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) regulations cited in this technical support 

document (TSD) contain legally-binding requirements. In several chapters this TSD 

offers illustrative examples for complying with the minimum requirements indicated by 

the regulations. This is done to provide information that may be helpful for reporters’ 

implementation efforts. Such recommendations are prefaced by the words “may” or 

“should” and are to be considered advisory. 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 regulation itself, so it does not impose legallybinding requirements on EPA or the regulated community. It may not apply to a 

particular situation based upon the circumstances. 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 regulated community are determined by statutes, 

regulations or other legally binding requirements. In the event 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 issues covered by 49 CFR part 98, subpart RR 

and subpart UU, which are being promulgated under EPA’s authorities under the Clean 

Air Act (CAA). Other statutory and regulatory requirements, such as compliance with 

Safe Drinking Water Act (SDWA) and Underground Injection Control (UIC) Program 

requirements1

, are not within the scope of this TSD. Please see section I.D. of the 

preamble to the final rule for more information 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/groundwater/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 CO2 ..................................................................... 9
 

1.2	 Delineation of Facility........................................................................................ 10
 

2. Reporting Threshold Analysis ................................................................................16
 

3. Monitoring Methods for CO2 Received and CO2 Injected...................................23
 

3.1 Determining the Amount of CO2 Received Using Data from Sales, Contracts, 

Invoices, or Manifests Associated with Commercial Transactions.............................. 23
 

3.2 Determining the Amount of CO2 Received, Injected, or Produced Using Mass 

Flow Meters or Volumetric Flow Meters ..................................................................... 24
 

4. Overview of Monitoring Technologies for CO2 Leakage Detection and 

Quantification...................................................................................................................30
 

4.1	 Monitoring of the Injection Well ....................................................................... 31
 

4.2	 Monitoring of Subsurface CO2 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 Precision 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 CO2 to the Surface................. 54
 

5.2.1 Assessment of the Risk of Potential Leakage of CO2 through Wells......... 55
 

5.2.2 Assessment of the Risk of Potential Leakage of CO2 through Fractures, 

Faults, and Bedding Plane Partings .......................................................................... 58
 

5.2.3 Assessment of the Risk of Potential Leakage of CO2 based on the 

Competency, Extent, and Dip of the Confining Zone .............................................. 59
 

5.3	 Strategy for Detecting and Quantifying any CO2 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
 

3
 
5.7 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 CO2 Injection for Enhanced Oil Recovery.................87
 

Appendix C: Summary of Other End Uses of Captured or Produced CO2 .......................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
 

4 
List 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 CO2 used in ER showing growth since 2004......................................... 17 

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

Requirements .................................................................................................................... 54 

List of Tables 

Table 2-1: Threshold Analysis Based on Amount of CO2 Received by a Facility........... 21 

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

Table 5-1. Surface Components as Potential CO2 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 for Testing and Materials 

bbl Barrel 

CCS Carbon Dioxide Capture and Geologic Sequestration 

CFR Code of Federal Regulations 

CH4 Methane 

CO2 Carbon Dioxide 

CO2FI	 Total annual CO2 mass emitted (metric tons) as equipment leaks or vented 

emissions from equipment located on the surface between the flow meter 

used to measure injection quantity and the injection wellhead. 

CO2FP	 Total annual CO2 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. 

CO3

- - 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 

H2CO3 Carbonic Acid 

H2S Hydrogen Sulfide 

HCO3

- 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 

6
 
km 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 

7
 
 

 

 

1. Source Description 

Preliminary estimates indicate that the amount of carbon dioxide (CO2) captured from 

industrial processes, including combustion and chemical manufacturing, and produced 

from naturally occurring subsurface CO2 reservoirs is approximately 44 million metric 

tons carbon dioxide equivalent .2,3 Currently more than 95 percent of this CO2 supplied 

to the economy is injected underground for enhanced oil and gas recovery (ER).2 CO2 

may be injected underground for geologic sequestration (GS). GS is the long-term 

containment of a CO2 stream in subsurface geologic formations and is a key component 

of a set of climate change mitigation technologies known as carbon dioxide capture and 

geologic sequestration (CCS). CCS has the potential to enable large emitters of CO2 such 

as coal fired power plants to significantly reduce greenhouse gas (GHG) emissions. 

1.1 Overview of Source Categories 

Three sectors were considered for inclusion in this rule: injection of CO2 underground for 

GS, injection of CO2 underground for ER, and end uses of CO2 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 unmineable coal seams. In addition, CO2 may be 

injected into other types of subsurface geologic formations, such as basalt formations. 

The UIC program, which is authorized by Part C of the SDWA, regulates underground 

CO2 injection. 

Geologic sequestration occurs through a combination of structural and stratigraphic 

trapping, residual CO2 trapping, solubility trapping, mineral trapping, and preferential 

adsorption trapping. These mechanisms are functions of the physical and chemical 

properties of CO2 and the geologic formations into which the CO2 is injected. For more 

background information on GS trapping mechanisms, see the Vulnerability Evaluation 

Framework for Geologic Sequestration of Carbon Dioxide.4 

1.1.2 Enhanced Oil and Gas Recovery 

CO2 is currently being injected into subsurface geologic formations in the United States 

(U.S.) for ER. The CO2 currently being used in ER is primarily produced from naturally 

occurring underground CO2 reservoirs but is also captured from industrial processes, 

including combustion and chemical 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 CO2 does not include biogenic CO2. 4 Vulnerability Evaluation Framework for Geologic Sequestration of Carbon Dioxide (see docket ID No. 

EPA-HQ-OAR-2009-0926)
 

8
 
 

 

 

ER involves injecting CO2 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 CO2 mixture is produced from production wells and sent to a two-phase 

separator where the crude oil is separated from the gaseous hydrocarbons and CO2. The 

gaseous CO2-rich stream then is typically dehydrated, recompressed, and reinjected into 

the oil or natural gas reservoir to further enhance recovery. If the concentration of 

hydrocarbons in the CO2 stream from the dehydrator is significant, then an acid gas 

recovery unit is used to separate the hydrocarbons from the CO2. 

Injection of CO2 into unmineable coal seams may result in displacement of methane 

(CH4) from the coal seam and subsequent production of the methane as a product (or 

enhanced coal bed methane). 

There are currently 80 ER fields operating in the United States where CO2 is being 

injected for the purposes of ER.5

 ER projects operating in the United States range from 

new pilot-scale projects with one or two injection wells to CO2 floods that commenced 

operation in the 1970s and that have hundreds of injection wells. Approximately 44 

million metric tons of CO2 was received for injection underground for ER in 2008. Of 

this amount approximately 80 percent was produced from naturally occurring 

underground CO2 reservoirs and 20 percent was captured 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 specifications. In some fields 

the natural gas may contain a significant quantity of hydrogen sulfide (H2S) or CO2, 

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 H2S and CO2 

separated from the natural gas is called acid gas. The composition is quite variable and 

can range from 2 percent H2S and 98 percent CO2 to about 85 percent H2S and 15 percent 

CO2.

7

 Most acid gas is disposed of by underground injection under a UIC Class II permit. 

These permits may allow for disposal of other oil and gas production wastes, including 

brine, well completion and work-over fluids, and spent dehydration unit fluids, in 

addition to the acid gas. 

1.1.3 Other Industries That Use CO2 

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/emissions/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. 

9
 
 

 

EPA identified and considered a total of 22 commercial end use sectors8 that use gaseous, 

liquid, or solid CO2, 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 CO2 and if so, 

which industries this would include; how many facilities operate in each of these 

industries; how much of the CO2 consumed in each industry would be sequestered; 

whether a sequestration factor would be reasonable in any case; and what methodologies 

could be used to verify this sequestration. These sectors were not included in this final 

rule. Please refer to the Response to Comments document for further information.9 

1.2 Delineation of Facility 

For CO2 received by pipeline, the point of measurement for reporting the amount of CO2 

received at a facility will often be identified by a change in ownership (or custody) of the 

CO2. The transfer of custody of the CO2 is the basis of sales contracts and revenue 

reporting, and is generally measured with meters that conform to state oil and gas board 

regulations and industry standards. The question arises of how to delineate a facility 

when collecting data on CO2 received. Subparts RR and UU rely on the definition of 

“facility” in 40 Code of Federal 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 adjacent 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 CO2 as an end 

product and excludes intermediate CO2 processors. After CO2 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 CO2 into their processes in the necessary state; e.g., food 

grade CO2 used for food and beverage production. Intermediate processors often receive the produced CO2 

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. 

10
 
Figure 1-1: Facility Example 1 

In the first example (Figure 1-1) an operator is conducting CO2-ER operations in a field 

that is fully contained within one leased area. A large-diameter CO2 supply pipeline 

(trunk line) owned by a third party supplies all the CO2 used in the field. The CO2 is 

delivered to the field from the trunk line via a distribution line owned by the field 

operator. The custody of the CO2 is transferred to the field operator at the meter where 

the distribution line begins. Once the field operator takes possession of the CO2, it is 

transported over some distance and further distributed 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 facilities that capture and re-process the CO2 for reinjection downstream of the custody transfer meter. In this scenario the field is one 

facility because it is under common control, and the meter reading at the custody transfer 

point is the amount of CO2 received. 

11
 
Figure 1-2: Facility Example 2 

In the second example, Figure 1-2, two fields under common control are fed by a 

continuous CO2 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 reservoir 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. 

12
 
Figure 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 different entities, but fed by a single CO2 

distribution line from the main trunk line. Ownership of the CO2 is transferred at the 

meter between Fields A and B. In this example because Field A and Field B are under 

different ownership and control, they represent two different facilities. The amount of 

CO2 passing through meter A (at the trunk line) represents the total amount of CO2 

supplied to both fields; therefore the owner of Field A should report the total amount at 

meter A less the amount at meter B (the amount of CO2 provided to Field B). 

13
 
Figure 1-4: Facility Example 4 

Figure 1-4 shows a trunk line that splits and supplies two different fields operated by the 

same entity, and thus are under common control. Custody of the CO2 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 review the definition of 

facility carefully and decide whether to report as one or two facilities in their specific 

situation. 

Figure 1-5: Facility Example 5 

14
 
In large ER operations in a single field operated by the same entity, the trunk line may 

pass directly through the field and connect to multiple distribution lines (Figure 1-5). 

Custody of the CO2 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 CO2 received at the facility, 

the reporter would sum the CO2 amounts from all meters within the field. 

Figure 1-6: Facility Example 6 

In the last example, Figure 1-6, a CO2 generator supplies CO2 to an ER project that it 

operates. The generation facility and ER operation are located 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 are under common ownership and are located 

on the same property and therefore are considered a single facility under subpart RR. The 

CO2 received is the amount passing through the meter at the point of generation in this 

example. A third-party pipeline company that 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. 

15 
 

2. Reporting Threshold Analysis 

To determine the appropriate threshold for reporting, EPA considered a threshold based 

on the amount of CO2 emitted, a threshold based on the amount of CO2 injected, and a 

threshold based on the amount of CO2 received by the facility. EPA concluded that an 

emissions-based threshold would be problematic because of the lack of data on the 

incidence and scale of surface emissions and leakage from facilities that conduct GS and 

all other facilities that inject CO2 underground. EPA also concluded that the amount of 

CO2 injected one year is not a good indicator of the amount of CO2 injected the following 

year, and that injected CO2 may be produced and recycled at some facilities. EPA 

accordingly analyzed injection facilities based on the quantity of CO2 received by the 

facility. 

EPA conducted the threshold analysis based on the quantity of CO2 received at the 

facility (not including CO2 being recycled onsite) and considered whether a threshold on 

CO2 received should apply. EPA evaluated a no threshold option (i.e., all facilities that 

inject CO2 would be required to report), 1,000 metric tons per year, 10,000 metric tons 

per year, 25,000 metric tons per year, and 100,000 metric tons per year of CO2 received 

per facility. Only facilities expected to be operating in 2011, the first year of reporting 

under this proposal, were considered in the analysis. For this analysis it was assumed that 

all of the CO2 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 producers reporting miscible and immiscible CO2 

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.” For projects that were active throughout 2007 

the value represents annual production (12 months). Several of the projects started midyear, or had scheduled downtime in 2007, so the reported annual 2007 production may 

represent only a partial year of production. Production data were not pro-rated to come up 

with an annual estimate. Some projects starting late in the year did not see any increase in 

crude oil production due to 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 the O&GJ. The O&GJ did not specify how the 

production data were to be calculated by the reporting facilities, so most of the data are 

based on internal oil company reporting, which is consistent with state oil and gas 

commission reporting requirements. 

The O&GJ left it up to the companies to define a “project” when they reported data. Most 

projects are defined based on production reporting 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 resource 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 extent. The company reported two “projects” 

separately to the O&GJ even though they are located in the same field, because it appears 

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

16
 
 

 

that they target different producing zones within the same formation. A somewhat 

different situation exists for the Seminole field in West Texas, where several projects are 

listed. These projects are in different geographic locations within the large Seminole 

field, and target different parts of the reservoir (i.e., main oil pay or residual oil) using 

different CO2 injection technologies. These are identified as “pilot tests” in the O&GJ 

data, so the company considers them separate projects for evaluation purposes. 

Depending on how “project” or “facility” is defined, they could be separate or combined. 

The use of CO2 in ER has increased significantly since 2004 (Figure 2-1), and is expected 

to increase further in the next five to 10 years. 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 projects listed for miscible and immiscible CO2 

floods11 reported in the O&GJ survey. The list of active projects represents a wide crosssection of several geologic basins in 10 states, ranging from relatively recent pilot-scale 

projects with one or two injection wells to CO2 floods started in the 1970s with hundreds 

of injection wells. The Wasson Field in the Permian Basin is the largest user of CO2, and 

has six active CO2 ER projects managed by two operators. 

Figure 2-1: Total CO2 used in ER showing growth since 2004. Graph based on data from 

specified anthropogenic and natural CO2 sources. 

Data based on sales. Source: Kinder Morgan CO2 Company, CCS briefing to EPA June 3, 200912 

11 A miscible CO2 flood injects CO2 as a liquid at high pressure to completely mix with oil and make it 

flow more easily. An immiscible CO2 flood uses lower pressures of CO2 to swell the oil and provide 

additional gas pressure to move the oil. 

12 Note that the CO2 being produced by Dakota Gasification Plant in North Dakota is being injected into an 

ER project in Canada. 

17
 
 

 

A total of 105 active ER projects operated by 23 different companies were reported in the 

O&GJ survey. In some cases multiple projects were reported by the same company in an 

oil field, reservoir, or operator unit. For the purposes of this analysis, EPA grouped these 

reported projects by field and by owner or operator to align with the definition of facility 

at 40 CFR 98.6. This computation results in 80 facilities that conduct ER. EPA further 

grouped the fields by their source of CO2 as determined from geographic location, U.S. 

DOE pipeline maps, and operator-published information. As of 2008, four natural sources 

(Jackson Dome, MS; Bravo Dome, NM; Sheep Mountain, CO; and McElmo Dome, CO) 

and five anthropogenic CO2 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 CO2 for ER that is conducted in the United States.13 

The O&GJ survey does not provide the specific volume of CO2 used in each of the active 

ER projects, but does provide the total oil production attributed to the ER process. To 

calculate the estimated volume of CO2 received by each ER project, EPA determined the 

total amount of CO2 used daily for ER based on data from the U.S. EPA 1990–2007 

Inventory of U.S. Greenhouse Gas Emissions and Sinks14 (Inventory). According to the 

Inventory, approximately 2.08 billion cubic feet per day of CO2 from natural and 

anthropogenic sources is received (purchased) for ER. The threshold analysis was 

performed two ways, one based on total daily CO2 received combined for all fields in the 

U.S., and one based on the total from each source of CO2 received for ER (natural or 

anthropogenic). The daily average CO2 production from each source was apportioned 

among the projects supplied by the source based on an average value for the fractional 

production of oil attributed to ER as presented in the O&GJ survey and normalized on an 

annual basis (see Appendix B). The analysis was further complicated because 

anthropogenic gas from the Val Verde Gas Plants is mixed with natural CO2 in the 

pipeline carrying the CO2 to the Permian Basin; therefore the specific projects supplied 

by the Val Verde Gas Plants could not be determined. To accommodate the mixture of 

sources in the Permian Basin, the CO2 from the Val Verde Gas Plants was apportioned 

based on the total crude oil production in the Permian Basin and the known quantities of 

CO2 supplied from natural sources. The CO2 from the Val Verde Gas Plants represents 

approximately 5.39 percent of the CO2 used in Permian Basin Enhanced Recovery 

projects. 

EPA recognizes that this is likely an oversimplification of the actual volume of CO2 

received by each facility, but notes that it follows the principle that higher production is a 

function of higher CO2 injection volumes. The volume of CO2 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/technologies/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 significant 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 CO2 use. Injection well pattern, miscible or immiscible processes, CO2 

saturation target as a percent of hydrocarbon pore volume (HCPV), and use of 

surfactants and additives also influence CO2 use. 

 Project age: The stage of the project is a significant factor in determining CO2 

use. New CO2 floods use more purchased CO2 and produce less oil because 

the CO2 has not fully penetrated the reservoir. It may take 6–12 months to see 

an increase in oil production upon initiation of injection. As the reservoir 

becomes saturated with CO2, the amount of new CO2 added to the project is 

reduced, and the majority of the injected CO2 is recycled from producing 

wells. 

The calculation of CO2 utilization in the threshold analysis presented in this chapter is 

based on the volume of new (purchased) CO2 for ER obtained from the Inventory. The 

value represents the “Net CO2 Utilization” in thousand cubic feet (mcf)/barrel (bbl). 

“Gross CO2 Utilization” is the total amount injected, including purchased and recycled 

CO2. Gross CO2 Utilization was not analyzed in this threshold analysis because the total 

injection data were not available. 

To evaluate the reasonableness of the approach, EPA compared the calculated Net CO2 

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 CO2 Utilization. EPA 

performed this comparison because the age of the project is one of the most significant 

factors in determining Net CO2 Utilization. The threshold analysis evaluated ER projects 

by CO2 source (essentially by producing basin) and resulted in Net CO2 Utilization 

estimates by basin. The results provided support that the estimates of CO2 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 CO2 Utilization (7.2 

mcf/bbl) for this basin. 

15 DOE. 2006. Evaluating the Potential for “Game Changer” Improvements in Oil Recovery Efficiency 

from CO2-Enhanced Oil Recovery, Prepared by Advanced Resources International for DOE NETL, 

February 2006. Available at: 

http://fossil.energy.gov/programs/oilgas/eor/Game_Changer_Oil_Recovery_Efficiency.html. 

19
 
 

	 The Mississippi Interior Salt Basin has the youngest CO2 EOR projects (15 

percent started before 2000) and the Threshold Analysis shows the highest 

Net CO2 Utilization (19.2 mcf/bbl) of any basin. 

Based on the analysis described above, the simplified estimation using productionapportioned CO2 volumes shows a good correlation with independent data and is an 

appropriate estimation of the amount of CO2 received by the facility. 

Analysis of the ER injection data showed five fields with no enhanced production, which 

were correspondingly allocated to no CO2 use. One additional field showed near zero 

production. Two of the six fields reported the projects as having “just started,” and four 

reported projects at the “nearing completion” stage. This demonstrated to EPA that 

injection activity generally follows a curve that can slowly increase in the beginning, as 

the project moves from a pilot test to a larger scale, or slowly decrease toward the end of 

operations. Development of a full-scale CO2 ER project requires extensive testing and 

ramping up over many years. Additionally, EPA determined that some ER production 

operations inject CO2 and water in alternating pulses rather than continuously over years 

to maximize production, and the CO2 injection periods and the corresponding 

(alternating) water injection periods may last from several months to two years or more. 

Therefore, the annual snapshot of data compiled for ER does not necessarily represent the 

typical operating conditions of full-scale projects 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 locations are within oil fields that 

are listed in the O&GJ EOR survey, and inject into oil producing zones, suggesting the 

acid gas is being used for ER and not being injected 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 Dakota, two in the Palo Duro basin of Texas, 

one in the Permian Basin in New Mexico, and one in Utah. These sites generally inject 

the acid gas for disposal into permeable strata below the deepest currently producing oil 

zone. EPA could not find any data to estimate quantity of CO2 received for injection, so 

these facilities are not included in the threshold analysis. 

Table 2-1 shows that nearly all facilities (92.5 percent) received greater than 1,000 metric 

tons of CO2 per year. At a reporting threshold of up to 25,000 metric tons of CO2 

received per year, essentially all CO2 (100 percent) received would be included, but not 

all facilities would report. At a reporting threshold of 25,000 tons of CO2 received per 

year, 65 of the 80 facilities (81 percent) would report. At a 100,000 metric tons of CO2 

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-sequestration/executive-white-papers/ccgs-task-forcephase-i-final-report-2005 

20
 
 

 

 

 

received per year threshold, 97.4 percent of all CO2 used in ER would be reported from 

60 percent of the facilities. The majority of the 40 percent of facilities not covered are 

characterized in the O&GJ Survey as pilot projects, projects that have just started, or 

projects nearing completion. 

Table 2-1: Threshold Analysis Based on Amount of CO2 Received by a Facility 

Threshold 

Level 

(metric 

tons/yr of 

CO2 

received) 

Total 

National 

(metric 

tons/yr of 

CO2 

received) 

Total 

Number of 

U.S. 

Facilities 

Amount of CO2 Received Number of Facilities 

Metric tons/yr 

of CO2 

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 TSD17 were published, a 

new O&GJ survey of ER projects was published. The 2010 O&GJ Worldwide Survey of 

Enhanced Oil Recovery projects was conducted by O&GJ and published on April 19, 

2010 (Volume 108 Issue 14). The data were collected and presented in the same manner 

as the 2008 survey that EPA used in the Threshold Analysis and described in the March 

2010 General TSD. 

The 2010 survey reflects the status of CO2 ER projects at the end of 2009, and shows that 

the popularity of CO2 ER is growing. There was a 14 percent increase in the number of 

fields employing CO2 flooding, a 4 percent increase in the acreage of projects, and a 2 

percent increase in the acreage of the fields. The projects 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 appear to be more successful, producing 14 

percent more oil per project with only a 3–5 percent increase in the number of producing 

and injection wells. This is likely due to the increased volumes of CO2 being used for 

flooding.18
 

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

CO2 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 CO2 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 available 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, producers of natural sources of CO2 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 (CO2 –EOR), U.S. Department 

of Energy, DOE/NETL 2009-1354, January 26, 2009. 

21
 
 

 

production19,20,21 in response to the growing demand for CO2 in new and existing ER 

projects. The 2008 Inventory shows an increase from 2007 of approximately 3 million 

metric tons of CO2 production from natural sources. Additionally, as noted above, the 

volume of CO2 used in each field is increasing, as is the Net CO2 Utilization. 

19 Denbury Resources 2009 Annual Report page 20 shows a 7.2 percent increase in production of CO2 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 CO2 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. 

22
 
3. Monitoring Methods for CO2 Received and CO2 Injected 

This chapter presents monitoring methods for determining the amount of CO2 received 

(subparts RR and UU) and the amount of CO2 injected (subpart RR). 

CO2 is a gas whose volume is typically reported at standard temperature and pressure 

(STP). The behavior of CO2 at low pressure and high temperatures can be satisfactorily 

approximated by the ideal gas law. The ideal gas law is simple to apply in practice, but 

the behavior of CO2 deviates from ideal gas with an increase in pressure or decrease in 

temperature as the assumptions made in deriving the ideal gas equation begin to deviate 

from actual gas behavior. The GHG Reporting Program addresses CO2 equipment leaks, 

vented CO2 emissions, and combustion CO2 emissions as well as CO2 streams, which can 

be at a wide range of temperatures and pressures. In addition, the program also covers 

facilities that conduct GS and all other facilities that inject CO2 underground, which may 

use mixtures of several fluids that predominantly contain CO2. The ideal gas law is only 

applicable to fluids in the gas phase; therefore significant error will occur if it is used to 

calculate densities for liquids and supercritical fluids. 

Measuring CO2 in gas phase should be performed differently from CO2 in the 

supercritical phase. In supercritical phase, CO2 behaves much like a liquid, and other 

gases can dissolve into supercritical-phase CO2. This means the volumetric reading of 

supercritical phase CO2 stream can be misleading if there is any significant amount of 

impurities dissolved in the CO2 stream. The discussion below describes different 

measurement and calculation methods that may be required to accurately measure the 

different phases of CO2. 

3.1	 Determining the Amount of CO2 Received Using Data from Sales, Contracts, 

Invoices, or Manifests Associated with Commercial Transactions 

In order to determine the amount of CO2 received, a facility would measure the flow rate 

of the CO2 at the custody transfer meter at the facility boundary prior to any subsequent 

processing operations at the facility, use flow rate data from the sales contract associated 

with CO2 received from a one-time commercial transaction, use data from invoices or 

manifests for CO2 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 CO2 supplied from a production process that is part of a facility. Also, for commercial 

transactions for which the sales contract specifies a range of CO2 concentration, and if the 

supplier of the CO2 sampled the CO2 stream and measured its concentration per the sales 

contract terms, the reporter can use the average CO2 concentration data from the sales 

contract or the seller’s measured value. 

Information concerning the use of mass or volumetric flow meters for measurement of 

the amount of CO2 received is included below under Chapter 3.2 concerning the use of 

data from sales contracts, invoices, or manifests associated with commercial transactions 

is discussed in this chapter. 

23
 
 

For a one-time commercial transaction between a CO2 supplier and a CO2 recipient (i.e., 

the reporter) there would generally be a sales receipt indicating the amount of CO2 that 

was supplied by the supplier and that was received by the recipient in the commercial 

transaction. 

For an ongoing commercial transaction between a CO2 supplier and a CO2 recipient (i.e., 

the reporter) involving a series of discrete shipments, there would generally be invoices 

or manifests indicating the amount of CO2 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 CO2 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 commercial transactions, the sales receipts, 

invoices, and manifests provided by the CO2 supplier should report the amount of CO2 

supplied (and the amount of CO2 received) in the same physical units (mass units) as are 

required to be reported under the subpart, and 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 CO2 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 transaction is actually tied to a different set of measurement 

units (e.g., volumetric units) the sales receipt, invoice, or manifest should report the 

amount of CO2 supplied in both the units to which the transaction is tied and the units 

that are required to be reported under the subpart. The units of CO2 concentration 

measurements provided by the CO2 supplier in sales contracts used by the reporter to 

determine the CO2 content should also be in the same units as required to be used under 

the subpart, and the methodology used by the CO2 supplier to measure the CO2 

concentration should be consistent with the methodology specified under subpart PP for 

CO2 suppliers. 

For ongoing transactions, the reporter should compare invoices and manifests received 

for CO2 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 CO2 supplied. Unanticipated variation in the amount of CO2 

supplied (and received) between one invoice/manifest period and the next could indicate 

a reporting error on the part of the CO2 supplier, for example. 

3.2	 Determining the Amount of CO2 Received, Injected, or Produced Using Mass 

Flow Meters or Volumetric Flow Meters 

In order to determine the amount of CO2 received, injected, or produced (at ER or other 

fluid production operations), a facility would measure the flow rate using either a mass 

flow meter or a volumetric flow meter. To determine the mass, the facility would either 

multiply the mass flow rate by the concentration of CO2 in that flow or multiply the 

volumetric flow rate at STP by the concentration of CO2 in the flow and by the density of 

24
 
 

CO2 at STP. Either a continuous mass flow meter or a continuous volumetric flow meter 

would most accurately account for the fluctuations over time of flow rate. 

To minimize the error in calculating the mass from CO2 volumetric readings, the 

application of an equation of state22 (EOS) more accurate than the ideal gas law is 

recommended. The EOS proposed by Span and Wagner23 represents the state of science 

in theoretical prediction of gas phase CO2 properties. This EOS predicts density of CO2 

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 same time, the Span and Wagner EOS may be 

too complex to be directly applied by reporters. Therefore, EPA recommends using the 

database of thermodynamic properties developed by the National Institute of Standards 

and Technology (NIST). This online database, available at 

http://webbook.nist.gov/chemistry/fluid/, provides density of CO2 using the Span and 

Wagner EOS at a wide range of temperature and pressures. 

The following generic protocol is recommended to calculate CO2 mass from volumetric 

measurements, with the assumption that the gas stream is predominantly CO2: 

 Obtain volumetric measurements using consensus standards at operating 

conditions; 

 Determine the density of CO2 at operating conditions using the Span and 

Wagner EOS from NIST tables; 

 Calculate the mass of CO2 in the required units by multiplying the density by 

the volumetric measurements of CO2. 

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

CO2. The sample can be analyzed using standards from consensus standards 

organizations for methods such as chromatography or mass spectroscopy to 

identify all chemical constituents and their mass fractions. With knowledge of 

the mass of CO2 calculated, the masses of the other individual species present 

may be evaluated knowing their individual mass fractions in the CO2 stream. 

The density of liquid or supercritical phase24 CO2 depends significantly on process 

conditions as well as mixture composition. Therefore, available theoretical models to 

calculate density of CO2 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 the purpose of measuring the density of CO2 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 1100 K at Pressures up to 800 MPa, J. Phys. Chem. Ref. Data, Vol 25. 24 Supercritical CO2 refers to CO2 with both pressure and temperature greater than their critical values. 

Critical temperature of a gas is the temperature above which the gas cannot be liquefied at any pressure. 

This temperature for CO2 is 88°F. Critical pressure is the pressure required to liquefy the gas at its critical 

temperature. Critical pressure for CO2 is 1072 psi. 

25
 
to calculate density of CO2 in liquid or supercritical state at process conditions or 

conditions at the point of transfer/measurement: 

 Collect a representative sample of liquid or supercritical CO2 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 analytical laboratory for compositional 

analysis. The laboratory may expand the contents in sampling container to 

testing conditions. A sub-sample is analyzed 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 sample and mass fractions. Mass of CO2 

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., CO2 Mass flow rate = CO2 Volume flow rate *(Mass of 

Representative Sample / Volume of Sample Container) * Mass fraction of 

CO2 in the sample. 

It is important to note that the sampling of liquid or supercritical CO2 should be 

performed so the sample represents the process 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 sensitive to temperature difference between the 

empty container and the container with the sample. Care must be taken to minimize such 

error. 

Facilities subject to the UIC program for permitting of injection wells would already have 

flow meters installed to measure the flow rate of the CO2 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 CO2 stream that is CO2, the facility would sample 

the stream and analyze it for its CO2 concentration. EPA has identified three industry 

standards that provide methods to quantify CO2 that may be applicable to CO2 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 CO2, in addition to other gaseous constituents, 

and various hydrocarbons. The method consists of physically separating the gaseous 

26
 
constituents by gas chromatography with a thermal conductivity type detector. 

Procedures are outlined for component concentrations by mathematical procedures and 

using calibration data from a reference standard. The method is applicable to mixtures 

that confirm to component concentrations 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 compositional analysis of demethanized liquid 

hydrocarbon streams that also contain CO2, in addition to nitrogen and various 

hydrocarbons. The method consists of physically separating the liquid mixture 

constituents by gas chromatography having a thermal conductivity type detector. 

Procedures are outlined for component concentrations by mathematical procedures and 

using calibration data from a reference standard. The method is applicable to mixtures 

that confirm to component concentrations 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 CO2 for use in chemical extraction and 

chromatography applications. The guide defines standards for impurities in CO2 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 standards are not specifically designed for the analysis of CO2 

for use in ER or GS applications. The GPA standards note that the methods use gas 

chromatography to separate and identify compositional characteristics of the constituents 

of the gas/liquid mixtures; however, they are recommended and applied for mixtures with 

a relatively low concentration of CO2 (less than 20.0 mol percent in the case of GPA 

Standard 2261-00, and less than 5.0 mol percent in the case of GPA Standard 2177-03). 

Typical applications of CO2 for ER or sequestration may have CO2 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 CO2 streams, but the 

reporter should evaluate the suitability of these methods if they are used. 

Using the operating temperature and pressure, the volume of CO2 can be converted into 

STP conditions and, using a STP density value for CO2, from the NIST online database 

(0.0018682 grams per milliliter or 0.11663 lb/ft3

) one can calculate the CO2 quantity in 

metric tons. A facility would apply the same method in order to calculate the quantity in 

metric tons of CO2 received. 

Measurements of CO2 volume may be taken at actual pressure and temperature 

conditions and may therefore need to be converted to STP conditions for the purposes of 

reporting under subpart RR. If the CO2 is not in a liquid or supercritical state the reporter 

may apply the Ideal Gas Law to convert measurements at actual temperature and pressure 

conditions to STP conditions. Standard Temperature is defined in the Rule as 60 degrees 

Fahrenheit. Standard Pressure is defined in the Rule as 1.0 atmosphere. 

27
 
For example, if a CO2 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 measurement to the volume of CO2 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: 

P1 x V1 / T1 = P2 x V2 / T2 

Where: 

P1 = Actual pressure 

T1 = Actual temperature 

V1 = Actual volume 

P2 = Standard pressure 

T2 = Standard Temperature 

V2 = Volume at Standard Conditions 

For the example of a measurement of 1,000 cubic feet of CO2 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: 

T1 = Actual Temperature = 300 + 459.67 = 759.67 Deg R 

P1 = Actual Pressure = 1.1 atmosphere 

T2 = Standard Temperature = 60 + 459.67 = 519.67 Deg R 

P2 = Standard Pressure = 1.0 atmosphere 

V1 = Actual Volume = 1,000 cubic feet 

The equation P1 x V1 / T1 = P2 x V2 / T2 would then be solved for the variable V2. 

V2 = (P1 x V1 / T1) / (P2 / T2) 

28
 
 

 

 

 

V2 = [(1.1 atm) x (1,000 ft3) / (759.67 Deg R)] / [(1.0 atm) / (519.67 Deg R)] 

Therefore: 

V2 = 752.48 cubic feet at standard temperature (60 degrees F) and pressure (1.0 atm) 

For CO2 that is in a supercritical state, the Ideal Gas Law is not applicable and therefore a 

different equation of state is needed to calculate the volume of the CO2 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 CO2 at actual temperature and pressure conditions. 

For example, for supercritical CO2 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/in2) the NIST Thermophysical Properties database shows the 

density of the supercritical CO2 to be 18.614 lb/ft3

. 

Temperature 

(F) 

Pressure 

(atm) 

Density 

(lbm/ft3) 

State 

140 100 18.614 supercritical 

At the standard temperature of 60 degrees Fahrenheit and standard pressure of 1.0 

atmosphere, the density of CO2 is 0.11663 lb/ft3. 

So if a volume of 1000 ft3 of supercritical CO2 was measured at actual pressure and 

temperature conditions of 100 atmospheres and 140 degrees Fahrenheit, that volume of 

CO2 would be equivalent to: 1000 ft3 x 18.614 lb/ft3 = 18,614 lb of CO2. 

The density of CO2 is 0.11663 lb/ft3

 at STP. Therefore, 18,614 lb of CO2 at a density of 

0.11663 lb/ft3

 = 18,614 lb / 0.11663 lb/ft3 = 159,598.7 ft3 CO2 at STP. 

Therefore, the volume of the 1,000 ft3

 of CO2 at actual conditions would be reported as 

159,598.7 ft3 CO2 under standard conditions. 

29 
 

 

4.	 Overview of Monitoring Technologies for CO2 Leakage Detection and 

Quantification 

This chapter describes technologies for monitoring of the injection well, subsurface CO2 

plume, vadose zone25, soil zone and vegetation, and atmosphere and how they may be 

applied to detect and quantify movement of CO2 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 Technologies as of June 2009. Joint Global Change 

Research Institute. Pacific Northwest National Laboratory. June 2009. PNNL-18520) 

While technologies for quantifying CO2 surface leakage from GS sites are continuously 

being refined, it is generally recognized that, when properly planned and implemented, 

monitoring methods will be effective at detecting surface leakages.27, 28 A wide range of 

25 The vadose zone is the relatively shallow zone beneath 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/onepetropreview?id=SPE-102833-MS&soc=SPE (at cost). 28 FutureGen Alliance. 2006. Mattoon Site Environnemental Information Volume. December, 2006. 

http://www.futuregenalliance.org/. 

30
 
 

 

techniques for monitoring GS have been used at GS sites as well as for a number of years 

in other applications, including oil and gas production, ER, and plant and soil science. 

These techniques may be used at a GS site to monitor the injected CO2, the surrounding 

rocks and fluids, wells and equipment, and the surface conditions. EPA has concluded 

that a GS facility would be able to propose a site-specific monitoring, reporting, and 

verification (MRV) plan for leak detection and quantification based on the current 

availability of monitoring technologies. In addition, it is expected that site 

characterization and screening will lead to selection of sites that are suitable for longterm sequestration, and that incidences of leaks 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 nature of the injected CO2. 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 cement 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 the wellbore, the injected CO2 can make its way vertically to 

access shallow formations, and possibly escape to the surface. External MIT is a reliable 

and effective method commonly carried out using 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 recording the log response continuously as the 

tool is pulled upward. This generates a detailed picture of the borehole 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 the casing and cement, and between 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/groundwater/uic/wells_sequestration.cfm. 30 Koplos, Jonathan, B. Kobelski, A. Karimjee, C.H. Sham. 2006, UIC Program 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. Technologies for Measuring Well Integrity in a CO2 Field.
 

Sixth Annual Conference on Carbon Capture and Sequestration. DOE/NETL, May 2007. Available at: 

http://www.netl.doe.gov/publications/proceedings/07/carbon-seq/data/papers/tue_064.pdf. 

31
 
 

 

 

 

formations, while the noise log detects the sound of CO2 flow behind the pipe. To some 

extent, the log response might be used as a qualitative measure of the amount of leakage. 

Other external integrity tests 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 integrity of the well materials: the tubing, 

packers, and long string casing. During injection operations, there can be continuous 

monitoring of the annulus fluid pressure, which is typically maintained at a higher 

pressure than that of the injected CO2. A drop in the annulus pressure may indicate cracks 

or holes in the long string casing, or may also indicate a leak in the tubing or packers. 

This would not necessarily be an indication of a CO2 leak to the atmosphere. In addition 

to continuous pressure monitoring in the annulus, internal well damage can be monitored 

with periodic wireline logs, including caliper tools, radioactive tracer tests, and downhole 

video. Logs can detect corroded or damaged tubing or casing even before a leak occurs. 

All of these methods are commonly used in the oil and gas industry. 

In certain circumstances, new technologies allow well logging to be conducted while 

drilling using small, sophisticated tools. 

4.2 Monitoring of Subsurface CO2 Plume 

The location and size (areal extent) of the injected CO2 plume can be evaluated using 

several approaches. These include the acquisition of active seismic data, passive seismic 

data, gravity data, and information from monitoring wells. This information can be used 

in concert with reservoir modeling to predict subsurface CO2 plume movement. Please 

refer to the UIC program Web site for information on requirements related to tracking 

and monitoring the CO2 plume.33 

The active seismic geophysical technique involves the generation of sound waves that 

propagate downward or laterally through the subsurface, are reflected 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 spatial 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) CO2. In 

conventional active seismic, both sound sources and detectors are located on the surface. 

In vertical seismic profiling, the source is on the surface and the detector is downhole. In 

another arrangement called cross-well seismic, both source and detector are downhole in 

different wells. Periodic acquisition of active seismic data can in some cases be used to 

detect subsurface CO2 movement within and outside of the injection zone (IZ). This may 

include leakage from or around the injection 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 CO2 Stored in Deep 

Geologic Formations. U.S. Department of Energy, National Energy Technology Laboratory. Available at: 

http://www.netl.doe.gov/technologies/carbon_seq/refshelf/MVA_Document.pdf. 33 http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

32
 
 

A variety of active seismic methods are in use today in the oil and gas industry, and can 

be used for CO2 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 arrangement of receivers. The acoustic energy source is from small 

explosive charges or from “vibro-seis” trucks. 3-D seismic may provide better resolution, 

accuracy, and tracking of the CO2 if it migrates from the storage reservoir into the 

overburden. 3-D seismic evaluates a large volume of the subsurface, has high resolution, 

and is more complex and more costly to obtain and analyze. Surface receivers are laid in 

a grid pattern, and large amounts of data are simultaneously recorded and subsequently 

processed. Sophisticated software allows the conversion of this raw information into a 

detailed subsurface representation. 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 immediate vicinity of the well.34 It is a high-resolution method that 

evaluates a small volume of the subsurface adjacent to a single well. A variation of 

vertical seismic profiling is “walk-away” 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 injector 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 CO2 plume under very controlled conditions. This 

calibration can then be used to better interpret 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 

CO2 plume under certain subsurface conditions. These methods are known to be effective 

in many cases where CO2 is injected into a saline reservoir and has a good density 

contrast with the saline fluid. The ability to image and track a CO2 plume depends upon 

factors such as lithology (sandstone, limestone, coal, or shale), porosity (pore space), - - fluid content, and depth. ) 35 Seismic detection of a CO2 plume in a carbonate (CO3 

(limestone or dolomite) reservoir may be a challenge due to low porosity and other 

factors. Seismic detection of CO2 in a depleted oil reservoir may be more challenging 

than monitoring a saline reservoir due to lower average fluid density contrast (both oil 

34 DOE/NETL. 2009. Best Practices for Monitoring, Verification, and Accounting for CO2 Stored in Deep
 

Geologic Formations. U.S. Department of Energy, National Energy Technology Laboratory. Available at: 

http://www.netl.doe.gov/technologies/carbon_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. 

33
 
 

 

and free-phase CO2 are less dense than saline water). Studies have been undertaken to 

evaluate seismic plume monitoring in coal beds.36 

Active seismic methods including 2-D, 3-D/4-D, and cross-well seismic can achieve high 

plume detection resolution, and therefore can be used to develop a first-order estimate of 

plume dimensions for leakage quantification; a drawback is that seismic methods only 

image free-phase CO2 in the reservoir and not the dissolved CO2 component. In addition, 

the amplitude of the seismic signal (which is used to detect the CO2) is only partially 

related to the concentration and therefore cannot fully quantify even the free-phase part 

of the CO2. However, amplitude anomalies have been observed in CO2 sequestration 

monitoring that have been related to CO2 concentration. Such amplitude effects have 

been observed at the Sleipner and Weyburn projects.37 To be detectable, the CO2 

accumulation must have lateral and vertical dimensions sufficient to produce a 

discernible seismic response. One study based on theoretical resolution considerations38 

has suggested that CO2 buildups as small as 10,000 to 20,000 metric tons may be 

detectable at typical injection 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 than 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 Sleipner, Weyburn and Frio, accumulations on the 

order of 1,000 to 10,000 metric tons of CO2 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-pressure injection sites with sophisticated 

instrumentation and decipher the results using computational methods. As the pressurized 

CO2 moves through the reservoir, it creates microfractures that release acoustic energy 

that is detected in 3-D space. Passive seismic methods can be used to track the subsurface 

plume and the areas of high pressure. They can also be used to detect where fractures are 

occurring that might signal breaks 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 CO2
 

Sequestration Pilot – Red Deer, Alberta. CREWES Research Report 14. Available at: 

http://www.crewes.org/ForOurSponsors/ResearchReports/2002/2002-64.pdf. 37 DOE. 2009. Best Practices for Monitoring, Verification, and Accounting for CO2 Stored in Deep
 

Geologic Formations. U.S. Department of Energy, National Energy Technology Laboratory. Available at: 

http://www.netl.doe.gov/technologies/carbon_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. 

34
 
 

 

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

Because CO2 is usually less dense than native fluids and petroleum, reservoirs that fill 

with CO2 will appear as lower gravity areas. Gravity 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 influences from the data set prior to creating a 

model of the gravity field. Studies at Sleipner site indicate the method shows promise to 

help constrain the reservoir simulation models40. This technology is still 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 CO2. Certain wireline tools may be used to 

collect a fluid sample under reservoir pressure and temperature conditions, and retrieve 

the sample to the surface for laboratory analysis.41 They can also be used for cross-well 

seismic data acquisition, in which seismic signals are broadcast from one well and 

detected in an adjacent well to characterize the formation between the wells. Monitoring 

wells can be designed to allow testing of the CO2 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 inorganic carbon (DIC) can be determined using 

complex algorithms. DIC includes aqueous CO2, carbonic acid (H2CO3), bicarbonate 

(HCO3

-

), and CO3

- -. CO2 leakage from the reservoir can be detected long before the CO2 

can escape to shallower zones or to the surface. 

Geochemical sampling of the fluid from monitoring wells can also be used to detect 

natural or artificial “tracers” in the injected CO2. Monitoring to gather additional data 

may be necessary if the instrumentation indicates 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 surface. As with the deeper wells, downhole 

instruments can measure pressure, temperature, and conductivity/salinity. Further 

monitoring may be implemented when readings depart from background levels; for 

example, a 3-D seismic survey may be undertaken if the anomaly is within an appropriate 

depth range. 

Surface deformation monitoring is currently being tested as a rapid cost effective method 

to identify plume movement and potential leakage pathways in the subsurface. As CO2 is 

injected the ground surface may be raised a minute amount in response to the addition of 

fluids to the subsurface. Highly sensitive tiltmeters (much like a highly sensitive 

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

CO2 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. 

35
 
 

 

 

electronic carpenters level) and Differential Global Positioning Systems can be used to 

measure ground movements over small areas, and specialized radar (Interferometric 

Synthetic Aperture Radar (InSAR)) can be used 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) with accuracy in the millimeter range.42 When 

combined with tiltmeter and global positioning system (GPS) data, accuracy and 

resolution can be improved. Surface deformation at In Salah was monitored using InSAR 

from 2003 to 200843 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 infer underground pressure gradients and fluid 

movements from the changes in surface deformation over time. Surface deformation 

surveys are influenced by vegetation, frost heaves 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, monitoring in this zone therefore is limited to 

testing the chemistry of the gases contained within the pore space. The CO2 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 CO2 (or other gases) in the sample. 

Background levels must first be measured to determine the statistical variations of CO2 

concentration accounting for sample temperature, seasonal variations, diurnal variations, 

and the like. Later, a presumptive leak is detected if the monitored CO2 concentration 

exceeds a value corresponding to a very high (e.g., exceeds the 99 percentile) prediction 

for the natural CO2 concentration accounting for sample temperature, seasonal variations, 

diurnal variations, etc. Should significant anomalies be detected, an expanded soil or 

atmospheric testing program may provide additional information. In addition to the use of 

IRGAs for CO2 concentration, vadose zone sampling can include testing for tracers, 

should they be used, and for sampling for carbon and oxygen isotopes, to determine 

whether the CO2 is that which is being injected or naturally occurring CO2.

44 As with 

data collected in monitoring wells, these individual measurements are quite reliable and 

accurate, but their limitation is that they represent a single point in 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 uppermost layer of the vadose zone. The soil zone is the fertile 

42 McColpin, L. 2009. Surface Deformation Monitoring 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 CO2 injection by 

D InSAR at In Salah, Algeria Energy Procedia, 1, (2009) pp. 2177-2184

44 FutureGen Alliance. 2006. Mattoon Site Environmental Information Volume. Available at: 

http://www.futuregenalliance.org/news/fg_mattoon_eiv_v1_master_rev1.pdf 

36
 
 

portion that can retain water (i.e., topsoil). A monitoring program in the soil zone can 

detect the vertical CO2 flux. It is especially important in the soil zone that background 

levels (which vary with time of day and season) be determined to provide a wellcharacterized baseline against which statistically significant anomalies can be detected 

and estimated. 

Accumulation chambers can be used to estimate CO2 flux from the ground surface to the 

atmosphere, and be used to directly detect and quantify the mass of CO2 leaking from the 

subsurface.44 The approach may consist of a grid of accumulation chambers in which the 

CO2 flux is periodically measured.45 Commercially available accumulation chamber 

instrument packages are currently being used to track seasonal variations in CO2 flux as 

part of climate change studies. The accumulation chamber is a method of measuring soil 

CO2 flux that involves the placement of a collection chamber directly on or into the soil 

surface, with the rate of CO2 accumulation measured periodically with an IRGA. The rate 

of change in CO2 concentration defines the rate of flux. The calculated rate of flux can be 

used as a standalone quantification method if CO2 leakage is detected. This type of 

measurement could be used to quantify leakage that is moving up through the soil zone 

across a wide area, as opposed to point sources such as a leaking injection well. To 

account for local variations in the underlying geologic, soil characteristics, and soil 

moisture levels, several accumulation chambers would have to be distributed over the 

area to quantify the leakage rate. CO2 flux measurement systems based on accumulation 

chambers are commercially available and can provide a measurement of anomalous CO2 

flux at a point, with a precision better than 5 micrograms per square meter per second. 

That point measurement precision corresponds to a leak rate of 25,000 metric tons per 

year distributed across an area of 150 square kilometers. 

Surface leaks detected in the soil zone may also be quantified through tenting methods, in 

which large tents (made of impermeable material) are used to capture and accurately 

measure the CO2 leakage from a much larger soil surface area. Tenting methods have 

been used to detect CH4 leaks from natural gas pipelines and could also be used for CO2 

quantification. Variations of this method are commonly used in measuring CH4 flow rates 

from equipment leaks.46 A tent or bag is constructed 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 sample is obtained from the bag and the CH4 content 

of the sample is determined. The leak flow rate is calculated from the purge flow rate 

through the enclosure and the concentration of CH4 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. 2003. 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/servlets/purl/840984­

dTw752/native/840984.pdf. 46 Envirotech Engineering. 2007. Review and Update of Methods Used for Air Emissions Leak Detection 

and Quantification. February 5th, 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 

37
 
 

 

 

 

 

Table 4-2: Example Leak Quantification Using Tenting and Known Test Gas Flow47 

Inlet Flow of Conveyed 

Test Gas 

(cu. ft./minute) 

Measured CO2 

Concentration at Outlet 

(%) 

Calculated Outlet 

Flow Rate 

(cu. ft./minute) 

Calculated CO2 

Leak Rate 

(cu. ft./minute) 

10 50% 20 10 

10 10% 11.1 1.1 

This approach is limited to sampling a point source or small area of leakage. However, if 

the site of the leakage can be mapped by airborne methods such as are described below, it 

should be possible to set up a number of tent measurement locations such that the leaks 

over a large area can be quantified using statistical sampling. However, the cost and time 

to 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). 

CO2 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 CO2. Some indicator parameters such as 

pH, alkalinity, electrical conductance and dissolved oxygen can be measured in the field, 

and other parameters (trace metals, dissolved organic carbon, organic compounds and 

isotopes) are submitted to a laboratory for analysis. Pilot tests and controlled release 

experiments demonstrate that the rapid and significant changes in chemical parameters 

were observed in response to the presence of CO2.

48 As with soil testing, background 

levels must first be established in order to detect changes that may indicate CO2 leakage. 

Vegetative stress can also be a leakage indicator. Vegetative stress can be detected 

through tower-mounted or airborne imaging instruments, such as digital color infrared 

orthoimagery or hyperspectral and multispectral imaging, to detect changes to vegetation 

coloration in the visible, infrared, and ultraviolet spectrum. These are relatively new 

technologies with uncertainty in the interpretation of the results. Recent work has shown 

that vegetation in the vicinity of a leak may 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 CO2 leakage hot spots could be delineated to within 2.5 meters using 

portable hyperspectral imagers. The plant response was dependent on plant species but 

was discernable when soil concentrations reached 4 to 8 percent CO2 concentration.50 

47 The Calculated Outlet Flow Rate (cu. ft./minute) is inlet flow volume divided by concentration. The 

Calculated CO2 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 CO2 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 CO2 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 CO2 sequestration
 

38
 
 

 

4.5 Atmospheric Monitoring 

The atmosphere above a GS site may be monitored with an array of CO2 detectors 

(closed-path point measurements and open-path line measurements), tracer gas and CO2 

isotopic measurements, eddy covariance methods, Raman LIDAR (Light Detection and 

Ranging), or Differential Absorption LIDAR (DIAL). In all methods, CO2 concentration 

data are integrated with data on wind speed and direction to determine the vertical CO2 

flux and locate the CO2 leakage footprint. As noted previously, establishing baselines are 

important to distinguish between natural CO2 fluxes and CO2 flux due to leakage from 

geologic storage.51 

CO2 detectors are commercially available for short 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 

CH4 leaks in areas with road access. While these packages have not been widely tested 

for CO2, various types of CO2 monitors are commercially available, generally relatively 

low cost, reliable, and could be used in these applications. The technologies include 

IRGAs (including Fourier transform infrared (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 concentration, and, when packaged with 

measurements of wind speed and wind direction, they measure the total gas flow. The 

method is described in detail in EPA Other Test Method 10 —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 locating the source of emissions or hot 

spots); 

 Vertical radial plume mapping (for estimating the rate of gaseous emissions 

from an area fugitive emission source); and 

 One-dimensional radial plume mapping (for 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 CO2 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 these systems for methane leak detection, in which 

the detectors are integrated onto ground or airborne 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 quantification approaches 

include tracer gases and CO2 isotopic measurements. The incorporation of trace 

amounts of chemical compounds into the injected CO2 may be useful in circumstances in 

which a suitable baseline for a natural parameter (e.g., soil CO2 flux or surface-toatmosphere CO2 flux) cannot be established due to the parameter’s wide and 

unpredictable natural variation. In such cases, tracers could be added to the injected CO2 

and continuous or periodic monitoring could 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 helium (He), argon (Ar), and xenon (Xe), including 

specific isotope concentrations. Tracers can be detected at levels of a few parts per billion 

or even parts per trillion. 

PFC tracers have been applied in several pilot studies and experimental tests and appear 

to have good detection capabilities for leakage detection and potentially for quantification 

in both soil gas53 and the atmosphere.54 The CO2 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 within 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 CO2 plume56 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 pilot 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 assess leakage from the sequestration of CO2 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/science/article/B6VDG-4N3GFGS3/2/f16a133a1eda34353e1cbcc8dd05c917. 56 McCallum, S.D., Riestenberg, D.E., Cole, D.R., Freifeld, B.M.,Trautz, R.C., Hovorka, S.D., and Phelps, 

T.J. 2005. Monitoring Geologically Sequestered CO2 during the Frio Brine Pilot Tests Using 

Perfluorocarbon Tracers. Fourth Annual Conference on Carbon Capture and Sequestration, 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 (CO2/H2S) into a Devonian Pinnacle Reef at Zama, Alberta, for 

40
 
 

 

The amount of tracer added to the injected CO2 will depend on the minimum detectable 

amount within the medium to be monitored and the probable leakage volumes and 

dispersion patterns for the relevant leakage pathways. It also depends on how the tracers 

will move along the leakage pathway relative to the leaking CO2. Therefore, if tracers are 

proposed to be used, the monitoring strategy should consider the proposed tracers 

characteristics in terms of: 

 dissolution in water more/less than CO2; 

 sorption into coals/shales more/less than CO2; 

 chemical reactions with fluids and rocks; and 

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

In some cases, tracers can move more quickly than the CO2 and will reach sensors or 

sample collection points well before any CO2 leak. In other instances a tracer might be 

trapped along the leakage pathway, reducing its effectiveness. Certain tracers are GHGs 

and if leaked, would contribute to total GHG emissions. 

Another consideration for tracers is the possibility of contamination 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 surface 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 tracers through careful design of where and how 

tracers are injected and how equipment and fluids 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 contaminated locations (e.g., from surface 

to subsurface); 

 changing type of tracer used; and 

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

Alternatively, CO2 isotopic measurements are able to distinguish between CO2 derived 

from fossil fuels and naturally occurring atmospheric and underground CO2. Researchers 

in Australia note that even relatively large leaks at the well could dissipate rapidly away 

from the source and be indistinguishable from background concentrations of CO2. They 

suggest that the use of radioactive 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. 

41
 
 

sequestered fluids will improve detection sensitivity. 58 Field studies of carbon ratios in 

injected and recovered CO2 have been conducted at Weyburn-Midale CO2 Monitoring 

and Storage Project (Saskatchewan), the Pembina Cardium CO2 Monitoring Project 

(Alberta), and the Lost Hills oil field (California). Recently a commercially available 

carbon isotope instrument was modified for portable use and deployed during the 

controlled release field tests at the ZERT site in Bozeman Montana.59 The advantage of 

the technique is that it provides essentially real time results of the carbon isotope 

concentrations across a potential leak location. The results 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 CO2 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 instantaneous wind speed and direction. Time 

series data are recorded and evaluated using computer methods. The size and shape of the 

sampling footprint (the surface area that is sampled by the instrument) is derived 

mathematically from the anemometer data. A typical station consists of sensors mounted 

on a tower from several meters to 30 meters or more high. The stations can be operated 

with solar power and can be set up for data telemetry for transmission to a central facility. 

Deployment of a grid of such detectors over an area provides information regardless of 

wind direction. CO2 concentration data are integrated with meteorological data including 

wind speed and direction, relative humidity, and temperature. 

Such methods have the ability to measure CO2 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. Variations in plant cover, land use, and 

topography may create challenges. As with soil sampling, the rate of leakage of CO2 from 

the site must be a statistically significant anomaly above the background variability. 

Therefore, to provide the required precision, eddy covariance towers would have to 

collect data over an appropriate time period to provide a baseline which includes diurnal 

and seasonal variations. With careful installation and the collection of baseline data, the 

eddy covariance method can potentially provide a precise average of CO2 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 CO2 flux averaged over a large surface 

area, with an precision less than 50 micrograms 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 CO2 Measurements via WS-CRDS-based Analyzers: Investigations in Real 

Time Monitoring at CO2 Geological Storage Sites. Presented at American Geophysical Union, Fall 

Meeting 2008, abstract #U41C-0024, poster available at: 

http://www.picarro.com/assets/docs/AGU_poster_sequestration.pdf

59 Krevor, S., Perrin, J.-C., Esposito, A., Rella, C., Benson, S., 2010. Rapid detection and characterization 

of surface CO2 leakage through the real-time measurement of [delta]13 C signatures in CO2 flux from the 

ground. International Journal of Greenhouse Gas Control 4, 811-815. 

42
 
 

 

corresponds to a leak rate of 25,000 metric tons per year distributed across an area of 17 

square kilometers. 

Another potential technology for measurement of CO2 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 CO2. 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 interaction with the target scattering molecules 

(e.g., CO2) along the resolved path length. By comparing the Raman signal of the CO2 to 

the Raman signal of nitrogen or oxygen, a direct measurement of CO2 concentration can 

be obtained. 

A similar method, DIAL, would use two wavelengths of laser light to measure the CO2 

concentration in the atmosphere. The wavelengths used are specific to CO2. One 

wavelength is selected to correspond to a CO2 spectral absorption line, while the other is 

a non-absorbing wavelength. The average CO2 concentration over the path length can be 

determined from the ratio of the backscatter signals for the two laser wavelengths. The 

instrumentation for both methods (Raman LIDAR and DIAL) can be ground, truck, 

helicopter, or airplane mounted and can provide similar precision at similar cost. Truck 

methods can cover up to tens of square kilometers per day. Helicopter and airplane 

mounted platforms can cover a much larger area. 

Airborne DIAL methods are currently in use 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 system. 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 measures the concentration of methane by 

measuring how much of the reflected laser pulse has been absorbed. These data could be 

integrated with real time wind direction and velocity to define the leakage footprint and 

estimate a leakage rate. 

While DIAL is commercially available for methane, Raman LIDAR and DIAL are 

currently under development for commercial CO2 applications. Etheridge61 reports that 

ground-based and airborne LIDAR and DIAL technologies appear to be feasible 

technologies when used in conjunction with other sources of information, however 

additional research is needed to improve precision for measuring and monitoring leaks at 

geosequestration sites. Researchers at Montana 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 Annual 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, Trudinger, C, Allison, C, Fraser, 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 Publication Number RPT05-0134. 83pp. Available at: 

http://www.co2crc.com.au/publications/index.php. 

43
 
 

 

 

 

 

resolution 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 area, and ground methods (such as accumulation 

chambers and tents) could be installed on the surface leakage area to measure the 

combined background and anomaly CO2 flux and outside the surface leakage area to 

measure just the background CO2 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 CO2 entering the 

ocean from an offshore geologic formation is dependent on the temperature, pressure, and 

CO2 flux, and may result in the formation of CO2 hydrates, may dissolve into the 

seawater, or may be released into the atmosphere. Shallow monitoring systems aim to 

detect and quantify CO2 that has migrated into the shallow sediments and related water 

bearing strata or seabed, and, ultimately, into the seawater or atmosphere. Shallow 

monitoring includes those methods that detect and measure CO2 in the subsurface (e.g., 

potable aquifers, soil, sub-seabed) and those that actually measure CO2 in the water 

column or atmosphere. 63 

Sparker surveys detect reflections of acoustic signals produced from electro-capacitive 

sources that penetrate several hundred meters beneath the seafloor. Boomer surveys 

detect reflections of acoustic signals produced from electromagnetic (EM) sources that 

penetrate about 100 meters beneath the seafloor. 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 detected 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 Intensity 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 map glacial and other sedimentary deposits in 

shallow water. These techniques are potentially very useful for shallow storage 

monitoring. They offer high-resolution profiling 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/factsheets/project/Project642.pdf 63 Cleaner Fossil Fuels Programme, 2005. Monitoring Technologies for the Geological Storage of CO2. 

Technology Status Report, DTI/Pub URN 05/1032, Didcot, Oxfordshire, UK, March 2005. Available at: 

http://www.co2net.eu/public/reports/tsr025abc.pdf. 

44
 
 

 

 

 

 

zones 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 CO2 leakage. Two principal 

types are available: sidescan sonar using piezoelectric transducers mounted on towfish,64 

and multibeam echo sounding using magneto-restrictive transducers from ships. 

Multibeam echo sounders integrate bathymetric and backscatter information and can 

provide a highly efficient way of obtaining very 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 either side of a ship collecting echoes from 

the entire swath width as the ship advances. The fan is narrow in the fore and aft 

direction, typically 1.5 degrees, and wide in the port and starboard direction—around 120 

degrees. For each beam, the system reports depth and 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 utilize 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. CO2 is resistive, so electrical/EM 

methods are likely to be suitable for monitoring storage in saline formations where CO2 is 

displacing more conductive formation waters. Placing the electrical sources or receivers 

(or both) in the subsurface, within or around the storage reservoir, radically increases 

spatial resolution while reducing power requirements. Downhole configurations seem to 

offer the greatest potential for useful offshore application. 

Recent developments of sea floor EM systems, previously used (typically) for deep-water 

tectonic studies, have led to “direct-detection-of-hydrocarbons” systems. Two of the most 

advanced systems are referred to as SeaBed Logging65 and Offshore Hydrocarbon 

Mapping66. The systems consist of towed Controlled Source transmitters and static seabed receiver arrays. The source is a horizontal electric dipole, towed behind an 

64 A towfish is an underwater equipment package towed 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 European Region. Search and Discovery Article #40277 

(2008) Posted January 31, 2008. Available at: 

http://www.searchanddiscovery.net/documents/2008/08008ridyard/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.
 

45
 
 

instrumented towfish on a neutral buoyant streamer. 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 and several kilometers. Recent surveys have 

successfully determined the presence and absence of hydrocarbons within reservoirs. 

Direct detection of resistive CO2 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 global carbon budgets and the relative size and directions of 

carbon (mainly CO2) fluxes between the sea, the atmosphere and the sediment. These 

technologies are relatively well tested and are deployed extensively across the world, 

often routinely on ships regularly crossing oceans. A sensitive pH sensor for marine 

studies has recently been developed in the United Kingdom and would be useful to 

monitor changes in seawater pH resulting from CO2 leaks. Four parameters are typically 

measured that, together with ancillary information such as temperature, pH, and salinity 

etc., can be used to describe the CO2 system in a given sample. These parameters are: - total DIC (a measure of the concentrations of CO2 (aq), H2CO3 (aq), HCO3 and CO3 

2-), 

total alkalinity (a form of mass-conservation relationship for the hydrogen ion), fugacity 

of CO2 in equilibrium with seawater (a measure of the partial pressure of CO2), and total 

hydrogen ion, primarily controlled by total sulfate concentration. 

Seawater samples obtained at depth, which are more appropriate to the needs of 

monitoring for CO2 escape, require the pressure to be maintained in order to ensure that 

degassing does not occur. One such gas-tight sampling device has been developed to 

obtain fluids samples (both waters and gases) at elevated temperatures and pressures. A 

key feature is that fluid within the chamber is maintained at seafloor pressures during 

sampling, allowing fluid aliquots to be withdrawn for an 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 above involves the application of technologies 

to detect and quantify CO2 leakage. Monitoring is effective in detecting the presence of 

both subsurface and atmospheric leakage. Methods of surface leak quantification 

continue to be an active 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 location, the atmospheric background CO2 variability, the 

number and distribution of sampling stations, and the limits of the technology itself. Each 

technology typically has strengths and weaknesses, and only a combination of approaches 

is expected to ensure reliable monitoring and leak detection. 

To evaluate the capabilities of monitoring technologies, one must look at the theoretical 

limits of CO2 detection, the size of anomaly that can be detected, and the precision and 

46
 
 

 

accuracy 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 CO2 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 measured 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 

CO2. 

Eddy 

Covariance 

1, 2, 4 Continuous >10 

microgram 

/ m2

/ sec 

>45 

microgram/s 

q. m/sec 

5 - 30% of 

the CO2 flux 

NA Commerciall 

y available 

technology 

used in other 

fields; signal 

to noise 

challenges 

CO2 

Detectors 

(closed path 

and open 

path) 

2 1 - 10 Hz 

during 

sampling 

0 - 3,000 

ppmv 

NA 0.2 ppm at 

350 ppm 

CO2 

concentratio 

n 

NA Established 

technology; 

Portable and 

inexpensive. 

Accumulatio 

n Chamber 

2, 3, 4 Continuous >0.46 

microgram 

s/ m2

/ sec 

NA 10% of the 

CO2 flux 

12.5% of 

the CO2 

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, 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. 69 IPCC. 2006. 2006 IPCC Guidelines for Greenhouse Gas 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 CO2 Stored in Deep
 

Geologic Formations. U.S. Department of Energy, National Energy Technology Laboratory. Available at: 

http://www.netl.doe.gov/technologies/carbon_seq/refshelf/MVA_Document.pdf. 

47
 
 

 

Many 

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 % 

CO2 

NA 1 - 5% of the 

CO2 

concentratio 

n 

NA Technology 

available for 

methane; 

CO2 

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 CO2 Stored in Deep 

Geologic Formations. U.S. Department of Energy, National Energy Technology Laboratory. Available at: 

http://www.netl.doe.gov/technologies/carbon_seq/refshelf/MVA_Document.pdf. 

48
 
5. Monitoring, Reporting, and Verification Plans 

Facilities conducting GS are required to develop 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 monitoring 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 CO2 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 meets the regulatory requirements. Examples are 

provided throughout the chapter to illustrate how these requirements may be addressed 

under different scenarios. 

In the MRV plan, the reporter should show that 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 demonstration that the statistical basis of the 

monitoring strategy or the quantification method meets a certain level of performance. In 

some cases the MRV plan may not include specific details of implementation because 

there are many site-specific or event-specific factors 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 process and tools used to detect and quantify the potential 

leaks. The reporter should provide 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, environmental, 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 uncertainties and inherent variability in the 

natural systems will necessitate modifications to the selected methods and approaches 

over time and in response to unexpected events. 

49
 
 

The site-specific approach also allows the reporter to leverage the site characterization, 

modeling, and monitoring approaches (e.g. monitoring of injection pressures, injection 

well integrity, groundwater quality and geochemistry, and CO2 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 focused on demonstrating that underground 

sources of drinking water (USDWs) are not endangered as a result of CO2 injection into 

the subsurface, while requirements under the GHG Reporting Program through subpart 

RR will enable reporters to quantify the amount of CO2 that is geologically sequestered. 

However, monitoring approaches and technologies employed for these two objectives 

may overlap. The MRV plan submitted for subpart RR may describe (or provide by 

reference to the UIC permit) the relevant elements of the UIC permit (e.g. assessment of 

leakage pathways in the monitoring area) and how those elements satisfy the subpart RR 

requirements. 

Beyond describing how the existing or planned UIC monitoring procedures form the 

basis for fulfilling the subpart RR leakage detection requirements, the subpart RR MRV 

plan should show how any detected anomalies would be further studied to verify and then 

quantify leakage. Leakage verification and quantification could include 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/groundwater/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 CO2 in the reservoir, to predict the size and location of 

the plume, and is an integral aspect of project design, planning, site 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 injection, 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 applied at GS sites. The model is a 3-D construct 

of the subsurface reservoir, and uses a numerical approach in which the reservoir is 

divided into a large number of discrete 3-D volumes for analysis. Input data include 

reservoir thickness, depth, pressure, porosity, permeability, fluid saturations, and other 

71 DOE. 2009. Best Practices for Monitoring, Verification, and Accounting for CO2 Stored in Deep 

Geologic Formations. U.S. Department of Energy, National Energy Technology Laboratory. 

http://www.netl.doe.gov/technologies/carbon_seq/refshelf/MVA_Document.pdf. 

50
 
 

parameters. Each 3-D volume has its own specific characteristics. In the case of GS, the 

model is set up using all available data, and the model is run to estimate future movement 

of CO2 through the reservoir. The model is then calibrated and updated through time as 

the injection proceeds. This is accomplished through history-matching of actual 

subsurface data, such as pressure or the detection of CO2. 

There are three general types of simulation models used for GS: multiphase fluid flow 

models, reactive transport models, 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 simulation 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 input 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 construction of the underlying governing equations, and 

uncertainties in the values used to represent the actual site conditions73. The accuracy of 

the model will improve as model input parameters more accurately reflect the actual 

subsurface conditions within the modeled area. It is important, therefore, for reporters to 

evaluate the accuracy of the model, and identify the input parameters which are most 

sensitive to the model output. Developing accurate input values for the most sensitive 

parameters will improve the models predictive 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, and flow models to predict reservoir 

performance. The authors also note, however, that relative permeability and residual CO2 

saturation are sensitive input parameters for accurate reservoir models and need to be 

better constrained with data from current projects. The evaluation also notes that there is 

72 DOE. 2009. Best Practices for Monitoring, Verification, and Accounting for CO2 Stored in Deep
 

Geologic Formations. U.S. Department of Energy, National Energy Technology Laboratory. 

http://www.netl.doe.gov/technologies/carbon_seq/refshelf/MVA_Document.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. 

CO2 storage in saline aquifers I—current 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 CO2 in saline aquifers – A review of the experience from existing storage operations 

51
 
limited 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 CO2 over the life of the project, including 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 greater than the area expected to contain the 

free-phase CO2 plume until the CO2 plume has stabilized, plus an all-around buffer zone 

of at least one-half mile. The buffer is intended to encompass leaks that might migrate 

laterally as they move towards the surface. EPA 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 potential 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 for 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 CO2 injected, as well as the geologic characteristics of the IZ 

including the CZ geometry, IZ thickness, permeability, and porosity, and the amount of 

anisotropy within the IZ. The resolution of the reservoir model used to predict plume 

behavior will also influence the delineation of the area of free-phase CO2. A model that 

can predict characteristics of thin layers at the upper boundary of the IZ, or predict the 

presence of lower CO2 saturations, may be able to resolve a larger area of free-phase 

CO2. The reporter should describe the rationale for defining the free-phase plume 

boundary by presenting the results of the reservoir simulation including the minimum 

CO2 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 free phase plume boundary and depends on the rate 

of movement of the free-phase CO2 and the moderation of pressures within the free-phase 

plume. The reporter should define what criteria 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 CO2 is less than a certain value (X foot per 

52
 
year), in any direction, greater than the natural (or not influenced by the site) 

hydrodynamic movement of the IZ, and the pressure change within the reservoir is less 

than a certain value (Y psi per year). The values of fluid movement and pressure would 

be generated from runs of the reservoir model. The values that define 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 significantly 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 potential 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 likely 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 should be determined 

using the most recent monitoring and characterization data available. The MRV plan 

should include a description of how the AMA was determined. 

To ensure that the proposed leak detection 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 areas: 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 area projected to contain the free-phase CO2 

plume five years after the end 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 than the projected free-phase plume, for two 

reasons. First, there may be uncertainty in the projected 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 

CO2 versus the portion that still will contain naturally occurring saline fluids. This 

uncertainty will be greatest at the start of injection and will be reduced over time as the 

reservoir simulation models are calibrated through history-matching 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 monitoring period, so as to 

account for this IZ-related uncertainty in reservoir characteristics. 

The second reason why the AMA needs be larger than the expected free-phase plume 

area is that any CO2 leaks from the IZ will not necessarily follow a straight path upward 

to the surface. The flow path of leaking CO2 will be influenced by buoyancy forces that 

53
 
move the CO2 laterally in an up-dip direction, via hydrogeologic pressure differences. 

The leaked CO2 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 movement 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 encountering leaks in many circumstances. At sites 

where there are known geologic features that may 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 CO2 to the Surface 

Reporters are required to evaluate the risk for leakage of CO2 through all potential 

pathways within the monitoring area described in Chapter 5.1. As discussed in Chapter 

5.1, leakage pathways outside the monitoring area should be evaluated if the pathway has 

the potential to carry a leak outside the monitoring area. Once a potential leakage risk 

pathway is identified, it should be evaluated to determine the likelihood, magnitude, and 

timing of potential leakage. Each leakage pathway should be numerically identified and 

referenced in the MRV plan. The evaluation of leakage pathways will likely be 

54
 
 

 

 

 

qualitative in nature. If a reporter has sufficient 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 Environmental Impact Statement for the FutureGen 

project.76 Another method of quantifying leakage risk was developed by Oldenburg, 

Bryant and Nicot who applied their methodology to a GS site in the Gulf Coast. 77 

One or a combination of physical phases of CO2 that have varying chemical and physical 

properties could be present in leakage from a GS system. These phases of CO2 include: 

 Dry supercritical CO2; 

 The wetted portion of the supercritical CO2 plume; 

 Native fluids in the IZ in which high concentrations of CO2 are dissolved; and 

 Fluids above the confining zone (ACZ) that mix with CO2-containing fluids 

migrating from the GS system. 

Fluids in these phases may be present in the IZ or adjacent geologic layers, and could 

come into contact with the potential subsurface leakage pathways. Escape of any of these 

CO2-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-specific geologic attributes, potential release pathways at GS 

sites could be: 

 Wells; 

 Fractures, faults, and bedding plane partings; 

 Competency, extent, and dip78 of the confining system.79
 

Please refer to relevant UIC regulations80 for information on suitable sites for GS, and the 

Vulnerability Evaluation Framework81 for further background information on potential 

leakage pathways. 

5.2.1 Assessment of the Risk of Potential Leakage of CO2 through Wells 

Of the potential conduits for CO2 leakage, abandoned wells are the most likely conduits 

for leakage of CO2 from the IZ.82 The presence of oil, gas, 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 CO2 to pass though it via permeable zones or 

fractures, or if the CZ is not continuous across the plume area and CO2 escapes around the CZ. Leakage 

may also occur if the CZs is at an angle and CO2 moves up the incline to the surface or to other permeable 

zone. 

80 http://water.epa.gov/type/groundwater/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. 

55
 
 

 

 

and/or abandoned over the last century poses a risk for CO2 leakage due to the potential 

for casing and cement failure, as well as the potential for incompetent bonding between 

cements and either well casing and/or the confining formation.83 Abandoned oil and gas 

wellbores and exploratory boreholes may be present at GS sites located in depleted or 

active oil and gas fields, or in formations near current or historic petroleum exploration or 

production. 

Well plugging and abandonment methods have evolved over time from makeshift 

plugging with available materials to a regulated, documented process with quality control 

measures. Gasda et al.83 describe the possibility of improperly cemented and abandoned 

wellbores to function as conduits for CO2 due to a variety of mechanisms, including: 

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

 CO2 flow through degraded cements; 

 CO2 flow along the borehole wall; 

 CO2 flow along the interface of the casing and cement; and 

 CO2 flow through holes in the casing or annular seals. 

As a depleted oil and gas reservoir is repressurized by GS activities, potentially to 

pressures exceeding those present at the start of the field’s development, risks posed by 

weak well seals can be expected to increase significantly. Newer wells constructed 

specifically for service in CO2 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 CO2 ER in the Permian Basin for 30 years84, and a 30 year 

old CO2 production well in Colorado85 showed effective sealing ability of the cement. 

These studies concluded that although the cement reacted with the CO2 it was not 

compromised possibly due to re-mineralization of the cement into impermeable 

materials. 

Although relatively rare, blowouts from operating oil and gas wells can occur as a result 

of injection. A study of the rate of oil well blowouts in California’s southern San Joaquin 

Valley between 1991 and 2005, indicated that approximately one-third of the blowouts 

occurred at active producing wells, most of which were in fields undergoing thermally 

82 Gasda, S.E., S. Bachu, and M.A. Celia. 2004. The potential for CO2 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. Spatial Characterization of the Location of Potentially 

Leaky Wells Penetrating a Deep Saline Aquifer in a Mature Sedimentary Basin. Environmental Geology 

46, 707–720.

84 Carey, J.W., M. Wigand, S.J. Chipera, G. WoldeGabriel, R. Pawar, P.C. Lichtner, S.C. Wehner M.A. 

Raines and G.D. Gutherie Jr., “Analysis and Performance 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. Gasda, “Wellbore integrity analysis of a natural CO2. 

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

56
 
 

 

enhanced oil recovery86. However, the study also showed that the number of blowouts 

per year declined by 80 percent, which the authors attribute to improved industry 

operational and safety practices. 

As part of an MRV plan, the reporter should identify the risk of leakage to the surface 

through abandoned wells by considering the location, depth, type and age of well, and 

reviewing the available documentation to evaluate the quality of construction and 

effectiveness of the closure methods. The associated risks should be described in terms of 

the relative likelihood, magnitude, and timing 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 potential 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 monitoring well construction, 

evaluation, and leakage risk is also an active area of research.88, 89, 90 

Injection wells pose a potential CO2 leakage risk because they will be subjected to high 

pressures and flows of CO2. Monitoring wells in the IZ may also pose a risk for potential 

CO2 leakage because they will be within the area of increased pressure from the injection 

wells, and could be in contact with native fluids containing CO2 which may affect 

cement integrity. Additionally, nearby monitoring wells within the IZ will experience 

extended periods of exposure to corrosive mixtures of resident fluids and CO2 as the CO2 

plume migrates outward from the injection wells. The combination of potential corrosion 

and high pressures will increase risks associated with monitoring wells in the IZ. 

Injection and monitoring wells constructed of materials that can withstand the pressures 

and the corrosive environments can minimize risk of an accidental release. Mechanical 

integrity testing of cement, cement bonds, casing, tubing, packers, valves, and piping can 

ensure that injection and monitoring wells are capable of withstanding the pressures and 

geochemical conditions anticipated to occur 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/groundwater/uic/wells_sequestration.cfm.
 88 Chabora, Ethan and Benson, S. 2008. Monitoring Pressure Transients in Zones Overlying CO2 Storage 

Reservoirs as a Means of Leak Detection and Diagnosis. Poster presented at 7th Annual Conference on 

Carbon Capture and Sequestration - Pittsburgh, PA, May 7, 2008. 

89Nordbotten, J.M., D. Kavetski, M.A. Celia, and S. Bachu. 2009. Model for CO2 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 CO2
 

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.
 

57
 
 

 

The 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 CO2 through Fractures, 

Faults, and Bedding Plane Partings 

Fractures, faults, and partings along bedding planes are potential leakage 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. Faults 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 conduits for fluids moving through the subsurface 

or as barriers to fluid movement. Bedding plane partings are naturally occurring areas of 

weakness, often found between poorly bonded sedimentary layers, which may be 

laterally extensive and intersect vertical migration pathways. Fractures, faults, and 

bedding plane partings can be forced open by fluids whose pressures exceed the 

fracture/fault reactivation pressure. 

These features may not be observed at the surface or be apparent during geologic site 

characterization, due to overburden or insufficient offset to be observed by standard 

geophysical imaging. Additionally, due to the significantly lower viscosity of 

supercritical CO2 relative to water, these features may not be observed during site 

characterization hydraulic testing of the CZ and the ACZ. Risk presented by these 

features exists due to the ability of CO2 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 samples and various geophysical and 

hydraulic testing methods. Once identified, these features should be monitored for early 

detection of leaks, in accordance with the approved 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/groundwater/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. British 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
 

58
 
 

The possibility of induced seismicity from fluid injection94 compounds the risks 

associated with the above leakage pathways. Seismic events (e.g. small earthquakes) 

resulting from overpressure in the IZ, CZ, or well materials can cause fracturing and 

create preferential pathways for CO2 movement. While induced seismicity may occur 

along pre-existing faults identified during site characterization, it may also occur along 

features that were not detected prior to injection, and be activated as a result of increased 

pore pressure from injection. 

The MRV plan should describe the leakage 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 CO2 and splays in the fault and 

fracture systems as well as offsets within the 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 supplemented and updated with measurements specific 

to the needs of understanding CO2 leakage. For example, existing or new geophysical 

survey data may need to be re-processed and re-interpreted to evaluate the extent of faults 

and fractures, the competency of the CZ or the current location of the CO2 plume. In 

areas where there is limited geological information from exploration wells, reporters may 

need to increase the density of data sampling. 

5.2.3	 Assessment of the Risk of Potential Leakage of CO2 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 CO2 into the ACZ. The risk of a release of CO2 

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, interconnected bedding plane partings, susceptibility to 

degradation by CO2 and impacted native fluids, or low capillary entry pressures95 could 

render the CZ capable of transmitting CO2 from the IZ into the ACZ. These properties 

should be evaluated during site characterization, and any potential conduits should be 

monitored during baseline data collection and facility operation. 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 should be performed as part of GS system 

characterization and facility 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 immiscible fluid phases (e.g., supercritical CO2 and water or brine) for 

CO2 to enter the confining system. If the IZ pressure exceeds the capillary entry pressure, CO2 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. 

59
 
 

 

The lateral extent of the CZ should be sufficient to contain the CO2 plume as it spreads 

and migrates laterally, during and after injection, until physical and geochemical trapping 

mechanisms can sequester the CO2. General CZ extent and thickness 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 well 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 around the edge of the CZ may be present. 

The dip of the confining system is an important component of the GS system. Due to the 

buoyancy of supercritical CO2, until geochemical trapping mechanisms sequester the 

CO2, the injected fluid can be expected to move in an up-dip direction until a structural or 

stratigraphic trap97 is encountered or the lateral extent 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 CO2 to the ACZ and subsequently to the atmosphere. The risk of leakage at the 

up-dip locations should be considered a potential 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, CO2 until geochemical and structural trapping mechanisms can 

effectively sequester the CO2. The likelihood, magnitude, and timing of the risk of 

releases through the CZ should be assessed and presented in the MRV Plan.98 The MRV 

plan should present an assessment of the risk of leakage from the CZ with supporting 

information for how the risk was determined. The description should evaluate the 

uncertainties in the risk evaluation and consider movements of the plume throughout the 

lifecycle of the sequestration. 

5.3 Strategy for Detecting and Quantifying any CO2 Leakage to the Surface 

5.3.1 Detecting Leakage 

After the potential leakage pathways in the MMA have been identified, 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 detect 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 permeability 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. Cook. 2002. Risk and hazard assessment for projects 

involving the geological sequestration of CO2. In Kaya et al. GHGT-6: Sixth International Conference on 

Greenhouse gas control technologies, Kyoto, Japan, September 30–October 4 2002. Elsevier. 

60
 
which case subsequent verification and quantification analysis will be needed to 

determine if the leak has reached or is likely to reach the surface (described in Chapter 

5.3.2 and 5.3.3). 

The strategy for detecting CO2 leakage to the surface could include taking measurements 

on a continuous basis, such as pressure readings in injection and monitoring wells, or 

continuously reading eddy covariance monitoring. The leakage 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 regular 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 leakage 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 capability, 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 transmitted to a monitoring station or 

measurement point. 

 The ability to use the monitoring program to reliably recognize leaks of the 

targeted magnitude. 

The identification and influence of site characteristics 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 detection methods. The considerations for the 

approach and techniques are described below. 

Part of the suite of leakage detection monitoring should include 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 not limited to noise logs; cement bond/variable 

density logs; mechanical, electrical, or acoustical caliper tools; tracer logs; and other 

specialized well inspection tools. MIT utilized for satisfying UIC requirements could be 

described as part of the leakage detection strategy in the MRV plan. Although there are 

no UIC requirements for performing MIT on monitoring wells, it may be prudent for 

reporters to include in their MRV plans a periodic evaluation of the integrity of 

monitoring wells that penetrate the IZ. The reporter’s process for selecting and 

interpreting MIT should be provided in the MRV plan. Additional information on the use 

of these and other monitoring techniques is provided in Chapter 4 of this TSD. 

61
 
 

 

 

The process and technologies for detecting leakage 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 points, which are detectable in the monitoring 

wells and with other subsurface imaging technologies. For example, pressure changes 

observed in multiple monitoring wells can be used to locate the general area of leakage 

through triangulation. The process and technologies for detecting 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 abandoned boreholes are potential leakage pathways, 

where a range of different monitoring technologies could detect leakage, depending on 

site-specific conditions. Near-surface monitoring devices may include eddy covariance, 

LIDAR, accumulation chambers, soil gas surveys, isotopic analysis of CO2 at the surface 

or in shallow wells, and monitoring for tracers injected with the CO2. Leakage from the 

ground into surface water, such as a leaking fault that intersects 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 CO2 fluxes are detectable using 

the proposed methodology. Subpart RR does not have a specific leak detection minimum 

volume or reliability standard. 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 UIC permit will have separate UIC requirements 

if a leak is detected that may include reporting of the leak, ceasing 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 subsurface. There is little published 

research on measured subsurface leakage rates for GS sites, so the reporter should 

provide a justification for selection of the target rate. The reporter may wish to review the 

risk assessment performed for the proposed FutureGen project100 which tabulated surface 

emissions rates from 28 locations including natural CO2 sources (domes, volcanic, and 

hydrothermal sites) and ER/GS sites. The surface emissions ranged over eight orders of 

magnitude, but all of the ER and GS sites had 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 capability of several monitoring methods101. 

99 Oldenburg, C.M., and J.L. Lewicki. 2006. On leakage and seepage of CO2 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., 

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For the evaluation of near-surface monitoring 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 leaks or limits on what leaks can or should be 

detectable. Rather, they are benchmarks against which the performance of the leak 

detection strategy can be measured using statistically valid techniques. 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 CO2 per year within Y days with a probability 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 detection strategy (and in establishing expected 

baselines) for the MRV plan is ensuring adequate data resolution to cover a range of 

points in space and time. A non-representative data set that contains 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 should be designed to ensure that it 

considers the appropriate frequency of sampling, aerial extent of sampling, and sample 

size. The MRV plan is likely to include approaches that involve collecting data at one or 

more locations within the MMA.102 For example, CO2 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 adequacy of a given sampling program (i.e., the 

probability a given size of leak will be detected). 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 verification process is intended to be a quick 

and cost effective step to help the reporter focus efforts on deviations from expected 

measurements that would need to be quantified. 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 leak, for verifying the location and source of the 

leak, and what level of accuracy is anticipated. This description 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. Ground surface monitoring of CO2 and associated gases. Presented at CO2 GeoNet 

Open Forum, March 2009, Venice, Italy. 

63
 
 

operational variability (see Chapter 5.4 for a detailed presentation of this topic). If 

possible, the MRV plan should provide criteria that will be used to identify the presence 

of a leak. Monitoring systems for each pathway are likely to employ different 

technologies at different measurement frequencies. For example, ACZ pressure 

monitoring may be conducted continuously at several locations over a broad part of the 

CO2 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 detection 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 representative 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 necessitate 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 continuous 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 cellars may provide adequate verification of 

a large leak. 

2.	 Identification of the location or the source of a suspected leak. Once the accuracy 

of the measurement is confirmed, other methods may be used to further refine the 

location of a leak, including triggered or episodic monitoring that takes place after 

a leak is suspected. For example, if a release of CO2 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 define 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 scale to improve the resolution of the source 

area. For subsurface leakage in the injection 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. 

64
 
provide a list of possible quantification methods and a discussion of when and how those 

methods might be employed for each risk pathway identified in the leakage pathway 

assessment. To the extent possible, the expected accuracy of the techniques should also 

be discussed. EPA understands that it may be difficult to measure CO2 leakage quantities 

and that modeling and estimation processes with 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 CO2 leaked to the surface that is then reported to 

EPA. In other cases, the estimation process 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 CO2 

leaked to the surface, and reported to EPA. The choice of quantification 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 the IZ. Since leaks will cause monitored 

pressure in the IZ to be lower than expected, 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 conditions, this technique 

would be expected to have a very wide margin of error, particularly in the early 

phases of injection when pressure differences above background levels are small 

and reservoir characteristics have not been confirmed/adjusted by historymatching. The estimated leaked amounts will be reported in volume of fluids 

(e.g., cubic feet or cubic meters) and should be broken out into the amounts of 

water versus amounts of CO2. Then the amount of subsurface CO2 leakage must 

be converted to the amount of CO2 that has leaked or will leak to the surface. (See 

discussion below on these two estimation steps.) 

2.	 Estimation of subsurface leakage by material 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 technique should be more accurate than the 

first technique using IZ pressures, because 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 leaked will have to be converted to CO2 

leaked to the surface. 

3.	 Estimation of leakage by reservoir simulation that triangulates leak location and 

calculates leak rate by interpreting pressures 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 scattered leaks). The volume of fluids leaked 

will have to be converted to CO2 leaked to the surface. 

4.	 Estimation of leakage by measuring CO2 flux at several locations on the surface 

with eddy covariance, accumulation chamber, tenting, etc., can be used in 

extrapolating the entire area of leak. This process would involve identifying that 

65
 
 

the 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 covariance 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 

CO2 on vegetation104. It may be possible to approximate the surface extent and 

rate of leakage by looking at vegetative effects. This option is likely to have a 

very uncertain accuracy. It may best be used to estimate the areal extent of the 

leak or to determine whether subsurface leak has reached the surface. 

6.	 Estimation of the plume size and location 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 CO2 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 CO2 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, estimation 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 logs indicate the leak of fluids along the 

wellbores, it might be possible to estimate the extent of leakage 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 will have to be converted to 

CO2 leaked to the surface. 

When leaks are quantified in the subsurface as volumes of CO2 or fluids, it will be 

necessary to convert this value to an estimate of the amount of CO2 that has leaked to the 

surface. One method to estimate CO2 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 CO2 

leak flux and leakage area, and then estimate the leak volume by multiplying leakage area 

by flux and duration. Alternatively, the reporter can choose to use techniques such as 

modeling to more directly estimate what portion of the subsurface leak is CO2 that has or 

will reach the surface. When the leak has been measured as total volume of fluids, the 

amount of the leak that is CO2 versus water may be inferred by analysis of where the leak 

occurs relative to the position 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 

66
 
outside of the plume area are assumed to be 100 percent water and no CO2. Leaks 

through the CZ within the plume area might be estimated based on the relative modeled 

CO2/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 the leakage rate at the surface is likely to 

increase over time. 

The portion of CO2 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 characterization of the rocks and fluids to be encountered by the 

CO2 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 CO2 

may eventually be produced from the USDW, and therefore counted as a leak to the 

surface, unless the reporter demonstrates that the CO2 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 injectate 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 step in implementing the leakage detection and 

quantification monitoring strategy. The primary goal of establishing expected baselines 

is so that the reporter can discern whether or not the results of monitoring are attributable 

to leakage of injected CO2. This chapter describes considerations for developing 

expected baselines that will ensure adequate leakage detection capability within the 

monitoring system. 

Leakage of sequestered CO2 may result in detectable deviations from the expected 

baseline values in one or more of a number of environmental conditions, such as 

subsurface pressure, groundwater chemical composition, the concentration of CO2 in air, 

soil, surface or near-surface CO2 flux rates, surface CO2 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 strategy may include monitoring a selection of 

these indicator parameters to detect potential CO2 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 plan, 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 

67
 
 

basis for statistically evaluating if the measured parameter values obtained during GS 

operations are of a level that suggests a leakage of injected CO2. 

In most cases seepage fluxes will far exceed background;105 however, some natural 

systems, especially the concentration of CO2 in near-surface soil and air, are quite 

variable and are affected by many factors, making prediction of baseline difficult. There 

may be situations where conditions limit the ability to collect or model representative 

conditions, either for baseline or monitoring applications. For example, in the subsurface, 

heterogeneity may create complex pressure pathways 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 production and reservoir manipulation, 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 baseline could lead to erroneous conclusions. If 

the baseline is inaccurately determined to be too low, then “false positives” would result; 

in other words, CO2 leakages would be detected even when they were not occurring. On 

the other hand, if the baseline is inaccurately determined to be too high, then “false 

negatives” would result; that is, CO2 leakages would not be detected even when they 

were in fact occurring. 

In the MRV plan submittal, the reporter should provide a description of the baseline 

monitoring that demonstrates the statistical validity of the selected approach for each 

monitoring method proposed. This discussion should include documentation of the 

environmental variability and instrument capability, and a determination 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 CO2 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 Sequestration Leadership Forum meeting in Melbourne Australia. September 13-15, 

2004. 

68
 
eliminate one potential source of error and variability in the determination of anomalous 

readings and potential leakage. However, the disadvantage is that operational stage and 

pre-injection values are measured at different points in time, resulting in possible 

variance from temporally varying factors such as weather. 

Contemporaneous Monitoring of Environmental Parameters 

There are two potential approaches involving contemporaneous monitoring of 

environmental parameters. One approach involves contemporaneous monitoring of the 

indicator environmental parameters at a site similar to the sequestration facility, but at an 

offsite location that is unaffected by the CO2 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 CO2 facility not been built and the CO2 not been injected. The advantage 

of this method is that the reference site readings are contemporaneous to the monitoring 

zone readings and would therefore be matched in terms of weather conditions and season 

(provided the reference site is fairly close 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 models 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 CO2 injection, although they lie 

within the maximum monitoring area of the sequestration 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 mathematical model, usually developed through 

regression analysis, that estimates the expected baseline as a function of other variables 

(e.g., predicting expected CO2 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 influences, 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, then the plan should 

lay out how the predictive model will be developed and how the model will change the 

bias and variance in the expected baseline. The MRV plan should describe how the 

predictive model is based on available monitoring data. Examples of predictive models 

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used to calculate flux can be found in recent studies of natural CO2 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-injection historical environmental data, changes in 

land use in the surrounding region could affect 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-determined baseline would have to be adjusted to 

factor in the effect of the current land use change, or the 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 reference 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 define 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 influence 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 negative 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 leakage detection and quantification, 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 CO2 flux are 

likely to be harder to measure accurately than others. For example, surface-to-atmosphere 

CO2 flux varies considerably by time of day, 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 and 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 CO2 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. 

70
 
 

 

 

 

 

variables influence surface-to-atmosphere CO2 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 the statistical model that converts wind 

and CO2 concentration readings to flux and the values of the coefficients in the model. 

This suggests that CO2 flux estimates may have sizeable confidence intervals or error 

bars.109 In a study of the CO2 leakage potential from the ER operations at the Rangely oil 

field in Colorado, Klusman found that CO2 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 environmental parameter with a considerable error 

bar or confidence interval is likely to be difficult to discriminate from baseline 

conditions. High error bars in either or both the operational stage monitoring estimates or 

the baseline estimates will increase the probability of false negative readings, thus 

potentially leading to erroneous conclusions. An environmental parameter with a low 

error bar is preferable to alternative indicators that are associated with high error bars. 

Predictive models have been applied at ER and sequestration pilot tests to compare 

background CO2 flux and concentrations to measured values.111, 112, 113, 114 These studies 

demonstrate the use of predictive models and the challenges115 of discriminating natural 

conditions from leakage especially over small areas or with low leakage rates. 

108 Oldenburg, C.M., and J.L. Lewicki. 2003. Near-surface monitoring strategies 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 CO2leakage 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 CO2 and CH4 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 CO2 leakage by eddy covariance during the ZERT project’s CO2 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, Meyer, C and Krummel, P. 2007. Atmospheric monitoring and verification 

of geosequestration at the CO2CRC Otway Project 2007 Annual Report to the CO2CRC. Cooperative 

Research Center for Greenhouse Gas Technologies, Canberra, Australia, CO2CRC Publication Number 

RPT07-0735. 14pp. 

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Statistical Methods for Comparing Operational Stage Measurements and Expected 

Baseline Data 

In the MRV plan, the reporter may propose to use a statistical approach to conclude if the 

operational stage measurements differ from the expected baseline. Using statistics, the 

reporter can infer about a population using data from a sample. In many cases a statistical 

approach is advisable because environmental parameters tend to be inherently variableeven the best sampling program would only generate an estimate of the true value of a 

parameter. This sampling estimate could be mathematically expressed as a statistical 

probability distribution, which represents the 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 statistical comparisons are meaningful. For 

more information, see EPA’s Data Quality Assessment statistical guidance.116 

Using the Regional Hydrologic Evaluation to Determine Expected Conditions in the 

Monitoring Zones 

An understanding of the regional hydrogeologic characteristics in which the GS facility is 

situated will provide the context for conceptual site model development, and may be used 

to help quantify potential leaks from a GS reservoir. As an example, the presence of 

small-scale structural, stratigraphic, or geochemical features, such as faults, trapping 

structures, or mineral deposits, are often indicated by the broader geologic setting of an 

area. However, these features, which could impact geochemical monitoring parameters, 

may not be observed during site-specific investigations. IZ hydrogeologic and 

geochemical conditions should be evaluated during development of an expected baseline 

to anticipate the movement of injected CO2 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 fluids in the reservoir and ACZ prior to GS 

facility operations. These data can be used to predict CO2 plume migration, assist 

calibration of reservoir models, and during periodic reviews to quantify differences 

between observed changes in the hydrologic regime and predicted 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, determination of baseline hydraulic and geochemical 

conditions may allow determination of the presence and magnitude of any leakage that 

may be occurring. If strata in the ACZ are in hydraulic communication with a USDW, 

pumping regime changes in the USDW may cause pressure fluctuations that could be 

misinterpreted as being indicative of a release from the reservoir. With a sufficient period 

of baseline monitoring, seasonal fluctuations 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: Statistical Methods for Practitioners (EPA QA/G-9S, 2006) 

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Geochemical data are also an important part of baseline data collection, as naturally 

occurring localized mineral deposits or the presence of organic constituents such as 

natural gas or naturally occurring CO2 may mimic or obscure conditions indicative of a 

CO2 release. Depending on the site and on the proposed monitoring strategy, the GS 

reservoir and ACZ geochemistry could be measured as part of a baseline assessment, due 

to the possible presence of naturally occurring CO2, metals that may mobilize in the event 

of a GS reservoir leak such as iron and manganese, or naturally occurring constituents 

that could also be introduced by the CO2 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 are used to calculate the amount of CO2 

that is reported as sequestered and include the terms CO2FI and CO2FP. CO2FI is defined as 

the total annual CO2 mass emitted (metric tons) as equipment leakage or vented 

emissions from equipment located on the surface between the flow meter used to measure 

injection quantity and the injection wellhead. CO2FP is defined as total annual CO2 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 include a summary of considerations made to 

calculate equipment leaks and vented emissions from surface equipment between the 

flow meters and either injection or production wellheads, and the quantity of CO2 that is 

produced with oil and water. 

The mass balance equation assumes that all CO2 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 located on the injection line after the point of 

flow/mass measurement, and before the injection well, there is a potential for equipment 

leaks and vented emissions that will not be included in the mass balance. Similarly, the 

measurement point for produced CO2 (at the flow meter immediately downstream of the 

gas-liquid separator) is assumed to represent the amount of CO2 exiting the wellhead. 

However if additional surface equipment other than the separator is located between the 

production wellhead and point of CO2 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 Natural Gas Systems Reporting Rule (subpart 

W of the GHG Reporting Program).117 

The following table lists the surface CO2 emission sources at an injection facility that 

may be located between the point of transfer onsite and the injection wellhead (selected 

from the list of all emissions sources under onshore petroleum and natural gas production 

at §98.232) and describes the methodologies 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 CO2 that is mixed with the 

critical phase stream coming from outside facility boundary. In the event that there are 

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

73
 
 

 

 

 

 

 

 

 

 

 

other vented or fugitive CO2 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 CO2 Emissions Sources at Injection Facilities 

Emissions Source Engineering 

Estimates1 

Direct 

Measurement2 

Equipment Count 

and 

Population Factor3 

Natural gas pneumatic high bleed 

device venting4 X 

Natural gas pneumatic low bleed 

device venting4 X 

Natural gas pneumatic intermittent 

bleed device venting4 X 

Natural gas driven pneumatic pump 

venting4 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-specific emission factor for use between repeat measurements. 

(3) For the use of population factors, the relevant emission factors would be applied to all components 

using a count of the sources. 

(4) ER operations that power pneumatic equipment by instrument air rather than natural gas would not have 

natural gas pneumatic emissions sources. 

Equipment leaks and vented CO2 emissions at an ER operation can also occur from 

surface components located between the production well and the point of CO2 

measurement. Between these two points, an injection facility will typically have valves, 

connectors, meters, and headers (which are large pipes that mix the oil stream from 

74
 
multiple wellheads). The procedures provided in subpart W for determining CO2 

emissions from all of these sources are equipment count and population factor. 

The MRV plan must provide the basis for calculations of equipment 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, produced at GS facilities may contain CO2 that is not 

captured in the gas phase CO2 measurement downstream of the gas-liquid separator. The 

CO2 is present as dissolved gas in the oil and water phase of the produced fluids. To 

account for the amount of produced CO2 that is not sequestered, the reporter must tailor 

the mass balance equation to account for the mass of CO2 in all produced fluids. Equation 

RR-9 describes the mass balance of CO2 at the gas-liquid separator where CO2,P 

represents the total mass of CO2 in the incoming production stream (oil, water and CO2), 

and CO2,W represents the amount of CO2 in the separated gas stream. The value of “X” is 

the percent of CO2 expected to remain with the produced oil and gas when referenced to 

the CO2 separated for recycle or reuse. 

The MRV plan must describe how the volume of CO2 in produced fluids will be 

determined, and how the value of “X” will be calculated. The reporter should describe 

how the analysis of CO2 in produced fluids will be performed. Commercial laboratories 

perform crude oil analyses and separator liquid analyses that can include quantification of 

CO2 as a component. Because separators operate under pressure, the CO2 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 CO2 concentration is representative of the 

pressure conditions at the measurement location. For analysis, the water and oil may need 

to be separated and analyzed using different methods. Several steps would be needed in 

order to estimate the quantity of CO2 produced with oil, water or gas. The oil or gas 

stream of a production well at an ER operation is first separated into liquid phase and gas 

phase; the liquid phase is further separated into a water fraction and an oil fraction. CO2 

may be found in the following three streams following the gas-water-oil separation phase: 

1) CO2 in oil, 2) CO2 in water, and 3) CO2 in gas phase (along with other produced 

hydrocarbons). The amount of CO2 in the oil (or water) can be estimated by multiplying 

the gas-to-oil (or gas-to-water) ratio by the volume of oil (or water) produced. The gasto-oil (or gas-to-water) ratio can be determined using any standard test method (the ratio 

determination as well as chromatography are well understood techniques). A method to 

determine the amount of CO2 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 

CO2, take a sample of the stream, and analyze the stream for CO2 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 CO2 in the oil and produced water. The total fluid 

analyses are often a combination of several ASTM or other methods. The selected 

sampling and analytical method(s) should consider the pressure at which the fluid is 

separated from the gas and differences in CO2 solubility in oil and water. EPA has not 

75
 
identified consensus-based or industry standard analytical methods specifically for 

determining the amount of CO2 in mixed produced fluids (oil and water); however, two 

potentially applicable methods for CO2 in hydrocarbons were identified: 

ASTM D2597 - 94(2004) Standard Test Method for Analysis of Demethanized 

Hydrocarbon Liquid Mixtures Containing Nitrogen and Carbon Dioxide by Gas 

Chromatography 

GPA Standard 2177 Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing 

Nitrogen and Carbon Dioxide by Gas Chromatography 

To measure the CO2 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 methods used and demonstrate 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 accurate flow measuring devices on all streams 

in/out, and manifolded to divert 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 CO2 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 CO2 storage system. The 

amount of dissolved CO2 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. The MRV plan should describe 

the fate of the produced water and account for all CO2 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 program for data collection and analysis. The 

MRV plan should define what quality assurance 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 the reporter will ensure that sensor readings 

are correct, and describe (or reference) the quality control measures that are in place to 

ensure precision, accuracy, representativeness, completeness, and comparability of data. 

76
 
Examples of quality control measures that may be described in the MRV plan include 

standard operating procedures, calibration requirements, redundancy of the sensor or 

measurement, criteria for equipment selection, 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 CO2 injected and CO2 received are provided at 40 CFR 98.445. 

Procedures are also provided for missing data on CO2 production and for equipment leaks 

and vented emissions. 

The rule does not require the reporter to develop 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, information on the quantification 

approach should be included in the annual report. Similarly, if additional leakage 

pathways are identified, they should be assessed in accordance with the procedures in the 

“Assessment of potential surface leakage pathways” section of the MRV plan, and 

included in the annual report. Procedures for developing missing leak quantification data 

should be included in the MRV plan. 

77 
 

 

6. 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 CO2 

injection on or before December 31, 2010. 

 Within 180 days of receiving a final UIC permit (or offshore authorization) 

authorizing CO2 injection. 

 Any time if injecting CO2 to enhance oil and gas recovery and not permitted 

under UIC Class VI. 

Facilities will be allowed one extension of up to an additional 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; however, the plan may include information on 

geologic, topographic, cultural, and potential CO2 source conditions outside the MMA, 

where appropriate, to assist EPA in developing a full understanding of potential 

influences on the proposed monitoring strategy. 

6.2 Notification of Receipt of MRV Plan 

EPA will accept MRV plan submittals from reporting entities that have established a 

“Certificate of Representation” through the GHG Reporting Program’s Electronic 

Greenhouse Gas Reporting Tool (e-GGRT). All MRV plans must be submitted by the 

reporter electronically through e-GGRT. EPA has 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/emissions/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 requirements 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 reporter 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 that the MRV plan is complete and that the 

technical review will commence. In the case that the MRV plan is incomplete, the notice 

would specify the MRV plan requirements that were deemed to be incomplete, what 

additional information is needed, and the rationale for why such additional information is 

needed. If incomplete, the reporter must submit an updated MRV plan within 45 days of 

EPA notification unless otherwise specified by EPA. 

Note that the completeness check is not a substitute for the technical review process. EPA 

will initiate the technical review process only upon determination of the completeness of 

the MRV plan. 

Table 6-1: Completeness Check Criteria for 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 CO2 in 

the maximum monitoring area and the likelihood, magnitude, 

and timing, of surface leakage of CO2 through these pathways 

40 CFR 98.448(a)(2) 

A strategy for detecting and quantifying any surface leakage of 

CO2 

40 CFR 98.448(a)(3) 

A strategy for establishing the expected baselines for 

monitoring CO2 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 

79
 
 

 

After 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 interested 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 resubmittal if a material change was made to 

monitoring and/or operational parameters that was not anticipated in the original plan, if 

there has been a change in the permit class of the reporter’s UIC permit, if the reporter is 

notified by EPA of errors in their MRV plan or annual monitoring report, or if the 

reporter chooses to revise their MRV plan for any other reason. 

Examples of material changes include but are not limited to: large changes in the volume 

of CO2 injected; the construction of new injection 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 differs 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 monitoring 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. 

80 
 

7. 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 general 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 monitoring 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 were 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 any relevant tests or surveys that were 

conducted. This narrative history may include, for example, a general discussion crosswalking the monitoring activities implemented during the reporting year with the 

activities outlined in a facility MRV plan. Reporters may include a table that presents all 

the monitoring equipment used during a reporting 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 those 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 technology that are already included as part of 

the EPA-approved MRV plan, or changes in the location of equipment that do not alter 

the coverage of detection capability of monitoring. 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 Reporting Program Web site at: 

http://www.epa.gov/climatechange/emissions/ghgrulemaking.html 
MRV plan, including an identification of the part of the MRV plan affected by the nonmaterial change, supporting information for why 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 that were used to determine what constituted a 

non-material change to their EPA-approved MRV plan. (See Appendix D) 

7.3 Narrative History of Monitoring Anomalies 

The AMR must also contain a narrative history of monitoring anomalies that were 

detected in the year and how they were investigated and resolved. This discussion could 

include a detailed description of all monitoring anomalies detected, and how the 

anomalies were investigated in line with the 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 resolved. 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 include the following information in the AMR: 

a description of the pressure anomaly detected, a description of the steps taken to further 

investigate the reason for anomalous pressure reading and evaluate if it represents a leak 

(i.e., how the obstruction in the vent line was identified). The reporter may also include a 

description of the actions the reporter has taken/is planning 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 should also include a qualitative discussion of any unexpected 

operational or maintenance issues that caused down-time for the equipment. If the 

evaluation and investigation of a monitoring 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 year (if any). Reporters must provide a description of any 

surface leakages of CO2, including a discussion of all methodologies and technologies 

involved in detecting and quantifying the surface leakages and any assumptions and 

uncertainties involved in calculating the amount of CO2 emitted. 

In this section of the AMR, as part of the discussion of the methodologies and 

technologies involved in detection and quantifying the surface leakages, reporters could 

provide EPA with a demonstration showing that the methods and technologies used for 

leak detection and quantification followed the methods specified 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 leakage in that reporting year. If non-material deviations are 

made from the leakage detection and quantification approaches specified in the MRV 

plan it must be documented in the AMR. (See Chapter 7.2.) 

82
 
This component of the AMR may also include qualitative descriptions and quantitative 

identifications (i.e., if a leak rate were assumed) of the assumptions that went into each 

leakage calculation. Reporters may also provide information demonstrating the 

assumptions’ validity. Information on uncertainties may include a qualitative analysis of 

the uncertainty around the amount of CO2 emitted. For instance, such an analysis may 

include a description of how variables such as the accuracy and precision of measurement 

instruments may have affected calculating the quantity of leakage determined, and how 

uncertainty in baseline conditions may have affected 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 descriptions of the statistical 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-approved 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 retained should be sufficient to 

document the rationale of the decision-making process and demonstrate the completeness 

and accuracy of the data and calculations used in the detection and quantification of leaks 

to the surface. The MRV plan should state which 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 retained may include, but are not limited to, 

operational data, data sets used to construct expected baseline conditions, data relating to 

the detection or quantification of surface leakage, logs of mechanical integrity tests and 

pressure tests, and field books and photographs 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 monitored 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 superimposing two areas: 1) the area projected to 

contain the free-phase CO2 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 CO2 plume at the end of 

year t+5. (40 CFR 98.449) 

Carbon dioxide (CO2) plume: The extent underground, in three dimensions, of an 

injected CO2 stream. (40 CFR 146.81(d)) 

Carbon dioxide (CO2) stream: CO2 that has been captured from an emission source 

(e.g. a power plant) plus incidental associated substances derived from the source 

materials and the capture process, and any substances added to the stream to enable or 

improve the injection process. (40 CFR 146.81(d)) 

Confining Zone (CZ): A geologic formation, group of formations, 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 injection depth waiver, CZ means a geologic 

formation, group of formations, or part of a formation stratigraphically 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 anticipated value of a monitored 

parameter that is compared to the measured monitored parameter. (40 CFR 98.449) 

Formation or geological formation: A layer of rock that is made up of a certain type of 

rock or a combination of types. (40 CFR part 144 and part 146) 

Free-phase CO2 plume: That part of the CO2 plume in which the injected CO2 stream 

exists in gaseous, liquid or supercritical free phase. The precise definition will be stated 

by the reporter in the MRV plan based on site characteristics and the proposed methods 

of monitoring and modeling. 

Free-phase CO2 plume area: The 2-D vertical projection onto the surface of the freephase CO2 plume. The free phase CO2 plume area is included within the AMA and 

MMA. 

84
 
Geophysical surveys: The use of geophysical techniques (e.g., seismic, electrical, 

gravity, or EM surveys) to characterize subsurface 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 CO2 stream. 

Injection Zone (IZ): A geologic formation, group of formations, or part of a formation 

that is of sufficient aerial extent, thickness, porosity, and permeability to receive CO2 

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 equal to or greater than the area expected to contain the free 

phase CO2 plume until the CO2 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 (known 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 system 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). CO2 injected into the subsurface can displace pre-existing fluids 

to occupy some of the pore spaces of the rocks in the IZ. (40 CFR part 144 and part 146) 

Separator: means a vessel in which streams of multiple phases are gravity separated into 

individual streams of single phase. (40 CFR 98.449) 

Stratigraphic zone (unit): A layer of rock (or stratum) that is recognized as a unit based 

on lithology, fossil content, age, or other properties. (40 CFR part 144 and part 146) 

Subsurface CO2 Leakage: Subsurface leakage is injected CO2 that is present outside the 

IZ but has not reached the surface. 

Surface CO2 Leakage: The movement of the injected CO2 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 designed releases of CH4 or CO2 containing natural gas 

or hydrocarbon gas (not including stationary combustion flue gas), including process 

85
 
designed flow to the atmosphere through seals or vent pipes, equipment blowdown for 

maintenance, and direct venting of gas used to power equipment (such as pneumatic 

devices). (40 CFR 98.449) 

86 
 

Appendix B: U.S. Oilfields Using CO2 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 

87
 
Albert 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 

88
 
South Welch Occidental TX 865 

T-Star (Slaughter Abo) Occidental TX 2,100 

Twofreds Great Western Drilling TX 170 

Wasson (Cornell and Mahoney 

Units) XTO Energy Inc. TX 2,250 

Wasson (4 Units) Occidental TX 44,325 

West Welch 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 CO2 

The following is a summary of end uses of captured or produced CO2 (with the exception 

of ER and GS). 

Cement. While not a common practice in the cement industry, some companies are 

currently working to employ a cement manufacturing process that uses captured CO2.

121 

The process will convert CO2 into carbonic acid, which will be made into CO3

- -. The 

CO3

- - will be combined with calcium and magnesium from seawater to make calcium 

carbonate and magnesium carbonate for the cement.122 EPA does not have enough 

information to conclude whether cement production using this CO2 capture method 

permanently sequesters CO2. 

Precipitated Calcium Carbonate (PCC). PCC is produced through a chemical reaction 

process that utilizes calcium oxide (quicklime), water, and CO2. The CO2 used to 

manufacture the PCC is in some cases captured from lime kilns operated at pulp and 

paper manufacturers. The PCC is available in numerous crystal morphologies and sizes, 

which can be tailored to optimize performance in specific applications. EPA does not 

have enough information to conclude whether PCC production using this CO2 capture 

method permanently sequesters CO2. 

Food and Beverage Manufacturing. The food and beverage industry is one of the largest 

consumers of manufactured and captured CO2 in the U.S. CO2 is used widely throughout 

the food and beverage industry for a variety of applications including: 

 Carbonation of soft drinks; 

 Beer and wine production; 

 Decaffeination of coffee and tea; 

 pH adjustment and shelf life lengthener for dairy products; 

 Frozen food production; and 

 Canning. 

Pulp and Paper Manufacturing. CO2 is used in the pulp and paper industry in production 

processes to control pH, decrease calcium levels, increase de-watering, buffer the paper 

making system, and recover chemicals in the mill process.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 CO2: A Concrete Cure for Global Warming?, Scientific American, 

http://www.scientificamerican.com/article.cfm?id=cement-from-carbon-dioxide (accessed July 26, 2009). 123 Linde Gas, AGA and the Pulp and Paper Industry. 

http://www.aga.fi/international/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). 

90
 
 

 

 

Industrial and Municipal Wastewater Treatment. Industrial and municipal wastewater 

treatment facilities use CO2 to control pH levels in the water and treat soft water by 

dissolving lime.125 

Metal Fabrication. CO2 is used for metal fabrication to enhance the hardness of casting 

molds; CO2 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. CO2 is used to increase plant growth in greenhouses 

that produce flowers to full growth, nursery plants in early developing stages, and some 

produce (e.g., tomatoes). 

Fumigants and Herbicides. CO2 is used in the agricultural sector as an herbicide for 

organic produce that successfully kills insects and increases storage life; and as a 

fumigant for grain storage to control insects in the storage facility. 

Medical Treatment. For medical treatment, CO2 is added to oxygen to stimulate breathing 

and balance CO2/O2 levels in patients. 

Construction. In the construction and manufacture industry, CO2 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 CO2 is commonly used to achieve a higher welding rate and reduce 

the need for post-weld treatment. Additionally, dry ice pellets are used to replace 

sandblasting when removing paint from surfaces. Dry ice aids in reducing the cost of 

disposal and cleanup. 

Rubber and Plastic Industry. CO2 cleaning, also known as dry ice blasting, is a method of 

cryogenic cleaning. Dry ice is used to remove flash from rubber objects by tumbling 

them with crushed dry ice in a rotating drum. Almost all major tire manufacturers use 

CO2 cleaning in their rubber molds. Shoe companies as well as gasket and other small 

rubber companies have successfully been using CO2 cleaning as part of their routine 

machine maintenance. Additionally, in the production of polymer foams, liquid CO2 is 

used as a blowing agent instead of environmentally hazardous substances. CO2 is a 

physical blowing agent with properties desired for ideal foaming, while simultaneously 

fulfilling many requirements related to quality, efficiency, and the environment. 

Fire Suppression. CO2 fire extinguishers are used for Class B fires (involving flammable 

and volatile liquids) and Class C fires (involving electrical equipment). 

Cleaning and Solvent Use. Liquid CO2 is used a solvent for cleaning a variety of products 

during manufacturing processes, e.g., electronics cleaning and metal cleaning. Liquid 

125 Linde Industrial Gases, Products and Supply, Wastewater. http://www.lindegas.com/en/products_and_supply/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). 

91
 
 

 

CO2’s solvent potential has been employed in some dry cleaning equipment as a 

substitute for conventional solvents. 

Refrigeration and Cooling. Liquid and solid CO2 are important refrigerants, especially in 

the food distribution industry, where they are employed during the transportation and 

storage of ice cream and other frozen foods, primarily in small retail food stores. In those 

cases, the CO2 may be stored on-site or be provided by refrigerant technicians at the time 

of recharging. 

Transportation and Storage of Explosives. CO2 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 CO2 from electric power 

and chemical production projects. The biofuel production from captured CO2 represents a 

potential GHG/carbon sink. Also of strong interest is the use of algae as a source of 

feedstock material for the production of biodiesel, and perhaps fermentation. CO2 is an 

ingredient used by algae for normal growth, during photosynthesis. The process is being 

studied at various pilot projects in the U.S. and elsewhere. 

Pressurized Gas. CO2 is used as an inexpensive, nonflammable pressurized gas. 

Compressed CO2 gas is used in life jackets (stored inside canisters), in air guns, in 

paintball markers, and for inflating bicycle tires. 

Chemical processes. CO2 is currently used for various processes 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 CO2 as a less toxic 

alternative to organochlorides or more traditional solvents. 

92
 
Appendix D: Suggested Outlines for MRV Plans, 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 CO2 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 CO2 injection 

ii) Estimated tons CO2 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 CO2 composition 

ii) Number, location and depth of injection wells 

iii) Compression/pumping, conditioning and 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 and 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) 

93 
b) Fractures, faults and bedding 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 verifying 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) CO2 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 

94
 
 

 

Suggested 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 Monitoring Effort Conducted 

a) Listing of all monitoring equipment, period of operation, and relevant tests or 

surveys conducted (see also suggested table format above) 

b) Cross walk of annual monitoring activities 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 investigations, 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 detection of monitoring anomalies 

b) Assumptions Involved in Calculating the Quantity of CO2 Emitted 

i) Assumption identification and supporting information 

c) Uncertainties Involved in Calculating the Quantity of CO2 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. 

95
 
 

Appendix E: Sampling Considerations for Designing a Monitoring Strategy 

A consideration in designing a leakage detection 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 contains 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 designed to ensure consideration of the 

appropriate frequency of sampling, aerial extent of sampling, and sample size. 

Frequency of Sampling 

If the environmental factor being measured incurs considerable intra-day and/or seasonal 

variation, the sampling program may be designed to capture these fluctuations. An 

example of a parameter that shows high intra-day and seasonal variation is near-surface 

CO2 flux. A program based on CO2 flux monitoring would need a high frequency of 

sampling across the year. On the other hand, if the environmental parameter being 

monitored is not known to show a substantial intra-day or seasonal variation, the 

sampling program could rely on a lower frequency 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 monitoring technologies or variability in the 

monitoring area, the reporter may employ different frequencies within the monitoring 

area to achieve adequate baseline definition. The MRV plan should clearly define the 

frequency of baseline sampling and provide a rationale for the chosen frequency. 

Areal Extent of Sampling and Subdividing Maximum Monitoring Area 

The specific method used for the measurement of the monitored environmental parameter 

will produce values representative 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 balance cost and coverage. 

Accumulation chambers are an example of a technique that measures a very small area 

(tens of cm2

). Expert judgment based on modeling results may be used to focus sampling 

in higher CO2 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 demonstrate that it provides 

adequate coverage to determine a representative 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 

96
 
 

 

Sample Size 

An adequate sample size will ensure greater ability to detect differences between 

prevailing conditions and the expected baseline. Approximate knowledge of sampling 

variation in the measured parameter (potentially based on prior sampling experience) 

could be used to estimate the number of samples needed to limit the occurrence of false 

positives and false negatives to the desired level. Frequently, cost considerations place 

limitations on the number of samples that may be gathered such that reporters should 

estimate the probability of occurrence of false positives and false negatives to better 

guide decision making. For instance, if calculations 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 accuracy of the predicted sample size for the 

specified error rates. The MRV plan should demonstrate that the sample size is adequate 

to account for the observed variability 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 involve collecting data at one or more locations within the 

MMA. This appendix explains how the statistical 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: 

Pd  Pe  Pr 

(Equation 1) 

Where: 

Pd = overall probability leak will be detected 

Pe = probability leak will be encountered by a sampling program 

Pr = probability leak will be recognized once encountered 

The probability that the leak will be recognized after it is encountered (Pr) can be 

computed given the mean and standard deviation in the expected environmental or 

operating baseline, and the mean and standard deviation of the measured parameter. As 

noted earlier, Pr is equal to one minus the chance of false negatives. As discussed below, 

the probability of any given monitoring element encountering the leak, Pe, is a function of 

the size of the monitoring area, the size and shape of the leak area, the size and shape of 

the sample coverage, and the number and pattern of sampling. 

97
 
 

 

 

The “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 with 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 the surface flux in units such as micrograms of 

CO2 per square meter per second (g m

-2

 s

-1). The probability of encountering 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 measurement 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” for a limited area without a significant length 

or width. A closed-path remote sensing sample 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 circular area with a given radius. An example of the effect 

of leakage footprint size on eddy covariance detection station 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. 

98