TECHNICAL SUPPORT DOCUMENT FOR
C02 SUPPLY: PROPOSED RULE FOR
MANDATORY REPORTING OF
GREENHOUSE GASES


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CONTENTS

1.	Source Description	3

a.	Overview	3

b.	Definition of Source Category	4

c.	Total Emissions	5

d.	Types of Emissions to be Reported	7

2.	Options for Reporting Threshold	7

a.	Overview of Options Considered	7

b.	CO2 Production Well Facilities	9

c.	CO2 Capture Facilities	10

3.	Monitoring Methods Considered	11

4.	Procedures for Estimating Missing Data	13

a. CO2 Capture Facilities and CO2 Production Facilities	13

5.	QA/QC and Data Verification Requirements	15

a.	General QA/QC Requirements	15

b.	Equipment Maintenance	15

c.	Data Management	16

d.	Calculation Checks	17

e.	Data Verification	17

6.	Data to Be Reported	17

a.	Direct Measurement of C02 Supply for C02 Capture and C02 Production Well
Facilities	17

b.	Additional Data for Verification	18

c.	Additional data to be retained onsite (recordkeeping)	18

7.	ATTACHMENTS	19

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1. Source Description

Preliminary estimates indicate that the amount of CO2 captured from industrial processes
and natural sites and used for enhanced oil recovery (EOR) is approximately 39
MMTC02e. An additional 1.6 MMTCC^e is estimated to be captured for non-EOR
applications (EPA 2008). Inclusion of CO2 suppliers in a mandatory GHG reporting
program would allow for the tracking of the total supply of CO2 being used in the
economy, whether it is for EOR, or any number of emissive end uses, such as beverage
manufacturing. The successful implementation of any future policies or programs for
geologic sequestration will rely on knowing the total potential CO2 that has been supplied
to the economy.

There are potentially three different entities that might be the point of reporting for CO2
supply: CO2 capture facilities, natural CO2 production wells, and transport systems (e.g.,
CO2 pipelines). This technical support document attempts to address issues associated
with incorporating CO2 supply in a mandatory reporting system. This document focuses
on reporting of CO2 supply. Although not the focus of this document, some options for
quantifying fugitive emissions at capture and production sites are also discussed.

a. Overview

Processes to which CO2 capture could be applied include fossil fuel-fired electric power
plants, natural gas processing plants, cement kilns, iron and steel mills, ammonia
manufacturing plants, petroleum refineries, petrochemical plants, hydrogen production
plants, and other combustion and industrial process sources. Carbon dioxide is also
produced commercially for use in EOR from natural underground CO2 reservoirs, and
produced commercially for use in industrial gas applications (e.g., food production,
chemical manufacturing).

Carbon dioxide is currently being produced and captured in the United States for the
purposes of C02-based Enhanced Oil Recovery (EOR). EOR involves injecting CO2 into
injection wells at well fields for the purposes of increasing crude oil production. Some of
the injected CO2 is recovered with and separated from the produced oil and then
recompressed and reinjected into the well field. The CO2 being used in EOR is primarily
produced from naturally-occurring underground CO2 reservoirs, but is also captured from
natural gas processing plants and ammonia plants. There are approximately 80 operating
EOR sites in the United States that are injecting CO2. However, there are no operating
CO2 storage sites in the U.S.1

Pipelines could also be considered a point of reporting for CO2 supply. Transport systems
carry CO2 captured at industrial facilities and CO2 production well facilities and transport
it to an end user (e.g., industrial facilities or EOR operations). Based on data from the
Department of Transportation's Office of Pipeline Safety, there were approximately

1 Appendix A is a Summary of Carbon Capture, Injection, and Storage Research and Demonstration
Projects developed by the National Energy Technology Laboratory.

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3,740 miles of CO2 transport pipelines operating in the United States in 2006, operated by
approximately 27 separate business entities (some of which are subsidiaries of parent
companies). Pipelines operated by five of these business entities were inactive in 2006,
with no CO2 being transported.2

b. Definition of Source Category

For CO2 supply, monitoring and reporting procedures depend on the type and purpose of
facility operations. The monitoring and reporting procedures differ by the following
three source categories:

•	CO2 Capture Sites

•	CO2 Production Well Sites

•	Transport Systems

Each of these source categories is described below.

CO? Capture Sites

Capture of CO2 can occur at industrial facilities (e.g., ammonia production plants, natural
gas processing plants) and combustion source facilities (e.g., electric power or steam
production). The source category for CO2 capture is defined as production process units
that capture a carbon dioxide stream for purposes of supplying carbon dioxide for
commercial applications.

In most cases, identification of the CO2 capture facility and the facility from which the
CO2 is captured is straightforward. Individual CO2 capture facilities are typically
associated with industrial or combustion sites (e.g., stationary source electric power
production, cement production, ammonia production). The installations from which the
CO2 is being captured are readily identifiable as a facility, and given their generally
larger size (e.g., cement production.), would likely already be included in a reporting
program However, note that the CO2 capture process is a separate and distinct source
category from the process from which the CO2 is captured, even if owned and operated
by the same facility, and could therefore be subject to different reporting thresholds.

Also, commercial industrial gas suppliers may establish CO2 capture and processing
plants adjacent to an industrial or combustion facility that generates CO2 (e.g., an
ammonia plant) and in this case the facility generating the CO2 and the facility capturing
the CO2 may be two separate and distinct legal entities and also two separate and distinct
reporting facilities. In either case, the CO2 capture process may be a potential facility
subject to reporting for the purposes of reporting CO2 supply.

CO? Production Well Sites

2 Department of Transportation's Office of Pipeline Hazardous Liquid Annuals Data Report.
http://ops.dot.gov/stats/DT98.htm

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The source category for CO2 production is defined as carbon dioxide production wells
that drill in the earth to extract a carbon dioxide stream from a geologic formation or
group of formations which contain deposits of carbon dioxide. The production of CO2
from natural CO2 formations is categorized separately from "CO2 capture," because of
the different methods associated with producing and quantifying CO2 at these facilities.
Production of CO2 from natural formations involves extracting a CO2 stream from the
natural formation using CO2 production wells and subsequent processing of the CO2.

For the purposes of defining a "facility" a CO2 production well means any hole drilled in
the earth from which a carbon dioxide stream is extracted. A CO2 production well facility
could then be defined as one or more carbon dioxide production wells that are located on
one or more contiguous or adjacent properties, which are under the control of the same
person (or persons under common control). Under this definition, carbon dioxide
production wells located on different oil and gas leases, mineral fee tracts, lease tracts,
subsurface or surface unit areas, surface fee tracts, surface lease tracts, or separate surface
sites, whether or not connected by a road, waterway, power line, or pipeline, would be
considered part of the same CO2 production well facility.

Transport Systems

Transport systems carry CO2 captured at industrial and combustion facilities and CO2
production well facilities and transport it to an end user (e.g., industrial facilities or EOR
operations). Transport systems include CO2 pipelines and associated surface equipment
(e.g., compressors, pumps, valves, flanges). At this time, the majority of CO2 transported
for commercial use (e.g., to EOR operations) is transported by pipeline.

Pipelines could be considered for inclusion in a mandatory reporting program for the
purposes of reporting CO2 supply. The primary challenge with including transport
systems in a reporting program would be defining a facility. One option considered for
defining the facility is a contiguous pipeline owned and operated by a single business
entity. Another option for reporting of CO2 supply from a pipeline might be to require
corporate-level reporting. This would avoid having to explicitly define a facility, while
still ensuring that all CO2 transported, including fugitive emissions from transport, would
be reported.

For purposes of this background document, transport facilities were not considered the
most likely candidates for reporting due to the difficulty in defining a facility and
potentially complex resource ownership issues with pipelines. One disadvantage of
exempting transport systems from reporting would be that data would not be available on
the amount of CO2 actually transported in the CO2 pipeline system. These data would
potentially be useful for quality assurance purposes. For example, discrepancies between
the total amount of CO2 reported captured and the total amount of CO2 reported injected
and stored could not be as easily resolved in the absence of data from CO2 transport
systems.

c. Total Emissions

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The U.S. GHG Inventory includes a discussion of the amount of CO2 captured or
produced for EOR and injected at the approximately 80 operating EOR sites in the
United States.3 The discussion in the U.S. GHG Inventory identifies the amount of CO2
produced annually from natural CO2 sources for injection for EOR and the amount of
CO2 captured from natural gas processing plants and ammonia plants for injection for
EOR. Preliminary estimates indicate that the amount of CO2 captured from industrial
process and natural sites and used for EOR is, 39.0 MMTC02e. According to the U.S.
GHG Inventory, an additional 1.6 MMTC02e is captured and used for non-EOR
applications, for example chemical manufacturing and food production. Further research
conducted in support of this rulemaking identified four additional combustion process
facilities (coal-fired electric power plants) that are capturing CO2. Data for these
facilities indicates that an additional approximately 511,600 mtC02e per year are being
captured for use as food-grade CO2 (three plants) and for production of soda ash (one
plant.)4

A total of 31.4 MMTC02e were produced from natural CO2 sources in 2006 and a total
of 7.0 MMTC02e were captured from natural gas processing plants and ammonia plants
in 2006, for injection for EOR. Of the 7.0 MMTC02e, 6.3 MMTC02e is from gas
processing and 0.7 MMTC02e was captured from one ammonia plant in 2006 (a second
ammonia plant commenced capturing CO2 in 2007). Time series data for CO2 production
and capture for injection for EOR are included in Table 1. Table 1 is reproduced from
Table 3-45 of the 1990-2006 U.S. Inventory. Time series data for CO2 capture for food-
grade and industrial-grade CO2 (used for chemical production) are included in Table 2.
The facilities in Table 2 include those facilities listed in Table 4-41 of the 1990-2006
Inventory, as well as the additional facilities identified during this effort.

Table 1: Potential Emissions from CO2 Capture (l,000mtCO2e)

Year

1990 19951 2000 2001 2002 2003 2004 2005 2006

Acid Gas
Removal
Plants 4,832

Naturally
Occurring

C02 20,811

Ammonia
Production

Plants	0

3,6721 2,264 2,894 2,943 2,993 3,719 5,992 6,997

22,547

23,149 23,442 22,967 24,395 27,002 28,192 31,359

6761 676 676 676 676 676 676 676

3	U.S. Inventory 1990-2006: Box 3-3: Carbon Dioxide Transport, Injection, and Geological Storage

4	http://www.co2captureandstorage.info/cont northamerica.php

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Total

25,651126,904126,098 27,020 26,595 28,073 31,405 34,868 39,041

Table 2: CO2 Capture for non-EOR Applications (l,000mtCO2e)

Year

1990 1

1 1995 1

1 2000

2001

2002

2003

2004

2005

2006

C02

Captured

1,768 |

1 1,890 |

1 1,933

1,341

1,501

1,823

1,710

1,833

2,091

d. Types of Emissions to be Reported

In a mandatory reporting system where industrial facilities and CO2 production well
facilities are reporting the amount of CO2 that they supply to the market, the amount of
CO2 reported could be equal to the total amount of CO2 captured or extracted, or the
amount of CO2 transferred offsite, depending upon the available data. Reporting on the
amount captured or extracted would be the most accurate estimate of total CO2 supply,
because it would account for total CO2 prior to any onsite purification, processing, and
compression of the gas. The amount of CO2 available for sale (i.e., for transfer offsite to
commercial customers) would be the total captured or extracted, less any fugitive
emissions resulting from these processes. Note that it is assumed that the entire amount
of the captured or extracted CO2 that is transferred off site is assumed to be emitted to the
atmosphere from downstream systems in which the CO2 is used.

Fugitive CO2 emissions from capture or production of CO2 include both unintentional
and intentional releases. Fugitive emissions may arise from leakage of CO2 from surface
equipment such as flanges, valves, and flow meters. Emissions could also arise from
compressor seal vents, CO2 dehydrator vents, and other equipment in which produced or
captured CO2 is handled or processed.

Stationary combustion emissions (CO2, CH4 and N2O) associated with CO2 supply would
be related to fossil fuel-fired engines and turbines used to operate pumps, compressors,
and other equipment, and also related to fossil fuel-fired combustion systems to provide
process heat and/or electricity, including, for example, energy needed to heat amines used
to separate CO2 from gas streams. GHG emissions from combustion sources are
discussed in the Stationary Combustion Technical Support Document (EPA-HQ-OAR-
2008-0508-004) and are not discussed further here.

There may be specific types of operations in which the produced CO2 would also have a
CH4 component (but this is considered to be unlikely). However, any non-CC>2
emissions are expected to be low so they are not considered further here.

2. Options for Reporting Threshold
a. Overview of Options Considered

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The options for reporting threshold for CO2 supply are summarized in Table 3, and
expanded upon in the sections below.

Table 3. Summary of Options Considered

Source

Description of Option

Production

Option 1

All CO2 production well facilities could be required to report the amount
of CO2 extracted and the amount of CO2 transferred off site.

Option 2

A reporting threshold could be set based on the amount of CO2 produced.
CO2 production well facilities that produce less than the threshold amount
of CO2 annually would not be required to report

Capture

Option 1

All CO2 capture facilities could be required to report all CO2 captured and
the amount of CO2 transferred off site.

Option 2

Set a reporting threshold for CO2 capture facilities. CO2 capture facilities
that capture less than the threshold amount of CO2 annually would not be
required to report.

There were multiple options considered for including CO2 supply into a threshold
analysis, including:

•	Should EPA set a reporting threshold for CO2 capture and CO2 production well
facilities based on the amount of CO2 supply, or should EPA require that all CO2
capture and CO2 production well facilities report?

•	Should CO2 capture and CO2 production well facilities be required to separately
report the amount of CO2 supply and the onsite fugitive GHG emissions, or
should CO2 capture and CO2 production well facilities be required to only report
the amount of CO2 supply? Because this document focuses exclusively on the
supply of CO2 to the economy, and not fugitive emissions from the entire chain of
carbon dioxide capture, transport, injection and storage, fugitive emissions were
not explicitly addressed in the above options. Note, however, that if the total CO2
extracted is reported, this would implicitly include any subsequent fugitive
emissions from operations downstream of extraction.

•	An issue not explicitly addressed in this document, but which is relevant for
facilities where CO2 is captured, is whether the emissions reporting threshold for
the facility should assume that no carbon capture occurs, or whether the reporting
threshold for the facility should be based on the net emissions from the facility
[i.e., should the facility threshold determination be based on gross GHG emissions
or net GHG emissions?]5.

5 Note that the facility from which the carbon is captured (e.g., an ammonia plant) may be a different legal
entity, and a separate facility, than the facility that is capturing the C02 (e.g., a commercial industrial gas
supplier.)

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Allowing a facility from which CO2 is being captured to incorporate the CO2
capture into the facility emissions reporting threshold analysis suggests that that
CO2 is never emitted to the atmosphere. However, in order to know whether this
CO2 is ultimately emitted, the facility from which the carbon is being captured
(e.g., a utility) would have to know the end use of the CO2 (i.e., whether it is used
for emissive or non-emissive purposes). Due to the fact that the use of a facility's
net emissions to determine emissions reporting threshold applicability is not
transparent, the fact that net emissions at the facility could change significantly on
a year to year basis depending on the capture operations, and the fact that
facilities may not know the end use application of the CO2, this is likely not a
favorable approach.

b. CO2 Production Well Facilities

Option 1 (Production)

Under Option 1, all facilities producing CO2 from natural CO2 formations for the
purposes of injection (e.g., EOR), for storage, or for other purposes would pass the
threshold and report the amount of CO2 extracted and the amount transferred offsite. It is
estimated that CO2 produced from each CO2 production well facility is significantly
greater than any commonly considered threshold level (Table 4). CO2 production from an
individual CO2 production well facility ranged from about 883,000 mtCC^e annually to
over 18 MMTCC^e annually.

Table 4. Threshold Analysis Based on Quantity of CO2 Extracted at CO2 Production
Well Facilities













Number













Percent of

of

Percent of



Threshold

Total

Number

mtC02e/

Emissions

Facilities

Facilities

Source

Level

Production

of

yr over

over

over

over

Category

(mtC02e)

(mtC02e)

Facilities

Threshold

Threshold

Threshold

Threshold

Extraction

1,000

31,358,853

4

31,358,853

100%

4

100%

from Natural

10,000

31,358,853

4

31,358,853

100%

4

100%

C02

25,000

31,358,853

4

31,358,853

100%

4

100%

Formations

100,000

31,358,853

4

31,358,853

100%

4

100%

Option 2 (CO2 Production Well Facilities)

Under Option 2, EPA could set a reporting threshold based on the amount of CO2
extracted or transferred offsite annually. Based on Table 4 above, all CO2 production
well facilities would extract significantly more CO2 than any of the considered
thresholds. Therefore, there would be no difference between establishing a threshold
level, and indicating that all CO2 producers must report. Note that both Option 1 and
Option 2 define a "CO2 production well facility" at the "dome" level (i.e., Jackson Dome,
Bravo Dome, McElmo Dome, and Sheep Mountain Dome are each considered a facility)

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and does not consider the distribution of individual CO2 production wells at each of these
locations. There are a number of options for defining the reporter, and the definition of
"facility" could be based on the specific distribution of CO2 production wells from which
the reporter would have to report the amount of CO2 extracted.

For example, Denbury Resources reported that the company operates (as of 2004) 15 CO2
production wells at three separate locations in northern Rankin County Mississippi, near
Jackson, producing approximately 4.8 MMTCO2 per year. 6 These three locations are
referred to as the Goshen Springs Field, the Picah Field, and the Holly Bush Creek Field.
Information is not available as to how many CO2 production wells Denbury Resources is
operating at each location, however, EPA could define the entire Jackson Dome as a
single "CO2 production well facility" or define each of the three field locations as a
"facility" for the purposes of reporting.

c. CO2 Capture Facilities

Option 1 (CO2 Capture Facilities)

Under Option 1, all facilities conducting capture of CO2 could be required to report the
amount of CO2 captured and transferred, regardless of the amount of CO2 captured.

A primary rationale for requiring all CO2 capture to be reported is to ensure equity among
CO2 capture sites, as well as to provide the necessary data to evaluate future policies and
programs related to the full chain of carbon dioxide capture, transport, injection and
storage. Complete reporting of CO2 capture would be a strong quality control check
when assessing the total amount of CO2 injected and stored.

Option 2 (CO2 Capture Facilities)

Under Option 2, EPA could set a reporting threshold based on the amount of CO2
captured annually. There are currently nine CO2 capture operations operating in the U.S.
for which data are available concerning the amount of CO2 being captured. As shown in
Table 5, based on available information, each of these CO2 capture facilities is capturing
more than 25,000 mtC02e annually. If a threshold were established at 100,000 mtC02e
captured, four facilities would fall under the reporting threshold and would not be
required to report the quantity of CO2 captured. The number of potential new [future]
CO2 capture facilities has not been estimated.

6 http://findarticles.com/p/articles/mi aa5277/is 200405/ai n24278763 Carbon dioxide an often
overlooked natural resource, The Mississippi Business Journal, May 03. 2004 by McNeill. George

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Table 5. Threshold Analysis Based on Quantity of CO2 Captured









Metric















tons

Percent of

Number

Percent of



Threshold

Total

Number

C02e/ yr

Emissions

of Entities

Facilities



Level

Capture

of

over

over

over

over

Source Category

(mtC02e)

(mtC02e)

Facilities

Threshold

Threshold

Threshold

Threshold

Capture at

1,000

8,186,881

9

8,186,881

100%

9

100%

Industrial Process

10,000

8,186,881

9

8,186,881

100%

9

100%

and Stationary

25,000

8,186,881

9

8,186,881

100%

9

100%

Combustion









Facilities

100,000

8,038,478

5

8,038,478

98%

5

56%

3. Monitoring Methods Considered

This section presents the monitoring methods for CO2 production well facilities and CO2
capture facilities. One method was proposed for monitoring the total quantity of CO2
supplied. An additional method was also initially considered which would enable the
measurement of fugitive emissions in addition to CO2 supply.

(i) CO2 Production Well Facilities

Direct Measurement of CO2 Supply and Fugitive CO2 Emissions

For direct measurement of the CO2 supply and also measurement of the fugitive CO2
emissions from the CO2 production process, the flow rate of CO2 produced from the CO2
production wells and the composition of the CO2 produced from the CO2 production
wells would be monitored at the points of extraction (i.e., at the CO2 production wells).
The flow rate and composition of the CO2 produced and transferred to an offsite CO2
transport system would also be directly monitored. The difference between the flow
measurement of CO2 at the point of extraction and the flow measurement of CO2 at the
point of transfer would be the fugitive CO2 emissions from the CO2 production process,
including all equipment located between the point of capture and the point of transfer
(e.g., valves, flanges, compressor vents.) In addition, leak detection monitoring (e.g.,
infrared detection) would need to be applied to estimate the fugitive CO2 emissions from
any CO2 production process equipment that is located upstream of the point where the
amount of CO2 extracted is measured (e.g., the CO2 production well heads would
generally be upstream of the point at which the amount of CO2 extracted from the wells is
measured.) The fugitive emissions from upstream equipment would be added to the
difference between the amount extracted and the amount transferred to obtain the total
fugitive emissions from the CO2 production process.

In addition to measuring the volume of the CO2 stream captured, it would be necessary to
determine the CO2 composition of the CO2 stream sold. As the CO2 stream is not
necessarily 100% pure CO2, quarterly samples would be required to determine the CO2
content of the stream. Alternatively, an assumption could be made about the CO2 content

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of the sold gas, based on the end user of the gas. For example, food grade CO2 is usually
required to be of a known quality, similar to pipeline quality gas.

Direct Measurement of CO2 Supply (Only)

For direct measurement of the CO2 supply without any measurement of the fugitive CO2
emissions from the CO2 production process, the flow rate of the CO2 stream produced
from the CO2 production wells and the composition of the CO2 stream produced from the
CO2 production wells would be monitored either at the points of extraction (i.e., at the
CO2 production wells) or at the point at which the produced CO2 is transferred to an
offsite CO2 transport system, or both.

The value of the CO2 flow measured at the point of extraction would be somewhat
different than the value of the CO2 measured at the point of transfer. The value measured
at the point of extraction would be the total amount of CO2 extracted including any
[downstream] fugitive emissions from the CO2 production process. The value measured
at the point of transfer would be the total amount of CO2 extracted less any [upstream]
fugitive emissions from the CO2 production process. The principal advantage of
measuring the CO2 supply at the point of transfer rather than at the point of extraction is
that CO2 production well facilities are likely already measuring the amount of CO2
transferred using existing equipment, but may not already be directly measuring the
amount of CO2 extracted at the CO2 production wells. There may be an additional cost
for installation of monitoring equipment to directly measure the amount of CO2 extracted.

Similar to the discussion for "Direct Measurement of CO2 Supply and Fugitive CO2
Emissions" above, gas composition would also have to be quantified.

(ii) CO2 Capture Facilities

Direct Measurement of CO2 Supply and Fugitive CO2 Emissions

For CO2 capture facilities, the monitoring approach for monitoring both the CO2 supply
and fugitive CO2 emissions would be to monitor the amount of CO2 going into the carbon
capture process, monitor the amount of (un-captured) CO2 going out of the capture
process, and monitor the amount of CO2 that is actually captured by the CO2 capture
process. Alternatively, one could subtract the CO2 captured by the capture process from
the CO2 input to the capture process to estimate "fugitive" emissions from the carbon
capture process itself, i.e., the amount of CO2 actually emitted from valves, flanges, etc..
This method also directly monitors the amount of CO2 captured, i.e., the CO2 supply.

As above, gas composition would have to be quantified in a similar manner to quantify
the total potential CO2 supplied.

Direct Measurement of CO2 Supply (Only)

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If the only parameter of interest is the CO2 supply, then the amount of CO2 could be
monitored either at the point where the captured CO2 exits the capture system or at the
point where the captured CO2 is transferred offsite. As described for CO2 production,
above, the value measured at the point of capture would be the total amount of CO2
captured including any [downstream] fugitive emissions from the CO2 capture process
(e.g., CO2 compressors, dehydrators, and other downstream equipment). The value
measured at the point of transfer would be the total amount of CO2 extracted less any
[upstream] fugitive emissions from the CO2 capture process. The principal advantage of
measuring the CO2 supply at the point of transfer rather than at the point of capture is that
CO2 capture sites are likely already measuring the amount of CO2 transferred using
existing equipment, but may not already be directly measuring the amount of CO2
captured. There may be an additional cost for installation of monitoring equipment to
directly measure the amount of CO2 captured rather than the amount transferred.

As above, gas composition would have to be quantified in a similar manner to quantify
the total potential CO2 supplied.

Additional alternative monitoring methods for monitoring fugitive CO2 emissions from
CO2 capture facilities and CO2 production well facilities are include in Attachment 1.
These methods could be applied as alternatives to direct measurement of CO2 inlet and
outlet flow rates using continuous emissions monitors (CEMS). The alternative methods
listed in Attachment 1 may involve lower capital and operating costs than direct
measurement using CEMS.

4. Procedures for Estimating Missing Data
a. CO2 Production Facilities and CO2 Capture Facilities

Monitoring of CO? Supply from Production Facilities

Monitoring of CO2 supply for CO2 production well facilities is based on direct
measurement using CEMS. Procedures for management of missing data are established
under Part 75 (Acid Rain Program.) These procedures would be applicable to direct
measurement using CEMS for CO2 production facilities.

Part 75 Procedures for Estimating Missing CEMS Data

Procedures for management of missing data are described in Part 75.35(a), (b), and (d).
In general, missing data from operation of the CEMS may be replaced with substitute
data to determine the CO2 flow rates or CO2 emissions during the period in which CEMS
data are missing.

Under Part 75.35(a), the owner or operator of a unit with a CO2 CEMS for determining
CO2 mass emissions in accordance with Part 75.10 (or an O2 monitor that is used to
determine CO2 concentration in accordance with appendix F to this part) shall substitute
for missing CO2 pollutant concentration data using the procedures of paragraphs (b) and

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(d) of this section. Subpart (b) covers operation of the system during the first 720
quality-assured operation hours for the CEMS. Subpart (d) covers operation of the
system after the first 720 quality-assured operating hours are completed.

Under Part 75.35(b), during the first 720 quality assured monitor operating hours
following initial certification at a particular unit or stack location (i.e., the date and time
at which quality assured data begins to be recorded by a CEMS at that location), or (when
implementing these procedures for a previously certified CO2 monitoring system) during
the 720 quality assured monitor operating hours preceding implementation of the
standard missing data procedures in paragraph (d) of this section, the owner or operator
shall provide substitute CO2 pollutant concentration data or substitute CO2 data for heat
input determination, as applicable, according to the procedures in Part 75.31(b).

Under Part 75.35(d), upon completion of 720 quality assured monitor operating hours
using the initial missing data procedures of Part 75.31(b), the owner or operator shall
provide substitute data for CO2 concentration or substitute CO2 data for heat input
determination, as applicable, in accordance with the procedures in Part 75.33(b) except
that the term " CO2 concentration" shall apply rather than "SO2 concentration," the term
"CO2 pollutant concentration monitor" or "CO2 diluent monitor" shall apply rather than
"SO2 pollutant concentration monitor," and the term "maximum potential CO2
concentration, as defined in section 2.1.3.1 of appendix A to this part" shall apply, rather
than "maximum potential SO2 concentration."

Monitoring of CO? Supply from Capture Facilities

One option for "missing data" for CO2 capture facilities is that it could be assumed that
the facility did not capture any CO2 during the reporting period for which CEMS data for
the amount of CO2 captured are missing. If the amount of CO2 captured is not reported,
100 percent of the CO2 emissions from the industrial process source or stationary
combustion source would be assumed to be emitted to the atmosphere and zero percent of
the CO2 emissions would be assumed to be captured.

Another option for estimating missing data for CO2 capture is that alternative data could
be used, using the procedures described above under Part 75. For example, the amount of
CO2 captured would be metered at the capture facility fenceline, i.e., at the point where
the CO2 is transferred from the capture site to the offsite transport system. If the amount
of CO2 transferred offsite from the capture process was metered, but the amount of CO2
emitted from the capture process was not measured, the amount of CO2 emitted could be
estimated from the expected total amount generated by the industrial or stationary
combustion source (e.g., using historical data) and the amount transferred offsite.

Missing CEMS data for the amount of CO2 entering the capture process could be
estimated using CO2 (liquid) flow rate data (the amount of CO2 captured) and a "capture
process efficiency" factor developed from prior month or prior year CEMS data (e.g.,
using the historical CEMS data it can be estimated, over time, what percentage of the
CO2 input to the capture process was actually captured).

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5. QA/QC and Data Verification Requirements

a.	General QA/QC Requirements

Facilities could conduct quality assurance and quality control (QA/QC) of production
data, emissions measurements, flow measurements, carbon contents, and emission
estimates reported. Facilities could be encouraged to prepare an in-depth QA/QC plan
which would include checks on production data, carbon content data, and calculations
performed to estimate GHG emissions. Examples of specific QA/QC procedures to
include in a QA/QC plan for carbon dioxide capture and production are:

CO? Production Well Facilities and CO? Capture Facilities using CEMS

For CO2 production well facilities and CO2 capture facilities using CEMS to measure
CO2 inlet and outlet flow rates and fugitive CO2 emissions, the equipment could be tested
for accuracy and calibrated as necessary by a certified third party vendor. These
procedures could be required to be consistent in stringency and data reporting and
documentation adequacy with the QA/QC procedures for CEMS described in Part 75 of
the Acid Rain Program.

CO? Production Well Facilities and CO? Capture Facilities Measuring CO? Supply Only

For CO2 production well and CO2 capture facilities using CEMS to measure CO2 flow
rates (CO2 supply) but not fugitive CO2 emissions, equipment could be required to be
tested for accuracy and calibrated as necessary by a certified third party vendor. Mass
flow meter calibrations could be required to be NIST traceable. Methods to measure the
composition of the carbon dioxide captured, transferred, or extracted could be required to
conform to applicable chemical analytical standards. For example, CO2 used as a
Generally Recognized As Safe (GRAS) direct human food ingredient must be analyzed
for composition in accordance with U.S. Food and Drug Administration food-grade
specifications for carbon dioxide (see 21 CFR 184.1250.) Carbon dioxide used in
supercritical applications must be analyzed for composition in accordance with ASTM
standard E-1745-95 (2005).

b.	Equipment Maintenance

For units using flow meters to measure the amount of CO2 captured or produced, flow
meters could be required to be calibrated on a scheduled basis in accordance with
equipment manufacturer specifications and standards. Flow meter calibration is generally
conducted at least annually. A written record of procedures needed to maintain the flow
meters in proper operating condition and a schedule for those procedures could be part of
the QA/QC plan for the capture or production unit.

An equipment maintenance plan could be developed as part of the QA/QC plan.

Elements of a maintenance plan for equipment could include the following:

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• Conduct regular maintenance and calibration of equipment, including flow
meters:

o Keep a written record of procedures needed to maintain the monitoring

system in proper operating condition and a schedule for those procedures,
o Keep a record of all testing, maintenance, or repair activities performed on
any monitoring system or component in a location and format suitable for
inspection. A maintenance log may be used for this purpose. The
following records could be maintained: date, time, and description of any
testing, adjustment, repair, replacement, or preventive maintenance action
performed on any monitoring system and records of any corrective actions
associated with a monitor's outage period. Additionally, any adjustment
that recharacterizes a system's ability to record and report emissions data
could be required to be recorded (e.g., changing of flow monitor or
moisture monitoring system polynomial coefficients, K factors or
mathematical algorithms, changing of temperature and pressure
coefficients and dilution ratio settings), and a written explanation of the
procedures used to make the adjustment(s) could be kept.

c. Data Management

Data management procedures could be included in the QA/QC Plan. Elements of the
data management procedures plan could be as follows:

•	Assess the representativeness of carbon content data (e.g., for composition of CO2
supplied to an injection site) by comparing the values received from the supplier
to laboratory analysis;

•	Check for temporal consistency in production data, carbon content data, and CO2
emission and CO2 flow estimates. If outliers exist, determine whether they can be
explained by changes in the facility's operations, etc?

o A monitoring error is probable if differences between annual data cannot
be explained by:

¦	Changes in activity levels;

¦	Changes concerning input or output materials; or

¦	Changes concerning the emitting process (e.g. process
improvements).

•	Determine the "reasonableness" of the emission estimate by comparing it to
previous year's estimates and relative to national emission estimate for the
industry:

o Comparison of CO2 delivered to or consumed by specific sources with

purchasing or sales data and data on stock changes;
o Comparison of CO2 delivery or consumption totals with purchasing data
and data on stock changes;

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o Comparison of emission factors for specific equipment operations (e.g.,
CO2 compressors) to national or international reference emission factors
of comparable operations; and
o Comparison of measured and calculated emissions.

•	Maintain data documentation, including comprehensive documentation of data
received through personal communication:

o Check that changes in data or methodology are documented.

d.	Calculation Checks

Calculation checks could be performed for all reported calculations. Elements of
calculation checks could include:

•	Perform calculation checks by reproducing a representative sample of emissions
calculations or building in automated checks such as computational checks for
calculations;

•	Check whether emission units, parameters, and conversion factors are
appropriately labeled;

•	Check if units are properly labeled and correctly carried through from beginning
to end of calculations;

•	Check that conversion factors are correct;

•	Check the data processing steps (e.g., equations) in the spreadsheets;

•	Check that spreadsheet input data and calculated data are clearly differentiated;

•	Check a representative sample of calculations, by hand or electronically;

•	Check some calculations with abbreviated calculations (i.e., back of the envelope
checks);

•	Check the aggregation of data across source categories, business units, etc.; and/or

•	When methods or data have changed, check consistency of time series inputs and
calculations

e.	Data Verification

As part of the data verification requirements, the owner or operator could be required to
submit a detailed explanation of how company records of measurements are used to
quantify all sources of carbon input and output within a certain time period after receipt
of a written request from EPA or from the applicable State or local air pollution control
agency.

6. Data to Be Reported

a. Direct Measurement of CO2 Supply for CO2 production well and CO2 capture
Facilities

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For direct measurement of CO2 supply and fugitive emissions for CO2 production well
and CO2 capture facilities, the primary monitoring method discussed is based on direct
measurement of the gaseous and liquid CO2 flows. The difference between the inlet and
outlet CO2 flows could be used to estimate the fugitive CO2 emissions from the capture
process. CO2 capture facilities and CO2 production well facilities could be required to
report the CO2 emissions and the measured CO2 flows and measured CO2 concentrations
used to estimate the fugitive CO2 emissions and CO2 supply.

For measurement of CO2 supply for CO2 capture facilities and CO2 production well
facilities without measurement of fugitive CO2 emissions, the primary monitoring
methods discussed are based on direct measurement of the amount of CO2 captured or
extracted, or the amount of CO2 transferred from the CO2 production well or CO2 capture
facility to another facility. These facilities could be required to report the measured CO2
flows and measured CO2 concentrations used to estimate the CO2 supply.

b.	Additional Data for Verification

At a given production well or capture facility, if extraction/capture and the amount of
CO2 transferred offsite are reported, this provides one method of data verification. The
difference between extraction/capture and offsite transfers could indicate if one of the
pieces of data reported could be in error.

If the entire carbon extraction/capture, transport, injection and storage chain were
included in a reporting program, additional data for verification could include data from
CO2 pipeline operators concerning the amount of CO2 they are receiving from CO2
production well facilities and CO2 capture facilities and transporting to injection sites and
storage sites. Under the various options, capture sites could report how much CO2 they
are transferring to the pipeline operators and injection sites and storage sites would report
how much CO2 they are receiving from pipeline operators. In the event that these
reported values don't correspond, EPA may not be able to resolve this issue if there are
no data from CO2 pipeline operators to use for verification.

c.	Additional data to be retained onsite (recordkeeping).

Facilities could be required to retain data concerning monitoring of CO2 flows onsite for
a period of at least five years from the reporting year. EPA could use such data to
conduct trend analyses and potentially to develop process or activity-specific emission
factors for carbon extraction or capture.

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7. ATTACHMENTS

Attachment 1 summarizes alternative monitoring methods for CO2 capture facilities and
CO2 production well facilities. These methods are potential elements of site-specific
monitoring plans for monitoring fugitive CO2 emissions that represent potential
alternatives to direct measurement using CEMS. Schematic diagrams illustrating the
alternative monitoring points for carbon capture and production are included as
Attachment 2.

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a. Attachment 1: Monitoring Methods for CO2 Capture Facilities
1.1.1 Chemical Solvent (Amine) Absorption Unit

Process vent emissions

Solvent absorber tower vent flow rate:
Solvent absorber tower vent CO2:

Captured CO2 from regeneration unit:

Captured CO2 from regeneration unit:

Fugitive CO2 Emissions

Valves, flanges, flow meters:

1.1.2	Gas Separation Membrane

Process Vent Emissions
Inflow flue gas flow rate:

Inflow flue gas CO2 concentration:

Low pressure CO2 outflow:

Low pressure CO2 outflow:

Fugitive CO2 Emissions

Valves, flanges, flow meters:

1.1.3	Physical Absorption Unit

Process Vent Emissions

Vent gas flow meter

Continuous monitoring of CO2 vent gas
concentration

Direct measurement of CO2 flow rate using
flow meter

Continuous monitoring of captured CO2
concentration or periodic sampling and
analysis of captured CO2 concentration

Infrared Detection (Infrared Gas Analyzers
IRGA) or other atmospheric detection

Flue gas flow meter

Continuous monitoring of flue gas CO2
concentration

Direct measurement of CO2 flow rate using
flow meter

Continuous monitoring of captured CO2
concentration or periodic sampling and
analysis of captured CO2 concentration

Infrared Detection (Infrared Gas Analyzers
IRGA) or other atmospheric detection

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Exhaust/synthesis gas absorber tower vent: Vent gas flow meter

Exhaust/synthesis gas absorber tower vent: Continuous monitoring of vent gas CO2

concentration

Captured CO2 from regeneration unit:
Captured CO2 from regeneration unit:

Fugitive CO2 Emissions

Valves, flanges, flow meters:

Direct measurement of CO2 flow rate using
flow meter

Continuous monitoring of captured CO2
concentration or periodic sampling and
analysis of captured CO2 concentration

Infrared Detection (Infrared Gas Analyzers -
IRGA) or other atmospheric detection

1.1.4 Hydrate-based Separation Unit (R&D stage)
Process Vent Emissions

Input Synthesis gas flow rate:

Input Synthesis gas composition:
CO2 product gas outflow rate:
CO2 product gas outflow concentration:

Fugitive CO2 Emissions

Valves, flanges, flow meters:

Direct measurement of synthesis gas flow
rate using flow meter

Continuous monitoring of synthesis gas CO2
concentration

Direct measurement of CO2 flow rate using
flow meter

Continuous monitoring of CO2 outflow
concentration or periodic sampling and
analysis of CO2 outflow concentration

Infrared Detection (Infrared Gas Analyzers
IRGA) or other atmospheric detection

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1.2 CO2 Production from Natural CO2 Formations

Production of CO2 from natural formations involves fugitive CO2 emissions from CO2
production wells (wellheads) and fugitive and vent emissions of CO2 from associated
piping systems (e.g., valves and flanges,) dehydration, and compression systems.

1.2.1 CO2 Production Wells (and associated piping)

Fugitive emissions of CO2 from CO2 Production Wells

Monitoring Methods

Production Rate of CO2:	Measurement of CO2 flow from production wells at

on-site metering stations

Composition of Produced CO2:

Valves and Flanges:

Periodic measurement of composition of the CO2
produced by CO2 production wells (note that the
"CO2"produced by the CO2production wells will
not be 100 percent carbon dioxide)

Infrared Detection (Infrared Gas Analyzers - IRGA)
or other atmospheric detection

System Blowdown Venting:

Casing/annulus pressure testing:

Production wellhead leakage:

1.2.2 CO2 Dehydration System

Volume of blowdown vent gas (estimated from
piping system volume and pressure); composition of
vent gas (based on periodic sampling and analysis
of CO2 produced from the CO2 production wells)

Volume of pressure test vent gas (flow meter) and
composition of vent gas (based on periodic
sampling and analysis of CO2 from pressure testing
the wells)

Infrared detection (Infrared Gas Analyzers - IRGA)
or other atmospheric detection

The CO2 Production Well Facility is assumed to have a CO2 dehydration system to
dehydrate the CO2 produced by the CO2 production wells.

Fugitive and vent emissions of CO2 from CO2 dehydration system

Monitoring Methods

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Dehydrator Flash Tank Vent:	Vent gas flow rate (flow meter) and composition

(CEMS or periodic vent gas sampling and analysis)

Valves and Flanges:	Infrared Detection (Infrared Gas Analyzers - IRGA)

or other atmospheric detection

Combustion emissions of CO2 from CO2 dehydration system

Monitoring Methods

Dehydrator Pump Engine Exhaust: Fuel consumption (flow meter) and fuel

composition (periodic sampling and analysis)

1.2.3 CO2 Compression System

The CO2 Production Well Facility is assumed to have a CO2 compression system to
compress the CO2 for delivery to the CO2 pipeline.

Fugitive and vent emissions of CO2 from CO2 compression system

Monitoring Methods
Compressor Seals Exhaust Vent:

Compressor Seals Exhaust Vent

Pressure Relief Valves:

Pressure Relief Valves:

Open Ended Lines:

Compressor Intercooler Leaks:

System Blowdown Emissions:

23

Infrared detection (Infrared Gas Analyzers - IRGA)
or other atmospheric detection

Open ended line measurement: vent gas flow rate
(flow meter) and composition (CEMS or periodic
vent gas sampling and analysis)

Estimated from number of pressure relief incidents
and periodic sampling analysis of composition of
CO2 delivered to the compressor [or]

Infrared detection (Infrared Gas Analyzers - IRGA)
or other atmospheric detection

Infrared detection (Infrared Gas Analyzers - IRGA)
or other atmospheric detection

Estimated from pressure drop across intercooler and
periodic sampling and analysis of CO2 delivered to
the intercooler.

Volume of blowdown vent gas (estimated from
compressor cylinder volume, suction/discharge


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cylinder volumes, volume of piping between
valves) and composition of blowdown vent gas
(based on periodic sampling and analysis of CO2
delivered to the compressor)

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b. Attachment 2: Monitoring Points for Capture

Post-Combustion Carbon Capture

Coal Power Plant, NGCC Power Plant

= CCS inventory boundary

Fugitive
vented
C02 from
capture
process

co2

To Transport

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Pre-Combustion Carbon Capture

Coal Gasification Plant, IGCC Plant

C02 not
captured,

Fugitive
vented
C02 from
capture
process

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Oxv Combustion Carbon Capture

n2,

other gases

(No net C02 increase)

And Heat	c°2

Flue gas recycling

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Natural Gas Production and Processing

Natural
Gas (from
production
well)

Sweetened
Natural
Gas (some
C02 remains)

"=>

t

Chemical

Absorption

(amines)

Membranes

C02

Removal

CO,

Energy
Penalty for
Capture

To Transport

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Cement Plant Carbon Capture

Coal
Gas
Oil

Air

CaC03

I

CaO

Flue gas +
C02 from
cement-
producing
reaction

C02 not
captured,
other gases

t

Chemical
or Physical
Absorption

Membranes

Energy
Penalty for
Capture

C02

Removal

co2



co2

Dehydration

>->

Compression

1

co2

To Transport

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References

Battelle (2004) Greenhouse Gas Emission Reduction Protocol for the Monell and Salt
Creek Enhanced Oil Recovery (EOR) Project.

Clean Development Mechanism, Proposed New Methodology: Monitoring (CDM-
NMM).

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

IPCC (2006) 2006IPCC Guidelines for National Greenhouse Gas Inventories. The
National Greenhouse Gas Inventories Programme, The Intergovernmental Panel on
Climate Change, H.S. Eggleston, L. Buenida, K. Miwa, T Ngara, and K. Tanabe (eds.).
Hayama, Kanagawa, Japan.

IPIECA/API (2007) Oil and Natural Gas Industry Guidelines for Greenhouse Gas
Reductions Projects: Part II: Carbon Capture and Geological Storage Emission
Reduction Family. June 2007. International Petroleum Industry Environmental
Conservation Association. American Petroleum Institute.

U.S. DOE (2007) Technical Guidelines Voluntary Reporting of Greenhouse Gases
(1605(b)) Program. Available at

http://www.pi.energv.gov/enhancingGHGregistrv/documents/Januarv2007_1605bTechni
calGuidelines.pdf.

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