromatography and mass spectroscopy to identify all chemical constituents and their mass fractions.

 Determine the mass of each individual chemical species in the sampling container by the known mass of the sa mple and mass fractions. Mass of CO 2 in the process volumes from volume readings is determined by using volume of the sampling container and mass of individual species in each of the container; i.e., CO 2 Mass flow rate = CO 2 Volume flow rate *(Mass of Representative Sample / Volume of Sample Container) * Mass fraction of

CO 2 in the sample.

It is important to note that the sa mpling of liquid or supercritical CO 2 should be performed so the sample represents the pro cess fluid. Some American Society for Testing and Materials (ASTM) standards that detail procedures for sampling liquids, especially hydrocarbons such as liquefied natural gas, may be applicable to conduct this sampling. In addition, weighing scales may be sensit ive to temperature difference between the empty container and the container with the sa mple. Care must be taken to minimize such

error.

Facilities subject to the UIC program for pe rmitting of injection wells would already have
flow meters installed to measure the flow rate of the CO 2 stream injected for purposes of compliance with their UIC permits. It is common industry practice to use volumetric
rather than mass flow meters.

In order to determine the portion of the CO 2 stream that is CO 2 , the facility would sample the stream and analyze it for its CO 2 concentration. EPA has identified three industry standards that provide methods to quantify CO 2 that may be applicable to CO 2 streams. Facilities may use any standard method published by a consensus-based standards organization if such a method exists, or an industry standard practice.

Gas Processors Association (GPA) Standard 2261-00. Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography
This standard describes a method for the compositional analysis of natural gas and similar gaseous mixtures that also contain CO 2 , in addition to other gaseous constituents, and various hydrocarbons. The method consis ts of physically separating the gaseous

26constituents by gas chromatography with a thermal conductivity type detector. Procedures are outlined for component concen trations by mathematical procedures and using calibration data from a reference standa rd. The method is applicable to mixtures that confirm to component concentra tions as outlined in the standard.

GPA Standard 2177-03. Analysis of Natural Gas Liquid Mixtures Containing Nitrogen and Carbon Dioxide by Gas Chromatography
This standard describes a method for the co mpositional analysis of demethanized liquid hydrocarbon streams that also contain CO 2 , in addition to nitrogen and various hydrocarbons. The method consists of phys ically separating the liquid mixture constituents by gas chromatography havi ng a thermal conductivity type detector. Procedures are outlined for component concen trations by mathematical procedures and using calibration data from a reference standa rd. The method is applicable to mixtures that confirm to component concentra tions as outlined in the standard.

ASTM E1747-95 (re-approved 2005). Purity of Carbon Dioxide Used in Supercritical Fluid Applications This ASTM standard defines purity standards for CO 2 for use in chemical extraction and chromatography applications. The guide defines standards for impurities in CO 2 used in extraction and chromatography and it suggests methods of analysis for quantifying these impurities using gas chromatography with an electron capture detector and flame
ionization detector.

EPA recognizes that these sta ndards are not specifi cally designed for the analysis of CO 2 for use in ER or GS applications. The GP A standards note that the methods use gas chromatography to separate and identify com positional characteristics of the constituents of the gas/liquid mixtures; however, they are recommended and applie d for mixtures with a relatively low concentration of CO 2 (less than 20.0 mol perc ent in the case of GPA Standard 2261-00, and less than 5.0 mol percen t in the case of GPA Standard 2177-03). Typical applications of CO 2 for ER or sequestration may have CO 2 concentrations greater than 95 percent. There does not seem to be any indication in the standards themselves that the standards would be inaccurate or even biased for high CO 2 streams, but the reporter should evaluate the suitability of these methods if they are used.

Using the operating temperature and pressure, the volume of CO 2 can be converted into STP conditions and, using a STP density value for CO 2 , from the NIST online database (0.0018682 grams per millil iter or 0.11663 lb/ft 3 ) one can calculate the CO 2 quantity in metric tons. A facility would apply the same method in order to calcu late the quantity in
metric tons of CO 2 received.

Measurements of CO 2 volume may be taken at actu al pressure and temperature conditions and may therefore need to be conve rted to STP conditions for the purposes of reporting under subpart RR. If the CO 2 is not in a liquid or supe rcritical state the reporter may apply the Ideal Gas Law to convert measur ements at actual temperature and pressure conditions to STP conditions. Standard Temperat ure is defined in the Rule as 60 degrees
Fahrenheit. Standard Pre ssure is defined in the Ru le as 1.0 atmosphere.

27For example, if a CO 2 volume of 1,000 actual cubic feet was measured at an actual temperature of 300 degrees Fahrenheit and an actual pressure of 1.1 atmospheres, the
calculation to convert the meas urement to the volume of CO 2 at STP would be as
follows:

Volume Conversion using the Ideal Gas Law

The Ideal Gas Law is: P x V = n x R x T in which:

P = Pressure
V = Volume n = mass (number of lb-moles)

R = Gas Constant T = Temperature

For pressure in units of atmospheres, volume in units of cubic feet , and temperature in degrees Rankine, the Gas Constant R = 0.730 atm ft3 / lb-mol deg. R.

Degrees Rankine is defined as Degrees Fahrenheit + 459.67.

From the Ideal Gas Law:

P 1 x V 1 / T 1 = P 2 x V 2 / T 2

Where:

P 1 = Actual pressure

T 1 = Actual temperature

V 1 = Actual volume

P 2 = Standard pressure

T 2 = Standard Temperature

V 2 = Volume at Standard Conditions

For the example of a measurem ent of 1,000 cubic feet of CO 2 at actual temperature and pressure conditions of 1.1 atmospheres and 300 degrees Fahrenheit, the values for the Ideal Gas Law equation would be as follows:

T 1 = Actual Temperature = 300 + 459.67 = 759.67 Deg R

P 1 = Actual Pressure = 1.1 atmosphere

T 2 = Standard Temperature = 60 + 459.67 = 519.67 Deg R

P 2 = Standard Pressure = 1.0 atmosphere

V 1 = Actual Volume = 1,000 cubic feet

The equation P 1 x V 1 / T 1 = P 2 x V 2 / T 2 would then be solved for the variable V 2

.

V 2 = (P 1 x V 1 / T 1 ) / (P 2 / T 2 )

28V 2 = [(1.1 atm) x (1,000 ft 3 ) / (759.67 Deg R)] / [(1.0 atm) / (519.67 Deg R)]

Therefore:

V 2 = 752.48 cubic feet at standard temperatur e (60 degrees F) and pressure (1.0 atm)

For CO 2 that is in a supercritical state, the Idea l Gas Law is not applicable and therefore a different equation of state is needed to calculate the volume of the CO 2 at standard
conditions.

In such cases, the reporter may apply the NIST Thermophysical Properties of Fluid Systems (accessible at http://webbook.nist.gov /chemistry/fluid/ ) to look up the density of supercritical CO 2 at actual temperature and pressure conditions.

For example, for supercritical CO 2 at an actual temperature of 140 degrees Fahrenheit (60 degrees Celsius or 333.15 degrees Kelvin) and an actual pressure of 100 atmospheres (10.13 MPa or 1470 lb/in 2 ) the NIST Thermophysical Properties database shows the density of the supercritical CO 2 to be 18.614 lb/ft 3

.

Temperature (F) Pressure (atm) Density (lbm/ft 3 ) State

140 100 18.614 supercritical

At the standard temperature of 60 degrees Fahrenheit and standa rd pressure of 1.0 atmosphere, the density of CO 2 is 0.11663 lb/ft 3

.

So if a volume of 1000 ft 3 of supercritical CO 2 was measured at actual pressure and temperature conditions of 100 atmospheres a nd 140 degrees Fahrenheit, that volume of

CO 2 would be equivalent to: 1000 ft 3 x 18.614 lb/ft 3 = 18,614 lb of CO 2

.

The density of CO 2 is 0.11663 lb/ft 3 at STP. Therefore, 18,614 lb of CO 2 at a density of
0.11663 lb/ft 3 = 18,614 lb / 0.11663 lb/ft 3 = 159,598.7 ft 3 CO 2 at STP.

Therefore, the volume of the 1,000 ft 3 of CO 2 at actual conditions would be reported as 159,598.7 ft 3 CO 2 under standard conditions.

294. 

### Overview of Monitoring Technologies for CO 2 

### Leakage Detection and Quantification

This chapter describes technologies for mon itoring of the injection well, subsurface CO 2 plume, vadose zone 25 , soil zone and vegetation, and atmosphere and how they may be applied to detect and quantify movement of CO 2 to the surface at GS sites. Table 4-1 provides a list of monitoring methods that are being used at CCS projects. 26

Table 4-1: Monitoring Technologies as Deployed at 10 Existing CCS Projects

(Source: J.J. Dooley, CL Davidson and RT Dahowski. 2009. An Assessment of the Commercial Availability of Carbon Dioxide Capture and Storage Te chnologies as of June 2009. Joint Global Change Research Institute. Pacific Northwest National Laboratory. June 2009. PNNL-18520)

While technologies for quantifying CO 2 surface leakage from GS sites are continuously being refined, it is generally recognized th at, when properly planned and implemented, monitoring methods will be effectiv e at detecting surface leakages. 27

, 28 A wide range of

25 The vadose zone is the relatively shallow zone beneat h the surface that is not saturated with groundwater.

26 J.J. 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.

27 Benson, S.M. 2006. Monitoring 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/one p etropreview?id=SPE-102833-MS&soc=SPE (at cost).

28 FutureGen Alliance. 2006. Mattoon Site Enviro nnemental Information Vo lume. December, 2006. http://www.futuregenalliance.org/

.

30techniques for monitoring GS have been used at GS sites as well as for a number of years in other applications, incl uding oil and gas production, ER, and plant and soil science. These techniques may be used at a GS site to monitor the injected CO 2 , the surrounding rocks and fluids, wells and equipment, a nd the surface conditions. EPA has concluded that a GS facility would be able to pr opose a site-specific monitoring, reporting, and verification (MRV) plan for leak detection and quantific ation based on the current availability of monitoring technologies. In addition, it is e xpected that site characterization and screening will lead to se lection of sites that are suitable for longterm sequestration, and that incidences of leak s to the surface may be infrequent at wellselected and well-managed sites.

4.1 Monitoring of the Injection Well

Mechanical Integrity Testing (MIT) is commonly used at UIC permitted injection wells to demonstrate that the injection wells can resist the high pressures of injection, as well as the potentially corrosive na ture of the injected CO 2 . Please refer to the UIC program Web site for information on requirements related to monitoring of UIC permitted injection wells, including MIT. 29

Periodic external MIT checks the area between the cemen t and the formation in the long string casing to detect gaps or fluid flow. 30 Should there be a break in the bond between
the cement and the rock of th e wellbore, the injected CO 2 can make its wa y vertically to access shallow formations, and possibly escape to the surface. External MIT is a reliable and effective method commonly carried out usin g wireline logs or pressure tests.

Wireline logs are subsurface measurements of the wellbore taken by lowering an instrument on a wire into the well, and reco rding the log response continuously as the tool is pulled upward. This generates a deta iled picture of the bor ehole and nearby rock. There are numerous types of wireline logs used in the oil industry; the primary focus is on determination of reservoir properties such as lithology, porosity, and fluid content (oil, gas or water). Other types of tools 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 for 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 th e casing and cement, and be tween the cement and the
formation. 31

, 32 The temperature log helps identify hot spots due to flow from deeper

29 http://water.epa.gov/type/groundwat er/uic/wells_sequestration.cfm

. 30 Koplos, Jonathan, B. Kobelski, A. Karimjee, C. H. Sham. 2006, UIC Progra m Mechanical Integrity Testing: Lessons for Carbon Capture and Storage. Fifth Annual Conference on Carbon Capture and Sequestration, May 8-11, DOE/NETL, 2006. http://www.netl.doe.gov/publications/proceedings/06/carbonseq/Tech%20Session%20139.pdf

. 31 Duguid, Andrew, and John Tombari. 2007. T echnologies for Measuring Well Integrity in a CO 2 Field.
Sixth Annual Conference on Carbon Capture and Sequestration. DO E/NETL, May 2007. Available at: http://www.netl.doe.gov/publications/proceeding s/07/carbon-seq/data/papers/tue_064.pdf

.

31formations, 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 qua litative measure of the amount of leakage. Other external integrity test s include the oxygen activation log and radioactive tracer surveys, which indicate lack of fluid migration behind the casing.

Internal MIT of the injection well checks the inte grity of the well materials: the tubing, packers, and long string casing. During inje ction operations, there can be continuous monitoring of the annulus fluid pressure, wh ich is typically main tained at a higher pressure than that of the injected CO 2 . A drop in the annulus pre ssure may indicate cracks or holes in the long string cas ing, or may also indicate a leak in the tubing or packers. This would not necessarily be an indication of a CO 2 leak to the atmosphere. In addition to continuous pressure monito ring in the annulus, internal well damage can be monitored with periodic wireline logs, in cluding caliper tools, radioact ive tracer tests, and downhole video. Logs can detect corroded or damaged t ubing or casing even before a leak occurs. All of these methods are commonly us ed in the oil and gas industry.

In certain circumstances, new technologies allow well logging to be conducted while drilling using small, sophisticated tools.

4.2 Monitoring of Subsurface CO 2 Plume

The location and size (areal extent) of the injected CO 2 plume can be evaluated using several approaches. These include the acquisiti on of active seismic data, passive seismic data, gravity data, and informa tion from monitoring wells. This information can be used
in concert with reservoir m odeling to predict subsurface CO 2 plume movement. Please refer to the UIC program Web site for info rmation on requirements related to tracking and monitoring the CO 2 plume. 33

The active seismic geophysical technique involves the generation of sound waves that propagate downward or laterally through the subsurface, are reflect ed off of geological layers, and are subsequently detected and analyzed at the surface by advanced
instrumentation. The method is used to evaluate the structural or sp atial configuration of 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 locat ed on the surface.

In vertical seismic profiling , the source is on the surface and the detector is downhole. In another arrangement called cross-well seismic , both source and detector are downhole in
different wells. Pe riodic acquisition of active seismic data can in some cases be used to
detect subsurface CO 2 movement within and outside of the injection zone (IZ). This may include leakage from or around the injecti on well, from or around older pre-existing wells, or through geological zones of weakness in the confinement zone (CZ).

32 DOE/NETL. 2009. Best Practices for Monitoring, Verification, and Accounting for CO 2 Stored in Deep Geologic Formations. U.S. Department of Energy, Na tional Energy Technology Laboratory. Available at: http://www.netl.doe.gov/technologies/car bon _seq/refshelf/MVA_Document.pdf

. 33 http://water.epa.gov/type/groundwat er/uic/wells_sequestration.cfm

.

32A variety of active seismic methods are in us e today in the oil and gas industry, and can
be used for CO 2 plume monitoring. These include two-Dimensional (2-D) seismic, threeDimensional (3-D)/four-Dimensional (4-D) seismic

, vertical seismic profiling , and crosswell seismic. Surface seismic data may be either 2-D, 3-D or 4-D. 2-D seismic is obtained with a linear surface arrangeme nt of receivers. The acoustic energy source is from small explosive charges or from “vibro-seis” truc ks. 3-D seismic may provide better resolution, accuracy, and tracking of the CO 2 if it migrates from the storage reservoir into the
overburden. 3-D seismic evaluates a large volume of th e subsurface, has high resolution, and is more complex and more costly to obtai n and analyze. Surface r eceivers are laid in a grid pattern, and la rge amounts of data are simultaneou sly recorded and subsequently processed. Sophisticated software allows the conversion of this raw information into a detailed subsurface representation. 3-D data are being increasingly used in the oil industry, as they allow the mapping of structural details, small faults, rock properties, and fluid properties. 4-D seismic is 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 deployed in a borehole to measure sound propagation in the immediat e vicinity of the well. 34 It is a high-resolution method that
evaluates a small volume of the subsurface ad jacent to a single well. A variation of vertical seismic profiling is “walk-away” profiling, 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 evaluates a small rock volume. Vertical seismic profiling and cross-well seismic methods are used to develop a very high-resolution image of conditions relatively near the inject or or monitoring wells, due to the short
distance between seismic sources and receivers. These methods can also be used to calibrate the acoustic signature of the CO 2 plume under very controlled conditions. This calibration can then be used to better interp ret the 2-D and 3-D seismic, which cover 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. These methods are known to be effective in many cases where CO 2 is injected into a saline re servoir and has a good density contrast with the saline fluid. The ability to image and track a CO 2 plume depends upon factors such as lithology (sandstone, limest one, coal, or shale), porosity (pore space),

- - ) fluid content, and depth. 35 Seismic detection of a CO 2 plume in a carbonate (CO 3 (limestone 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 lowe r average fluid density contrast (both oil

34 DOE/NETL. 2009. Best Practices for Monitoring, Verification, and Accounting for CO 2 Stored in Deep Geologic Formations. U.S. Department of Energy, Na tional Energy Technology Laboratory. Available at: http://www.netl.doe.gov/technologies/car bon _seq/refshelf/MVA_Document.pdf

. 35 IPCC. 2005. Carbon Dioxide Capture and Storage. Intergovernmental Panel on Climate Change, pg. 237.
Available at: http://www.ipcc.ch/publications_and_data/publications_and_data_reports_carbon_dioxide.htm

.

33and free-phase CO 2 are less dense than saline water). Studies have been undertaken to evaluate seismic plume m onitoring in coal beds. 36

Active seismic methods includi ng 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; a drawback is that seismic methods only image free-phase CO 2 in 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 a nd 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 and Weyburn projects. 37 To be detectable, the CO 2 accumulation must have lateral and verti cal dimensions sufficient to produce a discernible seismic response. One study ba sed on theoretical resolution considerations 38
has suggested that CO 2 buildups as small as 10,000 to 20,000 metric tons may be detectable at typical injec tion depths, but amounts would be difficult to quantify, as saturation would remain a key uncertainty. In practice, results from the Sleipner timelapse surveys suggest that repeatability noise (which depends on the accuracy with which successive surveys can be matched), rather th an resolution, may be the key parameter in limiting the detection of small changes of seismic signature due to leakage. Under favorable conditions, such as those at Sl eipner, Weyburn and Frio, accumulations on the order of 1,000 to 10,000 metric tons of CO 2 are detectable at depths less than 1,000 meters (m), and smaller accumulations could be detected at shallower depths. 39

Passive seismic methods, which use only receivers ( no active acoustic sources), monitor the sound waves that are emitted from high-pres sure injection sites with sophisticated instrumentation and decipher the results usi ng computational methods . As the pressurized

CO 2 moves through the reservoir, it creates mi crofractures that release acoustic energy that is detected in 3-D space. Passive seismi c 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 in the CZ or activation of old faults.

Gravity surveys measure the earth’s gravitational field at a series of points over a subsurface target of interest. Gravity surveys have been used since the early 1900’s in oil exploration, and are now being evaluated for use in GS sites. Changes in the earth’s

36 Lawton, Don. 2002. A 3C-4D Surface Seismic and VSP Program for a Coalbed Methane and CO 2 Sequestration Pilot – Red Deer, Alberta. CR EWES Research Report 14. Available at: http://www.crewes.org/ForOurSponsors /Research Reports/2002/2002-64.pdf

. 37 DOE. 2009. Best Practices for Monitoring, Verification, and Accounting for CO 2 Stored in Deep Geologic Formations. U.S. Department of Energy, Na tional Energy Technology Laboratory. Available at: http://www.netl.doe.gov/technologies/car bon _seq/refshelf/MVA_Document.pdf

. 38 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. Available at: http://www.sciencedirect.com/science/book/9780080442761

. 39 Benson, S.M.. 2006. Monitoring Carbon Dioxide Sequestration in Deep Geological Formations for Inventory Verification and Carbon Credits. Society of Petroleum Engineers Paper 102833, 14pp. Available

at: http://www.energy.utah. gov /Utah_Actions/documents/dec2006/spe102833.pdf

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34gravitational field are caused by changes in density in the underlying rock layers.

Because CO 2 is usually less dense than native fluids and petroleu m, reservoirs that fill
with CO 2 will appear as lower gravity areas. Gr avity surveys are performed in a time lapse mode like 4-D seismic, to evaluate plume movement. Data processing is complex
and involves removal of several external influe nces from the data se t prior to creating a model of the gravity field. Studies at Sleipne r site indicate the method shows promise to help constrain the rese rvoir simulation models 40 . This technology is stil l in early stages of field testing and model development.

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 represent a single point in time and space. The monitoring wells can be logged periodically with wireline logs that can be used to detect the presence and depth of CO 2 . Certain wireline tools may be used to collect a fluid sample under reservoir pressu re and temperature conditions, and retrieve the sample to the surface for laboratory analysis. 41 They can also be used for cross-well

seismic data acquisition, in which seismic si gnals 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-tube 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 i norganic carbon (DIC) can be determined using complex algorithms. DIC includes aqueous CO 2 , carbonic acid (H 2 CO 3 ), bicarbonate (HCO 3 - ), and CO 3 - - . CO 2 leakage from the reservoir can be detected long before the CO 2 can escape to shallower zones or to the surface.

Geochemical sampling of the fluid from mon itoring 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 i ndicates a significant anomaly relative to background levels.

Intermediate monitoring wells can be used to test zones within a depth range of approximately 200 to 2,000 feet below the surf ace. As with the deeper wells, downhole instruments can measure pressure, temper ature, and conductivity/salinity. Further monitoring may be implemented when read ings depart from background levels; for example, a 3-D seismic survey may be undertaken if the anomaly is within an appropriate depth range.

Surface deformation monitoring is currently being tested as a rapid cost effective method to identify plume movement and potential l eakage pathways in the subsurface. As CO 2 is injected the ground surface may be raised a minute amount in response to the addition of fluids to the subsurface. Highly sensi tive tiltmeters (much like a highly sensitive

40 Arts, R., Chadwick, A., Eiken, O., Thibeau, S., Nooner, S., 2008. Ten years’ experience of monitoring

CO 2 injection in the Utsira Sand at Sleipner, offshore Norway, First Break , Volume 26, January 2008

41 FutureGen Alliance. 2006. Mattoon Site Environnemental Information Volume. Available at: http://www.futuregenalliance.org/news/fg_mattoon_eiv_v1_master_rev1.pdf

.

35electronic carpenters level) and Differential Gl obal Positioning Systems can be used to measure ground movements over small areas, and specialized rada r (Interferometric Synthetic Aperture Radar (InSAR)) can be us ed to survey large areas from the air. Tiltmeters are capable of detecting changes in slope on the order of one millimeter (mm) over 1000 kilometers. InSAR satellite images are collected monthly and can cover from 2,500 to 10,000 square kilometers (km) w ith accuracy in the millimeter range. 42 When combined with tiltmeter and global positioning system (GPS) data, accuracy and resolution can be improved. Surface deformatio n at In Salah was monitored using InSAR
from 2003 to 2008 43 and showed ground swelling on the scale of 3 to 14 mm per year near the injection wells, and several millimeters of subsidence near the natural gas production wells. The data can be used to in fer underground pressure gradients and fluid movements from the changes in surface deformation over time. Surface deformation surveys are influenced by vegetation, frost h eaves and other natural conditions that can be
removed from the data set with additional information.

4.3 Vadose Zone Testing

The vadose zone is the relatively shallow zone beneath the surface that is not saturated with groundwater. Due to absence of water, m onitoring in this zone therefore is limited to testing the chemistry of the gases contained within the pore space. The CO 2 concentration of gas samples taken in this zone can be measured using commercially available infrared gas analyzers (IRGAs), which measure the absorption of specific portions of the infrared spectrum to determine the concentration of CO 2 (or other gases) in the sample. Background levels must first be measured to determine the statistical variations of CO 2 concentration accounting for sample temperatur e, seasonal variations, diurnal variations, and the like. Later, a presumptive leak is detected if the monitored CO 2 concentration exceeds 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 a nomalies be detected, an expanded soil or atmospheric testing program may provide additio nal information. In addition to the use of
IRGAs for CO 2 concentration, vadose zone sampli ng can include testing for tracers, should they be used, and for sampling fo r carbon and oxygen isotopes, to determine
whether the CO 2 is that which is being inje cted or naturally occurring CO 2

. 44 As with data collected in monitoring wells, these indi vidual measurements are quite reliable and accurate, but their limitation is that they re present a single point in time and space.

4.4 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 uppermos t layer of the vadose zone. The soil zone is the fertile

42 McColpin, L. 2009. Surface Deformation Monito ring as a Cost Effective MMV Method. Energy Procedia, 1, (2009) pp. 2079-2086

43 Onuma, T, and Ohkawa, S. 2009 Detection of surface deformation related with CO 2 injection by D InSAR at In Salah, Algeria Energy Procedia, 1, (2009) pp. 2177-2184

44 FutureGen Alliance. 2006. Mattoon Site Envi ronmental Information Volume. Available at: http://www.futuregenalliance.org/news/fg_mattoon_eiv_v1_master_rev1.pdf

36portion that can retain water (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 background levels (which vary with time of day a nd season) be determined to provide a wellcharacterized baseline against which statisti cally significant anomalies can be detected
and estimated.

Accumulation chambers can be used to estimate CO 2 flux from the ground surface to the atmosphere, and be used to directly detect and quantify the mass of CO 2 leaking from the
subsurface. 44 The approach may consist of a grid of accumulation chambers in which the

CO 2 flux is periodically measured. 45 Commercially available accumulation chamber instrument packages are curre ntly being used to track seasonal variations in CO 2 flux as part of climate change studies. The accumu lation chamber is a method of measuring soil

CO 2 flux that involves the placement of a collect ion chamber directly on or into the soil surface, with the rate of CO 2 accumulation measured periodically with an IRGA. The rate of change in CO 2 concentration defines the rate of fl ux. The calculated rate of flux can be used as a standalone qua ntification method if CO 2 leakage is detected. This type of measurement could be used to quantify leak age that is moving up through the soil zone across a wide area, as opposed to point sour ces such as a leaking injection well. To account for local variations in the underlyi ng geologic, soil characteristics, and soil moisture levels, several accumulation chambers would have to be distributed over the area to quantify the leakage rate. CO 2 flux 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 better than 5 micrograms per square meter per second. That point measurement precis ion corresponds to a leak ra te 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 mate rial) 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 CH 4 leaks from natural gas pipelines and could also be used for CO 2 quantification. Variations of this me thod are commonly used in measuring CH 4 flow rates from equipment leaks. 46 A tent or bag is constructe d above a known leakage site. An inert gas such as nitrogen is conveyed through the bag at a known flow rate. Once the carrier gas attains equilibrium, a gas sa mple is obtained from the bag and the CH 4 content of the sample is determined. The leak flow rate is calculated from the purge flow rate through the enclosure and the concentration of CH 4 in the outlet stream. Table 4-2 illustrates the general approach to quantify the leak.

45 Oldenburg, C.M., Jennifer L. Lewicki, and Robert P. Hepple. 2 003. Near-Surface Monitoring Strategies for Carbon Dioxide Storage Verification. Earth Sciences Division, Lawrence Berkeley National Laboratory, publication LBNL-54089. Available at: http://www.osti.gov/bridge /serv lets/purl/840984­ dTw752/native/840984.pdf

. 46 Envirotech Engineering. 2007. Review and Update of Methods Used for Air Emissions Leak Detection and Quantification. February 5 th , 2007. Available at: http://eipa.alberta.ca/media/31357/1666%20review%20and%20update%20of%20methods%20used%20for %20air%20emissions%20leak%20detection%20and%20quantification%20-%20final%20report.pdf

37Table 4-2: Example Leak Quantification Using Tenting and Known Test Gas Flow 47

Inlet Flow of Conveyed
Test Gas (cu. ft./minute) Measured CO 2 Concentration 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 leakag e 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 statis tical sampling. However, the cost and time to set 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 be detected through shallow wells drilled to sample the groundwater. Such wells may be on the order of only several hundred feet deep. Water samples collected from the wells are analyzed for a wide range of parameters that may reflect changes due to the presence of CO 2 . Some indicator parameters such as pH, alkalinity, electri cal conductance and dissolved oxygen can be measured in the field, and other parameters (trace metals, disso lved organic carbon, organic compounds and isotopes) are submitted to a laboratory for an alysis. Pilot tests and controlled release experiments demonstrate that the rapid and si gnificant changes in chemical parameters were observed in response to the presence of CO 2

. 48 As with soil testing, background
levels must first be established in orde r to detect changes that may indicate CO 2 leakage.

Vegetative stress can also be a leakage indicator. Vegetative stress can be detected through tower-mounted or airborne imaging inst ruments, such as digital color infrared orthoimagery or hyperspectral and multispectra l imaging, to detect changes to vegetation coloration in the visible, infrared, and u ltraviolet spectrum. These are relatively new technologies with uncertainty in the interpre tation of the results. Recent work has shown that vegetation in the vicinity of a leak ma y be negatively affected, but vegetation farther from a leak may be positively affected. 49 A controlled release experiment at the Zero Emissions Research and Technology (ZERT) facility in Montana reported that the
surface area of CO 2 leakage hot spots could be delin eated to within 2.5 meters using portable hyperspectral imagers. The plant re sponse was dependent on plant species but was discernable when soil concentrations reached 4 to 8 percent CO 2 concentration. 50

47 The Calculated Outlet Flow Rate (cu. ft./minute) is inlet flow volume divided by concentration. The
Calculated CO 2 Leak Rate (cu. ft./minute) is calculated as outlet flow minus inlet flow.

48 Kharaka, Y., J. Thordsen, E. Kakouros, G. Ambats, W. Herkelrath, S. Beers, J. Birkholzer, J. Apps, N. Spycher, L. Zheng, R. Trautz, H. Rauch, and K. Gullickson 2009. Changes in the Chemistry of Shallow Groundwater Related to the 2008 Injection of CO 2 at the ZERT Field Site, Bozeman Montana. Environ. Earth Sci. (2010) 60:273-284

49 Rouse, J.H. 2008. Measurements of Plant Stress in Response to CO 2 Using a Three-CCD Imager. Montana State University. Available at: http://etd.lib.montana.edu/etd/2008/rouse/RouseJ1208.pdf

50 Male, E.J., W.L. Pickles, E.I. Silver, G.D. Hoffmann, J. Lewicki, M. Apple, K. Repasky, and E.A. Burton, Using hyperspectral plant signatures for leak detection during the 2008 ZERT CO 2 sequestration

384.5 Atmospheric Monitoring

The atmosphere above a GS site may be monitored with an array of CO 2 detectors (closed-path point measurements and open-pa th line measurements), tracer gas and CO 2 isotopic measurements, eddy covariance met hods, Raman LIDAR (Light Detection and Ranging), or Differential Absorption LIDAR (DIAL). In all methods, CO 2 concentration data are integrated with data on wind speed and direction to dete rmine the vertical CO 2 flux and locate the CO 2 leakage footprint. As noted prev iously, establishing baselines are important to distinguish between natural CO 2 fluxes and CO 2 flux due to leakage from geologic storage. 51

CO 2 detectors are commercially available for shor t closed-path and short open-path (point) measurements, as well as long open- path (radial line) measurements. Similar detectors have been integrated into stationary, mobile, and airborne monitoring packages that are commonly used in combination with high-resolution GPS to detect and quantify

CH 4 leaks in areas with road access. While thes e packages have not been widely tested
for CO 2 , various types of CO 2 monitors are commercially available, generally relatively low cost, reliable, and could be used in these applications. The technologies include IRGAs (including Fourier transform infrar ed (FTIR) and non-dispersive infrared analyzers), tunable diode lasers (TDLs), cavity ring-down techniques, and others. The sample path can range from 10 cm to 1 km, by reflecting a laser beam off retro-reflecting mirrors. These devices measure the gas c oncentration, 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 Othe r Test Method 10 —Optical Remote Sensing
for Emission Characterization from Non-Point Sources. 52 The protocol describes three methodologies, each for a specific use:

 Horizontal radial plume mapping (for lo cating the source of emissions or hot spots);

 Vertical radial plume mapping (for estim ating the rate of gaseous emissions from an area fugitive emission source); and

 One-dimensional radial plume mapping (f or profiling pollutant concentrations along a line-of-sight which is downwind of an emission 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:

field experiment in Bozeman, MT. Environmental Earth Sciences, 60, 251-261, doi: 10.1007/s12665-009­ 0372-2, 2010.

51 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. 2005. Atmospheric monitoring and verification technologies for CO 2 storage at geosequestration sites in Australia. CO2CRC Report No: RPT05-0134, Prepared by CSIRO Marine and Atmospheric Research for CANSYD Australia and the CRC for Greenhouse Gas Technologies (CO2CRC). Available at: http://www.co2crc.com.au/publications/index.php

. 52 http://www.epa.gov/ttn/emc/prelim.html

.

39 Open-Path FTIR Spectroscopy;

 Ultra-Violet Differential Optical Absorption Spectroscopy;

 Open-Path TDL Absorption Spectroscopy; and

 Path-Integrated Differential Absorption LIDAR.

EPA is also testing mobile versions of thes e systems for methane leak detection, in which the detectors are integrated onto ground or ai rborne vehicles with high-resolution GPS to
aim the lasers at the retro-reflectors and correctly locate the methane leak.

Other atmospheric monitoring for leakage detection and quantif ication approaches
include tracer gases and CO 2 isotopic measurements . The incorporation of trace amounts of chemical compounds into the injected CO 2 may be useful in circumstances in which a suitable baseline for a natural parameter (e.g., soil CO 2 flux or surface-toatmosphere CO 2 flux) cannot be established due to the parameter’s wide and unpredictable natural variation. In such cases, tracers could be adde d to the injected CO 2 and continuous or periodic monitoring coul d be conducted to determine if the tracer
could be identified outside the IZ in water, soil or air. The UIC Class VI rule does not require the use of tracers.

Tracers can be manmade molecules such as perfluorocarbons (PFCs) and sulfur hexafluoride, or noble gases such as heliu m (He), argon (Ar), and xenon (Xe), including specific isotope concentrations. Tracers can be de tected at levels of a few parts per billion or even parts per trillion.

PFC tracers have been applied in several pilo t studies and experimental tests and appear to have good detection capabilities for leakag e detection and potential ly for quantification in both soil gas 53 and the atmosphere. 54 The CO 2 injection pilot test at West Pearl Queen
ER site in New Mexico used PFC tracers to detect and quantify leakage from injection wells at soil gas monitoring points wi thin 300 meters of the injection well. 55 PFC tracer analysis has also been used in monitoring wells in the IZ to map the location of the advancing CO 2 plume 56 in the Frio Brine Test, and to monitor for potential surface leakage at the Zama Acid gas injection project in Alberta. 57

53 Strazisar B.R., Wells A.W., Diehl J.R. (2009) Near surface monitoring for the ZERT shallow CO2 injection project. Int J Greenh Gas Control 3(6):736–744. doi:10.1016/j.ijggc.2009.07.005
54 Wells , Arthur, Strazisar , B., Diehl , J., and Veloski , G. 2010. Atmospheric tracer monitoring and surface plume development at the ZERT pilo t test in Bozeman, Montana, USA, Environ. Earth Sci

. Volume 60,
Number 2 , 299-305, DOI: 10.1007/s12665-009-0371-3

55 Arthur W. Wells, J. Rodney Diehl, Grant Bromhal, Brian R. Strazisar, Thomas H. Wilson, Curt M.
White. 2007. The use of tracers to asse ss leakage from the sequestration of CO 2 in a depleted oil reservoir, New Mexico, USA. Applied Geochemistry , Volume 22, Issue 5, May 2007, Pages 996-1016, ISSN 0883­
2927. Available at: http://www.sciencedirect.com/s cien ce/article/B 6VDG-4N3GFGS3/2/f16a133a1eda34353e1cbcc8dd05c917

. 56 McCallum, S.D., Riestenberg, D.E., Cole, D.R., Freife ld, B.M.,Trautz, R.C., Hovorka, S.D., and Phelps,

T.J. 2005. Monitoring Geologically Sequestered CO 2 during the Frio Brine Pilot Tests Using
Perfluorocarbon Tracers. Fourth Annual Conference on Carbon Capture and Se questration, May 2005.

57 Smith, Steven A., J.A. Sorensen, A.A. Dobroskok, B. Jackson, D. Nimchuck, E. N. Steadman, and J. A. Harju. 2009. Injection of Acid Gas (CO 2 /H 2 S) into a Devonian Pinnacle Reef at Zama, Alberta, for

40The amount of tracer added to the injected CO 2 will depend on the minimum detectable
amount within the medium to be monito red and the probable leakage volumes and dispersion patterns for the relevant leakage pa thways. It also depends on how the tracers will move along the leakage pathway relative to the leaking CO 2 . Therefore, if tracers are proposed to be used, the monitoring strate gy should consider the proposed tracers
characteristics in terms of:

 dissolution in water more/less than CO 2 ;

 sorption into coals/shales more/less than CO 2 ;

 chemical reactions with fluids and rocks; and

 physical separation due to differences in molecular size and weight.

In some cases, tracers can m ove more quickly than the CO 2 and will reach sensors or sample collection points well before any CO 2 leak. In other instances a tracer might be trapped along the leakage pathway, reducing it s effectiveness. Certain tracers are GHGs and if leaked, would contri bute to total GHG emissions.

Another consideration for tracers is the possibility of contamin ation of sensor locations or sample collection point through:

 spills during transport and loading of the tracer;

 equipment leaks and vented emissions from surface equipment;

 equipment (tubing) brought to surf ace for repair and replacement;

 fluid retrieved from IZ for analysis; and

 old leaks that have been repaired.

Therefore a monitoring strategy that includes the use of tracers should include ways of preventing contamination by misplaced tracer s through careful desi gn of where and how tracers are injected and how equipment and flui ds that contact the tracers are handled.
Considerations should be made on what could be done in the event of contamination including options for:

 moving sampling point away from contam inated locations (e.g., from surface to subsurface);

 changing type of tracer used; and

 measuring a tracer “baseline” and looki ng for deviations from the baseline.

Alternatively, CO 2 isotopic measurements are able to distinguish between CO 2 derived from fossil fuels and naturally occu rring atmospheric and underground CO 2 . Researchers in Australia note that even relatively large l eaks at the well could di ssipate rapidly away from the source and be indistinguishabl e from background concentrations of CO 2 . They suggest that the use of radi oactive tracers or natural carbon isotope ratios in the

Enhanced Oil Recovery and Carbon Sequestration, Search and Discovery Article #40355. Adapted from extended abstract prepared for oral presentation at AAPG Convention, San Antonio, TX, April 20-23,
2008.

41sequestered fluids will improve detection sensitivity. 58 Field studies of carbon ratios in injected and recovered CO 2 have been conducted at Weyburn-Midale CO 2 Monitoring and Storage Project (Saskatche wan), the Pembina Cardium CO 2 Monitoring Project (Alberta), and the Lost Hills oil field (C alifornia). Recently a commercially available carbon isotope instrument was modified for portable use and deployed during the
controlled release field tests at th e ZERT site in Bozeman Montana. 59 The advantage of the technique is that it pr ovides essentially real time results of the carbon isotope concentrations across a potent ial leak location. The result s showed that the portable instrument was capable of real time spatially distributed measurements of carbon isotopes to detect leakage for a subsurface source. The authors note that other techniques would need to be used to quantify the leakage rate and background fluxes may complicate the interpretation of results.

Eddy Covariance systems can measure the vertical CO 2 flux in the atmosphere. They combine an open-path IRGA on a tower alongside a sensitive, high-speed, 3-D anemometer, a device used for measuring inst antaneous wind speed and direction. Time
series data are recorded and evaluated usi ng 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 te lemetry for transmission to a central facility. Deployment of a grid of such detectors ove r 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.

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 surface to interpret the data. Va riations in plant cover, land use, and topography may create challenges. As with so il sampling, the rate of leakage of CO 2 from the site must be a statistically signifi cant anomaly above the background variability. Therefore, to provide the required precision, eddy covariance towers would have to collect data over an appropria te time period to provide a baseline which includes diurnal
and seasonal variations. With careful installation and the co llection of base line data, the eddy covariance method can potentially provide a precise average 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 2 flux averaged over a large surface area, with an precision less than 50 micr ograms per square meter per second, which

58 Paul Steele, Zoë Loh, David Etheridge, Ray Leuning, Paul Krummel, Aaron Van Pelt. 2008. Continuous Greenhouse Gas and Isotopic CO 2 Measurements via WS-CRDS-based An alyzers: Investigations in Real Time Monitoring at CO2 Geological Storage Sites. Presented at American Geophysical Union, Fall Meeting 2008, abstract #U41C-0 024, poster available at: http://www.picarro.com/assets/docs/AGU_poster_sequestration.pdf
59 Krevor, S., Perrin, J.-C., Esposito, A., Rella, C., Be nson, S., 2010. Rapid detection and characterization

of surface CO 2 leakage through the real -time measurement of [delta]13 C signatures in CO 2 flux from the ground. International Journal of Greenhouse Gas Control 4, 811-815.

42corresponds to a leak ra te of 25,000 metric tons per year distributed across an area of 17 square kilometers.

Another 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 in teraction with the target scattering molecules (e.g., CO 2 ) along the resolved path length. By comparing the Raman signal of the CO 2 to the Raman signal of nitrogen or oxy gen, a direct measurement of CO 2 concentration can
be obtained.

A similar method, DIAL , would 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 wavelength. The average CO 2 concentration over the path length can be
determined from the ratio of the backscatte r 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 k ilometers per day. Helic opter and airplane mounted platforms can cover a much larger area.

Airborne DIAL methods are currently in us e for methane leakage detection along natural gas pipelines. 60 Instrumentation includes the LIDAR , a digital mapping camera, a color video system, and an optical guidance syst em. The airplane flies a survey over the pipeline at an altitude of about 1,000 feet, approximately perpendicular to the wind
direction. The LIDAR instrumentation meas ures the concentrat ion of methane by measuring how much of the reflected laser pu lse has been absorbed. These data could be integrated with real time wind direction and ve locity to define the leakage footprint and estimate a leakage rate.

While DIAL is commercially available for methane, Raman LIDAR and DIAL are currently under development for commercial CO 2 applications. Etheridge 61 reports that ground-based and airborne LIDAR and DIAL technologies appear to be feasible technologies when used in conjunction w ith other sources of information, however additional research is needed to improve pr ecision for measuring and monitoring leaks at geosequestration sites. Researchers at M ontana State University are developing and testing a portable DIAL with the ability to monitor several square kilometers at a

60 Brake, D. 2005. Detection and Measurement of Fugitive Emissions Using Airborne Differential Absorption Lidar (DIAL). EPA Gas Star Program A nnual Implementation Workshop. Available at: http://www.methanetomarkets.org/expo_china07/docs/postexpo/oag_brake.pdf

61 Etheridge, D, Leuning, R, de Vries, D, Dodds, K, Tr udinger, C, Allison, C, Fras er, P, Prata, F, Bernardo, C, Meyer, M, Dunse, B and Luhar, A, 2005. Atmospheric monitoring and verification technologies for CO2 storage at geosequestration sites in Australia. Cooperative Research Centre for Greenhouse Gas Technologies, Canberra, Australia, CO2CRC Publica tion Number RPT05-0134. 83pp. Available at: http://www.co2crc.com.au/publications/index.php

.

43resolution on the order of 100 m. 62 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 surface leakage ar ea, 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.

4.6 Leakage Detection and Quantification in the Offshore Environment

Reservoir modeling and monitoring techniques, such as seismic and monitoring wells, can also be applied to the detect leakage in subsurface geologic formations and shallow ocean bottom sediments located offshore. However, the fate of the CO 2 entering the ocean from an offshore geologic formation is dependent on the temperature, pressure, and

CO 2 flux, and may result in the formation of CO 2 hydrates, may dissolve into the seawater, or may be released into the at mosphere. Shallow monitoring systems aim to detect and quantify CO 2 that has migrated into the shallow sediments and related water bearing strata or seabed, a nd, ultimately, into the seawat er or atmosphere. Shallow monitoring includes those methods that detect and measure CO 2 in the subsurface (e.g., potable aquifers, soil, sub-seabed) and those that actually measure CO 2 in the water column or atmosphere. 63

Sparker surveys detect reflections of acoustic signals produced from electro-capacitive sources that penetrate several hund red meters beneath the seafloor. Boomer surveys detect reflections of acoustic signals produ ced from electromagnetic (EM) sources that penetrate about 100 meters beneath the seaf loor. Both methods 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 2­ D profiles, which render them less effective for systematic areal detection of undiscovered leaks. Their main use may lie in high-resolution imaging of shallow features previously detect ed on 3-D conventional data.

Shallow sedimentary deposits can also be examined using high-resolution acoustic imaging . The technique should reveal anomalous features in the top 100 meters beneath the seafloor as well as direct imaging of rising gas bubbles in the water column. Transducers such as Compressed High Inte nsity Radar Pulse Sonars, operating at frequencies between 2 and 8 kilohertz, have been widely employed on the continental margins, and have also been used to ma p glacial and other sedimentary deposits in shallow water. These techniques are potenti ally very useful for shallow storage monitoring. They offer high-resolution prof iling of seabed morphology but also have sufficient depth penetration to identify anomalous features in the subsurface; for example,

62 DOE/NETL, 2010, Development and Deployment of a Compact Eye-safe Scanning Differential Absorption Lidar (DIAL) for Spatial Mapping of Carbon Dioxide for MVA at Geologic Carbon Sequestration Sites, Project 642, March 2010 http://www.netl.doe.gov/publications/f actsh eets/project/Project642.pdf

63 Cleaner Fossil Fuels Programme, 2005. Monitoring Technologies for the Geological Storage of CO 2

. Technology Status Report, DTI/Pub URN 05/1032, Didcot, Oxfordshire, UK, March 2005. Available at: http://www.co2net.eu/pub lic/repo rts/tsr025abc.pdf

.

44zones of acoustic blanking interpreted as signifying high gas saturations. The techniques can also permit direct imaging of gas plumes in seawater.

Several acoustic sonar bathymetric systems have 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 2 leakage. Two principal types are available: sidescan sonar using piezoelectric transducers mounted on towfish, 64

and multibeam echo sounding using magneto-restrictive tr ansducers from ships.

Multibeam echo sounders integrate bathymetric and backscatter information and can provide a highly efficient way of obtaining ve ry useful views of the sea floor. A multibeam echo sounder may be considered as a series of around 100 single-beam echo sounders, mounted in a fan-shaped array on eith er 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 the echo maximum amplitude over time. This allows the detailed mapping of the seafloor bathymetry and inferences about
the nature of the sediment.

Electrical and EM methods offer the theoretical potential for low-resolution, low-cost, site monitoring. The techniques ut ilize the propagation of electrical or EM fields within the earth to map subsurface variations in electrical conductivity. A distinction can be
made between electric methods that use zero frequency (DC) or very-low-frequency methods, where no EM induction occurs, and EM techniques that use 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 suitable for monito ring storage in saline formations where CO 2 is displacing more conductive formation waters. Pl acing the electrical so urces or receivers (or both) in the subsurface, within or around the storage re servoir, radically increases spatial resolution while reducing power require ments. Downhole configurations seem to offer the greatest potential fo r useful offshore application.

Recent developments of sea floor EM systems , previously used (typically) for deep-water tectonic studies, have led to “direct-detection-of-hydrocarbons” systems. Two of the most advanced systems are referred to as SeaBed Logging 65 and Offshore Hydrocarbon Mapping 66 . The systems consist of towed Controlled Source transmitters and static seabed receiver arrays. The source is a horizo ntal electric dipole , towed behind an

64 A towfish is an underwater equipment package towe d a few hundred feet above the seafloor using an
umbilical cable connected to a support craft.

65 Ridyard, D. 2007. Seabed Logging – A Proven Tool for Offshore Exploration and Development. Summarized from a Presentation given to AAPG Euro pean Region. Search and Discovery Article #40277 (2008) Posted January 31, 2008. Available at: http://www.searchanddiscovery.net/documen ts/2 008/08008ridyard/images/ridyard.pdf

. 66 Greer, A. MacGregor, L. Weaver, R. 2003, Remote mapping of hydrocarbon extent using marine Active Source EM Sounding EAGE 65th Conference & Exhibition — Stavanger, Norway, 2 - 5 June 2003.

45instrumented towfish on a neutral buoyant stre amer. During a survey the source is towed around and through the array of receivers that each measure 2 or 3 orthogonal components of the electric field. The technique is sensitive to thin resistive anomalies at depths between several tens of meters a nd several kilometers. Recent surveys have successfully determined the presence and absence of hydrocarbons within reservoirs.
Direct detection 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 to understand the role oceans play in gl obal carbon budgets and the relati ve size and directions of carbon (mainly CO 2 ) fluxes between the sea, the atmosphere and the sediment. These technologies are relatively we ll tested and are deployed ex tensively across the world, often routinely on ships regularly crossing o ceans. A sensitive pH sensor for marine studies has recently been developed in th e United Kingdom and would be useful to monitor changes in seawater pH resulting from CO 2 leaks. Four parameters are typically measured that, together with ancillary information such as temperature, pH, and salinity etc., can be used to describe the CO 2 system in a given sample. These parameters are:

- total DIC (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-conservati on 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.

Seawater samples obtained at depth, whic h are more appropriate to the needs of monitoring for CO 2 escape, require the pressure to be maintained in order to ensure that degassing does not occur. One such gas-ti ght sampling device has been developed to obtain fluids samples (both wate rs and gases) at elevated te mperatures and pressures. A key feature is that fluid within the chamber is maintained at seaf loor pressures during sampling, allowing fluid aliquots to be wit hdrawn for an almost unlimited number of analytical techniques without degassing the remaining fluid.

4.7 Detection Range, Accuracy and Precision of Various Monitoring Technologies

Each of the monitoring methods discussed a bove involves the application of technologies to detect and quantify CO 2 leakage. Monitoring is effectiv e in detecting the presence of both subsurface and atmospheric leakage. Methods of surface leak quantification
continue to be an act ive research area.

The ability to detect or quantify a plume or leak is dependent upon factors such as the rate of leakage, its depth and lo cation, the atmospheric background CO 2 variability, the number and distribution of samp ling stations, and the limits of the technology itself. Each technology typically has strength s and weaknesses, and only a combination of approaches is expected to ensure reliable monitoring and leak detection.

To evaluate the capabilities of monitoring t echnologies, one must l ook at the theoretical
limits of CO 2 detection, the size of anomaly that can be detected, and the precision and

46accuracy of the method. Table 4-3 presents this information for a number of technologies that can potentially be used for leak quantification. 67

, 68

, 69

, 70 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.

 Anomaly detection threshold. The size of the CO 2 anomaly that can be detected under typical background conditions.

 Precision. The degree of mutual agreement among a series of individual

measurements.

 Accuracy . The degree of conformity of a meas ured quantity to its actual value.

Table 4-3: Detection Range, Accuracy, and Precision of Various Monitoring Technologies
Technology Reference Sampling

rate Detection Range Anomaly
Detection
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
accumulatio

ns NA +/-20% of plume vol. Established technology; expensive,
resolution
decreases with depth.

Cannot image
dissolved

CO 2

. Eddy Covariance 1, 2, 4 Continuous >10 microgram
/ m 2 / sec >45 microgram/s

q. m/sec 5 - 30% of
the CO 2 flux NA Commerciall y available technology
used in other fields; signal

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 concentratio

n NA Established technology;
Portable and inexpensive.

Accumulatio n Chamber 2, 3, 4 Continuous >0.46 microgram
s/ m 2 / sec NA 10% of the
CO 2 flux 12.5% of
the CO 2

flux Commerciall y available technology;

67 Benson, S.M. 2006. Monitoring Carbon Dioxide Sequestration in Deep Geological Formations for Inventory Verification and Carbon Credits. Society of Petroleum Engineers Paper 102833, 14pp. Available

at: http://www.energy.utah. gov /Utah_Actions/documents/dec2006/spe102833.pdf

. 68 Oldenburg, C.M., J.L. Lewicki, an d R.P. Hepple. 2003. Near-Surface Mo nitoring Strategies for Geologic Carbon Dioxide Storage Verification. Report #LBNL 54089, Lawrence Berkeley National Laboratory, Berkeley, CA, October 30, 2003. Available at: http://www.osti.gov/bridge/servlets/purl/840984­ dTw752/native/840984.pdf

. 69 IPCC. 2006. 2006 IPCC Guidelines for Greenhouse Ga s Inventories. Intergovernmental Panel on Climate Change, Simon Eggleston, ed. Available at http://www.ipcc-nggip.iges.or.jp/public/2006gl/index.html

. 70 DOE. 2009. Best Practices for Monitoring, Verification, and Accounting for CO 2 Stored in Deep Geologic Formations. U.S. Department of Energy, Na tional Energy Technology Laboratory. Available at: http://www.netl.doe.gov/technologies/car bon _seq/refshelf/MVA_Document.pdf

.

47Many sampling
stations needed; average data from multiple

chambers; samples small area;

signal to

noise challenge.

Raman
LIDAR and
DIAL 2, 4 Continuous or periodic <1ppmv to
several %
CO 2 NA 1 - 5% of the
CO 2 concentratio

n 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. Monitoring Carbon Dioxide Sequestration in Deep Geological Formations for Inventory Verification and Carbon Credits. Society of Petroleum Engineers Paper 102833, 14pp. Available

at: http://www.energy.utah. gov /Utah_Actions/documents/dec2006/spe102833.pdf

. 2. Oldenburg, 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, Berkeley, CA, October 30, 2003. Available at: http://www.osti.gov/bridge/servlets/purl/840984­ dTw752/native/840984.pdf

. 3. IPCC. 2006. 2006 IPCC Guidelines for Greenhouse Gas Inventories. Intergovernmental Panel on Climate Change, Simon Eggleston, ed. Available at: http://www.ipccnggip.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, Na tional Energy Technology Laboratory. Available at: http://www.netl.doe.gov/technologies/car bon _seq/refshelf/MVA_Document.pdf

.

485. 

### Monitoring, Reporting, and Verification Plans

Facilities conducting GS are required to de velop and implement an EPA-approved MRV plan that includes the following five major components (which are identified at 40 CFR 98.448):

 Delineation of the maximum monitori ng area (MMA), and active monitoring areas (AMAs);

 Identification of the potential surface leakage pathways and an assessment of the likelihood, magnitude, and timing of surface leakage of CO 2 through these pathways;

 Strategy for detection and quantification of surface leakage;

 Approach for establishing the expected baselines; and

 Considerations made to calculate site -specific variables for the mass balance equation.

Chapters 5.1 through 5.5 describe these MRV plan requirements and present considerations for developing site-specific MRV plans. For each requirement, the chapter lays out key information that may address the requirement, and provides illustrative examples and metrics to help the reporter determine the level of performance necessary to design and implement a system that meet s the regulatory requirements. Examples are provided throughout the chapter to illustrate how these re quirements may be addressed
under different scenarios.

In the MRV plan, the reporter should show th at the approach taken to address each MRV plan component provides an adequate level of assurance that the regulatory requirement
will be met. This assurance could include a de monstration that the statistical basis of the monitoring strategy or the quan tification method meets a certain level of performance. In some cases the MRV plan may not include sp ecific details of implementation because there are many site-specific or event-specific f actors that will influence the selection of a particular method or technology. For example, prior to writing the plan the reporter will
not know the exact location or cause of a future surface leak, and therefore should provide a description of the pr ocess and tools used to dete ct and quantify the potential leaks. The reporter should pr ovide the process and decision rationale for how such eventspecific decisions will be made.

EPA is taking this site-specific flexible approach for three reasons. First, each facility will have a unique set of geologic, environmenta l, and operational conditions that are best addressed with site-specific solutions to satisfy each MRV requirement. Second, as projects mature, reporters will collect new information and may choose to improve their conceptual site models and modify their monitoring, modeling, and evaluation techniques. Third, EPA recognizes that the unce rtainties and inherent variability in the natural systems will necessitate modifications to the select ed methods and approaches over time and in response to unexpected events.

49The site-specific approach also allows the reporter to leverage the site characterization, modeling, and monitoring appro aches (e.g. monitoring of inj ection pressures, injection well integrity, groundwater quali ty and geochemistry, and CO 2 plume location, etc.) developed for their UIC permit. The UIC Class VI permit (including the Testing and Monitoring plan) and subpart RR MRV plan have separate monitoring objectives. Requirements under the UIC program are fo cused on demonstrating that underground sources of drinking water (USDWs) ar e not endangered as a result of CO 2 injection into the subsurface, while requirements under the GHG Reporting Program through subpart RR will enable reporters to quantify the amount of CO 2 that is geologically sequestered. However, monitoring approaches and tec hnologies employed for these two objectives may overlap. The MRV plan submitted fo r subpart RR may describe (or provide by reference to the UIC permit) the relevant el ements of the UIC permit (e.g. assessment of leakage pathways in the mon itoring area) and how those elements satisfy the subpart RR requirements.

Beyond describing how the existing or planne d UIC monitoring procedures form the basis for fulfilling the subpart RR leakage detection requirements, the subpart RR MRV plan should show how any detect ed anomalies would be further studied to verify and then quantify leakage. Leakage verification and quantification could in clude more frequent monitoring, denser spatial coverage, or the deployment of additional monitoring technologies.

For more information on UIC regulations, including requirements and guidance documents, please go to http://water.epa.gov/type/g roundwater/uic/index.cfm

.

5.1 Delineation of the MMA and AMA

The MRV plan must include a delineation of the area that will be monitored. The maximum areal extent of the plume area of the life of the project should be determined using a reservoir simulator model informed by site characterization data and monitoring results. Reservoir modeling or simulation is a powerful mathematical tool that is used to evaluate the movement of injected CO 2 in the reservoir, to predict the size and location of the plume, and is an integral aspect of pr oject design, planning, s ite characterization, and monitoring program design. 71 An initial model can be used to forecast how the plume is expected to move and change. After the beginning of injectio n, the data from the injection well and data from the other types of monitoring should be used to calibrate and history-match 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, and is applie d at GS sites. The model is a 3-D construct of the subsurface reservoir, and uses a numer ical approach in which the reservoir is divided into a large number of discrete 3-D volumes for an alysis. Input data include reservoir thickness, depth, pressure, porosit y, permeability, fluid saturations, and other

71 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/car bon _seq/refshelf/MVA_Document.pdf

.

50parameters. Each 3-D volume has its own specifi c characteristics. In the case of GS, the model is set up using all availa ble data, and the model is run to estimate future movement
of CO 2 through the reservoir. The model is th en calibrated and updated through time as the injection proceeds. This is accomp lished through history-matching of actual subsurface data, such as pre ssure or the detection of CO 2

.

There are three general types of simulation models used for GS: multiphase fluid flow models, reactive transport mode ls, and geomechanical models. 72 The simulators allow the prediction of the following:

 Temporal and spatial migration of the plume;

 Geochemical reactions;

 CZ and wellbore integrity;

 Potential leakage pathways and estimates of travel times for these routes;

 Effects of unplanned hydraulic fracturing;

 Potential leakage near the injector well; and

 Consequences of wellbore failure.

Like all numerical models, reservoir simu lation models for GS are not an exact representation of the subsurface reality, but provide an approximation of the conditions throughout the reservoir based on the given i nput values and the computational codes used in the simulation. Some uncertainty is inherent in the model output as a result of
uncertainties related to the constructi on of the underlying governing equations, and uncertainties in the values used to represent the actual site conditions 73 . The accuracy of the model will improve as model input parame ters more accurately reflect the actual
subsurface conditions within the modeled area. It is important, therefor e, for reporters to evaluate the accuracy of the model, and iden tify the input parameters which are most sensitive to the model output. Developing accu rate input values for the most sensitive parameters will improve the models predic tive accuracy. The model input parameters may need to be updated often to reflect new information gained from the operation of the GS project.

A recent evaluation of advances in numerical modeling by Michael et al. 74

, 75 notes that significant improvements have been made in the numerical models particularly in the linking of geochemical, geomechanical, a nd flow models to predict reservoir performance. The authors also note, however , that relative permeability and residual CO 2 saturation are sensitive input pa rameters for accurate reser voir models and need to be better constrained with data from current proj ects. The evaluation also notes that there is

72 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/car bon _seq/refshelf/MVA_Document.pdf

. 73 US EPA, 2003. Draft Guidance on the Development, Evaluation, and Application of Regulatory Environmental Models. Prepared by The Council for Regulatory Environmental Modeling.

74 Michael, K., Arnot, M., Cook, P., Ennis-King, J., Funnell, R., Kaldi, J.G., Kirste, D., Paterson, L., 2009.

CO 2 storage in saline aquifers I—curr ent state of scientific knowledge. Energy Procedia 1, 3197–3204.

75 Michael, K., Golab, A. Shulakova, V., Ennis-King, J., Allinson, G., Sharma, S., and Aiken, T.2010. Geological storage of CO 2 in saline aquifers – A review of the experience from existing storage operations

51limited data from post injection monitoring to calibrate models for the long term
assessment of reservoir conditions.

As described below, subpart RR requires that two monitoring areas be delineated: the
MMA and the AMAs.

5.1.1 Maximum Monitoring Area (MMA)

Under 40 CFR 98.448(a)(1) the reporter will need to establish the maximum areal extent of the injected CO 2 over the life of the project, in cluding the post-injection period, to define boundaries for monitoring leakage. This boundary is used to help define the MMA. The MMA is defined as equal to or grea ter than the area expected to contain the free-phase CO 2 plume until the CO 2 plume has stabilized, plus an all-around buffer zone
of at least one-half mile. The buffer is in tended to encompass leaks that might migrate laterally as they move towards the surface. EP A has determined that a buffer zone of at least one-half mile will have an acceptable probability of encountering leaks in many
circumstances. In some cases the use of a one-half mile buffer zone may not account for uncertainties in the subsurface conditions, or may not incorporate pot ential leakage risks
from faults and fractures that extend into the edge of the modeled MMA, and the buffer zone should be expanded.

For example, if there is a specific leakage pathway or a pronounced regional dip that might carry a leak further, the buffer zone should be expanded beyond one-half mile. The reporter should derive the MMA from site characterization, monitoring, and models. The MRV plan should describe the rationale fo r how the MMA was determined, including a
discussion of the uncertainties of the models and buffer zones.

In order to determine the MMA, the reporter should estimate, by modeling, the future area of the free-phase plume. The geometry of the free-phase plume will be a function of
the amount and rate of CO 2 injected, as well as the geolog ic characteristics of the IZ including the CZ geometry, IZ thickness, permeability, and porosit y, and the amount of anisotropy within the IZ. Th e resolution of the reservoir model used to predict plume
behavior will also influence the de lineation of the area of free-phase CO 2 . A model that can predict characteristics of thin layers at the upper boundary of the IZ, or predict the presence of lower CO 2 saturations, may be able to re solve a larger area of free-phase

CO 2 . The reporter should describe the rati onale for defining the free-phase plume boundary by presenting the results of the re servoir simulation including the minimum

CO 2 saturation that defines free-phase, and the thickness of the zone over which the
saturation is estimated. The determination of both minimum saturation and saturated thickness help define the plume edge.

Plume stabilization is the basis of the fr ee phase plume boundary and depends on the rate of movement of the free-phase CO 2 and the moderation of pressures within the free-phase plume. The reporter should define what criteri a will be used to determine when the freephase plume is to be considered stable. For example, this could be stated in terms of when the rate of movement of free phase CO 2 is less than a certai n value (X foot per

52year), in any direction, greater than th e natural (or not influenced by the site) hydrodynamic movement of the IZ, and the pressu re change within th e reservoir is less than a certain value (Y psi pe r year). The values of fluid movement and pressure would be generated from runs of the reservoir mode l. The values that de fine plume stability should be consistent with the proposed monitoring and modeling methods.

The reporter should redefine the MMA to reflect changes to the plume area if observations of the plume extent are significan tly different from the modeled or expected
extent and should also resubmit the MRV plan (see Chapter 6.7).

5.1.2 Active Monitoring Area (AMA)

It may not be practical or cost-effective to implement a full-scale monitoring program for the entire MMA when in the early years of operation the free-phase plume covers only a small portion of the MMA. The deployment of monitoring locations may be phased in over time to include those areas where the pot ential leakage may occur. The AMA is the part of the project area that will employ the monitoring methods and systems described in the MRV plan for a period of time less than the life of the project but greater than a year. Over the life of the project there will likel y be several monitoring phases, each with an AMA that will increase in size as the plume expands. The MRV plan should describe the area and duration of each AMA as defined by the reporter, and s hould be determined using the most recent monitoring and charac terization data available. The MRV plan should include a description of how the AMA was determined.

To ensure that the proposed leak detec tion monitoring systems provide adequate coverage, the AMA must extend beyond the modeled plume position at the end of the monitoring period. The AMA is established by superimposing two ar eas: the first is a
one-half mile buffer zone around the outline of the anticipated plume location at the end of the AMA period, and the second is the ar ea projected to contain the free-phase CO 2 plume five years after the e nd of the AMA. The area encompassed by either or both of the two areas will represent the AMA.

Subpart RR requires that the AMA be larger th an the projected free-phase plume, for two reasons. First, there may be uncertainty in the proj ected plume location, given
uncertainties in the characteristics of the IZ . The biggest element of uncertainty may be the “storage efficiency” of the IZ, or what portion of the pore space will be filled with

CO 2 versus the portion that still will contai n naturally occurring saline fluids. This uncertainty will be greatest at the start of in jection and will be reduced over time as the
reservoir simulation models are calibrated through history-matchi ng of observed plume migration. The initial AMA must encompass the area that the free-phase plume is expected to occupy five years beyond the end of the initial monito ring period, so as to account for this IZ-related uncertainty in reservoir characteristics.

The second reason why the AMA needs be larg er than the expected free-phase plume area is that any CO 2 leaks from the IZ will not necessarily follow a straight path upward to the surface. The flow path of leaking CO 2 will be influenced by buoyancy forces that

53move the CO 2 laterally in an up-dip direction, via hydrogeologic pressure differences.
The leaked CO 2 will tend to follow formation fluid movements, or geologic features such as reservoir heterogeneities or faults that may produce circuitous upward leakage pathways. Therefore, a monitoring buffer around the free-phase plume needs to be applied. To account for sites where lateral m ovement of the plume will be controlled by structural features (and where the free-phase plume five years past the end of the active monitoring period will be nearly the same location as at the end of the long-term monitoring period), EPA has determined that a monitoring buffer of at least one-half mile will have an acceptable probability of encounter ing leaks in many circumstances. At sites where there are known geologic features that ma y carry leaks laterally more than one-half mile beyond the free phase plume, then that monitoring buffer zone should be extended to encompass those specific leakage pathways.

Figure 5-1: Monitoring Areas as They Relate to UIC Class VI and subpart RR Requirements

5.2 Assessment of the Risk of Potential Leakage of CO 2 to the Surface

Reporters are required to evalua te the risk for leakage of CO 2 through all potential pathways within the monitoring area described in Chapter 5.1. As discussed in Chapter
5.1 , leakage pathways outside the monitoring ar ea should be evaluated if the pathway has the potential to carry a leak outside the mon itoring area. Once a potential leakage risk pathway is identified, it should be evaluate d to determine the likelihood, magnitude, and timing of potential leakage. Each leakage pa thway should be numeri cally identified and referenced in the MRV plan. The evaluation of leakage pathways will likely be

54qualitative in nature. If a reporter has suffi cient information to develop a quantitative analysis of the likelihood, magnitude, or timing of leakage risk, it may be presented in the MRV plan. One example of a quantitative analysis of leakage risk is presented in the Risk Assessment appendix to the Final Environmen tal Impact Statement for the FutureGen project. 76 Another method of quantifying leak age risk was developed by Oldenburg, Bryant and Nicot who applied their met hodology to a GS site in the Gulf Coast. 77

One or a combination of physical phases of CO 2 that have varying ch emical and physical properties could be presen t in leakage from a GS system. These phases of CO 2 include:

 Dry supercritical CO 2 ;

 The wetted portion of the supercritical CO 2 plume;

 Native fluids in the IZ in wh ich high concentrations of CO 2 are dissolved; and

 Fluids above the confining zone (ACZ) that mix with CO 2 -containing fluids migrating from the GS system.

Fluids in these phases may be present in th e IZ or adjacent geologic layers, and could come into contact with the potential subsur face leakage pathways. Escape of any of these

CO 2 -containing substances to the surface could constitute a reportable release requiring quantification by the reporter. While the nature of individual GS systems can be expected to differ with respect to site-s pecific geologic attributes, pote ntial release pathways at GS
sites could be:

 Wells;

 Fractures, faults, and bedding plane partings;

 Competency, extent, and dip 78 of the confining system. 79

Please refer to rele vant UIC regulations 80 for information on suitable sites for GS, and the Vulnerability Evaluation Framework 81 for further background information on potential leakage pathways.

5.2.1 Assessment of the Risk of Potential Leakage of CO 2 through Wells

Of the potential conduits for CO 2 leakage, abandoned wells are the most likely conduits for leakage of CO 2 from the IZ. 82 The presence of oil, ga s, and water wells completed

76 U.S. Department of Energy (DOE). 2007. FutureGen Environmental Impact Statement.

77 Oldenburg, C. Bryant, S., and Nicot, J., 2009. Certification Framework Based on Effective Trapping for Geologic Carbon Sequestration. International Journal of Greenhouse Gas Control Volume 3, Issue 4 , July 2009, Pages 444-457

78 Dip is the angle at which the rock unit is included from horizontal.

79 Leakage related to the CZ can occur if the CZ allows CO 2 to pass though it via permeable zones or fractures, or if the CZ is not c ontinuous across the plume area and CO 2 escapes around the CZ. Leakage may also occur if the CZs is at an angle and CO 2 moves up the incline to the surface or to other permeable

zone.
80 http://water.epa.gov/type/groundw ater/uic/wells_sequestration.cfm

81 US EPA. 2008. Vulnerability Evaluation Framework for Geologic Sequestration of Carbon Dioxide.

U.S. Environmental Protection Agency Technical Support Document EPA430-R-08-009, July 10, 2008.

55and/or abandoned over the last century poses a risk for CO 2 leakage due to the potential for casing and cement failure, as well as th e potential for incompetent bonding between cements and either well casing and/or the confining formation. 83 Abandoned oil and gas wellbores and exploratory borehol es may be present at GS sites located in depleted or active oil and gas fields, or in formations near current or hist oric petroleum exploration or production.

Well plugging and abandonment methods ha ve evolved over time from makeshift plugging with available materials to a regulat ed, documented process with quality control
measures. Gasda et al. 83 describe the possibility of improperly cemented and abandoned
wellbores to function as conduits for CO 2 due to a variety of mechanisms, including:

 Degradation of cement and piping by co rrosive fluids from the GS system;

 CO 2 flow through degraded cements;

 CO 2 flow along the borehole wall;

 CO 2 flow along the interface of the casing and cement; and

 CO 2 flow through holes in the ca sing or annular seals.

As a depleted oil and gas reservoir is re pressurized by GS activ ities, potentially to pressures exceeding those present at the start of the field’s development, risks posed by weak well seals can be expected to incr ease significantly. Newe r wells constructed specifically for service in CO 2 environments are less likely to show cement and casing deterioration than older oil and gas production wells. Recent studies of cement cores from a 52 year old well exposed to CO 2 ER in the Permian Basin for 30 years 84 , and a 30 year
old CO 2 production well in Colorado 85 showed effective sealin g ability of the cement.
These studies concluded that alt hough the cement reacted with the CO 2 it was not compromised possibly due to re-mineralization of the cement into impermeable
materials.

Although relatively rare, blowout s from operating oil and gas wells can occur as a result of injection. A study of the rate of oil well bl owouts in California’s southern San Joaquin Valley between 1991 and 2005, indicated that ap proximately one-third of the blowouts occurred at active producing we lls, most of which were in fields undergoing thermally

82 Gasda, S.E., S. Bachu, and M.A. Celia. 2004. The potential for CO 2 leakage from storage sites in geological media: Analysis of well distribution in mature sedimentary basins. Environmental Geology 46(6-7):707–720.

83 Gasda, S.E., S. Bachu, and M.A. Celia. 2004. Spa tial Characterization of the Location of Potentially Leaky Wells Penetrating a Deep Saline Aq uifer in a Mature Sedimentary Basin. Environmental Geology 46, 707–720.

84 Carey, J.W., M. Wigand, S.J. Chipera, G. WoldeGab riel, R. Pawar, P.C. Lichtner, S.C. Wehner M.A. Raines and G.D. Gutherie Jr., “Analysis and Perf ormance of Oil Well Cement with 30 Years of CO2 Exposure from the SACROC Unit, West Texas, USA”, preprint submitted to International Journal of Greenhouse Gas Control, October 18, 2006

85 W. Crow, B. Williams, D. Carey, J.W. Celia, S. Ga sda, “Wellbore integrity analysis of a natural CO 2

. producer, Energy Procedia, Vol 1 (1), Proceedings GHGT- 9, Washington, D.C., (2008).

56enhanced oil recovery 86 . However, the study also showed that the number of blowouts per year declined by 80 percent, which th e authors attribute to improved industry operational and safety practices.

As part of an MRV plan, the reporter should identify the risk of l eakage to the surface through abandoned wells by considering the lo cation, depth, type and age of well, and reviewing the available documentation to evaluate the quality of construction and
effectiveness of the closure methods. The associ ated risks should be de scribed in terms of the relative likelihood, magnitude, and timi ng for surface leakage. The rationale for estimating likelihood, magnitude and timing of each pathway should be presented.

Injection and monitoring wells of the GS project are potenti al leakage pathways but are also the conduits over which the facility will have the highest level of control. The UIC program regulates injection well construction and integrity testing. Please refer to the UIC program Web site for information on requirements related to monitoring of permitted UIC wells, including MIT. 87 Injection and mon itoring well construction, evaluation, and leakage risk is al so an active area of research. 88

, 89

, 90

Injection wells pose a potential CO 2 leakage risk because they will be subjected to high pressures and flows of CO 2 . Monitoring wells in the IZ may also pose a risk for potential

CO 2 leakage because they will be within the ar ea of increased pressure from the injection wells, and could be in contact with nativ e fluids containing CO 2 which may affect cement integrity. Additionally, nearby monito ring wells within the IZ will experience extended periods of exposure to corrosiv e mixtures of resident fluids and CO 2 as the CO 2 plume migrates outward from the injection wells. The combination of potential corrosion and high pressures will increase risks associ ated with monitoring wells in the IZ. Injection and monitoring wells constructed of materials that can withstand the pressures
and the corrosive environments can minimize ri sk of an accidental release. Mechanical integrity testing of cement, cement bonds, casin g, tubing, packers, valves, and piping can ensure that injection and monitoring wells ar e capable of withsta nding the pressures and geochemical conditions anticipated to occu r during GS injection and post-injection period.

86 P. Jordan and S. M. Benson, 2009. Well blowout rates in California Oil and Gas District 4: update and trends. Exploration and Production: Oil and Gas Review.

87 http://water.epa.gov/type/groundwat er/uic/wells_sequestration.cfm.

88 Chabora, Ethan and Benson, S. 2008. Monitoring Pressure Transients in Zones Overlying CO 2 Storage
Reservoirs as a Means of Leak De tection and Diagnosis. Poster pres ented at 7th Annual Conference on Carbon Capture and Sequestration - Pittsburgh, PA, May 7, 2008.

89 Nordbotten, J.M., D. Kavetski, M.A. Celia, and S. Bachu. 2009. Model for CO 2 leakage including multiple geological layers and multiple leaky wells. Environmental Science and Technology 43: 743–749.

90 Celia, Michael A., Bachu, S., Nordbotten, J., Gasda, S., Dahle, H. 2004. Quantitative Estimation of CO 2 Leakage from Geological Storage: Analytical Models, Numerical Models and Data Needs. Proceedings of the 7th International Conference on Greenhouse Gas Control Technologies, September 5-9 2004, Vancouver, B.C.

57The MRV plan should describe and reference construction and MIT methods to be used for GS system injection and monitoring wells, 91 and include an analysis of the likelihood and magnitude of releases from wells.

5.2.2 Assessment of the Risk of Potential Leakage of CO 2 through Fractures, Faults, and Bedding Plane Partings

Fractures, faults, and partings along bedding pl anes are potential l eakage pathways in a GS system. Fractures are breaks in the rock caused by compression or stress, which result
in areas of weakness in the rock that can also serve as conduits for fluid movement.
Individual fractures are often part of a larger group of similarly oriented fractures resulting from regional and local stresses. Faul ts are features in the earth at which the rock has broken and along which movement has occurred. Depending on the properties of the strata in which a fault occurs, nature of the movement, and subsequent mineralization or dissolution, faults may function as condu its for fluids moving through the subsurface or as barriers to fluid movement. Bedding pl ane partings are natura lly occurring areas of weakness, often found between poorly bonde d sedimentary layers, which may be laterally extensive and intersect vertical migration pathways. Fractures, faults, and bedding plane partings can be forced ope n by fluids whose pressures exceed the fracture/fault reactivation pressure.

These features may not be observed at the su rface or be apparent during geologic site characterization, due to overburden or insuffi cient offset to be observed by standard geophysical imaging. Additionally, due to the significantly lower viscosity of supercritical CO 2 relative to water, these features may not be observed during site characterization hydraulic tes ting of the CZ and the ACZ. Risk presented by these features exists due to the ability of CO 2 to move along open fractures and faults, and the ability of pressurized fluids to open faults, 92 fractures, and bedding plane partings. 93
These potential conduits can be identified from core sample s and various geophysical and hydraulic testing methods. Once identified, thes e features should be monitored for early detection of leaks, in accordance with the a pproved MRV plan. Please note that for GS wells permitted by the UIC Class VI program, there are extensive site characterization and suitability requirements, including that the CZ must be free of transmissive faults and
fractures.

91 Please see http://water.epa.gov/type/groundwat er/uic/wells_sequestration.cfm for UIC program MIT requirements and guidance documents. Additional guidance is provided at the EPA Region V UIC Web
site: http://www.epa.gov/r5water/uic/techdocs.htm

. 92 Evans, D.J. 2007. An appraisal of Underground Gas Storage Technologies and Incidents, for the Development of Risk Assessment Methodology. Britis h Geological Survey. (OR/07/023), Nottingham, UK,
Available via http://nora.nerc.ac.uk/7877/

. 93 Watney, Willard L., Byrnes, Alan P. Bhattacharya, Saibal, Nissen, Susan E., and Anderson, Allyson K. 2003. Natural Gas Explosions in Hutchison, Kansas: Geologic Factors. Geological Society of America, North-Central Section - 37th Annual Meeting, Kansas City, Missouri, March 24–25. Updated presentation
available from: http://www.kgs.ku.edu/Hydro/Hutch/GSA_Watney_updated082004.pdf

58The possibility of induced seismicity from fluid injection 94 compounds the risks associated with the above leakage pathwa ys. Seismic events (e.g. small earthquakes) resulting from overpressure in the IZ, CZ, or well materials can cause fracturing and create preferential pathways for CO 2 movement. While induced seismicity may occur along pre-existing faults identi fied during site characterizat ion, it may also occur along
features that were not detected prior to injection, and be activ ated as a result of increased pore pressure from injection.

The MRV plan should describe the leakag e risk from known and inferred faults and fracture systems based on their extent, depth and historical data. The analysis of risk should consider the possibility of lateral transmission of CO 2 and splays in the fault and fracture systems as well as offsets within th e subsurface. The evaluation of faults and fractures should encompass a large enough area to account for plume movement that is different from the predicted reservoir simulation model.

Existing data sets may need to be supplemen ted and updated with measurements specific to the needs of understanding CO 2 leakage. For example, existing or new geophysical survey data may need to be re-processed and re-i nterpreted to evaluate the extent of faults and fractures, the competency of the CZ or the current location of the CO 2 plume. In areas where there is limited ge ological information from expl oration wells, reporters may
need to increase the dens ity of data sampling.

5.2.3 Assessment of the Risk of Potential Leakage of CO 2 based on the Competency, Extent, and Dip of the Confining Zone

The CZ overlying a GS system performs a critical function of preventing the upward migration of highly buoyant supercritical CO 2 into the ACZ. The risk of a release of CO 2 into the ACZ and subsequently into the atmosphere is greatly dependent on the competency, extent, and slope of this rock unit.

The presence of fractures, faults, interconnect ed bedding plane partings, susceptibility to degradation by CO 2 and impacted native fluids, or low capillary entry pressures 95 could render the CZ capable of transmitting CO 2 from the IZ into the ACZ. These properties should be evaluated during site characteri zation, and any potential conduits should be monitored during baseline data collection and facility opera tion. In addition, anticipated injection pressures should be compatible with the geomechanical properties of the CZ to prevent fracturing and creation of conduits to the ACZ. Geochemical, hydraulic, and geomechanical testing of the CZ materials s hould be performed as part of GS system
characterization and f acility construction. 96

94 Ingebritsen, S. E , Sanford, W. E, Neuzil, C. E. 2006. Groundwater in Geologic Processes. Cambridge University Press, p. 29.

95 Capillary entry pressure is defined in the Vulnerability Evaluation Framework as the added pressure that
is needed across the interface of two immisc ible fluid phases (e.g., supercritical CO 2 and water or brine) for

CO 2 to enter the confining system. If the IZ pressure exceeds the capillary entry pressure, CO 2 could be
forced out of the IZ into the CZ.

96 US EPA. 2008. Vulnerability Evaluation Framework for Geologic Sequestration of Carbon Dioxide.

U.S. Environmental Protection Agency Technical Support Document EPA430-R-08-009, July 10, 2008.

59The lateral extent of the CZ shoul d be sufficient to contain the CO 2 plume as it spreads and migrates laterally, during and after inj ection, until physical and geochemical trapping mechanisms can sequester the CO 2 . General CZ extent and th ickness should be available from previous oil and gas or ER studies or regional geologic studies used in the GS system siting. These data can be supplemented by well logging performed during injection and monitoring we ll drilling, records from oil and gas exploration and production drilling, and geophysical studies. At sites where the CZ is not laterally extensive, an increased risk of leakage ar ound the edge of the CZ may be present.

The dip of the confining system is an importa nt component of the GS system. Due to the buoyancy of supercritical CO 2 , until geochemical trapping mechanisms sequester the

CO 2 , the injected fluid can be expected to move in an up-dip direction until a structural or stratigraphic trap 97 is encountered or the lateral exte nt of the confining unit is reached and the plume moves upward into the ACZ. A relatively steep dip of the overlying CZ may result in the need for a more laterally extensive confining system to prevent the escape of CO 2 to the ACZ and subsequently to the atmosphere. The risk of leakage at the up-dip locations should be considered a potenti al leakage pathway for sites with steeply dipping CZ without structural closure. GS system modeling studies including simulation of multiphase fluid flow may be performed to determine expected travel times and evaluate the potential for the confining system to retain supercritical, and subsequently dissolved-phase, CO 2 until geochemical and structural trapping mechanisms can effectively sequester the CO 2. The likelihood, magnitude, and timing of the risk of releases through the CZ should be asse ssed and presented in the MRV Plan. 98 The MRV plan should present an assessment of the ri sk of leakage from the CZ with supporting
information for how the risk was determin ed. The description should evaluate the
uncertainties in the risk evaluation and c onsider movements of the plume throughout the lifecycle of the sequestration.

5.3 Strategy for Detecting and Quantifying any CO 2 Leakage to the Surface

5.3.1 Detecting Leakage

After the potential leakage pathways in the MMA have been identif ied, the reporter will design a strategy to assess the pathways for conditions that could indicate leakage from the AMA within specified time intervals. The strategy should be designed so that potential leakage pathways are monitored in a comprehensive manner that allows for timely and accurate identification of leaks. Subpart RR requires quantification and reporting of leakage to the surface; however, the reporter’s leakage detection program may rely on subsurface measurements to dete ct leaks (such as may be implemented for compliance with a UIC permit). A leak may be initially detected in the subsurface in

97 A stratigraphic trap is caused by changes in the permeab ility or porosity of the reservoir rock that restrict flow. An example of a stratigraphic trap would be a sand lens that is surrounded by silt or clay.

98 K. P. Saripalli, N. M. Mahasenan, and E. M. C ook. 2002. Risk and hazard assessment for projects involving the geological sequestration of CO 2 . In Kaya et al. GHGT-6: Sixth International Conference on Greenhouse gas control technologies , Kyoto, Japan, September 30–October 4 2002. Elsevier.

60which case subsequent verification and quantification analysis will be needed to
determine if the leak has reached or is likel y to reach the surface (described in Chapter
5.3.2 and 5.3.3 ).

The strategy for detecting CO 2 leakage to the surface could include taking measurements on a continuous basis, such as pressure readings in inje ction and monitoring wells, or continuously reading eddy cova riance monitoring. The leakag e detection strategy could also include regularly scheduled periodic monitoring events and surveys designed to evaluate conditions at a snapshot in time. Regularly scheduled monitoring events could include periodic sampling of water chemistry, MIT of injection and monitoring wells, or whole-area airborne surveys conducted at re gular intervals. The area covered by the leakage detection measurements may change over time as the plume expands, and the AMA is expanded, or new wells are added, but the practices would likely remain the

same.

The detection capability of l eakage detection monitoring systems should be described in the MRV plan. Reporters should develop a robust monitoring system that ensures adequate detection capability. In determining the detection ca pability, the reporter should
consider:

 The accuracy and precision of the instruments used to measure data that will be quantified.

 The statistical variability of the expected baselines against which the measurements will be compared.

 The time required for a leak to be tr ansmitted to a monitoring station or measurement point.

 The ability to use the monitoring progra m to reliably recognize leaks of the targeted magnitude.

The identification and influence of site ch aracteristics such as topography, land use, weather, and climate on the detection methods should be presented in the MRV plan as part of the assessment of adequacy for de tection methods. The considerations for the approach and techniques are described below.

Part of the suite of leakag e detection monitoring should in clude MIT of injection wells, using a suite of well logs that are capable of determining leakage under the site-specific conditions. Such logs may include but are no t limited to noise logs; cement bond/variable density logs; mechanical, electrical, or acous tical caliper tools; tracer logs; and other specialized well inspection tools. MIT utili zed for satisfying UIC requirements could be described as part of the l eakage detection strategy in the MRV plan. Although there are no UIC requirements for performing MIT on mo nitoring wells, it may be prudent for reporters to include in their MRV plans a periodic evaluation of the integrity of monitoring wells that penetr ate the IZ. The reporter’s process for selecting and interpreting MIT should be provided in the MR V plan. Additional information on the use of these and other monitoring tec hniques is provided in Chapter 4 of this TSD.

61The process and technologies for detecting l eakage through CZ or spill points should be presented in the MRV plan. In some cases, changes to the ACZ will likely be a result of leakage through the CZ or structural spill poin ts, which are detectable in the monitoring wells and with other subsurface imaging tec hnologies. For example, pressure changes observed in multiple monitoring wells can be used to locate the general area of leakage through triangulation. The proce ss and technologies for detec ting leakage through CZ or spill points should be presented in the MRV plan. The reporter should determine the targeted leak size and estimate the reliability of its detection for the proposed monitoring technologies and procedures.

Faults, natural fracture systems, and abandone d boreholes are potenti al leakage pathways, where a range of different monitoring tec hnologies could detect leakage, depending on site-specific conditions. Near-surface mon itoring devices may include eddy covariance, LIDAR, accumulation chambers, soil gas surveys, isotopic analysis of CO 2 at the surface or in shallow wells, and monitoring for tracers injected with the CO 2 . Leakage from the ground into surface water, such as a leaking fault that inte rsects a lake, may require different approach to monitoring and flux calculation. 99

The reporter should consider the characteristics of the GS site and the capabilities of the monitoring systems to analyze what leak sizes or surface CO 2 fluxes are detectable using the proposed methodology. Subpart RR does not have a specific leak detection minimum volume or reliability standa rd. Instead, it is requested that reporters compute the statistical reliability of the monitoring element given one or more targeted leak rate(s). Note that a GS project operating under a UI C permit will have separate UIC requirements if a leak is detected that may include repor ting of the leak, ceasi ng injection, and taking
corrective action.

The targeted leak rates for the probability calculations in the MRV plan should be appropriate to the site, and for example could be on the order of thousands or tens of thousands of metric tons per year as measured in the subs urface. There is little published research on measured subsurface leakage rate s for GS sites, so the reporter should provide a justification for selection of the targ et rate. The reporter may wish to review the risk assessment performed for the proposed FutureGen project 100 which tabulated surface emissions rates from 28 locations including natural CO 2 sources (domes, volcanic, and hydrothermal sites) and ER/GS sites. The su rface emissions ranged over eight orders of magnitude, but all of the ER and GS sites ha d surface flux of less than one micromole per square meter per second. The reporter may also wish to review the design of studies
conducted at the Zero Emissions Research and Technology Center in Bozeman Montana where controlled release experiments were performed to simulate low-level seepage in order to test the detection capab ility of several monitoring methods 101

.

99 Oldenburg, C.M., and J.L. Lewicki. 2006. On leakage and seepage of CO 2 from geologic storage sites
into surface water. Environmental Geology , 50(5), 691-705 LBNL-59225

100 U.S. Department of Energy (DOE). 2007. FutureGen Environmental Impact Statement.

101 Spangler, L.H., Dobeck, L.M., Repasky, K.S., Nehrir, A.R., Humphries, S.D., Barr, J.L., Keith, C.J., Shaw, J.A., Rouse, J.H., Cunningham, A.B., Benson, S.M., Oldenburg, C.M., Lewicki, J.L., Wells, A.W., Diehl, J.R., Strazisar, B.R., Fessenden, J.E., Rahn , T.A., Amonette, J.E., Barr, J.L., Pickles, W.L., Jacobson, J.D., Silver, E.A., Male, E.J., Rauch, H.W., Gullickson, K.S., Trautz, R., Kharaka, Y.,

62For the evaluation of near-surface monitori ng techniques, these leak rates should be
translated to surface leak areas and fluxes based on dispersion modeling or calculated
factors to be discussed below. It should be understood that these leak rate assumptions are not intended as predictions of actual le aks or limits on what leaks can or should be detectable. Rather, they are benchmarks ag ainst which the performance of the leak detection strategy can be measured using sta tistically valid techni ques. The performance would generally be stated in terms of a leak rate target, a time period, and percent probability of detection.

For example a plan to detect leaks with pressure monitoring using wells in the ACZ might have a performance evaluation concluding that it can detect “leaks of X metric tons
of CO 2 per year within Y days with a proba bility of Z percent.” The performance
estimate does not mean that leaks smaller or larger than this cannot be detected. Smaller leaks can be detected, but they may take more time or will be detectable with less reliability; larger leaks may be detectable in less time with greater reliability.

A consideration in designing a leakage detec tion strategy (and in establishing expected baselines) for the MRV plan is ensuring ade quate data resolution to cover a range of points in space and time. A non-representative da ta set that contains too few samples at too few times of day/year from too few locatio ns will generate a biased picture and result in erroneous decision making. A sampling progra m should be designed to ensure that it considers the appropriate frequency of samp ling, aerial extent of sampling, and sample size. The MRV plan is likely to include appr oaches that involve coll ecting data at one or
more locations within the MMA. 102 For example, CO 2 isotope ratios in soil gases might be measured throughout the entire AMA as one leak detection method. The MRV plan could present the statistical coverage ade quacy of a given sampling program (i.e., the probability a given size of leak will be detect ed). Please refer to Appendix E for further discussion of this topic.

5.3.2 Verifying Leakage

The MRV plan should describe the strategy to verify and confirm the location and source of leakage that has been detected. The leak ve rification process is in tended to be a quick and cost effective step to help the reporter focus efforts on deviations from expected measurements that would need to be quan tified. The MRV plan should describe the methods and criteria for determining how an anomalous reading or condition will be evaluated to determine if it represents a lea k, for verifying the location and source of the leak, and what level of accur acy is anticipated. This descri ption should include details of the approach for determining how readings will be distinguished from background or

Birkholzer, J., and Wielopolski, L .,, A shallow subsurface controlled release facility in Bozeman, MT, USA, for testing near surface CO2 detection techniques and transport models. Environmental Earth Sciences, 60, 227-239, doi:10.1007/s12665-009-0400-2, 2010

102 Jones, David. 2009. Groun d surface monitoring of CO 2 and associated gases. Presented at CO 2 GeoNet Open Forum, March 2009, Venice, Italy.

63operational variability (see Chapter 5.4 for a detailed presenta tion of this topic). If possible, the MRV plan should pr ovide criteria that will be used to identif y the presence of a leak. Monitoring systems for each pa thway are likely to employ different technologies at different m easurement frequencies. For example, ACZ pressure monitoring may be conducted co ntinuously at severa l locations over a br oad part of the

CO 2 plume however, leak detection at active or abandoned wells may be performed using a truck-mounted laser scanning survey that is conducted once per year at specific well locations within the AMA. Likewise, leak detection and verification methods will vary with the monitoring technology. Since each monitoring system will be different, and the monitoring systems may change location over time as the plume changes, the reporter may simplify the presentation of the leak de tection and verification process in the MRV by describing the leak detection and verification in a flowchart or process diagram.

The verification steps may include:

1. Verification that the reading is accurate and truly repr esentative of the condition. This may require repeating the measurement, recalibrating the measurement device and repeating the measurement, taking a second measurement with a
redundant device or a different device of greater accuracy or higher precision, or evaluating other data and measurements that may be affected by the condition. Verification of the reading may also n ecessitate collecting measurements for a longer period of time to determine if the anomalous reading is of a short duration or part of a longer or co ntinuous trend of anomalous readings. For very large
leaks that are manifested at the surface, direct visual observation of ice crystals, vapor plumes, or gas bubbles in well cella rs may provide adequate verification of a large leak.

2. Identification of the location or the sour ce of a suspected le ak. Once the accuracy of the measurement is confirmed, other met hods may be used to further refine the location of a leak, including triggered or episodic monito ring that takes place after a leak is suspected. For ex ample, if a release of CO 2 from a fault zone is suspected based on fixed location eddy covariance data , a soil gas survey of the fault area could be performed to more accurately de fine the location of the leak. Resolution of the source can also be made with surface measurements by using a denser sampling grid or more frequent time scal e to improve the resolution of the source area. For subsurface leakage in the inj ection or monitoring wells, mechanical integrity well logs can be used to help define the area and pathway of leakage.

5.3.3 Quantifying Leakage

The MRV plan must include a discussion of how leaks will be quantified once they are
detected and verified. 103 Given the uncertainty concerning the nature and characteristics of leaks that will be encountered, EPA expects that this section of the MRV plan will

103 Any leakage detected would constitute a failure of mechanical integrity and would necessitate the cessation of injection in accordance with the UIC permits.

64provide a list of possible quantification met hods and a discussion of when and how those methods might be employed for each risk pa thway identified in the leakage pathway assessment. To the extent possible, the exp ected accuracy of the techniques should also
be discussed. EPA understands that it may be difficult to measure CO 2 leakage quantities and that modeling and estimation processes wi th possibly wide margins of error may be
utilized.

In some cases the leak volume or rate may be estimated using near-surface parameters, and quantification will reflect a mass of CO 2 leaked to the surface that is then reported to EPA. In other cases, the estimation proce ss will employ subsurface parameters, and the
initial estimates will be of the subsurface leak rate and amount. These subsurface leakage
rate and amount estimates then need to be translated to an estimate of the mass of CO 2 leaked to the surface, and reported to EPA. The choice of quantific ation methods in an MRV plan will be site specific. They could include but are not limited to:

1. Estimation of leakage in the subsurface by material balance, using known injected quantities and monitored pressures in th e IZ. Since leaks will cause monitored pressure in the IZ to be lower than exp ected, leaked quantities might be estimated as those amounts that bring the modeled IZ pressure down to measured values. Given the uncertainty and variability in IZ reservoir conditi ons, this technique would be expected to have a very wide ma rgin of error, particularly in the early phases of injection when pressure differe nces above background levels are small
and reservoir characteristics have not been confirmed/adjusted by historymatching. The estimated leaked amounts w ill be reported in volume of fluids (e.g., cubic feet or cubic meters) and s hould be broken out into the amounts of
water versus amounts of CO 2 . Then the amount of subsurface CO 2 leakage must
be converted to the amount of CO 2 that has leaked or will leak to the surface. (See discussion below on these two estimation steps.)

2. Estimation of subsurface leakage by materi al balance using monitored pressures in the ACZ. Leaks through the CZ likely will cause monitored pressure in ACZ to be higher than expected. This second t echnique should be more accurate than the first technique using IZ pressures, b ecause there should be less uncertainty determining the value of “normal” pressure in the ACZ. However, a wide margin
of error will exist because of the given uncertainty in ACZ reservoir
characteristics. The volume of fluids l eaked will have to be converted to CO 2 leaked to the surface.

3. Estimation of leakage by reservoir simula tion that triangulates leak location and calculates leak rate by interpreting pressu res in ACZ at three or more monitoring wells. When several wells in the ACZ record pressure increases, it will be possible to locate and estimate volumes of a leak that is concentrated at one location (i.e., not made up of several scat tered leaks). The volume of fluids leaked
will have to be converted to CO 2 leaked to the surface.

4. Estimation of leakage by measuring CO 2 flux at several locations on the surface with eddy covariance, accumulation chamber, tenting, etc., can be used in extrapolating the entire area of leak. Th is process would involve identifying that

65the surface area through which the leak is occurring and directly measuring the leak rate at a sample of locations at or near the surface. The accuracy of this technique will depend on the shape and size of the leak at the surface, the sample footprint size, (i.e., point sampling for accumulation chambers versus a measurement area for an eddy covarian ce tower), density of sampling, and the ability to distinguish leak volumes from natural flux rates.

5. Estimation of a leak by remote sensing or ground surveys of the effects of leaked

CO 2 on vegetation 104 . It may be possible to approximate the surface extent and rate of leakage by looking at vegetative e ffects. This option is likely to have a very uncertain accuracy. It may best be us ed to estimate the areal extent of the
leak or to determine whether subs urface leak has r eached the surface.

6. Estimation of the plume size and locati on using seismic survey by mapping the primary plume size and density in the IZ and the subsurface leakage plume in the ACZ. Under favorable geologic circumstances , it will be possible to use periodic seismic surveys to track movements of the CO 2 plume in the IZ through time. Under those same circumstances, it might be possible to use the seismic surveys
to estimate how much of the CO 2 plume is still located in the IZ and how much
has leaked into the ACZ.

Though the state of the science does not currently support using existing logging techniques to quantify leakage in wells, es timation of well leakage through interpretation of mechanical integrity well logs of injection wells or monitoring wells drilled into the IZ can help to bound leakage estimates. When l ogs indicate the leak of fluids along the wellbores, it might be possible to estimate the extent of l eakage by analyzing those logs or supplemental logs. For example, the rate of fluid movement may be indicated by the analysis of the frequency of sound signals from noise logs. The analysis of the velocity of radioactive tracers up a borehole could also indicate rate of fluid leaks. In addition, an analysis of dimensions of damaged well materials (e.g., gaps in cement or corroded casing) determined from sidewall cores and pressure drawdown tests might be used to
constrain of the size of leaks. The volume of fluids leaked wi ll have to be converted to

CO 2 leaked to the surface.

When leaks are quantified in th e subsurface as volumes of CO 2 or fluids, it will be necessary to convert this value to an estimate of the amount of CO 2 that has leaked to the
surface. One method to estimate CO 2 volume leaked at the surface would be to apply one or more of the near-surface options listed in items #4, #5, and #6 above to measure CO 2 leak flux and leakage area, and then estimat e the leak volume by multiplying leakage area by flux and duration. Alternatively, the repo rter can choose to use techniques such as modeling to more directly estimate what portion of the subsurface leak is CO 2 that has or
will reach the surface. When th e leak has been measured as total volume of fluids, the
amount of the leak that is CO 2 versus water may be inferred by analysis of where the leak occurs relative to the positi on of the plume. The reporter may determine that leaks far

104 Keith C.J., Repasky K.S., Lawrence R.L., Jay S.C., Carlsten J.L. (2009) Monitoring effects of a controlled subsurface carbon dioxide release on vegetation using a hyperspectral imager. International Journal of Greenhouse Gas Control 3(5):626–632. doi:10.1016/j.ijggc.2009.03.003

66outside of the plume area are assume d to be 100 percent water and no CO 2 . Leaks through the CZ within the pl ume area might be estimated based on the relative modeled

CO 2 /water saturation levels at the point of the leak and modeled flow characteristics through the CZ.

The quantification of leakage should include consideration of the time at which the leakage began and when the monitoring system first detected the leak. Subsurface leaks may be identified relatively quickly if they occur near a monitoring well, but may take months or years to reach the surface. Leak quantification methods should also consider the effect of time on leakage rates because th e leakage rate at the surface is likely to
increase over time.

The portion of CO 2 that leaks through the CZ, out of structural spill points, or along boreholes that will ultimately reach the surface may also be estimated using modeling.
This will include careful charac terization of the rocks and flui ds to be encountered by the

CO 2 along the leakage pathways to the surface. If any part of the leak is modeled as trapped in a USDW, the assumption should be made that the water with the trapped CO 2 may eventually be produced from the USDW, and therefore counted as a leak to the surface, unless the reporter demonstrates that the CO 2 will not be emitted to the atmosphere. Alternatively, the reporter may report to EPA that 100 percent of the
subsurface leak has reached the surface. Note that if the injectat e reaches a USDW, the reporter will be in violation of their UIC permit.

5.4 Strategy for Establishing the Expected Baselines

Baseline monitoring is essentially the first st ep in implementing the leakage detection and quantification monitoring stra tegy. The primary goal of esta blishing expected baselines is so that the reporter can discern whether or not the results of mon itoring are attributable to leakage of injected CO 2 . This chapter describes considerations for developing expected baselines that will ensure adequa te leakage detection capability within the monitoring system.

Leakage of sequestered CO 2 may result in detectable deviations from the expected
baseline values in one or more of a nu mber of environmental conditions, such as subsurface pressure, groundwater chemi cal composition, the concentration of CO 2 in air, soil, surface or near-surface CO 2 flux rates, surface CO 2 isotope ratios, and other geophysical and geochemical parameters, or deviations from expected operational conditions, such as the injection pressure and the annular pressure in the well. The MRV plan leakage detection and quantification st rategy may include monitoring a selection of these indicator parameters to detect potential CO 2 leakages. To judge whether a set of measured parameter values obtained during GS operations presents a cause for concern, reporters should know what those parameter values would be expected to be in the absence leaks. In the MRV pl an, reporters should credibly explain how an expected baseline that represents the most probable range of the indicator parameters will be obtained. Once the expected baseline has been established, reporters would then have a

67basis for statistically evalua ting if the measured paramete r values obtained during GS operations are of a level that s uggests a leakage of injected CO 2

.

In most cases seepage fluxes will far exceed background; 105 however, some natural systems, especially the concentration of CO 2 in near-surface soil and air, are quite variable and are affected by many factors, ma king prediction of baseline difficult. There may be situations where conditions limit the ab ility to collect or model representative conditions, either for baseline or monitoring a pplications. For example, in the subsurface, heterogeneity may create complex pressure pa thways between the injection well and the monitoring well that can result in anomalous or unexpected readings that cannot be correlated to the injection well pressure. In ER areas with multiple stages of primary, secondary, and tertiary produc tion and reservoir manipulatio n, pressure transients and well stimulation practices may make pressure monitoring unreliable.

5.4.1 Approaches for Establishing an Expected Baseline

The baseline approach described in the MRV plan should be reliable, representative of the site conditions, and provide enough resolution such that an anomalous reading can be identified without an unacceptable level of false negative or false positive results. Inaccuracies in establishing the expected base line could lead to erroneous conclusions. If the baseline is inaccurately determined to be too low, then “false positives” would result; in other words, CO 2 leakages would be detected even when they were not occurring. On the other hand, if the ba seline is inaccurately determined to be too high, then “false negatives” would result; that is, CO 2 leakages would not be detected even when they were in fact occurring.

In the MRV plan submittal, the reporter shoul d provide a description of the baseline monitoring that demonstrates the statistical validity of the selected approach for each monitoring method proposed. This discussi on should include documentation of the environmental variability and instrument capability, and a de termination of the probability of detecting a leak of the targeted size(s). The identification and influence of
site characteristics such as topography, land use, weather, and climate on the monitoring
methods for baseline should be addressed in the MRV plan as part of the assessment of adequacy and potential for variability in conditions.

Pre-injection Monitoring of Environmental Parameters

Optimally the indicator parameters would be measured at the proposed locations prior to injection. Given the seasonal variability of some parameters, such as CO 2 flux, this historical baseline may need to encompass a range of seasonal and climatic conditions. An advantage of this approach is that the operational stage and pre- injection values are derived from the same location, thus minimizing variance derived from geographical differences. Using the same geographic location for baseline and measurements will

105 Benson, S. 2004. Monitoring Protocols and Life-Cycle Costs for Geologic Storage of Carbon Dioxide. Presentation at Carbon Sequestrati on Leadership Forum meeting in Melbourne Australia. September 13-15,
2004.

68eliminate one potential source of error and va riability in the determination of anomalous readings and potential leakage. However, th e disadvantage is that operational stage and pre-injection values are measured at diffe rent points in time, resulting in possible variance from temporally varyi ng factors such as weather.

Contemporaneous Monitoring of Environmental Parameters

There are two potential approaches in volving contemporaneous monitoring of environmental parameters. One approach involves contemporaneous monitoring of the indicator environmental parameters at a site si milar to the sequestration facility, but at an offsite location that is unaffected by the CO 2 injection. This reference site should be
established to be similar to the MMA in terms of all the relevant environmental parameters so that it serves as a proxy for what conditions would have been like in the
MMA had the CO 2 facility not been built and the CO 2 not been injected. The advantage
of this method is that the re ference site readings are cont emporaneous to the monitoring zone readings and would therefore be matche d in terms of weather conditions and season (provided the reference site is fairly cl ose to the MMA). The disadvantage of this approach is that it is usually difficult to find a reference site that is a perfect proxy for the facility site in every respect . For this reason it may be necessary to use data from the reference site indirectly in predictive m odels of the expected baseline values.

A second approach involves contemporaneous monitoring of the indicator environmental parameters at reference points within the maximum monitoring area. These reference points are expected to be currently unaffected by the CO 2 injection, although they lie within the maximum monitoring area of the se questration facility. The advantage of this approach is that it is likely to be cost-effective to implement. However, it suffers from the
drawback that the reference sites may unexpectedly be affected by the leakage, which would result in false negative determinations.

Use of Predictive Models

A predictive model for the baseline is a ma thematical model, usually developed through regression analysis, that estimates the expected baseline as a function of other variables (e.g., predicting expected CO 2 flux in soils as a function of season, time of day, recent rainfall, and temperatures). Predictive models may be useful when there may be bias in the historical data, or when the variation of the monitored parameters is very wide and
when it is known that certain measurable infl uences, such as weather, account for much of that variation. The creation of predictive models adds to the complexity and cost of the MRV plan development and implementation, but may improve the statistical reliability of a monitoring strategy. If the MRV plan relies on predictive models, th en the plan should lay out how the predictive model will be developed and how the model will change the
bias and variance in the e xpected baseline. The MRV plan should describe how the predictive model is based on available monitoring data. Examples of predictive models

69used to calculate flux can be found in recent studies of natural CO 2 releases, ER and sequestration sites. 106

, 107

5.4.2 Considerations in Establishing Expected Baselines

Adjustments for a Shifting Baseline

Changing natural and land-use factors may necessitate revisiting the expected baseline. In the case of a baseline defined by pre-injecti on historical environmental data, changes in land use in the surrounding region could aff ect current measured parameter values, biasing them in a certain direction and increasing the possibility of a false positive or negative. To prevent this, either the pre-determ ined baseline would have to be adjusted to
factor in the effect of the current land use change, or th e measurement of the current environmental parameter values would have to be adjusted to factor out the effect of the land use change.

For a baseline defined by contemporaneous refe rence data, natural or land use changes in
the reference area that do not influence the monitoring area would be a cause for concern. In such a situation, reporters would need to de fine a new reference site more reflective of original conditions at the monitoring area and create a new baseline there, or they would
need to factor out the influe nce of the natural/land use changes at the existing reference site. Depending on the particular influence of the change, failure to make these adjustments could lead to either false ne gative or false positive determinations.

If adjustments are made to the strategy for establishing the expected baseline after the MRV plan is approved by EPA, the reporter must describe the changes in the annual report. Changes to baseline may result in a material change and would require the MRV plan to be re-submitted.

Uncertainty and Variability in Baseline Data: The Choice of a Monitoring Method

In the choice of monitoring methods for leak age detection and quantif ication, the reporter should consider the issues posed by uncertainty and variability in both the baseline and the measured operational data. Certain environmental parameters such as CO 2 flux are likely to be harder to measure accurately th an others. For example, surface-to-atmosphere

CO 2 flux varies considerably by time of da y, by season, and by location. A number of

106 Etheridge D., R. Leuning, A. Luhar, D. Spenser, S. Coram, P. Steele, M. van der Schoot, S. Zegelin, C. Allison, P. Fraser, C.P. Meyer an d P. Krummel. 2007. Atmospheric monitoring and verification of geosequestration. At the CO2CRC Otway Project 2007 Annual Report, Report # RPT07-0735.

107 Stephanie Trottier, William D. Gunter, Bernice Kadatz, Mark Olson, Ernie H. Perkins. 2009. Atmospheric monitoring for the Pembina Cardium CO 2 Monitoring Project using open path laser technology, Energy Procedia, Volume 1, Issue 1, Greenhouse Gas Control Technologies 9, Proceedings of the 9th International Conference on Greenhouse Gas Control Technologies (GHGT-9), 16-20 November 2008, Washington DC, USA, February 2009, Pages 2307-2314. Available at:http://www.sciencedirect.com/science/article/B984K-4W0SFYGBM/2/e8c3fb1745fea4010531f65c351bd233

.

70variables influence surface-to-atmosphere CO 2 flux, many of which are associated with
measurement error. The measurement of surface-to-atmosphere flux using eddy covariance is reported to have a precision of up to 30 percent, with short-term error of 7 to 12 percent. 108 There is also uncertainty about th e statistical model that converts wind
and CO 2 concentration readings to flux and the va lues of the coefficients in the model. This suggests that CO 2 flux estimates may have sizeable confidence intervals or error
bars. 109 In a study of the CO 2 leakage potential from the ER operations at the Rangely oil field in Colorado, Klusman found that CO 2 flux and carbon isotope ratios varied significantly at reference locations and over the suspected source areas. 110 A predictive model based on regression analysis of the historical data could predict expected baseline
flux as a function of weather and other conditions.

A sampling program that measures an environm ental parameter with a considerable error bar or confidence interval is likely to be difficult to discriminate from baseline conditions. High error bars in e ither or both the operational stage monitoring estimates or the baseline estimates will increase the proba bility of false nega tive readings, thus potentially leading to erroneous conclusions . An environmental parameter with a low error bar is preferable to alte rnative indicators that are asso ciated with high error bars.

Predictive models have been applied at ER and sequestration pilo t tests to compare background CO 2 flux and concentrations to measured values. 111

, 112

, 113

, 114 These studies demonstrate the use of predictive models and the challenges 115 of discriminating natural conditions from leakage especially over sm all areas or with low leakage rates.

108 Oldenburg, C.M., and J.L. Lewicki. 2003. Near-s urface monitoring strategi es for geologic carbon dioxide storage verification, Lawrence Berkeley National Laboratory Report LBNL-54089, October 2003.

109 Confidence intervals or error bars are used to describe the most probable range of values with which a measured reading should be associated. Readings that closely match the actual values will have narrow confidence intervals or error bars; readings with high variability will have wide confidence intervals or
error bars.

110 Klusman, R., 2003. A geochemical perspective and assessment of leakage potential for a mature carbon dioxide-enhanced oil recovery project as a prototype for carbon dioxide sequestration; Rangely field, Colorado. AAPG Bulletin V. 87, No. 9 pp 1485-1507

111 Lewicki, J.L., G.E. Hilley, and C.M. Oldenburg. 2005. An improved strategy to detect CO 2 leakage for verification of geologic carbon sequestration. Geophysical Research

Letters , 32 (19), L19403, doi:10.1029/2005GL024281.

112 Loh, Z., Leuning, R., Zegelin, S., Etheridge, D., Bai, M., Naylor, T., Griffith, D. 2009. Testing Lagrangian atmospheric dispersion modelling to monitor CO 2 and CH 4 leakage from geosequestration. Atmospheric Environment doi: 10.1016/j.atmosenv.2009.01.053

113 Benson, S. 2004. Monitoring Protocols and Life-Cycle Costs for Geologic Storage of Carbon Dioxide, http://www.cslforum.org/documents/benson_sally_wed_Pal_AB_0915.pdf

. 114 Lewicki, J.L., G.E. Hilley, M.L. Fischer, L. Pan, C.M. Oldenburg, L. Dobeck, and L. Spangler. 2009.
Detection of CO 2 leakage by eddy covariance during the ZERT project’s CO 2 release experiments. Energy
Procedia , 1, 2301-2306.

115 Etheridge, D, Leuning, R, Luhar, A, Spencer, D, Coram, S, Steele, P, Van der Schoot, M, Zegelin, S, Allison, C, Fraser, P, Porter, L, Me yer, C and Krummel, P. 2007. Atmo spheric monitoring and verification of geosequestration at the CO2CRC Otway Project 2007 Annual Report to the CO2CRC. Cooperative Research Center for Greenhouse Gas Technologi es, Canberra, Australia, CO2CRC Publication Number RPT07-0735. 14pp.

71Statistical Methods for Comparing Operati onal Stage Measurements and Expected
Baseline Data In the MRV plan, the reporter may propose to us e a statistical approach to conclude if the operational stage measurements differ from th e expected baseline. Using statistics, the reporter can infer about a populat ion using data from a sample. In many cases a statistical approach is advisable because environmental pa rameters tend to be inherently variableeven the best sampling program would only gene rate an estimate of the true value of a parameter. This sampling estimate could be mathematically expressed as a statistical probability distribution, which represents th e most probable range of values for the parameter based on the sample data. A range of statistical tests are available to determine if the measured operational stage data differs significantly from the baseline. Heterogeneous populations should be split into homogeneous subdivisions to ensure that like quantities are being compared and the st atistical comparisons are meaningful. For more information, see EPA’s Data Qual ity Assessment statistical guidance. 116

Using the Regional Hydrologic Evaluation to Determine Expected Conditions in the Monitoring Zones

An understanding of the regional hydrogeologic ch aracteristics in which the GS facility is situated will provide the context for conceptual site model development, and may be used to help quantify potential leak s from a GS reservoir. As an example, the presence of small-scale structural, stratigr aphic, or geochemical featur es, such as faults, trapping structures, or mineral deposits, are often indi cated by the broader geologic setting of an area. However, these features, which could impact geochemical monitoring parameters, may not be observed during site-specific investigati ons. IZ hydrogeologic and geochemical conditions should be evaluated duri ng development of an expected baseline to anticipate the movement of injected CO 2 after injection has begun. As part of baseline data collection, data could be gathered to establish the ambient pressures, direction, velocity, and geochemical nature of native fl uids in the reservoir and ACZ prior to GS facility operations. These data can be used to predict CO 2 plume migration, assist
calibration of reservoir mode ls, and during periodic revi ews to quantify differences between observed changes in th e hydrologic regime and pred icted effects. The regional
model can also be combined with the site characterization model to assist siting of monitoring infrastructure.

In the strata comprising the ACZ, determin ation of baseline hydraulic and geochemical conditions may allow determination of the pr esence and magnitude of any leakage that may be occurring. If strata in the ACZ ar e in hydraulic communi cation with a USDW, pumping regime changes in the USDW may cau se pressure fluctuations that could be misinterpreted as being indicat ive of a release from the reservoir. With a sufficient period of baseline monitoring, seasonal fluctuati ons in ACZ pore pressures can account for seasonal trends in groundwater pumping, resulting in regular increases and decreases in ACZ fluid pressures.

116 US EPA. 2006. Data Quality Assessment: Statistic al Methods for Practitioners (EPA QA/G-9S, 2006)

72Geochemical data are also an important part of baseline data co llection, as naturally occurring localized mineral deposits or the presence of organic constituents such as natural gas or naturally occurring CO 2 may mimic or obscure conditions indicative of a

CO 2 release. Depending on the site and on the proposed monitoring strategy, the GS reservoir and ACZ geochemistry could be meas ured as part of a baseline assessment, due to the possible presence of naturally occurring CO 2 , metals that may mobilize in the event
of a GS reservoir leak such as iron and manganese, or natu rally occurring constituents that could also be introduced by the CO 2 stream such as argon, nitrogen oxide, hydrogen sulfide, and methane.

5.5 Site-Specific Variables for the Mass Balance Equation

The mass balance equations RR-11 or RR-12 ar e used to calculat e the amount of CO 2 that is reported as sequest ered and include the terms CO 2FI and CO 2FP . CO 2FI is defined as
the total annual CO 2 mass emitted (metric tons) as equipment leakage or vented emissions from equipment located on the surf ace between the flow meter used to measure injection quantity and the injection wellhead. CO 2FP is defined as total annual CO 2 mass emitted (metric tons) as equipment leakage or vented emissions from equipment located on the surface between the production wellhead and the flow meter used to measure production quantity. The MRV plan should incl ude a summary of considerations made to calculate equipment leaks and vented emissions from surface equipment between the
flow meters and either in jection or production wellhead s, and the quantity of CO 2 that is produced with oil and water.

The mass balance equation assumes that all CO 2 measured at the flow meter is injected at the wellhead. In most cases this will provide an accurate estimate of injection volume. However, if additional surface equipment is lo cated on the injection lin e after the point of flow/mass measurement, and before the inject ion well, there is a potential for equipment
leaks and vented emissions that will not be in cluded in the mass balance. Similarly, the measurement point for produced CO 2 (at the flow meter immediately downstream of the gas-liquid separator) is assumed to represent the amount of CO 2 exiting the wellhead. However if additional surface equipment other than the separator is located between the production wellhead and point of CO 2 measurement, an estimate of equipment leaks and vented emissions from that equipment must be made in accordance with the monitoring methods in §98.233 of the Petroleum and Natu ral Gas Systems Reporting Rule (subpart W of the GHG Reporting Program). 117

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 injec tion wellhead (selected
from the list of all emissions sources under onshore petroleum and natural gas production at §98.232) and describes the me thodologies provided in §98.233 of 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 compress the recycle stream, which is eventually converted to critical phase CO 2 that is mixed with the critical phase stream coming from outside fa cility boundary. In the event that there are

117 http://www.epa.gov/climatechange/emissions/subpart/w.html

73other vented or fugitive CO 2 emissions sources that are between the flow meter and the wellhead, the Reporter will need to use the respective monitoring methods for such sources as provided in §98.233.

Table 5-1: Surface Components as Potential CO 2 Emissions Sources at Injection Facilities

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 pneumatic intermittent bleed device venting 4 X

Natural gas driven pneumatic pump venting 4 X

Reciprocating compressor rod and packing venting X

EOR injection pump X

EOR injection pump blowdown X

Centrifugal compressor wet seal oil degassing venting X

Other equipment leaks (valve, connector, open-ended line, pressure relief valve) X

(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 pneumatic 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-spec ific 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 equipment by instrument air rather than natural gas would not have natural gas pneumatic emissions sources.

Equipment leaks and vented CO 2 emissions at an ER opera tion can also occur from surface components located between th e production well and the point of CO 2 measurement. Between these two points, an in jection facility will typically have valves, connectors, meters, and headers (which are large pipes that mix the oil stream from

74multiple wellheads). The procedures pr ovided in subpart W for determining CO 2 emissions from all of these sources ar e equipment count and population factor.

The MRV plan must provide the basis for calculations of equipmen t leaks and vented emissions estimates from these points and include the emissions in the mass balance equations RR-11 or RR-12.

Fluids, including oil and water, produ ced at GS facilities may contain CO 2 that is not captured in the gas phase CO 2 measurement downstream of the gas-liquid separator. The

CO 2 is present as dissolved gas in the oil and water phase of the produced fluids. To account for the amount of produced CO 2 that is not sequestered, the reporter must tailor the mass balance equation to account for the mass of CO 2 in all produced fluids. Equation
RR-9 describes the mass balance of CO 2 at the gas-liquid separator where CO 2,P represents the total mass of CO 2 in the incoming production stream (oil, water and CO 2 ),
and CO 2,W represents the amount of CO 2 in the separated gas stream. The value of “X” is the percent of CO 2 expected to remain with the produ ced oil and gas when referenced to
the CO 2 separated for recycle or reuse.

The MRV plan must describe how the volume of CO 2 in produced fluids will be determined, and how the value of “X” will be calculated. The reporter should describe how the analysis of CO 2 in produced fluids will be perf ormed. Commercial laboratories perform crude oil analyses and separator liquid analyses that can include quantification of

CO 2 as a component. Because separato rs operate under pressure, the CO 2 saturation in water and oil inside the separator is higher than it would be at atmospheric conditions.
Care must be taken to ensure the measured CO 2 concentration is representative of the pressure conditions at the measurement locati on. For analysis, the wa ter and oil may need to be separated and analyzed using different methods. Several steps would be needed in order to estimate the quantity of CO 2 produced with oil, water or gas. The oil or gas stream of a production well at an ER operation is first separate d 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 stream s following the gas-water-oil separation phase: 1) CO 2 in oil, 2) CO 2 in water, and 3) CO 2 in gas phase (along with other produced hydrocarbons). The amount of CO 2 in the oil (or water) can be estimated by multiplying the gas-to-oil (or gas-to-water) ratio by th e volume of oil (or water) produced. The gasto-oil (or gas-to-water) ratio can be determin ed using any standard test method (the ratio determination as well as chromatography ar e well understood techni ques). A method to
determine the amount of CO 2 in gas phase is to use a mass flow meter or volumetric flow
meter to measure mass or volumetric flow rate of the produced gas stream that contains

CO 2 , take a sample of the stream , and analyze the stream for CO 2 composition, which can be done using chromatography.

A total fluids analysis from the separator liquid stream can also be performed to
determine the amount of dissolved CO 2 in the oil and produced water. The total fluid analyses are often a combination of seve ral ASTM or other methods. The selected sampling and analytical method(s) should cons ider the pressure at which the fluid is separated from the gas and differences in CO 2 solubility in oil a nd water. EPA has not

75identified consensus-based or industry sta ndard analytical methods specifically for determining the amount of CO 2 in mixed produced fluids (o il and water); however, two potentially applicable methods for CO 2 in hydrocarbons were identified:

ASTM D2597 - 94(2004) Standard Test Me thod for Analysis of Demethanized Hydrocarbon Liquid Mixtures Containi ng Nitrogen and Carbon Dioxide by Gas Chromatography

GPA Standard 2177 Analysis of Demethani zed Hydrocarbon Liquid Mixtures Containing Nitrogen and Carbon Dioxide by Gas Chromatography

To measure the CO 2 content in water co-produced with the oil, the reporter may use the following potentially applicable method:

ASTM D2513 - 06 Standard Test Method for Total Dissolved Carbon Dioxide in Water

The reporter must describe the analytical me thods used and demonstr ate the applicability of the methods in the MRV plan.

It is common in centralized production collection 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 accura te flow measuring devices on all streams in/out, and manifolded to dive rt any one well through 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/ oil/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 2 stream from a single well. There may be an aggregate point of monitoring from a collection of wells.

At some geologic sequestration sites where oil is not produced, saline water may be removed from the IZ to manage the pressure and capacity of the CO 2 storage system. The
amount of dissolved CO 2 in the saline water removed from the IZ may be measured using
ASTM D2513 - 06 Standard Test Method for Total Dissolved Carbon Dioxide in Water,
or other consensus-based or industry standard methods. Th e MRV plan should describe the fate of the produced water and account for all CO 2 in the produced water.

5.6 Quality Assurance and Quality Control

To ensure accuracy in reporting the data from natural and engineered systems, reporters should document their quality assurance progr am for data collection and analysis. The MRV plan should define what quality assuranc e and quality control procedures will be implemented for each technology applied in the leak detection and quantification process. For example, the plan should describe how th e reporter will ensure th at sensor readings are correct, and describe (or reference) the qu ality control measures that are in place to ensure precision, accuracy, representativeness, completeness, and comparability of data.

76Examples of quality control measures that may be described in the MRV plan include standard operating procedur es, calibration requirements, redundancy of the sensor or measurement, criteria for equipment selec tion, maintenance schedules and procedures,
and surveillance of subcontracted surveys or vendor materials.

5.7 Missing Data

Missing data procedures for the quarterly values of mass or volume, density, and
concentration for both CO 2 injected and CO 2 received are provided at 40 CFR 98.445. Procedures are also provided for missing data on CO 2 production and for equipment leaks
and vented emissions.

The rule does not require the reporter to de velop missing data procedures for monitoring
data described in the MRV plan. However, if leakage is detected for which a quantification approach is not outlined in the plan, info rmation on the quantification approach should be included in the annual report. Similarly, if additional leakage pathways are identified, they should be assess ed in accordance with the procedures in the “Assessment of potential su rface leakage pathways” section of the MRV plan, and included in the annual report. Procedures fo r developing missing leak quantification data should be included in the MRV plan.

776. 

### MRV Plan Approval Process Overview

If a facility is subject to subpart RR, the MRV plan must be submitted: 118

 By June 30, 2011 if the facility was issued a UIC permit authorizing CO 2 injection on or before December 31, 2010.

 Within 180 days of receiving a final UI C permit (or offshore authorization) authorizing CO 2 injection.

 Any time if injecting CO 2 to enhance oil and gas recovery and not permitted
under UIC Class VI.

Facilities will be allowed one extension of up to an addi tional 180 days. After submission of the MRV plan, the following review and approval process steps apply:

 Notification of receipt of MRV plan.

 Completeness check.

 Technical review.

 Issuance of EPA decision.

This chapter describes each step of the MRV plan approval process.

6.1 Suggested Outline for the MRV Plan

A suggested outline for the MRV plan may be found in Appendix D. The reporter may choose to modify this outline to meet site-specific requirements. The MRV plan outline addresses characteristics within the MMA; how ever, the plan may include information on geologic, topographic, cu ltural, and potential CO 2 source conditions outside the MMA, where appropriate, to assist EPA in developing a full unders tanding of potential influences on the proposed monitoring strategy.

6.2 Notification of Receipt of MRV Plan

EPA will accept MRV plan submittals from re porting entities that have established a “Certificate of Representation” throu gh the GHG Reporting Program’s Electronic Greenhouse Gas Reporting Tool (e-GGRT). A ll MRV plans must be submitted by the reporter electronically through e-GGRT. EPA ha s provided information and directions on how to electronically submit MRV plans on the subpart RR Web site: http://www.epa.gov/climatechange/emissions /subpart/rr.html . Upon MRV plan submittal, EPA will send a notice of receipt to the reporter within 15 days to acknowledge that EPA has received the MRV plan submission.

6.3 Completeness Check

118 Please refer to http://www.epa.gov/climatechange/emi ssions/data-reporting-system.html for information on electronic data reporting.EPA will first conduct a completeness check of the MRV plan submittal based on the regulatory requirement s identified in Table 6-1 . In addition, if a facility uses their UIC permit to fulfill or provide the basis for certain MRV plan requirements, the reporter should clearly identify relevant sections of the UIC permit as well as reference this information clearly in the MRV plan. EPA will determine if the MRV plan is complete within 45 days of the notice of receipt and will notify the re porter whether the plan is complete or incomplete.

EPA will issue a written notice that either requests additional information from the reporter or provides notice to the reporter th at the MRV plan is complete and that the
technical review will commence. In the case th at the MRV plan is incomplete, the notice would specify the MRV plan requirements th at were deemed to be incomplete, what additional information is needed, and the rati onale for why such additional information is needed. If incomplete, the reporter must s ubmit an updated MRV plan within 45 days of
EPA notification unless othe rwise specified by EPA.

Note that the completeness check is not a subs titute for the technical review process. EPA will initiate the technical review process onl y upon determination of the completeness of the MRV plan.

Table 6-1: Completeness Check Criteria fo r MRV Plan Submittals and Resubmittals Requirement Subpart RR Section The facility holds a certificate of representation 40 CFR 98.448(g) Delineation of the maximum monitoring area and the active monitoring areas as defined in §98.449 40 CFR 98.448(a)(1)

Identification of potential surface leakage pathways for CO 2 in the maximum monitoring area and the likelihood, magnitude, and timing, of surface leakage of CO 2 through these pathways 40 CFR 98.448(a)(2)

A strategy for detecting and quantifying any surface leakage of

CO 2 40 CFR 98.448(a)(3)

A strategy for establishing the expected baselines for monitoring CO 2 surface leakage 40 CFR 98.448(a)(4)

Summary of considerations to calculate site-specific variables for mass balance equation 40 CFR 98.448(a)(5)

If a well is permitted or is to be permitted under the UIC Program, the well identification number in the permit or permit application and the UIC permit class 40 CFR 98.448(a)(6)

If an offshore well is not subject to SDWA, any well identification number and any identification number used for the legal instrument authorizing GS 40 CFR 98.448(a)(6)

Proposed date to begin collecting data for calculating total amount sequestered according to equation RR-11 and RR-12 of subpart RR 40 CFR 98.448(a)(7)

For MRV plan revisions, the reason for resubmission 40 CFR 98.448(d)

6.4 Technical Review

79After the determination of completeness, EPA will initiate technical review of the MRV plan. After 60 days of technical review, EPA will send the reporter a written request for additional information, including clarifying technical questions, if necessary. The reporter will be encouraged to provide a response to this request within 15 days; however, EPA recognizes that there may be circumstances where additional time is needed for the reporter to collect the information requested.

6.5 Issuance of EPA Decision

Within a reasonable period of time, EPA will issue a final MRV plan as submitted, or with revisions. EPA will post the approved MRV plan on a public Web site, subject to any limitations or requirements in its CBI determination. 119

6.6 Appeals Period

If the reporter, or any inte rested person, objects to EPA’ s final decision, it may be appealed to EPA’s Environmental Appeals Board. See Section II.B of the preamble for more information on the appeals process and see http://www.epa.gov/climatechange/emissions/subpart/rr.html for information on joining the interested person list.

6.7 Resubmittal of MRV Plans

An MRV plan may require revision and resubm ittal if a material change was made to monitoring and/or operati onal parameters that was not antici pated in the original plan, if there has been a change in the permit class of the reporter’s UI C permit, if the reporter is notified by EPA of errors in their MRV plan or annual m onitoring report, or if the reporter chooses to revise their MRV plan for any other reason.

Examples of material changes include but ar e not limited to: large changes in the volume
of CO 2 injected; the construction of new injectio n wells not identified in the MRV plan; failures of the monitoring system including monitoring system sensitivity, performance, location, or baseline; changes to surface land use that affects baseline or operational conditions; observed plume location that diffe rs significantly from the predicted plume area used for developing the MRV plan; a change in the maximum monitoring area or active monitoring area; or a change in mon itoring technology that would result in coverage or detection capability different from the MRV plan.

The reporter must submit a revised MRV plan if notified by EPA of errors in the MRV plan or annual monitoring report (AMR). A suggested format is provided in Appendix D.

119 At the time of publication of this TSD, the CBI determination rulemaking for the GHG Reporting Program is not finalized (see Section II.B of the final preamble for a brief description of the CBI determination rulemaking). Please refer to http://www.epa.gov/climatechange/emissions/CBI.html for
more information.

807. 

### Annual Monitoring Report and Records Retention

Under the GHG Reporting Program, all reporters are required to electronically submit an annual GHG report to EPA that includes ge neral reporting elements that are common
across all sectors covered under the GHG Reporting Program, 120 as well as reporting elements that are specific to each subpart. This chapter outlines information to be included in the subpart RR annual monito ring report (AMR), per 40 CFR 98.446(f)(12). AMRs will be submitted each year by reporting entities through the e-GGRT system with other GHG data, and will summarize monitoring activities conducted in the past year. Reporters must include four components in AMRs:

 A narrative history of the monitoring effort conducted;

 A description of any non-material changes made to the MRV plan;

 A narrative history of any monitoring anomalies that were detected in the previous calendar year and how they we re investigated and resolved; and

 A description of surface leakages, if any.

These four components are described in this chapter. Appendix D provides a suggested outline of an AMR. This outline includes all the key elements required to be included in an AMR, and is intended to be a suggestion for reporters to follow. The reporter may choose to modify this outline to meet site-specific requirements. Other information that reporters may deem as necessary to include in an AMR can and should be included as
well.

7.1 Narrative History of Annual Monitoring Efforts

The first required component of an AMR is a narrative history of the monitoring effort conducted over the reporting year, including a listing of all monitoring equipment that was operated and its period of operation and a ny relevant tests or surveys that were conducted. This narrative history may include, for example, a general discussion crosswalking the monitoring activities implemen ted during the reporting year with the activities outlined in a facility MRV plan. Repor ters may include a table that presents all the monitoring equipment used during a re porting period and the related information.

7.2 Report of Non-Material Changes to the MRV Plan

The second component required to be included in the AMR is a detailed report of any non-material changes made to the MRV plan over the course of the reporting year. Nonmaterial changes to the MRV plan are thos e that do not warrant the submission of a revised MRV plan to EPA. Non-material changes to an MRV plan may include, for example, the use of newer versions of a tec hnology that are already included as part of the EPA-approved MRV plan, or changes in th e location of equipment that do not alter the coverage of detection capability of mon itoring. To present this information in the AMR, a reporter could include a description of the non-material changes made to the

120 Please refer to EPA’s GHG Re porting Program Web site at: http://www.epa.gov/climatechange/emissions/ghgrulemaking.htmlMRV plan, including an identification of the part of the MRV plan affected by the nonmaterial change, supporting information for w hy the change is non-material, the purpose of the change, when the non-materials change occurred, and if it affected facility operations. To articulate non-material changes in the AMR, it may be useful for reporters to identify, in a list or table, the conditions th at were used to determine what constituted a non-material change to their EPA-ap proved MRV plan. (See Appendix D)

7.3 Narrative History of Monitoring Anomalies

The AMR must also contain a narrative hi story of monitoring anomalies that were detected in the year and how they were inve stigated and resolved. This discussion could include a detailed description of all m onitoring anomalies detected, and how the anomalies were investigated in line with th e methods in the EPA-approved MRV plan, to determine if they represent a leak. This part of the AMR may also contain a description of how the monitoring anomalies were reso lved. As an example, if an anomalous pressure reading at a monitoring well, that is later found out to be caused by a vent line obstruction, is detected, a reporter would incl ude the following information in the AMR: a description of the pressure anomaly detecte d, a description of the steps taken to further investigate the reason for anomalous pressure re ading and evaluate if it represents a leak (i.e., how the obstruction in th e vent line was identified). Th e reporter may also include a description of the actions th e reporter has taken/is pla nning to take to rectify the
obstruction in the vent line. Reporters could also present this information along with other monitoring information presented in a table format. (See Appendix D)

This section of the AMR shoul d also include a qualitative discussion of any unexpected operational or maintenance issues that cau sed down-time for the equipment. If the evaluation and investigation of a monitori ng anomaly did result in the detection and quantification of a leak, reporters should include information discussed in Chapter 7.4.

7.4 Description of Surface Leakage

The fourth required component of the AMR is a description of surface leakages that happened during the reporting y ear (if any). Reporters must provide a description of any surface leakages of CO 2 , including a discussion of a ll methodologies and technologies involved in detecting and quantifying the surface leakages and any assumptions and
uncertainties involved in calculating the amount of CO 2 emitted.

In this section of the AMR, as part of the discussion of the methodologies and technologies involved in detec tion and quantifying the surface leakages, reporters could provide EPA with a demonstration showing th at the methods and technologies used for leak detection and quantifica tion followed the methods spec ified in the facility’s MRV plan. This section might include, for instance, monitoring measurement records that showed monitoring anomalies that resulted in the reporter having to confirm the detection of a leak and quantify the leak age in that reporting year. If non-material deviations are made from the leakage detection and quantif ication approaches specified in the MRV plan it must be documented in the AMR. (See Chapter 7.2 .)

82This component of the AMR may also include qualitative descrip tions and quantitative identifications (i.e., if a leak rate were assumed) of the assu mptions that went into each leakage calculation. Reporters may also provide information demonstrating the assumptions’ validity. Information on uncertain ties may include a qualitative analysis of the uncertainty around the amount of CO 2 emitted. For instance, such an analysis may include a description of how variables such as the accuracy and prec ision of measurement instruments may have affected calculating th e quantity of leakag e determined, and how uncertainty in baseline conditions may have a ffected calculations as well. Reporters may also, if feasible, include a detailed quantitative analysis of the uncertainty around the quantity of leakage calculated. If a quantitative analysis is done, reporters should include examples of all calculations made, and desc riptions of the statis tical methodologies and parameters used.

In the AMR, reporters should show the verification of the quantity of leakage in
accordance with the methods in the EPA-a pproved MRV plan. Reporters should provide calculations used to determine the quantity of leakage.

7.5 Records Retention Requirements for MRV Plans

Subpart RR requires facilities to retain records specified for retention in the MRV plan. These may include data that support the development and implementation of the MRV plan. Such records may be required to provide an auditable record of documentation in the event of an EPA-requested audit. The records to be reta ined should be sufficient to
document the rationale of the decision-maki ng process and demonstrate the completeness and accuracy of the data and calculations used in the detection and qua ntification of leaks to the surface. The MRV plan should state wh ich documents are to be retained, and the
format and/or location of the records. The duration for retention is 3 years per 40 CFR 98.3(g). Examples of records to be reta ined may include, but are not limited to, operational data, data sets used to construct expected baselin e conditions, data relating to the detection or quantification of surface leakage, logs of m echanical integrity tests and pressure tests, and field books and photogra phs that record observations of field
conditions.

83

### Appendix A: Glossary

Above Confining Zone (ACZ) : The geologic formation that is immediately above the caprock or CZ.

Active Monitoring Area (AMA) : The area that will be m onitored over a specific time interval from the first year of the period (n) to the last year in the period (t). The boundary of the AMA is established by superim posing two areas: 1) the area projected to contain the free-phase CO 2 plume at the end of year t, plus an all-around around buffer zone of one-half mile or greater if known leakage pathways extend laterally more than one-half mile; and 2) the area projected to contain the free phase CO 2 plume at the end of year t+5. (40 CFR 98.449)

Carbon dioxide (CO 2 ) plume : The extent underground, in three dimensions, of an injected CO 2 stream. (40 CFR 146.81(d))

Carbon dioxide (CO 2 ) stream : CO 2 that has been captured from an emission source (e.g. a power plant) plus inci dental associated substan ces derived from the source materials and the capture process, and any subs tances added to the stream to enable or improve the injection process. (40 CFR 146.81(d))

Confining Zone (CZ) : A geologic formation, group of form ations, or part of a formation stratigraphically overlying the IZ(s) that acts as a barrier to fluid movement. For UIC Class VI wells operating under an injec tion depth waiver, CZ means a geologic formation, group of formations, or part of a formation stratigra phically overlying and underlying the IZ(s). (40 CFR 146.81(d))

Equipment leak : Those emissions that could not reasonably pass through a stack, chimney, vent, or other functionally -equivalent opening. (40 CFR 98.449)

Expected baseline : The expected baseline is the an ticipated value of a monitored parameter that is compared to the meas ured monitored parameter. (40 CFR 98.449)

Formation or geological formation : A layer of rock that is ma de up of a certain type of rock or a combination of types. (40 CFR part 144 and part 146)

Free-phase CO 2 plume : That part of the CO 2 plume in which the injected CO 2 stream exists in gaseous, liquid or supercritical free phase. The precise definition will be stated by the reporter in the MRV plan based on s ite characteristics and the proposed methods of monitoring and modeling.

Free-phase CO 2 plume area : The 2-D vertical projection onto the surface of the freephase CO 2 plume. The free phase CO 2 plume area is included within the AMA and

MMA.

84Geophysical surveys : The use of geophysical techniques (e.g., seismic, electrical, gravity, or EM surveys) to characterize s ubsurface rock formations. (40 CFR part 144 and part 146)

Injectate : The fluids injected (40 CFR part 144 and part 146). For the purposes of this rule, this is also known as the CO 2 stream.

Injection Zone (IZ) : A geologic formation, group of form ations, or part of a formation that is of sufficient aerial extent, thic kness, porosity, and permeability to receive CO 2 through a well or wells associated with a GS project. (40 CFR 146.81(d))

Maximum Monitoring Area (MMA) : The area that must be monitored under this regulation and is defined as equa l to or greater than the area expected to contain the free phase CO 2 plume until the CO 2 plume has stabilized plus an all-around buffer zone of at least one-half mile. (40 CFR 98.449)

Mechanical integrity (MI) : The absence of significant leakage within the injection tubing, casing, or packer (know n as internal mechanical integrity), or outside of the casing (known as external mechanical integrity. (40 CFR part 144 and part 146)

Mechanical Integrity Test (MIT) : A test performed on a well to confirm that a well maintains internal and external mechanical integrity. MITs are a means of measuring the adequacy of the construction of an injection well and a way to detect problems within the well system. (40 CFR part 144 and part 146)

Operational stage: The operational stage of a GS sy stem includes the period of time during injection.

Pore space : Open spaces in rock or soil. These are filled with water or other fluids such as brine (i.e., salty fluid). CO 2 injected into the subsurface can displace pre-existing fluids to occupy some of the pore spaces of the rock s in the IZ. (40 CFR pa rt 144 and part 146)

Separator: means a vessel in which streams of multiple phases are gravity separated into
individual streams of si ngle phase. (40 CFR 98.449)

Stratigraphic zone (unit) : A layer of rock (or stratum) th at is recognized as a unit based on lithology, fossil content, age, or other properties. (40 CFR part 144 and part 146)

Subsurface CO 2 Leakage : Subsurface leakage is injected CO 2 that is present outside the
IZ but has not reached the surface.

Surface CO 2 Leakage : The movement of the injected CO 2 stream from the IZ to the surface, into to the atmosphere, indoor air, oceans, or surface water. (40 CFR 98.449)

Vented emissions : intentional or de signed releases of CH 4 or CO 2 containing natural gas or hydrocarbon gas (not including stationary combustion flue gas), including process

85designed flow to the atmosphere through seal s or vent pipes, equipment blowdown for maintenance, and direct venting of gas us ed to power equipment (such as pneumatic devices). (40 CFR 98.449)

86

### Appendix B: U.S. Oilfields Using CO 2 

### Injection 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 and April 2010 with permission 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 Chevron CO 11,600 Hall-Gurney (removed 2010) Murfin Drilling KS 3 Lockhart Crossing Denbury Resources LA NR

Charlton 30-31 Core Energy MI 75

Charlton 6 Core Energy MI 10 Chester 2 (added 2010) Core Energy MI NR

Dover 33 Core Energy MI 75

Dover 35 Core Energy MI 286

Dover 36 Core Energy MI 195

Brookhaven Denbury Resources MS 3,100 Cranfield (added 2010) Denbury Resources MS 10,150

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 Heidelberg (added 2010) Denbury Resources MS 2,050

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

Camrick 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 Abell (added 2010) Fasken TX 85

Adair San Andres Unit Hess TX 900 Adair Wolfcamp Unit (added 2010) Apache TX 420

87Albert Spicer Unit (added 2010) Chaparral Energy TX NR

Anton Irish Occidental TX 4,000 Booker Trosper Unit (added 2010) Chaparral Energy TX NR

Cedar Lake Occidental TX 2,860

Central Mallet Unit Occidental TX 2,100 Cogdell Occidental TX 5,900

Cordona Lake XTO Energy Inc. TX 400 Dollarhide (Clearfork "AB") Unit Pure Resources (Chevron 2010) TX 1,970

Dollarhide Devonian Unit Pure Resources (Chevron 2010) TX 124

East Ford Orla 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 Gramstorff Unit (added 2010) Chaparral Energy TX NR

Hanford Fasken TX 300

Hanford East Fasken TX 45 Hanford San Andres (added 2010) Fasken TX NR

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 (Chevron 2010) TX 830 River Bend (Devonian) (added 2010) Fasken TX 20

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 ConocoPhillips TX 250

88South 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 Occidental TX 0

Yates Kinder Morgan TX 6,280

Greater Aneth Resolute Natural Resources UT 400

Greater Aneth Area ExxonMobil UT 3,000 Beaver Creek (added 2010) Devon WY 2,425

Lost Soldier Merit Energy WY 7,221

Patrick Draw Monell Anadarko WY 3,000

Salt Creek Anadarko WY 6,000

Sussex Anadarko WY NR

Wertz Merit Energy WY 4,019

89

### Appendix C: Summary of Other End Uses of Captured or Produced CO 2

The following is a summary of end uses of captured or produced CO 2 (with the exception of ER and GS).

Cement . While not a common pract ice in the cement industry, some companies are currently working to employ a cement manuf acturing process that uses captured CO 2

. 121
The process will convert CO 2 into carbonic acid, which will be made into CO 3 - - . The

CO 3 - - will be combined with calcium and magn esium from seawater to make calcium carbonate and magnesium carbonate for the cement. 122 EPA does not have enough
information to conclude whethe r cement production using this CO 2 capture method permanently sequesters CO 2.

Precipitated Calcium Carbonate (PCC) . PCC is produced through a chemical reaction process that utilizes calcium oxi de (quicklime), water, and CO 2 . The CO 2 used to manufacture the PCC is in some cases cap tured 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 perform ance in specific applications. EPA does not have enough information to conclude whether PCC production using this CO 2 capture method permanently sequesters 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 U.S. CO 2 is used widely throughout the food and beverage industry for a variety of applic ations including:

 Carbonation of soft drinks;

 Beer and wine production;

 Decaffeination of coffee and tea;

 pH adjustment and shelf life lengthener for dairy products;

 Frozen food production; and

 Canning.

Pulp and Paper Manufacturing. CO 2 is used in the pulp and paper industry in production processes to control pH, decr ease calcium levels, increase de-watering, buffer the paper making system, and recover chemicals in the mill process. 123

, 124

121 Engineering News-Record. 2009. New Green-Concrete Process Combines Seawater, Flue Gas, February 18, 2009, http://64.62.167.123/ images /uploads/news/press-coverage/enr .pdf (accessed July 26, 2009).

122 Biello, David. 2009. Cement from CO 2 : A Concrete Cure for Global Warming? , Scientific American, http://www.scientificamerican.com/artic le.cfm?id=cement-from-carbon-dioxide (accessed July 26, 2009).

123 Linde Gas, AGA and the Pulp and Paper Industry. http://www.aga.fi/inte rnational/web/lg/aga /like35agacom.nsf/docbyalias/nav_pulp_paper (accessed October 25, 2010)

124 US Patent 6200416 - Recycled paper production process which incorporates carbon dioxide, March
2001 http://www.patentstorm.us/patents/6200416/description.html (accessed July 26, 2009).

90Industrial and Municipal Wastewater Treatment. Industrial and muni cipal wastewater
treatment facilities use CO 2 to control pH levels in the water and treat soft water by dissolving lime. 125

Metal Fabrication. CO 2 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 Plant Growth. CO 2 is used to increase plant growth in greenhouses that produce flowers to full gr owth, nursery plants in earl y developing stages, and some produce (e.g., tomatoes).

Fumigants and Herbicides. CO 2 is used in the agricultural sector as an herbicide for organic produce that successfully kills in sects and increases st orage life; and as a fumigant for grain storage to contro l insects in the storage facility.

Medical Treatment. For medical treatment, CO 2 is added to oxygen to stimulate breathing
and balance CO 2 /O 2 levels in patients.

Construction. In the construction an d manufacture industry, CO 2 is used on a large scale as a shield gas in metal inert gas (MIG) welding and metal active gas (MAG) welding, where the gas protects the weld puddle against oxidation by the surrounding air. 126 A mixture of argon and CO 2 is commonly used to achieve a higher welding rate and reduce the need for post-weld treatment. Additiona lly, dry ice pellets are used to replace sandblasting when removing paint from surfaces . Dry ice aids in reducing the cost of disposal and cleanup.

Rubber and Plastic Industry. CO 2 cleaning, also known as dry i ce blasting, is a method of cryogenic cleaning. Dry ice is used to rem ove flash from rubber objects by tumbling them with crushed dry ice in a rotating dr um. Almost all major tire manufacturers use

CO 2 cleaning in their rubber molds. Shoe comp anies 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 th e production of polymer foams, liquid CO 2 is used as a blowing agent instead of e nvironmentally hazardous substances. CO 2 is a physical blowing agent with properties desi red for ideal foaming, while simultaneously fulfilling many requirements related to quality, efficiency, and the environment.

Fire Suppression. CO 2 fire extinguishers are used for Class B fires (involving flammable and volatile liquids) and Class C fire s (involving electrical equipment).

Cleaning and Solvent Use. Liquid CO 2 is used a solvent for cleaning a variety of products during manufacturing processes, e.g., elec tronics cleaning and metal cleaning. Liquid

125 Linde Industrial Gases, Products an d Supply, Wastewater. http://www.lindegas.com/en/products_and_suppl y/water_treatment/index.html (accessed October 25, 2010).

126 Metal inert gas (MIG) welding and metal active gas (MAG) welding are two subtypes of gas metal arc welding (GMAW).

91CO 2 ’s solvent potential has been employed in some dry cleaning equipment as a
substitute for conventional solvents.

Refrigeration and Cooling. Liquid and solid CO 2 are important refrigerants, especially in the food distribution industry, where they are employed during th e transportation and storage of ice cream and other frozen foods, pr imarily in small retail food stores. In those cases, the CO 2 may be stored on-site or be provide d by refrigerant technicians at the time of recharging.

Transportation and Storage of Explosives. CO 2 is used in the transportation and storage of explosives as it reduces the explosion risk.

Algae Production. Algae plantations for the production of biofuels 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 GHG/carbon sink. Also of strong intere st is the use of algae as a source of feedstock material for the production of biodiesel, and perhaps fermentation. CO 2 is an ingredient used by algae for normal growth, during photosynth esis. The process is being studied at various pilot projects in the U.S. and elsewhere.

Pressurized Gas. CO 2 is used as an inexpensive, nonflammable pressurized gas. Compressed CO 2 gas is used in life jackets (store d inside canisters), in air guns, in paintball markers, and for inflating bicycle tires.

Chemical processes. CO 2 is currently used for various pr ocesses in the chemical industry, including but not limited to, the production of:

• Urea (from ammonia);

• Methanol;

• Ethanol; and

• Sodium Bicarbonate.

Pharmaceutical Processes . Pharmaceutical processes may use CO 2 as a less toxic alternative to organochlorides or more traditional solvents.

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### Appendix D: Suggested Outlines for MRV Pl ans, MRV Plan Resubmittals, and Annual Monitoring Reports

Suggested Outline for MRV Plan and MRV Plan Resubmittals

1) Facility Information i) Reporter number ii) UIC permit class iii) UIC injection well identification numbers iv) Authorization for CO 2 injection if an offshore well not subject to SDWA i) MRV plan identification number (for resubmittals) ii) Date most recent MRV plan approved by EPA (for resubmittals) iii) Reason for re-submittal (for resubmittals) 2) Project Description a) Project characteristics i) Estimated years of CO 2 injection ii) Estimated tons CO 2 received over lifetime of project b) Environmental Setting of the MMA i) Surface and subsurface boundary of the MMA ii) Geology and hydrogeology iii) Historical use of subsurface and surface iv) Available reference sites (near but outside project area for development or adjustments to baselines) c) Description of the Injection Process i) Variability of CO 2 composition ii) Number, location and depth of injection wells iii) Compression/pumping, conditioning a nd pipelines at the facility d) Reservoir Characterization and Modeling i) Simulation model(s) used ii) Modeling objectives iii) Modeling procedures iv) Data inputs, sources, quality control, update process v) Model outputs vi) Grid size and resolution vii) Model calibration process a nd sensitivity analysis 3) Delineation of the monitoring areas a) MMA i) Determination of free phase plume extent ii) Determination of buffer zone b) AMA(s) i) Initial monitoring period, area and time frame ii) Future monitoring periods, areas and time frames 4) Evaluation of Leakage Pathways a) Well pathway(s)

93b) Fractures, faults and beddi ng plan parting pathway(s) c) Confining system pathway(s) d) Other identified pathways(s) 5) Detection, Verification and Quantification of Leakage a) Leakage detection methods i) Process for detecting leakage for each pathway ii) Performance measures for leak detection b) Leakage Verification and Quantification Methods i) Process for verifying and quantifying leakage for each pathway ii) Performance measures for veri fying and quantifying leakage 6) Determination of Expected Baselines a) Monitoring method A expected baseline method b) Monitoring method B expected baseline method c) Monitoring method C expected baseline method 7) Site Specific Modifications to the Mass Balance Equation a) Equipment leaks and vented emissions from surface equipment downstream of injection flow meter b) Equipment leaks and vented emissions from surface equipment downstream of production well flow meter (if applicable) c) CO 2 produced in oil and other fluids 8) Estimated Schedule for implementation of MRV plan a) Timing for expected baseline determination b) Timing of implementation of leakage detection and quantification monitoring c) Proposed date to begin collecting data for calculating total amount sequestered according to equation RR-11 or RR-12 of this subpart. 9) Quality Assurance Program 10) Records Retention 11) Appendices

94Suggested Outline for Annual Monitoring Report to EPA-approved MRV plans

1) Executive Summary a) Date MRV plan approved by EPA b) MRV plan identification number 2) Summary Table of Monitoring Activities (suggested format Table D-1 ) 3) Narrative History of the M onitoring Effort Conducted a) Listing of all monitoring equipment, pe riod of operation, and relevant tests or surveys conducted (see also s uggested table format above) b) Cross walk of annual monitoring ac tivities with approved MRV plan 4) Non-Material Changes to EPA-Approved MRV Plan 5) Narrative History of Monitoring Anomalies Found a) Monitoring anomalies detected, resulting i nvestigations, and resolutions (see also
Table D-1 ) 6) Description of Surface Leakage a) Methodologies and technologies used i) Description of alignment with EPA-approved MRV plan ii) Non-material deviations from the leakage detection and quantification approaches specified in the MRV plan iii) Measurement records showing dete ction of monitoring anomalies b) Assumptions Involved in Calc ulating the Quantity of CO 2 Emitted i) Assumption identification and supporting information c) Uncertainties Involved in Calc ulating the Quantity of CO 2 Emitted

Table D-1: Suggested Format for Listing of Monitoring Equipment

Monitoring Equipment Period of Operation Tests/Surveys
Conducted Test/Survey

Results Monitoring Anomaly Investigation Resolutions
After Monitoring

Anomaly
1 [Equipment technology type,
make and model number] [Dates of operation] [Identification of tests/surveys conducted] [Brief summary of survey results
and identification of any anomalies detected] [If anomalies were identified, a brief summary of
action taken to
evaluate and investigate the anomaly and the
related results (i.e., if it is
concluded that the anomaly
represents a leak)] [A brief summary of the follow-up
actions taken
after anomalies
are further
evaluated an investigated]

2 Monitoring well
Number
T31NR14WS23­ IZ, Paine model
213-36-940

Pressure
Transducer Continuous from August 1, 2011 through
December 31, 2011 Hourly recording of pressure in IZ
@ 5020 feet September 23­ 28, 2011,
increased pressure (up to 2180 psi)
detected at this
location.
Exceeded
baseline expectation by 21 psi Secondary

pressure transducer at this
location did not
read elevated

pressure. Investigation
revealed that
vent line was
obstructed. Vent line
obstruction
corrected on September 29,
2011.

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### Appendix E: Sampling Consideratio ns for Designing a Monitoring Strategy

A consideration in designing a leakage dete ction strategy and also in establishing an expected baseline is ensuring adequate data resolution to cover a range of points in space and time. A non-representative data set that co ntains too few samples at too few times of day/year from too few locations will generate a biased picture and result in erroneous decision making. A sampling program may be de signed to ensure c onsideration of the appropriate frequency of sampling, aeria l extent of sampling, and sample size.

Frequency of Sampling

If the environmental f actor being measured incurs consid erable intra-day and/or seasonal variation, the sampling program may be desi gned to capture these fluctuations. An example of a parameter that shows high intra- day and seasonal variation is near-surface

CO 2 flux. A program based on CO 2 flux monitoring would need a high frequency of sampling across the year. On the other ha nd, if the environmental parameter being
monitored is not known to show a substant ial intra-day or seasonal variation, the sampling program could rely on a lower fre quency of sampling. An example of such a parameter may be fluid pressure in a deep confined reservoir to be used for ACZ monitoring. To account for different monito ring technologies or variability in the monitoring area, the reporter may employ di fferent frequencies within the monitoring area to achieve adequate baseline definiti on. The MRV plan should clearly define the frequency of baseline samp ling and provide a rationale for the chosen frequency.

Areal Extent of Sampling and Sub dividing Maximum Monitoring Area

The specific method used for the measurement of the monitored environmental parameter will produce values representa tive of a certain area. Eddy covariance towers are known to produce flux estimates representative of a radius equal to approximately 50 times the height of the tower. 127 If cost-effective, it would thus be possible to construct as many eddy covariance towers as necessary to ensure coverage of the entire monitoring area. On the other hand, if the method employed produces representative values for a small range, it may be necessary to rely on statistical techniques to balanc e cost and coverage. Accumulation chambers are an example of a t echnique that measures a very small area (tens of cm 2 ). Expert judgment based on modeling re sults may be used to focus sampling in higher CO 2 leakage risk areas and limit sampling in lower risk areas. Modeling inputs and sensor placement should be updated periodically with the results from the monitoring program to redefine the areal sampling plan as necessary. The MRV plan should present the rationale for selecting the areal extent of sampling and demonstr ate that it provides adequate coverage to determine a representati ve baseline. If the monitored parameter is expected to vary by subdivisions of the MMA, then the proposed subdivisions and the process for preparing expected baselines for each should be presented in the plan.

127 Campbell Scientific, Inc. 2004-2006. Open Path Eddy Covariance System Operator’s Manual CSAT3, LI-7500, and KH20. Available at: http://www.campbellsci.com/documents/manuals/opecsystem.pdf

96Sample Size

An adequate sample size will ensure greater ability to detect differences between prevailing conditions and the expected ba seline. Approximate knowledge of sampling variation in the measured parameter (poten tially based on prior sampling experience)
could be used to estimate the number of sa mples needed to limit the occurrence of false positives and false negatives to the desired le vel. Frequently, cost considerations place limitations on the number of samples that may be gathered such th at reporters should estimate the probability of occurrence of false positives and false negatives to better guide decision making. For instance, if calcu lations show a high probability of a false negative at a given location for a given sample size, the reporter could initiate a program for securing more samples from that area before taking a decision. Knowledge of the expected sampling variation in a parameter will improve with each successive sampling phase, which in turn will improve the accur acy of the predicted sample size for the specified error rates. The MRV plan should de monstrate that the sample size is adequate
to account for the observed variabilit y in the measured parameter.

Coverage Adequacy of a Sampling Program

The MRV plan is likely to include one or more leakage detection or quantification monitoring techniques that invo lve collecting data at one or more locations within the MMA. This appendix explains how the statistic al coverage adequacy of a given sampling program (i.e., the probability a given size of leak will be detected) can be computed and presented in an MRV plan.

The overall probability that a given leak will be detected is the probability that the leak will be physically encountered by the sampling program times the probability the leak will be recognized once encountered. In equation form this is:



### P

d 

###  P

e 

###  P

r (Equation 1)

Where:

P d = overall probability l eak will be detected

P
e = probability leak will be encountered by a sampling program

P
r

= probability leak will be recognized once encountered

The probability that the l eak will be recognized af ter it is encountered (P
r ) can be computed given the mean and standard devi ation in the expected environmental or operating baseline, and the mean and standard deviation of the measured parameter. As noted earlier, P
r is equal to one minus the chance of false negatives. As discussed below, the probability of any given monitori ng element encountering the leak, P
e , is a function of the size of the monitoring area, the size and shap e of the leak area, the size and shape of the sample coverage, and the number and pattern of sampling.

97The “leak area” may be specified in terms of how much total area the expected leak will encompass. It may also be useful to know, if possible, how many separate pieces or segments the leak area will be in at the surface (or other monitoring zone), and what shape (maximum length of the leak in one dimension) those segments might take. The leak area can be estimated by hypothesizing a size of leak to be examined and estimating the expected dispersion pattern to the surface (or to another monitoring zone such as a shallow USDW) for a given leakage pathway. The dispersion pattern for leaks along artificial penetrations and faults would be expected to be more easily defined, and probably have smaller footprints compared w ith CZ leaks, which can meander and break apart traveling upward. The dispersion modeling would indicate the expected area of the leak in units such as square meters and th e surface flux in units such as micrograms of

CO 2 per square meter per second (  g m -2 s -1 ). The probability of en countering the leak is related to the leak area, while the probability of recognizing the leak once encountered is
often related to the flux.

The term “sample coverage” refers to the physical area over which the monitoring method provides a representative measurem ent of the parameter. Common types of sample coverage are: point, linear, and area. For example, a soil gas sample typically would provide a “point sample coverage” fo r a limited area without a significant length or width. A closed-path remote sensing samp le consisting of a laser beam bounced off a mirror would have a “linear sample coverage ,” which is an area with length but no significant width. An eddy covariance survey would typically have an “area sample coverage,” which is a roughly ci rcular area with a given radius . An example of the effect of leakage footprint size on eddy covariance detection statio n density is presented by
Cortis et al. 128

128 Cortis, A., Oldenburg, C.M., and Benson, S.M. 2008. The role of optimality in CO2 seepage detection for geological carbon sequestration sites. International Journal of Greenhouse Gas Control , Vol. 2(4) Special Issue: Sp. Iss. SI, 640-652. doi:10.1016/j.ijggc.2008.04.008.

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