GENERAL TECHNICAL SUPPORT DOCUMENT

FOR INJECTION AND GEOLOGIC

SEQUESTRATION OF CARBON DIOXIDE

PROPOSED RULE FOR MANDATORY

REPORTING OF GREENHOUSE GASES

Office of Air and Radiation

U.S. Environmental Protection Agency

March 2010
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

2

Table of Contents

1. Source Description................................................................................................................ 3

2. Overview of Source Category .............................................................................................. 4

2.1 Geologic Sequestration ....................................................................................... 4

2.2 Enhanced Oil and Gas Recovery ........................................................................ 4

2.3 Other Industries that Use CO2............................................................................. 5

2.4 Types of Data to be Reported ............................................................................. 5

3. Options for Reporting Threshold........................................................................................ 6

3.1 Threshold Analysis ............................................................................................. 6

4. Monitoring Methods Considered....................................................................................... 11

4.1 CO2 Injection .................................................................................................... 11

4.2 CO2 Production at ER Operations..................................................................... 12

4.3 Fugitive and Vented CO2 Emissions................................................................. 12

4.4 CO2 Leakage to the Surface.............................................................................. 14

4.4.1 Reservoir Modeling .................................................................................. 14

4.4.2 Environmental Baselines .......................................................................... 15

4.4.3 Monitoring Technologies for CO2 Detection and Quantification............. 16

4.4.4 Leak Detection and Quantification in the Offshore Environment............ 28

4.5 Detection Limits and Accuracy of Various Technologies................................ 31

Attachment A .............................................................................................................................. 34

Attachment B............................................................................................................................... 37

List of Figures

Figure 3-1. Total CO2 used in Enhanced Recovery showing growth since 2004............... 8

Figure 4-1. Example of a Vertical Radial Plume Mapping Configuration Setup............ 26

List of Tables

Table 3-1. Threshold Analysis Based on Amount of CO2 Injected.................................. 11

Table 4-1. Surface Components as CO2 Emissions Sources at Injection Facilities.......... 13

Table 4-2: Monitoring Technologies as Deployed at 10 Existing CCS Projects............. 17

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

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

Technologies..................................................................................................................... 32
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

3

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 40.6 million metric

tons carbon dioxide equivalent (MMTCO2e).

1 2

 Currently more than 95% of this CO2

supplied to the economy is injected underground for enhanced oil and gas recovery

(ER).3 The remaining estimated CO2 supply is captured and used for non-ER

applications.4In addition, captured CO2 may be injected underground for the purpose of

geologic sequestration (GS), or the long term containment of a gaseous, liquid, or

supercritical CO2 stream in subsurface geologic formations. GS is one of a portfolio of

options that could play an important role in mitigating CO2 emissions.

Data on captured or produced CO2 supplied to the economy will be reported to EPA

through subpart PP of the Mandatory Reporting for Greenhouse Gases Rulemaking

(MRR) (74 FR 56260). Subpart PP is applicable to all facilities with CO2 production

wells, facilities with production process units that capture and supply CO2 for

commercial applications or that capture and maintain custody of a CO2 stream to

sequester or otherwise inject it underground, and to importers and exporters of bulk CO2.

During the public comment period on the rule in 2009, EPA received many comments on

subpart PP indicating that underground injection and GS of CO2 should be considered

when estimating emissions from the CO2 supply industry.

Reporting on CO2 injection and GS would provide information and transparency on the

amount of CO2 injected and geologically sequestered in the United States. In

combination with other subparts of the MRR, these data would enable EPA to track the

flow of CO2 across carbon dioxide capture and sequestration (CCS) systems, monitor the

growth and efficacy of GS (and therefore CCS) as a mitigation technology over time, and

evaluate relevant policy options. Information would be reconciled with data on CO2

supplied (reported under subpart PP of the MRR) to better understand the quantity of CO2

supplied to emissive and non-emissive end-uses. Lastly, CO2 injection and GS data

would inform policy decisions under the Clean Air Act related to CCS as a climate

mitigation tool.

This technical support document (TSD) is focused on outlining options associated with

incorporating reporting on CO2 injection and GS in the MRR. In addition, EPA

1 U.S. EPA Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks, 1990-2007,

 Report, EPA 430-R-09-004. Available at:

http://epa.gov/climatechange/emissions/usinventoryreport.html

2

 The estimated 40.6 million metric tons of CO2 does not include biogenic CO2.

3

 U.S. EPA Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks, 1990-2007,

 Report, EPA 430-R-09-004. Available at:

http://epa.gov/climatechange/emissions/usinventoryreport.html

4

 EPA 2008. Inventory of U.S. GHG Emissions and Sinks 1990-2006. April 15, 2008. EPA 430-R-08-005.

Washington D.C.
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

4

considered reporting on other end uses of CO2 that could also be potentially nonemissive.

2. Overview of Source Category

Three sectors were considered for inclusion in subpart RR: injection of CO2 underground

for GS, injection of CO2 underground to enhance recovery of oil or gas, and end uses of

CO2 by other industries.

2.1 Geologic Sequestration

Carbon capture and sequestration involves capturing CO2 from industrial facilities,

combustion source facilities, or waste treatment process facilities, purifying and

compressing the CO2, transporting it (usually by means of a dedicated CO2 pipeline) to

an injection site, and injecting the CO2 into an underground geologic formation for longterm containment.

Underground geologic formations that can be used for GS include saline aquifers,

depleted or active 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.

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, see the Vulnerability Evaluation Framework for

Geologic Sequestration of Carbon Dioxide (see docket ID No. EPA-HQ-OAR-2009-

0926).

2.2 Enhanced Oil and Gas Recovery

Carbon dioxide is currently being injected into subsurface geologic formations in the U.S.

for the purposes of CO2-based enhanced oil and natural gas recovery (ER). The CO2

currently being used in ER is primarily produced from naturally-occurring underground

CO2 reservoirs but is also captured from natural gas processing plants and ammonia

plants.

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 out the hydrocarbons from the CO2.
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

5

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 (ECBM)).

There are currently 80 enhanced oil and natural gas recovery fields operating in the U.S.

where CO2 is being injected for the purposes of enhanced recovery.5 Enhanced recovery

projects operating in the U.S. range from new pilot scale projects with one or two

injection wells to CO2 floods that commenced operation in the 1970s and that have

hundreds of injection wells. Approximately 40 million metric tons of CO2 was injected

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

combustion or industrial process sources.6

2.3 Other Industries that Use CO2

EPA identified and considered a total of 22 commercial end use sectors7that use gaseous,

liquid, or solid CO2, excluding ER and GS. These end use sectors are summarized in

Appendix A.

For the purposes of this background document, these sectors were not considered likely

candidates for reporting at this time. EPA received comments to subpart PP suggesting

that at least one of these end-uses – precipitated calcium carbonate (PCC) production –

may be a non-emissive use. EPA does not have enough information at this time to

conclude whether PCC production or any other industrial end-use (other than ER and GS)

permanently sequesters CO2. EPA is seeking data and information on how many facilities

operate in these industries; how much CO2 would be sequestered using these

technologies; whether sequestration factors would be reasonable in either case; and what

methodologies could be applied to verify CO2 sequestration.

2.4 Types of Data to be Reported

In a mandatory reporting system, data on CO2 injection could be reconciled with data on

CO2 supplied to better understand the quantity of CO2 supplied to emissive and

potentially non-emissive end-uses. The types of data to be reported from all facilities that

inject CO2 could include the quantity of CO2 transferred to the facility from offsite

5

See Appendix B of this technical support document.

6

 U.S. EPA Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks, 1990-2007,

 Report, EPA 430-R-09-004. Available at:

http://epa.gov/climatechange/emissions/usinventoryreport.html

7

 This count includes the various chemical, pharmaceutical, and other processes that use CO2 as an end

product and excludes intermediate CO2 processors.. After carbon dioxide 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.
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

6

locations, the amount of CO2 that is injected into the subsurface at these facilities, and the

source of that CO2 (e.g. industrial process or combustion process).

In addition to basic reporting on CO2 injection, certain additional data could enable EPA

to monitor the growth and efficacy of GS. This could include information to understand

the quantity of injected CO2 that is permanently sequestered at a GS facility. Monitoring

of the injected CO2 would be necessary to demonstrate that it is remaining sequestered

underground, and in the unlikely case that some of the injected CO2 does leak from the

formation, to quantify the amount of the leak. At an ER operation that is also reporting

sequestered CO2, the amount of CO2 sequestered in a year would exclude the quantity of

CO2 that is removed from the reservoir, as well as any leakage from the subsurface.

Emissions from surface equipment at CO2 injection facilities could result from a variety

of sources. These sources could include:

 Combustion of fuel in the driver for the compressors or pumps and combustion of

fuel for heaters and boilers

 Venting from compressors, pumps, and pipelines; and

 Fugitive emissions from components (such as valves, connectors, etc.) and

pipeline leaks.

If the CO2 injection facility is an ER operation (i.e., producing crude oil or natural gas),

vented and fugitive emissions from surface components could more specifically include:

Venting from pipelines and separators, and

Venting of gas dissolved in the crude oil (in cases where gas is used as stimulant)

If an acid gas recovery unit is used, emissions could result from venting from the

glycol dehydrator vent.

3. Options for Reporting Threshold

To determine the appropriate threshold for reporting under subpart RR, EPA considered

both a threshold based on the amount of CO2 emitted and a threshold based on the

amount of CO2 injected underground. EPA concluded that an emissions-based threshold

would be problematic because of the lack of data on the incidence and scale of surface

emissions and leakage from injection and GS of facilities. Therefore EPA did not

conduct this analysis for the TSD. EPA accordingly analyzed injection facilities based on

the quantity of CO2 injected underground.

3.1 Threshold Analysis

EPA analyzed injection facilities based on the quantity of CO2 injected underground and

considered whether an injection threshold 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 per facility of CO2 injected. Only facilities expected to be operating in

2011, the first year of reporting under this proposal, were considered in the analysis.
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

7

To establish a count of CO2 injection facilities, EPA relied on data reported in the Oil and

Gas Journal (O&GJ) Enhanced Oil Recovery Survey published in April 20088. 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 mid year, or had scheduled downtime in 2007, so the reported annual

2007 production may represent only a partial year of production. Production data was

not pro-rated to come up with an annual estimate. Some projects starting late in the year

did not see any increase in crude oil production due to enhanced oil recovery operations,

or were unable to measure it. These were noted as "TETT" (Too Early To Tell) in the

O&GJ survey. In a few cases companies did not report crude oil production data to the

O&GJ. The O&GJ did not specify how the production data was to be calculated by the

reporting facilities, so most of it is based on internal oil company reporting which is

consistent with state Oil and Gas Commission reporting requirements.

The O&GJ left it up to the companies to define a "project" when they 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 which are limited in their extent. The company reported two "projects"

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

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

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

listed. These projects are in different geographic 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 3-1) 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 enhanced oil recovery projects in the U.S. EPA believes that

the 2007 data presented in the O&GJ survey are representative of the type and scope of

ER projects that will be operating in 2011.

For this analysis, EPA compiled all the projects listed for miscible and immiscible CO2

floods9 reported in the O&GJ survey. The list of active projects represents a wide cross

section 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

8

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

9

 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.
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

8

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.

0

20

40

60

1972197519781981198419871990199319961999200220052008

Million Tonnes

Val Verde Basin LaBarge

Dakota Gasification McElmo Dome

Bravo Dome Sheep Mtn.

Doe Canyon Jackson Dome

Figure 3-1. Total CO2 used in Enhanced Recovery 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, 200910

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

“injection-only” facility in this subpart. This computation results in 80 ER facilities.

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 Plant TX) supply CO2 for Enhanced Recovery.11

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 injected at each ER project, EPA determined the

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

2007 Inventory of U.S. Greenhouse Gas Emissions and Sinks12 (Inventory). According

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

ER project in Canada.

11 U.S. EPA Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks, 1990-2007,

 Report, EPA 430-R-09-004. Available at:

http://epa.gov/climatechange/emissions/usinventoryreport.html

12 U.S. EPA Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks, 1990-2007,
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

9

to the Inventory approximately 2.08 billion cubic feet per day (bcf) CO2 from natural and

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

two ways, one based on total daily CO2 use combined for all fields in the U.S., and one

based on the total from each source of CO2 used in EOR (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 enhanced recovery as presented in the O&GJ survey and normalized on an

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

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

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

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

sources in the Permian Basin, the CO2 from the Val Verde Gas Plant 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 Plant represents

approximately 5.39% of the CO2 used in Permian Basin Enhanced Recovery projects.

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

volumes used at each facility but notes that it follows the principle that higher production

is a function of higher CO2 injection volumes. The volume of CO2 used in a particular

enhanced recovery project is a function of many factors including:

 Reservoir characteristics –Heterogeneity is one of the most significant design

considerations, along with porosity, permeability, oil gravity, production

history, depth, and reservoir pressure.

 Flood design – The injection design (continuous, simultaneous water and gas,

water alternating gas, and number of injector wells are major factors in overall

CO2 use. Injection well pattern, miscible or immiscible processes, CO2

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

surfactants and additives also influence CO2 use.

 Project age – The stage of the project is the largest 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 to 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 section is

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

value represents the "Net CO2 Utilization" in mcf/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.

 Report, EPA 430-R-09-004. Available at:

http://epa.gov/climatechange/emissions/usinventoryreport.html
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

10

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 DOE13. 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 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 Use. This is because the

age of the project is one of the most significant factors in determining Net CO2

Utilization. The threshold analysis evaluated EOR 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% started before 2000) and

the Threshold Analysis shows the lowest Net CO2 usage (7.2 mcf/bbl) for this

Basin.

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

started before 2000) and the Threshold Analysis shows the highest Net CO2

Utilization (19.2 mcf/bbl) of any basin. The DOE report also indicates that

projects in this basin use higher CO2 volumes (60% hydrocarbon pore volume

(HCPV) versus 30% HCPV) which further increases the Net CO2 Utilization.

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

appropriate estimation of CO2 usage.

Analysis of the enhanced recovery injection data showed five fields with no enhanced

production, and were correspondingly allocated no CO2 use. One additional field showed

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

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

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

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

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

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

recovery 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 enhanced recovery

does not necessarily represent the typical operating conditions of full scale projects

expected in the future, as the number of enhanced recovery operations increase.

13 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
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

11

Table 3-1 shows that nearly all fields (92.5%) injected greater than 1,000 metric tons CO2

per year. At injection reporting thresholds of up to 25,000 metric tons per year

essentially all CO2 (100%) injected is included but not all facilities would report. At an

injection reporting threshold of 25,000 tons per year, 65 of the 80 facilities (81%) would

report. At a 100,000 metric tons per year threshold 97.4% of all CO2 used in enhanced

recovery would be reported from 60% of the facilities. The majority of the 40% of

facilities not covered are characterized in the O&GJ Survey as pilot projects, projects that

have just started, or projects nearing completion.

Table 3-1. Threshold Analysis Based on Amount of CO2 Injected

Threshold Amount of CO2 Injected Number of Facilities

Level

(metric

tons/yr of

CO2

injected)

Total

National

(metric

tons/yr of

CO2

injected)

Total

Number of

U.S.

Facilities

Metric tons/yr

of CO2

Injected

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%

4. Monitoring Methods Considered

This section presents monitoring methods for CO2 injection and GS facilities.

4.1 CO2 Injection

In order to determine the amount of CO2 injected, transferred from offsite, or produced

with oil and gas (at ER operations), an injection 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 standard temperature and pressure (STP) by the

concentration of CO2 in the flow and by the density of 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.

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 general, the CO2 injected for either ER or GS is not 100 percent CO2. Therefore, in

order to determine the portion of the stream that is CO2, the injection facility would

sample the stream and analyze it for its CO2 concentration. EPA has not identified
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

12

specific standards that provide methods to extract samples for analysis. However, it is

common practice in the oil and gas industry to take regular samples of CO2 streams. One

method would be to use “bomb sampling” (a bomb is usually a stainless steel or brass

vessel used to extract samples for lab testing). Once the sample has been collected, it can

be sent to a laboratory for compositional analysis using chromatography. Using the

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

conditions and, using a STP density value for CO2, one can calculate the CO2 quantity in

metric tons. An injection facility would apply the same method in order to calculate the

quantity in metric tons of CO2 transferred onsite from offsite.

4.2 CO2 Production at ER Operations

For an injection facility conducting ER, several steps would be needed in order to

estimate the quantity of CO2 produced with oil 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.

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.

4.3 Fugitive and Vented CO2 Emissions

Fugitive and vented CO2 emissions can occur from surface components located between

the point of transfer onsite and the injection wellhead. To measure or estimate these

emissions, an injection facility could use methodologies provided in the proposed

Petroleum and Natural Gas Systems Reporting Rule (subpart W of the MRR). 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 and describes the
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

13

methodologies provided in subpart W. Note that the compressors may or may not be a

part of this operation depending on how the individual site configures its recycle stream.

Compressors are used to 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.

Table 4-1. Surface Components as 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 driven pneumatic

pump venting4 X

Reciprocating compressor rod

and packing venting X

EOR injection pump X

Centrifugal compressor wet

seal oil degassing venting X

Other fugitive emissions

(Valve, Connector, Openended Line, Pressure Relief

Valve)

X

Notes:

(1) The engineering calculation methods use monitored process operating parameters and either

engineering calculations (in the case of EOR injection pumps) or emission factors provided by the

equipment manufacturer (in the case of 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.

Fugitive 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 gathering pipeline,

valves, connectors, meters, and headers (which are large pipes that mix the oil stream

from multiple wellheads). The procedures provided in subpart W for determining CO2

emissions from all of these sources is equipment count and population factor.
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

14

4.4 CO2 Leakage to the Surface

While the science of quantifying CO2 leakage from GS sites is evolving, it is generally

recognized that, when properly planned and implemented, monitoring methods will be

effective at detecting leakages.

14 15 16 A wide range of techniques for monitoring GS of

CO2 have been used for a number of years in other applications. These techniques may

be used in a GS project to monitor the injected CO2, the surrounding geology, and the

surface conditions. EPA has concluded that a GS facility would be able to propose a sitespecific monitoring plan for leak detection and quantification based on the current

availability of monitoring technologies, even though the methodologies for detecting and

quantifying leakage of CO2 from GS sites have not been standardized. In addition, it is

expected that site characterization and screening will lead to selection of sites that are

suitable for long-term sequestration and that incidences of leaks to the surface may be

infrequent at well-selected and well-managed sites.

The purpose of this section is to describe techniques available and under development for

monitoring the fate of the injected CO2 and verifying GS, including brief discussions of

reservoir modeling and the importance of establishing pre-injection environmental

baselines. The section describes how the techniques may be used for detection and

estimation of CO2 leaks in the subsurface and surface. It is expected that these estimates

may include engineering calculations and direct measurement where technically feasible.

4.4.1 Reservoir Modeling

Reservoir modeling or simulation is a powerful mathematical tool that is used to evaluate

the movement of injected CO2 in the reservoir and is an integral aspect of project design,

planning, site characterization, and monitoring program design.17 A computational

model based on the site characterization and monitoring data can be used to predict the

size and location of the plume. An initial model can be used to forecast how the plume is

expected to move and change. After injection begins, the data from the injection well

and data from the other types of monitoring can feed into the model, to calibrate and

history 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. The model is a three dimensional construct of the

subsurface reservoir, and uses a finite-difference approach in which the reservoir is

14 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).

15 FutureGen Alliance, 2006, “Mattoon Site Environmental Information Volume,” December, 2006.

http://www.futuregenalliance.org/.

16 Note that this document refers to some non-peer-reviewed documents which are publicly available via

the web links provided.

17 DOE/NETL, 2009, “Best Practices for Monitoring, Verification, and Accounting for 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.
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

15

divided into a large number of discreet three-dimensional volumes for analysis. Input

data include reservoir thickness, depth, pressure, porosity, permeability, fluid saturations,

and other parameters. Each three-dimensional volume has its own specific

characteristics. In the case of CO2 injection, 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: models that focus on

faults and fractures, models that focus on the transport of CO2, and geomechanical/flow

models.18 The simulators allow the prediction of the following:

 Temporal and spatial migration of the plume

 Geochemical reactions

 Cap rock and well bore integrity

 Potential leakage pathways and estimates of travel times for these routes

 Effects of unplanned hydraulic fracturing

 Potential leakage near the injector well

 Consequences of wellbore failure

The GEO-SEQ Project Team19 summarized the effectiveness and uncertainly of reservoir

modeling in the following:

Modeling and simulation are an intrinsic part of the design phase of a CO2

injection project. From capacity assessments to estimating travel times for

potential leakage routes, multiphase and multi-component reservoir simulation

provides the basis for defensible decisions and understanding of the system.

However, it is essential that simulation tools are used by competent engineers and

scientists who understand the pitfalls and complexities of subsurface reservoir

simulation. Furthermore, the practice of CO2 injection is immature; there is little

field experience in the physical processes involved, and therefore extra scrutiny

must be given to simulation results.

4.4.2 Environmental Baselines

An essential part of any monitoring program is determining the pre-injection subsurface

and surface environmental baselines against which monitoring results will be compared.

18 DOE, 2009, “Best Practices for Monitoring, Verification, and Accounting for 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.

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

Implementation, GEO-SEQ Project Team: Lawrence Berkeley National Laboratory, Lawrence Livermore

National Laboratory, Oak Ridge National Laboratory, Stanford University, University of Texas Bureau of

Economic Geology, Alberta Research Council, September 30, 2004, Earth Sciences Division, Ernest

Orlando Lawrence Berkeley National Laboratory, Berkeley, CA 94720.

http://www.netl.doe.gov/technologies/carbon_seq/refshelf/GEO-SEQ_BestPract_Rev1-1.pdf.
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

16

Applying monitoring technologies to detect CO2 flux at the surface is a challenge due to

the natural variability of background CO2 concentrations. The CO2 background levels

may vary with location, depth, air temperature, soil temperature, rainfall, time of day, and

season. It can be important to determine the statistical variations of CO2 background

levels and account for these when measuring anomalies that can indicate leaks. In

addition, correlations between CO2 flux and certain environmental parameters (e.g., soil

temperature and moisture, atmospheric temperature, pressure, and wind speed and

direction), can help predict the background CO2 fluxes expected under a given set of

environmental conditions. A leak may be presumed when the monitored CO2

concentrations are significantly higher than the range of natural CO2 concentration

expected under the sampling conditions. The background CO2 data can be collected both

before and during injection operations and comparisons made among widely scattered

sensors sampled at the same time as well as comparisons of samples over time at any one

location. Observations of CO2 concentration gradients with depth, surface CO2 fluxes,

atmospheric CO2 measurements, carbon isotopic compositions and tracers can be used

together to determine if CO2 has escaped the injection zone.

20 21

4.4.3 Monitoring Technologies for CO2 Detection and Quantification

This section describes monitoring technologies for CO2 leak detection and quantification,

in particular, monitoring of injection volumes and pressures, the injection well,

subsurface CO2 plume, vadose zone, soil zone and vegetation, and atmosphere.22

Table 4-2 provides a list of monitoring methods that are being used at CCS projects.23

This section summarizes these technologies and how they may be applied to detect and

quantify leakage, with a focus on detecting and quantifying CO2 movement to the

surface.

Monitoring of Injection Volumes and Pressures

During the injection phase, the volume of CO2 injected and the injection pressure are

commonly continuously measured at injection wells. There can also be monitoring of the

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

Implementation, GEO-SEQ Project Team: Lawrence Berkeley National Laboratory, Lawrence Livermore

National Laboratory, Oak Ridge National Laboratory, Stanford University, University of Texas Bureau of

Economic Geology, Alberta Research Council, September 30, 2004, Earth Sciences Division, Ernest

Orlando Lawrence Berkeley National Laboratory, Berkeley, CA 94720.

http://www.netl.doe.gov/technologies/carbon_seq/refshelf/GEO-SEQ_BestPract_Rev1-1.pdf.

21 Oldenberg, C.M., Jennifer L. Lewicki, and Robert P. Hepple, 2003, "Near-Surface Monitoring Strategies

for Carbon Dioxide Storage Verification," Earth Sciences Division, Lawrence Berkeley National

Laboratory, publication LBNL-54089. http://www.osti.gov/bridge/servlets/purl/840984-

dTw752/native/840984.pdf.

22 The vadose zone is the relatively shallow zone beneath the surface that is not saturated with groundwater.

23 JJ Dooley, CL Davidson and RT Dahowski. 2009. "An Assessment of the Commercial Availability of

Carbon Dioxide Capture and Storage Technologies as of June 2009." Joint Global Change Research

Institute. Pacific Northwest National Laboratory. June 2009. PNNL-18520.
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

17

injection well annulus between the tubing and the long string casing. The annulus in this

diagram is shown in white and the CO2 flow and plume are shown in purple.

Table 4-2: Monitoring Technologies as Deployed at 10 Existing CCS Projects

(Source: JJ Dooley, CL Davidson and RT Dahowski. 2009. "An Assessment of the Commercial

Availability of Carbon Dioxide Capture and Storage Technologies as of June 2009." Joint Global Change

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

Monitoring of the Injection Well

One of the greatest risks for leakage at a GS site is from inadequate wellbore integrity,

especially with the injection well. Mechanical Integrity Testing (MIT) is commonly used

at permitted UIC injection wells to demonstrate that the injection wells can resist the high

pressures of injection, as well as the potentially corrosive nature of the injected CO2.

Periodic external MIT checks the area between the cement and the formation in the long

string casing to detect gaps or fluid flow.24 Should there be a break in the bond between

the cement and the rock of the wellbore, the injected CO2 can make its way vertically to

24 Koplos, Jonathan, et al, 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/carbon-seq/Tech%20Session%20139.pdf.
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

18

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, and 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.25 26 The temperature log helps identify hot spots due to flow from deeper

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 injector 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.

Monitoring of Subsurface CO2 Plume

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

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

information from monitoring wells, and reservoir modeling.

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

propagate downward or laterally through the subsurface, are reflected off of geological

layers, and are subsequently detected and analyzed at the surface by advanced

instrumentation. The method is used to evaluate the structural or spatial configuration of

25 Duguid, Andrew, and John Tombari, 2007, “Technologies for Measuring Well Integrity in a CO2 Field,”

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

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

26 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.

http://www.netl.doe.gov/technologies/carbon_seq/refshelf/MVA_Document.pdf.
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

19

the subsurface, and can also be used in some cases to determine reservoir properties and

fluid content, including the presence of free-phase (but not dissolved) 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 down hole.

In another arrangement called cross-well seismic, both source and detector are down hole

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 intended reservoir. This may include leakage

from/around the injection well, from around older pre-existing wells, or through

geological zones of weakness in the caprock (confining zone).

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 2-D seismic, 3-D/4-D seismic, vertical

seismic profiling, and cross-well seismic. Surface seismic data may be either twodimensional (2-D) or three-dimensional (3-D). Two-dimensional seismic is obtained

with a linear surface arrangement of receivers. The acoustic energy source is from small

explosive charges or from “vibro-seis” trucks. Three-dimensional seismic may provide

better resolution, accuracy, and tracking of the CO2 if it migrates from the storage

reservoir into the overburden.

Three-dimensional (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. Three-dimensional data are

increasingly used in the oil industry, as they allow the mapping of structural details, small

faults, rock properties, and fluid properties. Four-dimensional 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.27 It is a high resolution method that

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

vertical seismic profiling is “walk-away” 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. This is because of

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

27 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.

http://www.netl.doe.gov/technologies/carbon_seq/refshelf/MVA_Document.pdf.
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

20

conditions. This calibration can then be used to better interpret the 2-D and 3-D seismic,

which covers a much larger area.

All these types of active seismic methods can be used to image the free-phase portion of a

CO2 plume under certain subsurface conditions. This method is 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.28 Seismic detection of a CO2 plume in a carbonate (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 and free-phase CO2

are less dense than saline water). Studies have been undertaken to evaluate seismic

plume monitoring in coal beds.29

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

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

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

only image free-phase 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 freephase 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 gas field and the Weyburn ER project.30 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

considerations31 has suggested that CO2 buildups as small as 10,000 to 20,000 tonnes

may be detectable, but amounts would be difficult to quantify, as saturation would remain

a key uncertainty. In practice, results from the Sleipner time-lapse surveys suggest that

repeatability noise (which depends on the accuracy with which successive surveys can be

matched), rather than resolution may be the key parameter in limiting the detection of

small changes of seismic signature due to leakage. Under favorable conditions, less than

1,000 tonnes of CO2 should be detectable at depths less than 1,000 m.

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

28 IPCC, 2005, “Carbon Dioxide Capture and Storage,” Intergovernmental Panel on Climate Change, pg.

237. http://www.ipcc.ch/.

29 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.

http://www.crewes.org/ForOurSponsors/ResearchReports/2002/2002-64.pdf.

30 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.

31 Myer, L. R., Hoversten, G. M., and Gasperikova, E., 2002. Sensitivity and Cost of Monitoring Geologic

Sequestration Using Geophysics. In: Gale, J. & Kaya, I. (eds.) Greenhouse Gas Control Technologies.

Elsevier, 377 – 382. http://www.sciencedirect.com/science/book/9780080442761.
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

21

instrumentation and decipher the results using computational methods. As the

pressurized CO2 moves through the reservoir, it creates microfractures which release

acoustic energy that is detected in three-dimensional space. Passive seismic methods can

be used to track the subsurface plume and the areas of high pressure. They can also be

used to detect where fractures are occurring that might signal breaks in the caprock or

activation of old faults.

Downhole instrumentation is used in monitoring wells to measure temperature, pressure,

conductivity/salinity, and fluid characteristics. The individual measurements are quite

reliable and accurate, but their limitation is that they represent a single point in time and

space. As discussed in the introduction to this section, baseline CO2 levels must be

determined to detect an anomaly. The monitoring wells can be logged periodically with

wireline logs that can be used to detect the 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.32 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 carbonate (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.

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 air contained within the pore space. The CO2

concentration of air samples taken in this zone can be measured using commercially

available infrared gas analyzers (IRGAs), which measure the absorption of specific

32 FutureGen Alliance, 2006, “MatoonMattoon Site Environmental Information Volume.”

http://www.futuregenalliance.org/. http://www.futuregenalliance.org/.
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

22

portions of the infrared spectrum to determine the concentration of CO2 (or other gases)

in the air sample. As discussed earlier in this section, 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.

33 As with

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

accurate, but their limitation is that they represent a single point in time and space.

Soil Zone and Vegetation Testing

The soil zone is generally present within the first few inches to possibly tens of feet

beneath the surface, the uppermost layer of the vadose zone. The soil zone is the fertile

portion that can retain 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. 34 The approach may consist of a grid of accumulation chambers in which

the CO2 flux is periodically measured.35 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

33 FutureGen Alliance, 2006, “MatoonMattoon Site Environmental Information Volume.”

http://www.futuregenalliance.org/

34 FutureGen Alliance, 2006, “MatoonMattoon Site Environmental Information Volume.”

http://www.futuregenalliance.org/.

35 Oldenberg, C.M., Jennifer L. Lewicki, and Robert P. Hepple, 2003, “Near-Surface Monitoring Strategies

for Carbon Dioxide Storage Verification,” Earth Sciences Division, Lawrence Berkeley National

Laboratory, publication LBNL-54089. http://www.osti.gov/bridge/servlets/purl/840984-

dTw752/native/840984.pdf.
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

23

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 less than 5 micrograms per square meter per second.

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

year distributed across an area of 150 square kilometers.

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

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

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

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

CO2 quantification. Variations of this method are commonly used in measuring methane

flow rates from equipment leaks.36 A tent or bag is constructed above a known leakage

site. An inert gas such as nitrogen is conveyed through the bag at a known flow rate.

Once the carrier gas attains equilibrium, a gas sample is obtained from the bag and the

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

purge flow rate through the enclosure and the concentration of methane in the outlet

stream. Table 4-3 illustrates the general approach to quantify the leak.

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

Inlet Flow of

Conveyed Test Gas

(cu. ft./minute)

Measured 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. 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 (CIR) or hyperspectral imaging to detect changes to vegetation coloration

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

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

36 Envirotech Engineering, 2007, “Review and Update of Methods Used for Air Emissions Leak Detection

and Quantification,” February 5th, 2007. http://www.envirotecheng.com/
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

24

that vegetation in the vicinity of a leak may be negatively impacted, but vegetation

farther from a leak may be positively impacted.37

Atmospheric Monitoring

The atmosphere above a GS site may be monitored with an array of 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. An additional challenge is to distinguish

between natural CO2 fluxes and CO2 flux due to leakage from geologic storage.

38

CO2 detectors are commercially available for short closed-path and short open-path

(point) measurements and long open-path (radial line) measurements. Similar detectors

have been integrated into stationary, mobile, and airborne monitoring packages that are

commonly used in combination with high-resolution global positioning system (GPS) to

detect and quantify methane 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 infrared gas analyzers (IRGAs, including Fourier transform

infrared (FTIR) and non-dispersive infrared (NDIR) 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 (OTM 10) -- Optical Remote Sensing for Emission

Characterization from Non-Point Sources.

39 The protocol describes three methodologies,

each for a specific use:

 Horizontal radial plume mapping (for locating the source of emissions or hot

spots)

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

from an area fugitive emission source)

 One-dimensional radial plume mapping (for profiling pollutant concentrations

along a line-of-sight which is downwind of an 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:

37 Montana State University , 2008 http://etd.lib.montana.edu/etd/2008/rouse/RouseJ1208.pdf

38 Atmospheric monitoring and verification technologies for CO2 storage at geosequestration sites in

Australia, David Etheridge, Ray Leuning, Donald de Vries, Kevin Dodds, Cathy Trudinger, Colin Allison,

Paul Fraser, Fred Prata, Cirilo Bernardo, Mick Meyer, Bronwyn Dunse and Ashok Luhar, October 2005

CO2CRC Report No: RPT05-0134, Prepared by CSIRO Marine and Atmospheric Research for CANSYD

Australia and the CRC for Greenhouse Gas Technologies (CO2CRC). http://www.co2crc.com.au.

39 http://www.epa.gov/ttn/emc/prelim.html
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

25

 Open-Path Fourier Transform Infrared Spectroscopy

 Ultra-Violet Differential Optical Absorption Spectroscopy

 Open-Path Tunable Diode Laser Absorption Spectroscopy

 Path-Integrated Differential Absorption LIDAR

Figure 4-1 illustrates vertical radial plume mapping using path-integrated optical remote

sensing (PI-ORS). EPA is also testing mobile versions of these systems for methane leak

detection in which the detectors are integrated onto ground or airborne vehicles with

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

and correctly locate the methane leak.

Other atmospheric monitoring for leakage detection and quantification approaches

include tracer gases and CO2 isotopic measurements. After adding a tracer gas to the

CO2 prior to injection, detectors focused on those tracer gases accomplish leak detection.

Examples of tracer gases include methane (CH4), CO2 with radioactive carbon 14,40 and

CO2 with carbon 13 and oxygen 17. On the downside, the cost of the tracer gas in

volumes required for GS might be prohibitive. Alternatively, CO2 isotopic measurements

might be 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 sequestered fluids will improve

detection sensitivity. 41 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.

40 Potential method for measurement of CO2 leakage from underground sequestration fields using

radioactive tracers, P. P. Bachelor, J. I. McIntyre, J. E. Amonette, J. C. Hayes, B. D. Milbrath, P. Saripalli,

Pacific Northwest National Laboratory, P. O. Box 999, Richland, WA, Journal of Radioanalytical and

Nuclear Chemistry, Vol. 277, No.1 (2008) 85–89.

41 Continuous Greenhouse Gas and Isotopic CO2 Measurements via WS-CRDS-based Analyzers:

Investigations in Real Time Monitoring at CO2 Geological Storage Sites, Paul Steele, Zoë Loh, David

Etheridge, Ray Leuning, Paul Krummel, Aaron Van Pelt, Centre for Australian Weather & Climate

Research/CSIRO Marine & Atmospheric Research, Energy Transformed Flagship. www.cmar.csiro.au.
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

26

Figure 4-1. Example of a Vertical Radial Plume Mapping Configuration Setup

(Pathlength-defining component (pdc) is used to denote the component on the other end

of the optical path from the PI-ORS instrument. Depending on the instrument selected,

this could be a source, detector, mirror, or other reflecting object.)

Source: EPA Other Test Method 10. http://www.epa.gov/ttn/emc/prelim.html.

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, threedimensional 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.
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

27

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

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.42 Instrumentation includes the LIDAR, a digital mapping camera, a color

video system, and an optical guidance system. The airplane flies a survey over the

pipeline at an altitude of about 1,000 feet, 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.

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

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

28

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

currently under development for commercial CO2 applications. Oldenburg43 reports that

“the advantages of Raman LIDAR and DIAL are that these are rapidly developing

technologies with potential applications over multiple spatial scales. The main

disadvantages are that they are expensive and measure average concentration over a path

length, which means that a large localized perturbation cannot be distinguished from a

small change in the bulk mean concentration.” Airborne methods may also be integrated

with ground methods to provide the best approach for quantification. Airborne methods

could be used to map out the 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.

4.4.4 Leak 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

subsurface 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 which has migrated into the shallow overburden (e.g., potable aquifers), into the soil

or seabed and, ultimately, into the seawater or atmosphere. Shallow monitoring includes

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.

Monitoring Near the Seafloor44

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

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

detect reflections of acoustic signals produced from electromagnetic sources which

penetrate about 100 meters beneath the seafloor. Both 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

2D 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 3D 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

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

for Carbon Dioxide Storage Verification,” Earth Sciences Division, Lawrence Berkeley National

Laboratory, publication LBNL-54089. http://www.osti.gov/bridge/servlets/purl/840984-

dTw752/native/840984.pdf.

44 Monitoring Technologies for the Geological Storage of CO2, Technology Status Report, DTI/Pub URN

05/1032, Cleaner Fossil Fuels Programme, Didcot, Oxfordshire, UK, March 2005.

http://www.co2net.eu/public/reports/tsr025abc.pdf.
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

29

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 kHz, have been widely employed on the continental

margins, and have also been used to map glacial and other sedimentary deposits in

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

monitoring. They offer high resolution profiling of seabed morphology but also have

sufficient depth penetration to identify anomalous features in the subsurface, for example

zones of acoustic blanking interpreted as signifying high gas saturations. The techniques

can also permit direct 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,45

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

Sidescan sonar is one of the most accurate systems for imaging large areas of the ocean.

It is a towed system that normally functions when it is moving in a straight line.

Somewhat similar to side looking airborne radar (SLAR), side scan transmits a specially

shaped acoustic beam 90 degrees from the support craft's path, and out to each side. This

beam propagates into the water and across the seabed. The roughness of the floor of the

ocean and any objects lying upon it, reflect some of the incident sound energy back in the

direction of the sonar. The sonar is sensitive enough to receive these reflections, amplify

them and send them to a sonar data processor and display. Images produced by quality

sonar systems are highly accurate, often photograph-like in quality, and can be used to

delineate even very small (<1 cm) objects, perhaps resolving features an order of

magnitude or more smaller than conventional seismic reflection data, and offering the

chance to image gas escape structures (pockmarks) and even free gas in the water

column. Naturally occurring pockmarks and shallow gas chimneys may act as potential

pathways for future CO2 seepage. The shape of the beam in side scan is crucial to the

formation of the final image. Typically, a side scan acoustic beam is very narrow in the

horizontal dimension (~ 0.1 degree) and much wider (40-60 degrees) in the vertical

dimension.

Multibeam echo 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 also the echo maximum amplitude

45 A towfish is an underwater equipment package towed a few hundred feet above the seafloor using an

umbilical cable connected to a support craft.
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

30

over time. This allows the detailed mapping of the seafloor bathymetry and inferences

about the nature of the sediment.

Electrical and electromagnetic (EM) methods offer the theoretical potential for low

resolution, low-cost, site monitoring. The techniques utilize the propagation of electrical

or electromagnetic fields within the earth to map subsurface variations in electrical

conductivity. A distinction can be made between electric methods which use zero

frequency (DC) or very low frequency methods where no EM induction occurs and EM

techniques that utilize 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 Logging (SBL) and Offshore Hydrocarbon

Mapping (OHM). The systems consist of towed Controlled Source (CS) transmitters and

static sea-bed receiver arrays. The source is a horizontal electric dipole (HED), towed

behind an instrumented towfish on a neutral buoyant streamer. During a survey the

source is towed around and through the array of receivers which each measure 2 or 3

orthogonal components of the 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 UK 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 dissolved

inorganic carbon (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.
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

31

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

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

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

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

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

sampling, allowing fluid aliquots to be withdrawn for an almost unlimited number of

analytical techniques without degassing the remaining fluid.

4.5 Detection Limits and Accuracy of Various Technologies

Each of the monitoring methods discussed above involves the application of technologies

to detect and potentially quantify CO2 movement or leaks in the subsurface or

atmosphere. Monitoring is effective in detecting the presence of both subsurface and

atmospheric leakage. However, methods of leak quantification at a site are generally at

an earlier stage of evaluation, and this is an area needing additional study.

As discussed above, leak quantification can be carried out through tenting methods if the

surface area or location of the leak is known. Other quantitative methods potentially

include wireline log analysis, well pressure analysis, 3-D or cross-well seismic analysis

and modeling, and plume dimension analysis. The ability to detect or quantify a plume

or leak is dependent upon factors such as the rate of leakage, its depth and location, the

atmospheric 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

accuracy of the method. Table 4-4 presents this information for a number of technologies

that can potentially be used for leak quantification. 46 47 48 49 The terminology in the table

is as follows:

 Sampling rate. The frequency of sampling.

 Detection range. The instrument detection limit or a range of instrument

detection limits in appropriate units for the instrument.

46 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

47 Oldenberg, C.M., J.L. Lewicki, and R.P. Hepple, 2003, “Near-Surface Monitoring Strategies for

Geologic Carbon Dioxide Storage Verification,” Report #LBNL 54089, Lawrence Berkeley National

Laboratory, Berkeley, CA, October 30, 2003. http://www.osti.gov/bridge/servlets/purl/840984-

dTw752/native/840984.pdf

48 IPCC, 2006, “2006 IPCC Guidelines for Greenhouse Gas Inventories, “ Intergovernmental Panel on

Climate Change, Simon Eggleston, ed. http://www.ipcc-nggip.iges.or.jp/public/2006gl/index.html.

49 DOE, 2009, “Best Practices for Monitoring, Verification, and Accounting for 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
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

32

 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 4-4. 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 Establishedand reliable.

3-D seismic 1, 4 Periodic

surveys

NA

1,000 to

10,000 metric

ton

accumulations

NA

+/-20% of

plume

vol.

Established

technology;

expensive,

resolution

decreases

with depth.

Cannot

image

dissolved

CO2.

Eddy

Covariance 1, 2, 4 Continuous

>10

microgram/

m

2

/ sec

>45

microgram/sq.

m/sec

5 - 30% of

the CO2 flux NA

Commercially

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

concentration

NA

Established

technology;

Portable and

inexpensive.

Accumulation

Chamber 2, 3, 4 Continuous

>0.46

micrograms/

m

2

/ sec

NA 10% of the

CO2 flux

12.5% of

the CO2

flux

Commercially

available

technology;

Many

sampling

stations

needed;

average data

from multiple

chambers;

samples

small area;

signal to

noise

challenge.
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

33

Raman

LIDAR and

DIAL

2, 4 Continuous

or periodic

<1ppmv to

several %

CO2

NA

1 - 5% of the

CO2

concentration

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.

http://www.onepetro.org/mslib/servlet/onepetropreview?id=SPE-102833-MS&soc=SPE

2. Oldenberg, C.M., J.L. Lewicki, and R.P. Hepple, 2003, Near-Surface Monitoring Strategies for

Geologic Carbon Dioxide Storage Verification, Report #LBNL 54089, Lawrence Berkeley National

Laboratory, Berkeley, CA, October 30, 2003. http://www.osti.gov/bridge/servlets/purl/840984-

dTw752/native/840984.pdf

3. IPCC, 2006, 2006 IPCC Guidelines for Greenhouse Gas Inventories, Intergovernmental Panel on

Climate Change, Simon Eggleston, ed. http://www.ipcc-nggip.iges.or.jp/public/2006gl/index.html.

4. DOE, 2009, Best Practices for Monitoring, Verification, and Accounting for 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
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

34

Attachment A

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.

50

The process will convert CO2 into carbonic acid, which will be made into carbonate. The

carbonate will be combined with calcium and magnesium from seawater to make calcium

carbonate and magnesium carbonate for the cement.51 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 United States. Carbon dioxide is

used widely throughout the food and beverage industry for a variety of applications

including:

– Carbonation of soft drinks

– Beer and wine production

– Decaffeination of coffee and tea

– pH adjustment and shelf life lengthener for dairy products

– Frozen food production

– 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.

52 53

50 Engineering News-Record, New Green-Concrete Process Combines Seawater, Flue Gas, February 18,

2009, http://www.calera.biz/pdf/ENR.com%2002-18-09.pdf (accessed July 26, 2009)

51 Biello, David. Cement from CO2: A Concrete Cure for Global Warming?, Scientific American,

http://www.calera.biz/pdf/scientifc_american%20copy.pdf (accessed July 26, 2009)

52 Linde Gas, AGA and the Pulp and Paper Industry,

http://www.aga.fi/international/web/lg/fi/likelgagafi.nsf/repositorybyalias/pulp_paper_industry/$file/AGA_

and_Pulp_Paper_Industry.pdf (accessed July 22, 2009)

53 US Patent 6200416 - Recycled paper production process which incorporates carbon dioxide, March 2001

http://www.patentstorm.us/patents/6200416/description.html (accessed July 26, 2009)
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

35

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.54

Metal Fabrication. Carbon dioxide 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.55 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. Carbon dioxide 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 carbon dioxide is used as a blowing agent instead of environmentally hazardous

substances. Carbon dioxide is a physical blowing agent with properties desired for ideal

foaming, while simultaneously fulfilling many requirements related to quality, efficiency,

and ecology.

Fire Suppression. Carbon dioxide fire extinguishers are used for Class B fires (involving

flammable and volatile liquids) and Class C fires (involving electrical equipment).

54 BOC Gases, Carbon Dioxide http://www.bocgases.com/products_and_services/by_product/carbon_dioxide/index.asp (accessed July 27, 2009)

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

welding (GMAW).
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

36

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 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. Carbon dioxide 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 greenhouse gas / carbon sink. Also of strong interest is the usage of algae as a

source of feedstock material for the production of biodiesel, and perhaps fermentation.

Carbon dioxide is an ingredient used by algae for normal growth, during photosynthesis.

The process is being studied at various pilot projects in the U.S. and elsewhere.

Pressurized Gas. Carbon dioxide 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. Carbon dioxide is currently used for various processes in the

chemical industry, including but not limited to, the production of:

 • Urea (from ammonia)

 • Methanol

 • Ethanol

 • Sodium Bicarbonate

Pharmaceutical Processes. Pharmaceutical processes may use CO2 as a less toxic

alternative to organochlorides or more traditional solvents
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

37

Attachment 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 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 Murfin Drilling KS 3

Lockhart Crossing Denbury Resources LA NR

Charlton 30-31 Core Energy MI 75

Charlton 6 Core Energy MI 10

Dover 33 Core Energy MI 75

Dover 35 Core Energy MI 286

Dover 36 Core Energy MI 195

Brookhaven Denbury Resources MS 3,100

East Mallalieu Denbury Resources MS 1,800

Eucutta Denbury MS 3,000

Lazy Creek Denbury Resources MS 250

Little Creek Denbury Resources MS 1,650

Martinville Denbury MS 830

McComb Denbury Resources MS 1,650

Smithdale Denbury Resources MS 600

Soso Denbury Resources MS 1,700

Tinsley Denbury Resources MS NR

West Mallalieu Denbury Resources MS 6,200

North Hobbs Occidental NM 6,300

Vacuum Chevron NM 2,950

Vacuum ConocoPhillips NM 5,200

Bradley Unit Merit Energy OK 600

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

Adair San Andres Unit Hess TX 900

Anton Irish Occidental TX 4,000

Cedar Lake Occidental TX 2,860

Central Mallet Unit Occidental TX 2,100

Cogdell Occidental TX 5,900
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

38

Cordona Lake XTO Energy Inc. TX 400

Dollarhide (Clearfork "AB") Unit Pure Resources TX 1,970

Dollarhide Devonian Unit Pure Resources TX 124

East Ford 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

Hanford Fasken TX 300

Hanford East Fasken TX 45

Hansford Marmaton Stanberry Oil TX 102

Igoe Smith Occidental TX 440

Levelland Occidental TX 950

Mabee Chevron TX 2,000

Means (San Andres) ExxonMobil TX 8,700

Mid Cross-Devonian Unit Occidental TX 296

N. Cross-Devonian Unit Occidental TX 835

North Cowden Demo. Occidental TX 80

North Dollarhide Occidental TX 1,000

North Perryton Chaparral Energy TX 170

North Ward Estes Whiting Petroleum TX 700

Reinecke Pure Resources TX 830

S. Cross-Devonian Unit Occidental TX 5,790

SACROC Kinder Morgan TX 24,227

Salt Creek Occidental TX 6,600

Seminole San Andres Unit -

Main Pay and ROZ Hess TX 24,350

Sharon Ridge Occidental TX 400

Slaughter Apache TX 4,580

Slaughter (5 Units) Occidental TX 3,800

Slaughter Sundown Chevron TX 4,747

South Cowden ConocoPhillips TX 250

South Welch Occidental TX 865

T-Star (Slaughter Abo) Occidental TX 2,100

Twofreds Great Western Drilling TX 170

Wasson (Cornell and Mahoney

Units) XTO Energy Inc. TX 2,250

Wasson (4 Units) Occidental TX 44,325

West Welch Occidental TX 0

Yates Kinder Morgan TX 6,280

Greater Aneth Resolute Natural Resources UT 400

Greater Aneth Area ExxonMobil UT 3,000
General Technical Support Document for Injection and Geologic Sequestration of

Carbon Dioxide: Proposed Rule for Mandatory Reporting of Greenhouse Gases

39

Lost Soldier Merit Energy WY 7,221

Patrick Draw Monell Anadarko WY 3,000

Salt Creek Anadarko WY 6,000

Sussex Anadarko WY NR

Wertz Merit Energy WY 4,019