Background for Regulating the
Transportation of Carbon Dioxide in a Gaseous State
Pipeline Safety, Regulatory Certainty,
And Job Creation Act of 2011, Section 15
February 2015
Office of Pipeline Safety
Pipeline and Hazardous Materials Safety
Administration (PHMSA)
U. S. Department of Transportation (DOT)
Table of Contents
Executive Summary ........................................................................................................................ 1
1.0 Introduction ............................................................................................................................... 4
1.1 Purpose of Study .................................................................................................................. 4
2.0 Background ............................................................................................................................... 4
2.1 History of CO2 Regulatory Actions ..................................................................................... 4
2.1.1 Incorporation of Carbon Dioxide Pipelines into 49 CFR Part 195............................... 4
2.1.2 Regulation of CO2 Transported in a Gaseous State ...................................................... 5
2.2 Physical Properties of CO2 that Affect Regulatory Approach ............................................. 6
2.3 Operational Factors Affecting the Phase in Which CO2 Is Transported .............................. 6
3.0 Current Carbon Dioxide Pipeline Mileage in the U.S. ............................................................. 7
3.1 Pipelines Transporting CO2 in the Supercritical Fluid State ................................................ 7
3.2 Pipelines Transporting CO2 in the Gaseous State ................................................................ 9
4.0 Planned CO2 Pipeline Construction .......................................................................................... 9
5.0 Potential Safety Consequences of Gaseous CO2 Pipeline Accidents ..................................... 12
6.0 Threats and Hazards to Gaseous CO2 Pipelines ..................................................................... 13
6.1 Internal Corrosion .............................................................................................................. 13
6.2 External Corrosion ............................................................................................................. 13
6.3 Excavation Damage............................................................................................................ 13
6.4 Natural Force Damage ....................................................................................................... 13
6.5 Other Outside Force Damage ............................................................................................. 14
6.6 Incorrect Operation ............................................................................................................ 14
6.7 Pipe Material & Weld Failure ............................................................................................ 14
6.8 Equipment Failure .............................................................................................................. 14
6.9 Accident History of CO2 Pipelines Regulated Under Part 195 .......................................... 14
7.0 Candidate Approaches to Regulating Gaseous CO2 Pipelines ............................................... 15
7.1 Regulating Gaseous CO2 Pipelines under Parts 192 and 195 ............................................ 15
7.1.1 §195.2 - Definition of Carbon Dioxide ...................................................................... 16
7.1.2 Compression Equipment............................................................................................. 16
7.1.3 Maintaining Gaseous CO2 in a Gaseous State ............................................................ 16
7.1.4 §195.8 - Transportation of gaseous carbon dioxide in pipelines constructed with other
than steel pipe ...................................................................................................................... 17
7.1.5 §195.102(b) - Design temperature .............................................................................. 17
7.1.6 §195.111 - Fracture propagation ................................................................................ 17
7.1.7 Part 195 Subpart E - Pressure Testing ........................................................................ 17
7.1.8 §195.11 - What is a regulated rural gathering line and what requirements apply? .... 17
7.2 Regulating Gaseous CO2 Pipelines under Part 192............................................................ 18
7.2.1 Comparability of Parts 192 and 195 with Respect to Regulating Gaseous CO2
Pipelines............................................................................................................................... 18
7.2.2 Determination of Covered Segment under Part 192, Subpart O (Integrity
Management) for Gaseous CO2 Pipelines ........................................................................... 20
7.2.3 Applicability of §192.5 - Class locations ................................................................... 20
7.2.4 §192.8 - How are onshore gathering lines and regulated onshore gathering lines
determined? ......................................................................................................................... 21
7.2.5 Maintaining Gaseous CO2 in a Gaseous State ............................................................ 21
8.0 Summary ................................................................................................................................. 21
Appendix A - Known CO2 Pipeline Projects Being Planned or Built ......................................... 24
A.1 Natural CO2 Reservoir Pipeline Projects........................................................................... 24
A.1.1 Kinder Morgan Energy Partners, LP (KMEP) .......................................................... 24
A.1.2 Denbury Resources .................................................................................................... 24
A.1.3 Blackstone Energy Partners ....................................................................................... 25
A.2 Anthropogenic Sources of CO2` ....................................................................................... 25
A.2.1 Southern Company/Denbury Resources .................................................................... 25
A.2.2 SCS Energy................................................................................................................ 25
A.2.3 Texas Clean Energy Project (TCEP) ......................................................................... 25
A.2.4 NRG Energy, Inc. ...................................................................................................... 26
A.3 Carbon Capture Projects Proposed or in Planning ............................................................ 26
Executive Summary
Currently, the Pipeline and Hazardous Materials Safety Administration (PHMSA) regulates
pipelines transporting carbon dioxide (CO2) in a supercritical fluid state1 under 49 C.F.R. Part
195, but does not regulate pipelines transporting CO2 in a subcritical liquid or gaseous state. The
Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (hereafter referred to as the
Act) mandated that the Secretary of Transportation “prescribe minimum safety standards for the
transportation of carbon dioxide by pipeline in a gaseous state.” The Act also mandated that, in
establishing those standards, the Secretary consider whether applying the existing minimum
safety standards in Part 195 “for the transportation of carbon dioxide in a liquid state to the
transportation of carbon dioxide in a gaseous state would ensure safety.”
In 2013 Annual Reports, hazardous liquid pipeline operators reported 5,195 miles of supercritical
CO2 pipelines. The Interstate Natural Gas Association of America (INGAA) and others have
estimated the need to build up to 66,000 miles of CO2 pipelines by 2030.2 This large expansion
of CO2 pipeline capacity is driven by two major factors:
(1) To reduce the amount of greenhouse gases released to the atmosphere, Carbon
Capture and Sequestration (CCS) projects are being constructed or planned. These
projects involve the retrofit of equipment to sources of anthropogenic (man-made) CO2
such as coal-fired electric power plants. The equipment would capture CO2 and transport
it for use in enhanced oil recovery (EOR) projects or for sequestration in depleted wells,
saline aquifers, or abandoned coal mines.
(2) The ongoing improvement in oil extraction technology is increasing demand for CO2
for use in EOR oil production.
For technical and economic efficiency, PHMSA expects that most CO2 would continue to be
transported in the supercritical phase, and thus would be regulated under the existing
requirements of Part 195. However, in some cases, technical issues such as the physical
characteristics of the sequestration storage reservoir, transportation distance, et cetera, may
impact whether the CO2 is transported as a gas or as a subcritical liquid. In such cases, revisions
of existing pipeline safety regulations would be needed to implement the statutory mandate,
since current regulations do not address the transportation of CO2 in a gaseous or subcritical
liquid state.
The Act specified that the Secretary of Transportation consider whether applying the existing
minimum safety standards in Part 195 “for the transportation of carbon dioxide in a liquid state
to the transportation of carbon dioxide in a gaseous state would ensure safety.” As described in
1
Supercritical (liquid) phase has a critical pressure of above approximately 1070 psig (73.8 bar) and critical
temperature of 88 ºF (31.1 ºC). Higher operating pressures are required for lower operating temperatures to
maintain the liquid phase.
2
Developing a Pipeline Infrastructure for CO2 Capture and Storage: Issues and Challenges, prepared for INGAA
Foundation by ICF International, February 2009.
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this preliminary evaluation, the application of the minimum safety standards that apply to
hazardous liquid pipelines in Part 195 gaseous state would likely ensure safety of gaseous CO2
pipelines, because many of the requirements applicable to supercritical CO2 pipelines in Part 195
would also be applicable to the transport of CO2 in a gaseous state.
Since the transportation of gases is subject to Part 192, an amendment to Part 192 would be
needed to accommodate the regulation of the transportation of CO2 by pipelines in a gaseous
state even if the requirements would be referenced within or very similar to those for
supercritical liquid pipelines under Part 195. However, some of the regulations in Part 195
applicable to supercritical CO2 would need to be modified to be applicable to the transport of
gaseous CO2.
Summary of the Evaluation of the Applicability of the Minimum Safety Standards of Part
195 to the Safe Transport of CO2 in a Gaseous State
In direct response to the statutory mandate, this is a preliminary evaluation of whether existing
minimum safety standards in Part 195 for the transportation of carbon dioxide in a supercritical
fluid state would ensure safety in the transportation of carbon dioxide in a gaseous state. In order
to implement this mandate, PHMSA has identified certain specific technical aspects of Part 195
that require further evaluation and possible revisions to Part 192 to accommodate the regulation
of gaseous CO2 pipelines. Some changes to Part 192 could be as simple as a cross reference to
those requirements of Part 195 that are also applicable to the transport of gaseous CO2 without
the need for revision or with minor revisions.

Re-define Carbon Dioxide: PHMSA would determine if CO2 pipelines in any state (gas,
subcritical liquid, as well as supercritical fluid) would be regulated, or if only gaseous
and supercritical CO2 pipelines would be regulated. Currently the definition of carbon
dioxide in Part 195 only applies to the transport of CO2 in the supercritical fluid state.

Address Compressor Stations: The current regulations in Part 195 are based on the
transportation of fluids in the supercritical fluid state. The requirements address pumps,
pump stations, etc., but do not address compressors, compressor stations, etc. This may
require that applicable sections of Part 192 be modified to allow for the transport of CO2
in a gaseous state.

Operational Controls to Maintain Gas Phase Operation: PHMSA may need to evaluate
the need to prescribe additional controls on operational parameters such as temperature
and pressure for this purpose. There is an interface pressure as a function of temperature
below which CO2 can be maintained in a gaseous state.

Non-steel Pipe: PHMSA may need to evaluate the applicability of non-steel pipeline
materials to gaseous CO2 pipelines, taking into account that pre-existing gaseous CO2
pipelines might have been built using plastic pipe or other materials besides steel.

Design Temperature: Part 195 contains a specific requirement that applies only to
supercritical fluid CO2 pipelines, due to the physical properties of supercritical fluid CO2.
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Pipeline and Hazardous Materials
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Design temperature requirements for the transport of gaseous CO2 may need to be added
to Part 192.

Fracture Propagation: Part 195 contains a specific requirement that addresses fracture
propagation for supercritical carbon dioxide pipelines. The potential for fracture
propagation of gaseous CO2 pipelines needs to be evaluated.

Pressure Testing: The current requirements in Part 195, since 1991, allow certain
supercritical CO2 pipelines to operate without a pressure test in accordance with Subpart
E, if they were constructed before becoming regulated under Part 195. Subpart E also
contains criteria for the use of CO2 as the test medium. Pressure testing requirements of
gaseous CO2 pipelines under Part 192 Subpart J would need to be evaluated.

CO2 Gathering Lines: Pipelines that gather CO2 from natural sources might meet the
definition of a gas gathering line.

Integrity Management: CO2 is a non-flammable gas. Under Subpart O, Part 192, covered
segments are determined using the CFER PIR equation. The PIR equation is applicable to
flammable gases only. If gaseous CO2 is kept completely within Subpart O an alternative
method for determining the impact of CO2 on an HCA will have to be devised. The
methods for determining a “could affect an HCA” segment in 195.452 includes air
dispersion. This is used to determine the impact of HVLs and supercritical fluid CO2,
which become gasses at atmospheric pressure. This is the method applicable to a release
of gaseous CO2.
Summary of Evaluation with Respect to Regulating Gaseous CO2 Pipelines under Part 192
Some requirements in Part 192 might require adjustments or modifications to accommodate the
regulation of gaseous CO2 pipelines. Those items are discussed below, but are not necessarily an
exhaustive list of topics that might need to be evaluated.






Specific Technical Differences between Parts 195 and 192 with respect to carbon dioxide
pipelines: These include, but are not necessarily limited to design temperature, fracture
propagation, component materials, pressure test medium, and line marker exceptions;
Design, Construction, Operations, and Maintenance Requirements;
Determination of Covered Segments under Integrity Management;
Class locations;
Gathering lines;
Operational Controls to Maintain Gas Phase Operation.
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1.0 Introduction
1.1 Purpose of Study
The purpose of this report is to evaluate existing and potential future gaseous carbon dioxide
(CO2) pipelines and outline an approach for establishing minimum pipeline safety standards for
the transportation of carbon dioxide in a gaseous state (specifically with respect to the adequacy
of existing regulations in Part 195) in order to fulfill the requirements of the Act,3 Section 15,
Carbon Dioxide Pipelines.
Section 15, Carbon Dioxide Pipelines, of the Act mandated that the Secretary of Transportation
“prescribe minimum safety standards for the transportation of carbon dioxide by pipeline in a
gaseous state.” In addition, the Act mandated that in establishing those standards, the Secretary
consider whether applying the existing minimum safety standards in Part 195 “for the
transportation of carbon dioxide in a liquid state to the transportation of carbon dioxide in a
gaseous state would ensure safety.” Further, the Act prescribed that it did not authorize the
Secretary to “regulate piping or equipment used in the production, extraction, recovery, lifting,
stabilization, separation, or treatment of carbon dioxide or the preparation of carbon dioxide for
transportation by pipeline at production, refining, or manufacturing facilities.”
2.0 Background
2.1 History of CO2 Regulatory Actions
2.1.1 Incorporation of Carbon Dioxide Pipelines into 49 CFR Part 195
Federal regulations in the original 49 CFR Part 1954 prescribed safety standards and reporting
requirements for pipeline facilities used in the transportation of hazardous liquids, which were
defined to include petroleum, petroleum products, and anhydrous ammonia.
In the mid-1980s, Congress addressed the need to regulate CO2 pipelines. The report on the
Pipeline Safety Reauthorization Act of 1988 from the House Committee on Energy and
Commerce in the 1987 session of the 100th Congress pointed out that:
3
4

“The Committee has for some time recommended the safety regulation and inspection of
CO2 pipelines.”

“The CO2 pipeline industry has a good safety record and performs an essential service
for enhanced oil recovery, but it is a very new industry. It is not a question of its safety
record that caused the requirement for safety regulation, but rather the unique potential
for disaster if there were ever a break in a CO2 pipeline.”
Public Law 112-90, January 3, 2012
69 FR 11911, October 3, 1969
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
“An event demonstrated just how lethal CO2 can be. On August 21, 1986, a catastrophic
release of gas dissolved in Lake Nyos in Cameroon, Africa, killed 1,700 people. At the
time, the news media characterized the gas as “toxic,” “poisonous” and “lethal.”
Subsequent investigation proved the gas was carbon dioxide.”

“The Committee believes that since CO2 is deadly, CO2 pipelines should have
appropriate Federal safety regulations (H.R. Rep. No. 100-445; 100th Congress; 1st
Session (1987)).”
Consequently, Section 211 of the Pipeline Safety Reauthorization Act of 1988 required that the
Department of Transportation (DOT) regulate the transportation of carbon dioxide (CO2) by
pipeline facilities. On March 16, 1989, the American Petroleum Institute (API) petitioned the
Department to amend Part 195 to regulate pipelines that transport CO2. The recommendations
contained in the petition were the product of a task force consisting of representatives of nine
companies that owned or operated supercritical fluid (i.e., liquid) CO2 pipelines. Because of the
technical and operating similarities between supercritical fluid CO2 and other hazardous liquids
transported in pipelines, the API recommended that the Research and Special Projects
Administration (RSPA) of DOT (the predecessor of PHMSA) amend existing Part 195 rather
than write a new part for CO2 pipelines only. The RSPA adopted that approach. On October 12,
1989, the RSPA published a Notice of Proposed Rulemaking (NPRM)5 proposing to amend 49
CFR 195 to also apply to the transportation of supercritical fluid CO2. The Final Rule was
published on June 11, 1991,6 with an effective date of July 12, 1992.
2.1.2 Regulation of CO2 Transported in a Gaseous State
By definition, none of the pipeline safety regulations in Chapter 49, Part 195, of the Code of
Federal Regulations cover pipelines that transport CO2 in the gaseous or subcritical liquid state.
Prior to the Act, PHMSA maintained that it did not have the authority to regulate pipelines
transporting gaseous CO2. On November 26, 2010, PHMSA published the Final Rule for the
“Updates to Pipeline and Liquefied Natural Gas Reporting Requirements.”7 NAPSR provided
this comment on the final rule: “NAPSR would add CO2 to the list of commodities given that
transport of CO2 as a gas is likely to become more prevalent with forthcoming carbon
sequestration projects.” PHMSA’s response was: “PHMSA recognizes that carbon sequestration
projects are likely to result in the transport of carbon dioxide in gaseous form. At present,
however, PHMSA does not have jurisdiction to regulate transportation of carbon dioxide as a
gas. Legislative change would be required to establish jurisdiction; therefore, PHMSA cannot
accept NAPSR's suggestion to add CO2 as a gas to the list of commodities transported.”
5
54 FR 41912
56 FR 26922
7
Admt. 192-115, 75 FR 72877
6
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Pipeline and Hazardous Materials
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That legislative change came as a result of the Act, Section 15, which mandated that the
Secretary of Transportation “shall prescribe minimum safety standards for the transportation of
carbon dioxide by pipeline in a gaseous state.”
2.2 Physical Properties of CO2 that Affect Regulatory Approach
At standard temperature and pressure, CO2 is an odorless, colorless, non-flammable gas, with a
density 1.5 times the density of air. It will not support combustion nor will it sustain human life
if inhaled. Because it is heavier than air, it displaces oxygen and can result in asphyxiation when
concentrated at levels above approximately 7 percent in the atmosphere. Carbon dioxide may
exist simultaneously as a gas, liquid, and solid at its triple point, which is -57 °C (-69 °F) and 5.2
atm. (60.43 psig). Below the triple point, it may be either a solid or gas depending on
temperature and pressure. Above the triple point, but below the critical point, CO2 can exist as
either a gas or a liquid. When pressure reaches the critical point, above a pressure of 73
atmospheres (1070 psig) and a temperature of 31 °C (88 °F), CO2 enters what is called the
supercritical fluid state (also referred to as a dense vapor phase). This is shown in the red area of
the CO2 phase diagram below.
Figure 1: CO2 phase diagram8
2.3 Operational Factors Affecting the Phase in Which CO2 Is
Transported
“Pipeline transportation of CO2 in the supercritical phase is more desirable than transportation in
the gaseous phase. As a dense vapor in the supercritical phase, CO2 can be transported more
economically and efficiently using smaller diameter pipelines (and pumps) because greater
volumes of fluid can be transported as a dense vapor than as a gas. In addition, CO2 would be
8 http://www.appliedseparations.com/supercritical-co2
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Pipeline and Hazardous Materials
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difficult to transport as a gas because it would enter into two-phase flow at a lower pressure than
that required for the efficient pipeline transportation of the CO2.”9 As a result, CO2 is normally
transported in the supercritical phase. To maintain the product in its supercritical phase, it is
transported at pressures that range from 1,500 to 3,000 psi.10 CO2 can be either a subcritical
liquid or a gas between 5.2 atm. and -57 °C (76 psi and -69 °F), the triple point, and 73 atm. and
31 °C (1070 psi and 88 °F), the critical point. Maintaining the pressure above or below the
interface pressure will determine its state (see Figure 1).
The transportation of CO2 in a gaseous state would be similar to the transportation of natural gas.
Pressures must be maintained below the interface pressure at which the CO2 would become two
phase.
Compressors would be used to transport the CO2 in the gaseous state. Wall thicknesses, steel
strengths, and transportation costs would be comparable to pipelines used in the transportation of
natural gas. However, transporting large volumes of CO2 as a gas would require larger diameter
pipelines, which would increase costs. A study performed in 197411 compared the cost of
construction of the Canyon Reef CO2 pipeline as a low pressure gas pipeline or as a dense vapor
(supercritical) pipeline. The construction costs of a dense vapor pipeline were 20 percent less
than the low pressure gas pipeline.
For both of these reasons, PHMSA believes that most future CO2 pipelines constructed for EOR
or CCS would transport the gas in the supercritical fluid state and would be regulated under
existing requirements of Part 195. However, in some cases, gaseous state CO2 pipelines may be
the selected technology (see section 4.0).
Because the properties of gaseous state CO2 that affect pipeline operation are similar to natural
gas (other than it is not flammable or explosive), the design, construction, operation, and
maintenance of a gaseous state CO2 pipeline would be very similar to a natural gas pipeline.
3.0 Current Carbon Dioxide Pipeline Mileage in the U.S.
3.1 Pipelines Transporting CO2 in the Supercritical Fluid State
9
Miscible Gas Injection, Facts about Miscible Displacement, MK Tech Solutions,
http://www.mktechsolutions.com/Miscble%20Gas.htm
10
PHMSA Presentation, Carbon Dioxide Pipelines, Senate Energy and Natural Resources Committee Briefing, May,
2011.
11
There are three phases to recovering oil from a well. The primary phase uses the natural pressure in the well to
extract the oil. The secondary phase uses a process called water flood to pressurize the well and extract additional
oil. The tertiary phase uses CO2 to extract additional oil from the well. This process is known as enhanced oil
recovery (EOR). There is an estimated 84.8 billion barrels of oil in existing US oilfields that potentially could be
recovered using state-of-the-art CO2 enhanced oil recovery. As technology improves, additional amounts of the
remaining oil may be recoverable.
Transport of CO2, IIPC Working Group III, http://www.ipcc-wg3.de/special-reports/.files-images/SRCCSChapter4.pdf
Department of Transportation
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Pipeline and Hazardous Materials
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There are currently 5,195 miles12 of dedicated CO2 pipelines regulated by PHMSA in the U.S.,
all serving enhanced oil recovery (EOR) projects and transporting supercritical CO2. Eighty
percent of the existing CO2 pipeline infrastructure (by mileage) was built to deliver CO2 into and
within the Permian Basin of West Texas for the purpose of EOR. The earliest pipelines were
built in the 1970s in Texas, where the first CO2 floods13 were initiated. The original CO2 floods
were in a gaseous state,14 but were converted to supercritical fluid state. Other regions with some
significant CO2 pipeline infrastructure include Wyoming/Colorado, New Mexico,
Mississippi/Louisiana/Texas, Oklahoma, and North Dakota. The largest of the existing CO2
pipelines is the 30-inch Cortez Pipeline, which was completed in 1983 and runs for more than
500 miles from the McElmo Dome in Southwestern Colorado to the EOR fields in West Texas.15
The following table provides mileages for those states that have supercritical CO2 pipelines
regulated under Part 195.
Table 1: Supercritical CO2 Pipelines Regulated
Under Part 19516
State
Mileage
Alabama
11
Colorado
242
Kansas
29
Louisiana
315
Mississippi
503
Montana
9
New Mexico
986
North Dakota
167
Oklahoma
304
Texas
1,882
Utah
89
Wyoming
658
Table 2 shows the CO2 mileage reported by operators in Annual Reports by year from 2004 to
2013. As can be seen, almost 2,000 miles have been constructed since 2004, all being used for
enhanced oil recovery.
Table 2: Supercritical CO2 Pipelines Regulated Under Part 195
by Year17
Year
Liquid CO2 Mileage
12
http://phmsa.dot.gov/pipeline/library/data-stats
A CO2 flood refers to injecting CO2 into depleted oil wells at pressures above the critical pressure of 1070 psi to
recover oil that cannot be recovered using the wells natural pressure or water floods.
14
Developing a Pipeline Infrastructure for CO2 Capture and Storage: Issues and Challenges, ICF International,
February, 2009
15
Comparing Existing Pipeline Networks with the Potential Scale of Future U.S. CO 2 Pipeline Networks, JJ Dooley,
RT Dahowski, CL Davidson, Pacific Northwest National Laboratory, February 2008
16
2013 Hazardous Liquid Annual Report
17
http://phmsa.dot.gov/resources/data-stats
13
Department of Transportation
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Pipeline and Hazardous Materials
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2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
3,221
3,846
3,827
3,884
4,203
4,192
4,560
4,735
4,840
5,195
Figure 2 shows the location of supercritical CO2 pipelines (as of 2009).
Figure 2: Liquid CO2 Pipelines in the U.S. Subject to Part 19518,19
3.2 Pipelines Transporting CO2 in the Gaseous State
Although there is information available on pipelines transporting CO2 in the supercritical fluid
state, little information exists on CO2 being transported by pipeline in the gaseous state. PHMSA
is aware of only one 78-mile pipeline that transports low pressure gaseous CO2 in a gas gathering
field.
4.0 Planned CO2 Pipeline Construction
A major reason for the Congressional mandate for DOT to regulate gaseous CO2 pipelines is that
recent technological breakthroughs and regulatory developments would require more pipelines.
Specifically, the development and improvement of enhanced oil recovery (EOR) technology is
creating a demand for more CO2 pipelines to deliver CO2 to oilfields. Also, the initiatives to
18
Ibid. 14, p. 5
Additional CO2 pipelines have been constructed since 2009 and are not represented on this map. For example,
the Louisiana terminus to Houston, TX expansion of the Green Pipeline by Denbury, a 314 mile expansion, began
construction in 2009 and is not shown on the map. (if able, move to previous page)
19
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Pipeline and Hazardous Materials
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reduce greenhouse gas (GHG) emissions is creating demand for carbon capture and sequestration
(CCS) projects,20 which require a means to transport captured carbon dioxide to long term
storage or locations where it can be utilized (such as EOR projects). As a result, projections are
estimating that the CO2 pipeline infrastructure will need to be expanded by up to an order of
magnitude (or more).
A study funded by INGAA21 has projected the need to construct 15,000 to 66,000 miles of new
CO2 pipelines by 2030 to connect anthropogenic (man-made) sources of CO2 with storage wells
and reservoirs. Another study performed by Pacific Northwest National Laboratory (PNNL) 22
estimates that 30,000 new CO2 pipeline miles will need to be constructed for CCS projects.
Some of this CO2 will be used for enhanced oil recovery, some will be stored in depleted
reservoirs (from which no further enhance oil recovery is possible), and some will be stored in
saline aquifers and abandoned coal mines. However, the studies did not specifically address the
state in which the CO2 would be transported (gaseous or supercritical). One report concluded that
“[A]lthough any widespread CCS scheme in the United States would likely require dedicated
CO2 pipelines, there is considerable uncertainty about the size and configuration of the pipeline
network required. This uncertainty stems, in part, from uncertainty about the suitability of
geological formations to sequester captured CO2 and the proximity of suitable formations to
specific sources. One analysis concludes that 77% of the total annual CO2 captured from the
major North American sources may be stored in reservoirs directly underlying these sources, and
that an additional 18% may be stored within 100 miles of additional sources.”23
While it is more efficient to transport CO2 in a supercritical fluid state, it may be more
economical, under some circumstances, to transport it for short distances in a gaseous state.
Some studies have indicated that the CO2 from anthropogenic sources may only have to be
transported for short distances. The disadvantage of transporting in a gaseous state is that to use
CO2 for EOR requires the minimum miscible pressure to be above the critical pressure of 1070
psig at a temperature of 88 °F. For transport to saline aquifers, minimum miscible pressure is not
a factor; however, to ensure maximum sequestration in a saline aquifer, high injection pressures
will be required. These pressures will, most likely, have to be above the minimum miscible
20
The first step in direct sequestration is to produce a concentrated stream of CO 2 for transport and storage.
Currently, three main approaches are available to capture CO2 from large-scale industrial facilities or power plants:
• Pre-combustion, which separates CO2 from fuels by combining them with air and/or steam to produce
hydrogen for combustion and CO2 for storage,
• Post-combustion, which extracts CO2 from flue gases following combustion of fossil fuels or biomass, and
• Ox fuel combustion, which uses oxygen instead of air for combustion, producing flue gases that consist mostly
of CO2 and water from which the CO2 is separated.
These approaches vary in terms of process technology and maturity, but all yield a stream of extracted CO 2 which
may then be compressed to increase its density and make it easier (and cheaper) to transport. Although
technologies to separate and compress CO2 are commercially available, they have not been applied to large-scale
CO2 capture from power plants for the purpose of long-term storage.
21
Ibid. 14, p. 5
22
Comparing Existing Pipeline Networks with the Potential Scale of Future U.S. CO 2 Pipeline Networks, JJ Dooley,
RT Dahowski, CL Davidson, Pacific Northwest National Laboratory, February 2008
23
Carbon Dioxide (CO2) Pipelines for Carbon Sequestration: Emerging Policy Issues, Paul Parfomak, Peter Folger,
Adam Vann, July 2009
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pressure of 1070 psig. There could be other factors where high pressure storage of CO2 is not
feasible due to the sub-surface rock characteristics of a particular storage reservoir.
Figure 3 shows the location of coal fired power plants, a major contributor of CO2 to GHG
emission, in relation to potential storage reservoirs. As can be seen, there are many saline
aquifers near these power plants, so a deciding factor in the amount of new CO2 pipeline to be
constructed will be whether it will be sequestered in saline aquifers or used in enhanced oil
recovery. If sequestration is the option for a large portion of the collected CO2, less pipeline
mileage will need to be constructed than if enhanced oil recovery is the option, due to the close
proximity of the aquifers to these major sources of CO2. However, the shorter the pipeline, the
more likely it would be that a gaseous state pipeline would be chosen.
Appendix A lists some planned CO2 pipeline projects obtained from publicly available sources.
(Note: this list represents a snapshot in time when this report was developed and some projects
may have been canceled while other projects may have been planned.) Some are known to be
planned to operate in the supercritical fluid state, but the state of operation for most of those
projects is not available.
Figure 3: Locations of Storage Reservoirs in Relation to Coal-Fired Power Plants24
24
Ibid. 14, p. 5
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5.0 Potential Safety Consequences of Gaseous CO2 Pipeline
Accidents
The most likely safety consequence of a CO2 pipeline accident is asphyxiation, when CO2 is
breathed by humans or animals. Since January 1, 2002, through August 1, 2014, there have been
5525 accidents involving supercritical fluid CO2 pipelines reported to the Pipeline and Hazardous
Material Safety Administration (PHMSA). There have been no reported fatalities and one injury
as a result of these accidents. The nature of the injury was not specified; however, the injured
party was a contractor working on the pipeline and the cause of the release was excavation
damage.
Carbon dioxide is heavier than air and therefore hugs the ground and could be a potential
asphyxiant when released from a pipeline, endangering the public, workers, and emergency
responders. Because it transitions rapidly into a gaseous form when released from a supercritical
fluid pipeline, it dissipates quickly into the atmosphere. Only accidents involving supercritical
fluid CO2 and meeting the PHMSA reporting requirements are in the PHMSA accident database.
Since CO2 transported in the gaseous state is not regulated, incidents that occur do not have to be
reported to PHMSA unless the operator voluntarily reports them. These incidents may, however,
be subject to National Reporting Center (NRC) reporting requirements. The risk of a release of
gaseous state CO2 versus CO2 in the supercritical fluid state are similar. The analysis of the
asphyxiation hazard that would result from a gaseous CO2 release is similar to the analysis of the
release of highly volatile liquids and supercritical CO2. Similar techniques are used to predict the
size, direction, and concentration of the gaseous cloud that results from a postulated release. The
difference would be in the amount released. In the supercritical fluid state the liquid to gaseous
conversion and expansion would result in a greater mass of CO2 release, as compared to a release
of pure CO2 gas.
As far as public and worker health is concerned, “…it is believed that nearly all workers may be
repeatedly exposed day after day without adverse effects [to CO2 levels] of 5000 ppm.”26 The
Center for Disease Control has established Immediate Danger to Life and Health (IDHL) levels
at 70,000 to 100,000 ppm in air. A model of the release of supercritical fluid CO2 from a 6-inch
pipeline at 2300 psig showed that a concentration of 40,000 ppm was reached at 2,151 ft. from
the release location.27 Higher concentrations would be seen closer to the release location as the
gas cloud expands and dissipates. Currently most CO2 pipelines are located in sparsely populated
areas, but that may change as CCS projects come into operation. One known exception is the
Denbury Resource Green CO2 pipeline, which runs through the high population areas of
Beaumont and Houston, Texas. As CCS projects come on-line, which may be in populated areas,
potential releases could represent an increase in risk of injuries and/or fatalities.
25
2002 through 2013 Hazardous Liquid Accident Reports
Eric J. Beckman, Supercritical and near-critical CO2 in green chemical synthesis and processing, Journal of
Supercritical Fluids, Volume 28, 2004
27
CFD Modelling of Gas Dispersion from a Ruptured Supercritical CO2 Pipeline,
http://www.cham.co.uk/casestudies/CCS_Gas_Dispersion.pdf
26
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Other possible hazards from a CO2 pipeline accident could be physical injury to workers or
persons in close proximity to the accident caused by pipe movement, flying debris, or jet
impingement of escaping gas from a relatively small through-wall flaw. A release of supercritical
CO2 or gaseous CO2 dissipates quickly into the atmosphere, but because it is non-flammable
there is no environmental impact in the area of the release. However, CO2 is the leading source
of Greenhouse Gas releases from human activities and its concentration in the atmosphere has
been linked to global warming.
6.0 Threats and Hazards to Gaseous CO2 Pipelines
CO2 pipelines – whether supercritical or gaseous – are susceptible to the same threats as are
natural gas and hazardous liquid pipelines. These threats are:
6.1 Internal Corrosion
Internal corrosion failures occur when the interior pipe wall thins to the point where it can no
longer resist the internal pressure of the pipeline. The higher the operating pressure in the
pipeline, the less wall thinning must occur before the pipe will fail. CO2 pipelines currently
restrict the chemical composition of fluids they transport. The most important limit is the amount
of water (which is an electrolyte) that corrodes standard carbon steel. Naturally occurring CO2
can contain other elements such as water and methane. The majority of these elements are
removed prior to transporting the CO2 by pipeline. CO2 mixed with any impurities such as water
or hydrogen sulfide can be an internal corrosion accelerant.
6.2 External Corrosion
External corrosion failures occur when the exterior pipe wall thins to the point where it can no
longer resist the internal pressure of the pipeline. The higher the operating pressure in the
pipeline, the less wall thinning must occur before the pipe will fail. Steel pipelines are typically
protected from external corrosion by cathodic protection systems and coatings. The pressures at
which gaseous CO2 will be transported will be similar to the pressures at which natural gas is
transported. The wall thickness, pipe material, coating type, and cathodic protection of the pipe
will be similar to those of natural gas pipelines.
6.3 Excavation Damage
Excavation damage typically occurs when construction is taking place in the vicinity of the
pipeline. All buried pipelines are susceptible to excavation damage. Carbon dioxide pipelines are
located in remote areas so the likelihood of a release due to excavation damage is lower than for
natural gas or hazardous liquid pipelines. This may change as CSS projects come on-line and
pipelines are routed through populated areas.
6.4 Natural Force Damage
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Natural force damage occurs as a result of hurricanes, floods, tornadoes, lightning strikes, earth
movement, or seismic events. Pipelines that are above ground are susceptible to all of the above
threats. Buried pipelines are susceptible to earth movement, lightning strikes, flooding, scouring,
or washout where pipelines cross water bodies, and seismic events.
6.5 Other Outside Force Damage
Other outside force damage occurs as a result of external events or circumstances such as fires or
explosions external to the pipeline, damage from vehicles, anchor drag, dredging, electrical
arcing or accelerated corrosion from nearby sources such as high voltage power lines, and
residual damage not caused by excavation such as rocks in contact with the pipeline.
6.6 Incorrect Operation
Failure due to incorrect operation occurs as a result of valve misalignment, overpressure events,
equipment incorrectly installed, or the wrong component having been installed.
6.7 Pipe Material & Weld Failure
Pipe material and weld failures occur as a result of poor welds made in the field, such as girth
welds, but may also be inherent in the manufacturing process, such as long seam welds with a
joint factor less than 1.0, hook cracks, and laminations in the pipe steel. Environmental cracking,
such as stress corrosion cracking, is also reported as a pipe material failure.
6.8 Equipment Failure
Equipment failures such as (but not limited to) compressor or pump malfunctions, connection
failures such as sensor lines, loose connections, or malfunction of pressure control/relief
equipment could cause an incident.
6.9 Accident History of CO2 Pipelines Regulated Under Part 195
Table 3 provides a summary of the number of reportable accidents, by cause, that have occurred
on pipelines transporting CO2 in a supercritical phase and regulated under Part 195 during the
period from 2002 through August 1, 2014.
Cause
# of
Acc.
Table 3: Number of Reportable CO2 Pipeline Accidents, by Cause (2002-August 1, 2014)
Internal
External
Excavation Natural Other
Incorrect
Mat’l or
Eqpt.
Corrosion Corrosion Damage
Force
Outside Operation Weld
Failure
Force
Failure
0
3
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2
0
14
0
2
17
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Unknown
8
7.0 Candidate Approaches to Regulating Gaseous CO2
Pipelines
The Act specified that the Secretary of Transportation consider whether applying the existing
minimum safety standards in Part 195 “for the transportation of carbon dioxide in a liquid state
to the transportation of carbon dioxide in a gaseous state would ensure safety.” After evaluation,
PHMSA believes that the application of existing minimum safety standards in Part 195 for the
transportation of carbon dioxide in a supercritical fluid state to the transportation of carbon
dioxide in a gaseous state would ensure safety. However, because of specific technical aspects
and the existing regulatory construct, some revisions to the pipeline safety regulations would be
needed to accommodate the regulation of the transportation of CO2 by pipelines in a gaseous
state. PHMSA is considering two candidate approaches to regulating gaseous CO2 pipelines:
1. Expanding the scope of Part 192 to include gaseous CO2 pipelines; however,
wherever possible cross referencing Part 192 to the applicable Part 195
regulations where no revisions or minor revisions are required.
2. Expanding the scope of Part 192 to include gaseous CO2 pipelines.
In either case, specific revisions to Part 192 would be needed to specific regulatory requirements
to accommodate the inclusion of gaseous CO2 pipelines.
7.1 Regulating Gaseous CO2 Pipelines under Parts 192 and 195
The Act specified that the Secretary of Transportation consider whether applying the existing
minimum safety standards in Part 195 “for the transportation of carbon dioxide in a liquid state
to the transportation of carbon dioxide in a gaseous state would ensure safety.” The implication
of this mandate is to evaluate if the regulations applicable to the transport of supercritical fluid
CO2 under Part 195 can also be applied to the safe transport of CO2 in a gaseous state.
The basic regulatory requirements (design, construction, operations, and maintenance) to ensure
the safe transportation of CO2 by pipeline are already in place in Part 195. These can either be
revised as necessary and incorporated into Part 192 or, in some cases, simply be referenced to
Part 195 from Part 192 where no revisions or minor revisions are necessary to make the Part 195
regulation applicable to the transport of gaseous CO2.
In order to implement the regulation of gaseous CO2 pipelines in Part 192, some code language
and requirements would need to be revised. In addition, other requirements might need further
evaluation to ascertain if revisions would be needed. PHMSA has performed a preliminary
evaluation of the Part 195 regulations and identified those that would or might need to be revised
to be applicable to the transport of gaseous CO2. These items are discussed below. These issues
are not necessarily an exhaustive list of topics that might need to be evaluated as a result of
covering gaseous CO2 pipelines under Part 195. A detailed technical evaluation of all Part 195
regulations would be conducted as part of any formal rulemaking proceeding.
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7.1.1 §195.2 - Definition of Carbon Dioxide
The current definition of carbon dioxide as used in Part 195 is that carbon dioxide is a fluid in
the supercritical state. The definition of carbon dioxide could be changed to eliminate reference
to the physical state of the carbon dioxide. Such an approach would include gaseous CO2 as well
as subcritical liquid CO2, along with supercritical CO2. If the intent is to regulate only CO2 in the
supercritical state, or the gaseous state, but not in the subcritical liquid state, then separate
definitions of supercritical and gaseous carbon dioxide would need to be included.
In addition, everywhere the term “carbon dioxide” is used in Part 195 (e.g., §§195.116, .401,
.402, .403), the meaning presumes supercritical CO2. An evaluation would be needed to
determine if those uses of the term in Part 195 are general (such that they would apply
appropriately to gaseous CO2 pipelines) or specific to supercritical CO2 (such that adjustments to
the regulatory language would be needed to accommodate the change in definition).
7.1.2 Compression Equipment
The current regulations in Part 195 are based on the transportation of fluids in the liquid state.
The definitions (e.g., component, line section, pipeline system, surge pressure) and requirements
(e.g., design, construction, operations, maintenance) address pumps, pump stations, et cetera, but
do not address compressors, compressor stations, et cetera. While compressors in a gas pipeline
system serve the same functional purpose as pumps in a liquid pipeline system, technical
differences in the two systems would need to be evaluated and addressed in the appropriate Part
of the CFR.
7.1.3 Maintaining Gaseous CO2 in a Gaseous State
The maximum operating pressure (MOP) specified in Part 195 is based exclusively on not
overstressing the pipe to assure pipeline integrity. In the case of gaseous CO2, there are safety
considerations that might require operational controls on pipelines transporting CO2 in the
gaseous state in order to maintain the CO2 in a gaseous state (i.e., it would be important to
preclude the CO2 from changing to subcritical liquid state or the supercritical state during
transportation operations). To maintain CO2 in a gaseous state, the pressure needs to be kept
below the interface pressure at which gaseous CO2 is compressed into a liquid (for the operating
temperature). Refer to Figure 1. To do this, the operator would need to take into account
topography, environmental conditions, and temperature extremes (both operational and
environmental).28
Therefore, PHMSA may need to evaluate the need to prescribe additional controls on operational
parameters, such as temperature and pressure, for this purpose. Such pressure controls might
require that pressures be maintained below the MOP that would have been determined under
28
For example, the design of an early CO2 pipeline in 1970, the Canyon Reef pipeline, considered two concepts.
One would control the pressure in the pipeline low enough to maintain the CO2 in a gaseous phase. The second
would control the pressure high enough to maintain the CO2 as a dense vapor. In that case, the design to keep the
CO2 as a gas would have maintained the operating pressure less than 696 psi.
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existing Part 195 requirements. This issue applies to regulating gaseous CO2 pipelines under Part
192 also (see 7.2.5).
7.1.4 §195.8 - Transportation of gaseous carbon dioxide in pipelines constructed with other
than steel pipe
The current requirements in Part 195, since 1991, preclude the transportation of supercritical
CO2 in pipelines made of material other than steel (unless the operator notifies PHMSA and
PHMSA does not object). PHMSA may need to evaluate the applicability of this requirement to
gaseous CO2 pipelines, taking into account that existing (and previously unregulated) gaseous
CO2 pipelines might have been built using plastic pipe or other materials besides steel. If such
practices were widespread (determination of such was outside the scope of this report), then
PHMSA may need to include language to grandfather, exempt, or otherwise address this
requirement for pre-existing non-steel pipe used to transport gaseous CO2.
7.1.5 §195.102(b) - Design temperature
Part 195 contains a specific requirement that applies only to supercritical CO2 pipelines, due to
the physical properties of supercritical CO2. “Components of carbon dioxide pipelines that are
subject to low temperatures during normal operation because of rapid pressure reduction or
during the initial fill of the line must be made of materials that are suitable for those low
temperatures.” PHMSA would need to address if this requirement should apply to pipelines
transporting gaseous CO2.
7.1.6 §195.111 - Fracture propagation
Part 195 contains a specific requirement that applies only to supercritical CO2 pipelines due to
the physical properties of supercritical CO2. “A carbon dioxide pipeline system must be designed
to mitigate the effects of fracture propagation.” Fracture propagation is also a concern for gas
pipelines because they operate with a highly compressed gas, which would also be the case for a
gaseous CO2 pipeline. It is presumed that this requirement would also apply to a gaseous CO2
pipeline, but additional evaluation may be needed to ascertain if the existing language in
§195.111 is sufficient and appropriate for a gaseous CO2 pipeline.
7.1.7 Part 195 Subpart E - Pressure Testing
The current requirements in Part 195, since 1991, allow certain supercritical CO2 pipelines to
operate without having had a pressure test in accordance with Subpart E, if they were constructed
before CO2 pipelines became subject to Part 195. PHMSA may need to evaluate the applicability
of this requirement to gaseous CO2 pipelines, taking into account that existing (and previously
unregulated) gaseous CO2 pipelines might have been built before promulgation of a rule that
regulates gaseous CO2 pipelines. In such cases, PHMSA may need to include language to
grandfather, exempt, or otherwise address pressure test requirement for pre-existing steel pipe
used to transport gaseous CO2.
7.1.8 §195.11 - What is a regulated rural gathering line and what requirements apply?
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There are two sources of CO2, natural and anthropogenic (manmade). Just as there are oil and
natural gas deposits trapped in the earth, there are also natural deposits of CO2. PHMSA
anticipates that most of the demand for gaseous CO2 pipelines would be to transport CO2
produced from man-made sources, such as from the combustion of fossil fuels in power plants,
as a result of the current environmental emphasis and development of CCS to reduce GHG
emissions (since the injected CO2 is then trapped and permanently stored in depleted oil wells).
However, pipelines that gather CO2 from natural sources might meet the definition of a gathering
line. Gathering pipelines that transport CO2 in a gaseous state may become regulated as
gathering pipelines. In the case of a rural gathering line, current requirements under §195.11 do
not regulate rural gathering lines if they do not impact Unusual Sensitive Areas. Since any
gaseous CO2 pipeline accident would release CO2 as a vapor and would have little if any impact
on USAs, PHMSA would have to address if and how to regulate gaseous CO2 rural gathering
pipelines.
7.2 Regulating Gaseous CO2 Pipelines under Part 192
7.2.1 Comparability of Parts 192 and 195 with Respect to Regulating Gaseous CO2
Pipelines
The design, construction, operation, maintenance, and surveillance requirements of Part 195 are
comparable to, and in many cases closely parallel, similar requirements in Part 192. In 2010,
PHMSA conducted a team review to compare Parts 192 and 195, with a view toward identifying
gaps or differences between the two, and harmonizing Parts 192 and 195 in subsequent
rulemaking. PHMSA believes that regulating gaseous CO2 under Part 192 would ensure safety
comparable to regulating supercritical CO2 under Part 195.
Table 4 lists the regulatory requirements in Part 195 that specifically mention CO2 by name (in
the context of Part 195, these refer to the transport of supercritical CO2). Some of these are
generic references that simply refer to the scope of Part 195 (i.e., they state that the requirement
applies to hazardous liquid and CO2 pipelines), while some of them are special technical
requirements that apply only to CO2 pipelines. Note that this table is not a complete list of
requirements in Part 195 that apply to CO2 pipelines, as all of Part 195 applies to CO2 pipelines
unless specified otherwise. However, most of the general requirements of Part 195 have parallel
and/or equivalent requirements in Part 192, or Part 191, which addresses reporting requirements.
Table 4 lists comments regarding if and how Part 192 could address those specific requirements
that exist in Part 195.
Table 4: Comparison of 49 CFR 195 Requirements that Specifically Name Carbon Dioxide
with Part 191 and 192 Requirements
49 CFR 195 Requirement
Comparison with Parts 191 and 192
§195.2 Definitions
§195.4 Compatibility with
hazardous liquids or carbon
dioxide being transported
§192.3 Definitions
§192.53(b) Compatibility with any gas the pipeline transports
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Table 4: Comparison of 49 CFR 195 Requirements that Specifically Name Carbon Dioxide
with Part 191 and 192 Requirements
49 CFR 195 Requirement
Comparison with Parts 191 and 192
§195.8 Transportation of
hazardous liquid or carbon
dioxide in pipelines
constructed with other than
steel pipe
§195.49 Annual report
§195.50 Reporting accidents
$195.52 Immediate notice of
certain accidents
§195.102(b) Design
temperature (see section
7.1.5)
§195.111 Fracture
propagation (see section
7.1.6)
§195.116(c) Compatibility of
material used in valves
§195.302 Test Requirements:
General requirements
§195.306(c) Test medium
§195.401 General operation
and maintenance
requirements
§195.402 Procedural manual
for operations, maintenance,
and emergencies
§195.403 Emergency
response training
§195.410 Line markers
§195.440 Public awareness
No comparable requirement in Part 192. Part 192 has design
requirements for plastic pipe, but no notification requirements.
An evaluation would be needed to determine if construction of
gaseous CO2 pipelines with pipe material other than steel should
be allowed. If not, appropriate regulations would be needed to
address this aspect.
§191.17
§191.15 Incident report
§191.5 Immediate notice of certain incidents
There is no equivalent requirement in Part 192. As discussed in
section 7.1.5, an evaluation is needed to determine if a similar
requirement would be needed for a gaseous CO2 pipeline.
There is no equivalent requirement in Part 192. As discussed in
section 7.1.6, an evaluation is needed to determine if a similar
requirement would be needed for a gaseous CO2 pipeline.
§192.145(c) is a comparable requirement, although it uses
different language. An evaluation is needed to determine if
revisions would be needed for a gaseous CO2 pipeline.
§192.503 Test Requirements: General requirements. Although
comparable, hoop stress limitations are based on class location,
which is not applicable to Part 195. See section 7.2.3, below, for
discussion on the need to address class locations for gaseous
CO2 pipelines.
§192.503(b) specifies that the test medium must be liquid, air,
natural gas, or inert gas. An evaluation is needed to determine if
this paragraph needs to be revised to add CO2 as an allowed test
medium and/or to address the limitations imposed by
§195.306(c) for the use of carbon dioxide as the test medium.
§192.603 General operating requirements and .703 general
maintenance requirements.
§192.605 Procedural manual for operations, maintenance, and
emergencies
§192.615(b)(2), a paragraph under §192.615 Emergency plans,
includes requirements for emergency response training.
§192.707 Line markers for mains and transmission lines. An
evaluation of the exceptions to marking pipelines specified in
§192.707(b) would be needed, since Part 195 does not have
similar exceptions.
§192.616 Public awareness.
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Table 4: Comparison of 49 CFR 195 Requirements that Specifically Name Carbon Dioxide
with Part 191 and 192 Requirements
49 CFR 195 Requirement
Comparison with Parts 191 and 192
§195.452 Integrity
management
§195.579 What must I do to
mitigate internal corrosion?
Part 192, Subpart O. However, the method for determining if a
segment could affect an HCA is not applicable to non-flammable
gas (such as CO2). See section 7.2.2.
§192.475 Internal corrosion control: General, and
§192.477 Internal corrosion control: Monitoring.
Since comparable requirements exist or could be addressed in Part 192, PHMSA believes that
the safety basis for regulation of gaseous CO2 pipelines under Part 192 would be comparable to
regulating gaseous CO2 pipelines under Part 195, as cross-referenced from Part 192. A related
option could be to regulate gaseous CO2 through a subset of the Part 192 regulations, similar to
current §192.9 regulations for gathering lines.
Some requirements in Part 192 might require adjustments or modifications to accommodate the
regulation of gaseous CO2 pipelines. Those items are discussed below, but are not necessarily an
exhaustive list of topics that might need to be evaluated as a result of covering gaseous CO2
pipelines under Part 192. A detailed technical evaluation would be conducted as part of any
formal rulemaking proceeding.
7.2.2 Determination of Covered Segment under Part 192, Subpart O (Integrity
Management) for Gaseous CO2 Pipelines
Whether a pipeline segment can impact a “high consequence area” (HCA) depends on whether
or not the segment is within the potential impact radius (PIR). The PIR of a pipeline is based on
the predicted heat flux of a pipeline explosion and is calculated using an equation that is based
on flammable gasses. The equation is applicable to flammable gases only, and not applicable for
determining the potential impact radius of an accident involving CO2. Hence, if CO2 is included
in Part 192, and included in Subpart O, an alternative method of determining if a CO2 pipeline
segment could impact an HCA would have to be devised. The most logical method of
determining the impact of a gaseous CO2 release would be the use of dispersion analysis to
determine the extent and concentration of a vapor cloud released following a CO2 pipeline
leak/rupture (similar to the technique used to comply with Part 195 to determine if a supercritical
CO2 line could affect an HCA), which would require Subpart O to be modified. Since HVLs and
supercritical CO2 behave as gases when released, and air dispersion is used to determine the
impact on an HCA, including gaseous CO2 pipelines into 195.452 may be the logical choice.
7.2.3 Applicability of §192.5 - Class locations
“Class locations were an early method of differentiating risk along gas pipelines. The class
location concept pre-dates Federal regulation of pipelines. These designations were previously
included in the ASME International standard, “Gas Transmission and Distribution Pipeline
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Systems,” (ASME B31.8) from which the initial pipeline safety regulations were derived.”29
Similar to subpart O, the class location concept was developed based on an explosion hazard
from natural gas. Class location impacts many design and operation requirements in Part 192,
including (notably) the design factor and the test pressure to establish maximum allowable
operating pressure (MAOP). PHMSA would have to address if and how to apply the class
location concept to gaseous CO2 pipelines.
7.2.4 §192.8 - How are onshore gathering lines and regulated onshore gathering lines
determined?
There are two sources of CO2, natural and anthropogenic (manmade). Just as there are oil and
natural gas deposits trapped in the earth, there are also natural deposits of CO2. PHMSA
anticipates that most of the demand for gaseous CO2 pipelines would be to transport CO2
produced from man-made sources, such as from the combustion of fossil fuels in power plants,
as a result of the current environmental emphasis and development of CCS to reduce GHG
emissions (since the injected CO2 is then trapped and permanently stored in depleted oil wells).
However, pipelines that gather CO2 from natural sources might meet the definition of a gas
gathering line. Gathering pipelines that transport CO2 in a gaseous state may become regulated
as either a Type A or B pipeline. PHMSA would have to address if and how to apply the class
location concept to gaseous CO2 gathering pipelines.
7.2.5 Maintaining Gaseous CO2 in a Gaseous State
The maximum allowable operating pressure (MAOP) specified in Part 192 is based exclusively
on not overstressing the pipe to assure pipeline integrity. In the case of gaseous CO2, there are
safety considerations that might require operational controls on pipelines transporting CO2 in the
gaseous state in order to maintain the CO2 in a gaseous state (i.e., it would be important to
preclude the CO2 from changing to liquid phase during transportation operations). To maintain
CO2 in a gaseous state, the pressure needs to be kept below the interface pressure at which
gaseous CO2 is compressed into a liquid (for the operating temperature). Refer to Figure 1. To do
this, the operator would need to take into account topography, environmental conditions, and
temperature extremes (both operational and environmental).30
Therefore, PHMSA may need to evaluate the need to prescribe additional controls on operational
parameters such as temperature and pressure for this purpose. Such pressure controls might
require that pressures be maintained below the MAOP that would have been determined under
existing Part 192 requirements.
8.0 Summary
29
78 FR 46560
For example, the design of an early CO2 pipeline in 1970, the Canyon Reef pipeline, considered two concepts.
One would control the pressure in the pipeline low enough to maintain the CO 2 in a gaseous phase. The second
would control the pressure high enough to maintain the CO2 as a dense vapor. In that case, the design to keep the
CO2 as a gas would have maintained the operating pressure less than 696 psi.
30
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The transport of CO2 in supercritical fluid form is currently regulated in Part 195 by PHMSA.
Operators are required to submit data on their CO2 pipelines in Hazardous Liquid Pipeline
Annual Reports. In 2013 Annual Reports, hazardous liquid pipeline operators reported 5,19531
miles of CO2 pipelines.
Currently, PHMSA does not regulate pipelines transporting CO2 in a subcritical liquid or gaseous
state. The Act mandated that the Secretary of Transportation “prescribe minimum safety
standards for the transportation of carbon dioxide by pipeline in a gaseous state.” The Act also
mandated that in establishing those standards, the Secretary consider whether applying the
existing minimum safety standards in Part 195 “for the transportation of carbon dioxide in a
liquid state to the transportation of carbon dioxide in a gaseous state would ensure safety.”
INGAA and others have estimated the need to build up to 66,000 miles of CO2 pipelines by
2030. This large expansion of CO2 pipeline capacity is driven by two major factors:
(1) To reduce the amount of greenhouse gases released to the atmosphere, Carbon
Capture and Sequestration (CCS) projects are being constructed or planned. These
projects involve the retrofit of equipment to sources of anthropogenic (man-made) CO2
such as coal-fired electric power plants. The equipment would capture CO2 at some point
in the process and transport it for use in enhanced oil recovery (EOR) projects or for
sequestration in depleted wells, saline aquifers, or abandoned coal mines.
(2) The ongoing improvement in oil extraction technology is increasing demand for CO2
for use in EOR oil production.
For technical efficiency, PHMSA expects that most CO2 would be transported in the supercritical
fluid state, and thus would be regulated under the existing requirements of Part 195. However, in
some cases, technical issues such as the physical characteristics of the sequestration storage
reservoir, transportation distance, et cetera, the CO2 might be transported in the gaseous state. In
such cases, revisions of the existing pipeline safety regulations would be needed to implement
the statutory mandate, since current regulations do not cover the transportation of gaseous CO2.
PHMSA performed a preliminary evaluation of two options for regulating gaseous CO2
pipelines:

Regulate the transport of gaseous CO2 entirely under Part 192, or

Under Part 192 where appropriate with reference to applicable sections of Part 195.
It should be noted that this preliminary evaluation might not have identified every issue that
would need to be addressed. A detailed technical evaluation would be conducted as part of any
formal rulemaking proceeding and industry, stakeholders, and other interested parties would be
given the opportunity to comment on any proposed rulemaking.
31
Ibid. 14, p. 5
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The conclusion is that the minimum safety standards for the transport of supercritical fluid CO2
under Part 195 can, with some modifications, ensure the safe transportation of gaseous CO2
under Part 192. Also, since comparable requirements exist or could be addressed in Part 192,
PHMSA believes that the safety basis for regulation of gaseous CO2 pipelines under Part 192
would be comparable to regulating gaseous CO2 pipelines under Part 195. Since the
transportation of gases is subject to Part 192, either scenario would require an amendment to Part
192 to accommodate the regulation of the transportation of CO2 by pipelines in a gaseous state.
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Appendix A Known CO2 Pipeline Projects Being Planned or Built
A.1 Natural CO2 Reservoir Pipeline Projects
There are several CO2 pipeline construction projects planned or underway from both natural and
anthropogenic sources. The following describes some planned and ongoing natural CO2 projects.
This is not intended to be a comprehensive list of new projects. It should also be noted that this
was a snapshot in time when this report was developed and some of projects presented below
may be canceled in the future. These projects will use CO2 for EOR and will transport it in a
supercritical phase.
A.1.1 Kinder Morgan Energy Partners, LP (KMEP)32
KMEP reported it will invest $671 million to expand its carbon dioxide infrastructure in
southwestern Colorado and New Mexico. KMEP plans to expand the production operations in
the Cow Canyon area of the McElmo Dome source field in Montezuma County, Colorado, and
expand the 500-mile Cortez Pipeline that transports CO2 from southwestern Colorado to eastern
New Mexico and western Texas for use in enhanced oil recovery projects.
KMEP investments are in addition to its recently announced initiative to invest $1 billion to
develop the St. Johns source field in Apache County, Arizona, and build a 241-mile pipeline to
transport CO2 from St. Johns to the Cortez Pipeline in Torrance County, New Mexico.
The Cortez Pipeline expansion consists of adding a 64-mile loop in New Mexico and three new
pump stations.
A.1.2 Denbury Resources33
Denbury Resources’ primary focus is on enhanced oil recovery utilizing CO2. Denbury has
operations in the Gulf Coast region (Texas, Louisiana, Mississippi, and Alabama) and in the
Rocky Mountain region (Montana, North Dakota, and Wyoming). Denbury has plans to expand
its operations in both regions.

Denbury will be constructing a 9-mile, 16-inch diameter pipeline connecting the existing
Green pipeline with the Webster Field in Texas. The project is expected to be operational
in 2015.

Denbury will be constructing a 90-mile pipeline connecting their Green pipeline with the
Conroe Field in Texas. The project is expected to be operational in 2017.
32
KMEP to expand CO2 systems in Colorado, New Mexico, http://www.ogj.com/articles/2014/05/kmep-to-expandcarbon-dioxide-systems-in-colorado-new-mexico.html?cmpid=EnlPipelineMay272014
33
CO2 Sources and Pipelines, http://www.denbury.com/files/2014-02%20UPLOADS/201311%20Analyst%20Day%20FINAL%20Website%20Print%20Version_v001_w0yoh7.pdf
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
Denbury will be constructing a 250-mile pipeline connecting their Riley Ridge and
LaBarge Fields with the Greencore pipeline in Wyoming. Operation is expected to
commence in 2019-2020.

Denbury will be constructing a 130-mile extension of the Greencore pipeline with the
Cedar Creek Anticline in Montana. Operation is expected to commence in 2020.
A.1.3 Blackstone Energy Partners
Blackstone Energy Partners and Blackstone Group affiliates have formed Windy Cove Energy
LLC with a commitment to invest $700 million to acquire and develop carbon dioxide enhanced
oil recovery assets in the U.S.34
A.2 Anthropogenic Sources of CO2
The following projects are anthropogenic (manmade) projects intended to capture and sequester
carbon in oil wells, saline aquifers, and abandoned coal mines. These projects were a snapshot in
time when this report was developed and some may have been canceled and new projects
planned. The CO2 used in the EOR projects described below will be transported in a supercritical
phase. The saline aquifer injection project will also transport CO2 in a supercritical phase.
A.2.1 Southern Company/Denbury Resources35
Southern Company has built a Carbon Capture facility in Kemper County, Mississippi. The
facility will capture carbon from a 582-megawatt gasification power plant. The CO2 will be
transported 60 miles to oil fields operated by Denbury for enhanced oil recovery through
pipelines operated by Denbury. The facility is expected to be operational in 2015.
A.2.2 SCS Energy36
SCS Energy is planning to construct a 4-mile pipeline to capture CO2 for enhanced oil recovery
in the Elk Hills oil field in Kern County, California. The project is expected to be operational in
2018.
A.2.3 Texas Clean Energy Project (TCEP)37
TCEP will construct pipelines to transport captured CO2 from a coal burning power plant near
Odessa, Texas, to wells in the Permian Basin for EOR. The project is expected to be operational
in 2015.
34
http://www.ogj.com/articles/2014/10/windy-cove-to-invest-700-million-in-us-carbon-dioxide-eorprojects.html?cmpid=EnlDailyOctober92014/
35
Carbon Capture, http://www.eenews.net/stories/1060003330
36
http://sequestration.mit.edu/tools/projects/
37
http://sequestration.mit.edu/tools/projects/
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A.2.4 NRG Energy, Inc.38
NRG will build a facility to capture carbon from an existing power plant in Fort Bend County,
Texas. The CO2 will be transported 82 miles to the West Ranch Oil Field. The project is
expected to be operational in 2016.
A.3 Carbon Capture Projects Proposed or in Planning
The Global CCS Institute tracks Carbon Capture and Sequestration (CCS) projects planned or
operational around the world.39 These projects were a snapshot in time when this report was
developed and some projects may have been cancelled and other new projects planned. The
phase in which the CO2 will be transported is unknown.
PROJECT NAME
Indiana Gasification
Medicine Bow Coal-to-Liquids
Facility
Mississippi Clean Energy
Project
Quintana South Heart Project
Riley Ridge Gas Plant
Sargas Texas Point Comfort
Project
Texas Clean Energy Project
CAPTURE TYPE
Pre-combustion capture
(gasification)
Pre-combustion capture
(gasification)
Pre-combustion capture
(gasification)
Pre-combustion capture
(gasification)
Pre-combustion capture (natural
gas processing)
Post-combustion capture
Pre-combustion capture
(gasification)
38
http://www.marketwatch.com/story/worlds-largest-post-combustion-carbon-capture-enhanced-oil-recoveryproject-to-be-built-by-nrg-energy-and-jx-nippon-oil-gas-exploration-2014-07-15?reflink=MW_news_stmp
39
http://www.globalccsinstitute.com/projects/browse
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In addition, INGAA40 has identified the following proposed CCS projects. The phase in which
the CO2 will be transported is unknown.
PROJECT
AEP
AEP
Basin Electric
Clean Energy Systems
Duke Energy Edwardsport
Duke Energy Cliffside
Excelsior Energy
H Energy (BP & Rio Tinto) Carson
Jamestown Bd Public Utilities
NRG Sugarland
NRG Tonawanda
Peabody Energy
Peabody Energy
Seminole Electric Coop. Tampa
Tenaska Sweetwater
Tenaska Taylorsville
Xcel
40
CAPTURE TYPE
Pulverized Coal power
Integrated Gasification Combined Cycle coal
power (two units)
PC power (retrofit)
Oxyfuel gas power
IGCC coal power
PC power
IGCC coal power
IGCC pet coke power
Circulating Fluidized Bed oxyfuel coal power
PC power (retrofit)
IGCC coal power
Syngas production
Supercritical pulverized coal (SCPC)
SCPC
SCPC power
IGCC coal power
IGCC coal power
Ibid. 14, p. 5
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