1555 Wilson Boulevard Corporate Headquarters:

Suite 300 57 Water Street

Arlington, VA 22209 Watertown, MA 02472

Tel: 703.247.6000 An Employee-Owned Company Tel: 617.673.7000

Fax: 703.247.6001 www.cadmusgroup.com Fax: 617.673.7001

Carbon Dioxide Pipelines in the United States

Contract EP-W-10-055

Work Assignment 27 

Technical Directive 3, Part 1

Submitted by The Cadmus Group, Inc. 

Under Subcontract to Eastern Research Group, Inc.
June 25, 2012

Draft 2

Carbon Dioxide Pipelines in the United States

1.0 Introduction

Enhanced oil recovery is the largest use of carbon dioxide in the United States, exceeding the use for 

food grade carbon dioxide by a factor of ten (Interstate Oil and Gas Compact Commission (IOGCC), 

2010). This carbon dioxide is transported from sources to oil fields for injection by means of 

pipeline. Pipelines are favored for carbon dioxide transport because they are the easiest means to 

transport large volumes of carbon dioxide the distances required to the oil fields. While transport is 

possible by tanker trucks or ships, transporting the volumes required for enhanced oil recovery 

would require an inordinate number of vehicles, would require significant storage, and would make 

continuous delivery of carbon dioxide difficult. 

Increased interest in geologic sequestration (GS) of carbon dioxide will significantly increase the 

need for carbon dioxide pipelines. Like oil recovery, pipelines would be the transportation mode of 

choice to enable delivery of carbon dioxide continuously at volumes and pressures adequate for GS 

injection. Estimates of the required mileage of pipeline to meet sequestration needs under a carbon 

regulation scenario range from 11,000 miles to 66,000 miles (Carbon Sequestration Leadership 

Forum, undated; IOGCC, 2010). This will represent a large increase in the total mileage of carbon 

dioxide pipelines. To ensure the safety of these future pipelines, it is instructive to review the 

current state of knowledge regarding carbon dioxide pipelines.

This report will review the current state of knowledge of carbon dioxide pipelines in the United 

States, and provide the following information:

 An overview of the existing pipeline network, including amounts of carbon dioxide shipped, 

miles of pipeline, and a description of the pipelines. 

 A review of various considerations for pipeline construction including materials, size, and 

other guidelines. 

 Costs of pipeline projects including capital, operations and maintenance, and other fees. 

 Pipeline safety, including regulations and past incidents. 

 A discussion of planned future pipelines.

2.0 Pipeline Statistics

Pipeline safety is regulated by the Pipeline Hazardous Materials and Substance Administration 

(PHMSA), which is a branch of the Department of Transportation. The PHMSA keeps statistics on all 

pipelines transporting hazardous substances. Although carbon dioxide is not considered a hazardous 

substance, it is regulated with hazardous liquids, as the construction requirements for supercritical 

carbon dioxide are similar to those for hazardous liquids (e.g., petroleum products) pipelines. 

Statistics are kept on all transportation pipelines. The segments covered would include pipelines

from the source up to the individual oil fields. Feeder lines to individual wells are not included in 
June 25, 2012

Draft 3

PHMSA statistics. Statistics are kept according to operator and not by pipeline. Therefore, PHMSA 

statistics do not enable analysis by pipeline or source. The following sections describe the statistics 

compiled by PHMSA supplemented by other sources to describe the current carbon dioxide pipeline 

situation.

2.1 Carbon Dioxide Transported

Table 1 gives the PHMSA statistics for carbon dioxide transported for 2010, the most recent year 

available. The table lists 25 operators transporting nearly 2 trillion barrel-miles of carbon 

dioxide. As a comparison, the 2008 statistics as cited in the Assessment of the Potential Costs, 

Benefits, and Other Impact of the Conditional Exclusion from the RCRA Definition of Hazardous 

Waste for CO2 Streams Managed in UIC Class VI Wells for the Purposes of Geologic 

Sequestration (EPA, 2011) lists 26 operators (Genesis is listed twice) transporting 34 billion 

barrel-miles of carbon dioxide. It is not known whether Transpetco, the operator not reported in 

the 2010 statistics is inactive or if operation of that pipeline was assumed by another company. 

The 2010 values represent a significant increase from the 2008 values. 

The largest shipper of carbon dioxide was Exxon/Mobil with nearly 1.8 trillion barrel-miles of 

carbon dioxide transported. The next biggest shippers of carbon dioxide in 2010 were Kinder 

Morgan, Enmark, and Bravo. All of the major operators saw significant increases. Exxon/Mobil 

saw a nearly 15 percent increase. Kinder Morgan nearly tripled its barrel-miles transported; 

Enmark went from just over 13 thousand barrel-miles to over 52 billion barrel-miles. Bravo saw 

a slight increase from 19.1 to 19.5 billion barrel-miles. It is possible there is some skew in the 

increase in delivery of carbon dioxide since results are reported in barrel-miles. The increase 

may represent increased volume delivered or it could represent increased distances of delivery. 

Most likely, both factors play into the significant increase.
June 25, 2012

Draft 4

Table 1: Barrel Miles of Carbon Dioxide Transported in 2010

Source: PHMSA (2010)

2.2 Miles of Pipe

The transport of nearly 2 trillion barrel-miles of carbon dioxide necessitates a significant pipeline 

network. The total miles of pipe by operator is shown in Table 2. PHMSA statistics indicate 

there were 4,477.6 miles of pipeline in 2010. This is an increase in approximately 200 miles over 

the 2008 statistics. Much of the increase was an addition of about 330 miles of pipeline for 

Denbury Offshore. They are in the middle of a pipeline project to bring carbon dioxide from 

sources in Mississippi and Louisiana to the Gulf Coast of Texas. The increase by Denbury was 

offset by the loss of the Transpetco pipeline from the 2010 data. Several other operators 

experienced small changes in their total pipe. Some of these changes may represent transfers of 

ownership rather than building or retiring of pipeline. 

Operator

Barel-Miles CO2 transported in

2010 Percent

Anadarko 2,254,621,218 0.113%

Apache Corporation 0 0.000%

BOC Gases 4,121,409 0.000%

Bravo 19,515,414,824 0.977%

Buckeye Development 96,865 0.000%

Chapparal Energy 794,512 0.000%

Chevron 246,409,813 0.012%

Dakota Gasification Company 7,870,732,750 0.394%

Denbury Onshore 8,366,393 0.000%

Devon Gas 210,607,136 0.011%

Energen 3,641,981 0.000%

Enmark 52,291,836,735 2.619%

Exxon/Mobil 1,807,716,478,441 90.524%

Genesis Energy 100 0.000%

Hess 1,171,622 0.000%

Kinder Morgan 105,148,616,401 5.265%

Legado Permian 916 0.000%

Merit Energy 305,000,000 0.015%

Occidental Petroleum 0 0.000%

PCS Nitrogen Fertilizer 873,600 0.000%

Resolute Natural Resources 151,678,821 0.008%

Sandridge CO2 1,204,646,754 0.060%

The George Brown Partnership 28,267 0.000%

Trinity Pipeline 9,482,465 0.000%

XTO Energy 177,572 0.000%

Total 1,996,944,798,594
June 25, 2012

Draft 5

Table 2. Miles of Pipeline by Operator

Source: PHMSA (2010)

* These pipelines were not included in the 2010 PHMSA data but appeared in previous years or were listed in other sources, their 

current status is unknown.

In terms of miles of pipe operated, the largest operators are Kinder Morgan, Bravo, and 

Denbury. These three operators represent over half of the carbon dioxide pipelines in service. 

Operator

Total Pipe 

(miles) Percent

Anadarko 155.0 3.27%

Apache Corporation 41.8 0.88%

BOC Gases 7.0 0.15%

Bravo 835.7 17.61%

Buckeye Development 0.6 0.01%

Chapparal Energy 202.4 4.27%

Chevron 128.9 2.72%

Dakota Gasification Company 167.0 3.52%

Denbury Onshore 754.6 15.90%

Devon Gas 46.0 0.97%

Energen 1.5 0.03%

Enmark 39.0 0.82%

Exxon/Mobil 185.4 3.91%

Genesis Energy 99.6 2.10%

Hess 31.5 0.66%

Kinder Morgan 1,294.3 27.28%

Legado Permian 3.3 0.07%

Merit Energy 138.0 2.91%

Occidental Petroleum 6.0 0.13%

PCS Nitrogen Fertilizer 1.3 0.03%

Resolute Natural Resources 27.7 0.58%

Sandridge CO2 185.4 3.91%

The George Brown Partnership 7.7 0.16%

Trinity Pipeline 115.9 2.44%

XTO Energy 2.0 0.04%

Petro Source* 120.0 2.53%

Whiting* 26.0 0.55%

Transpetco* 110.0 2.32%

Core Energy* 11.0 0.23%

Total 4,744.6
June 25, 2012

Draft 6

2.3 Map 

Figure 1 displays a map of current known and planned carbon dioxide pipelines in the United 

States. The date of the map is unknown, but the Denbury-Green pipeline shown as planned has 

been completed. The map shows the main transmission carbon dioxide pipelines in the United 

States. It does not show small lines to individual fields or wells. 

Figure 1: Map of Carbon Dioxide Pipelines in the United States

Source: Marston Law accessed at: http://www.marstonlaw.com/index_files/CO2pipeline_regulation.htm on 5/16/2012

2.4 Description of Pipelines

There are essentially three main carbon dioxide pipeline networks in the US, along with several 

other carbon dioxide pipelines that supply individual fields. This section includes brief 

descriptions of each pipeline including its sources and sinks.
June 25, 2012

Draft 7

West Permian Basin

The largest and oldest carbon dioxide pipeline network is in the West Permian Basin in Western 

Texas and Eastern New Mexico. Most of the pipelines feed from sources into a carbon dioxide 

hub located near Denver City, TX. Carbon dioxide is distributed from there to several pipelines 

feeding oil recovery fields in Western Texas, New Mexico, and Oklahoma. The first pipeline in 

both this basin and the nation was the Canyon Reef pipeline, carrying carbon dioxide from 

several gas plants in West Texas to the SACROC oil field, and is operated by Kinder Morgan. The 

Bravo Pipeline carries carbon dioxide from the Bravo Dome in Colorado into the Texas hub and 

is jointly owned by Occidental, XTO, and Kinder Morgan. The Sheep Mountain Pipeline carries 

carbon dioxide from a natural source in Colorado and connects into the central hub near Denver 

City, TX. The Cortez Pipeline extends from the McElmo Dome in Utah to the hub in Texas and is 

operated by Kinder Morgan. Another pipeline from a Doe Canyon natural source in Utah also 

connects into the Cortez Pipeline. From the Denver City hub, pipelines extend to several 

different oil fields including the Postle Field, Comanche Creek Field, North Ward Estates Field, 

and fields in Cochran, Hockley, and Yoakum County Texas. Operators active in the Permian basin 

carbon dioxide pipelines include Kinder Morgan, Exxon/Mobil, XTO, Occidental, Hess, Trinity 

Pipeline, and Apache. In addition, Sandridge CO2 also operates a pipeline from the Pike’s Peak 

gas plant in Texas to the Val Verde oil fields also in Texas. 

LaBarge Pipeline

The second major area of carbon dioxide supply is from the Exxon/Mobil Shute Creek gas plant 

in Sublette County, Wyoming. The plant is currently capable of producing 365 million cubic feet 

of carbon dioxide a day (Oil and Gas Journal, 2010). Gas is shipped from the plant to oil fields in 

Wyoming and Colorado. Oil fields supplied by the LaBarge plant include Beaver Creek, Rangeley, 

Salt Creek, and Monell. Operators active in this area include Exxon/Mobil, Anadarko, Chevron, 

and Devon. 

Jackson Dome Area

The last major pipeline network carries carbon dioxide from the Jackson Dome in Mississippi. It 

currently extends to the Hastings Oil Field near Houston, Texas. Denbury has also negotiated, or 

is in the process of negotiating, deals with several gas plants and power plants to supply gas to 

this pipeline as well. Denbury is the main operator in this area with Enmark being active as well. 

This pipeline was also used to deliver carbon dioxide to the Cranfield Department of Energy 

(DOE) Carbon Capture and Storage (CCS) demonstration site in Mississippi.

Dakota Gasification Pipeline

While the Dakota Gasification Pipeline has a single source and sink, it is still one of the major 

carbon dioxide pipelines. Completed in the 1990s, it delivers carbon dioxide from the Dakota 

Gasification Plant in North Dakota to the Weyburn oil field in Canada. The pipeline stretches 

over 200 miles, with about 167 of those miles inside the United States. 
June 25, 2012

Draft 8

Chapparal Energy Pipelines

Chapparal Energy also runs several pipelines from dedicated sources to oil fields. One such 

pipeline runs from the Arkalon ethanol plant in Kansas to the Farnsworth Unit in Oklahoma. 

Another line runs from a fertilizer plant in Texas to the Camrick Unit in Oklahoma.

Enid Pipeline

Merit Energy runs a carbon dioxide pipeline that runs from the Enid Fertilizer plant in Enid, 

Oklahoma to the Purdy oil field also in Oklahoma. 

White Frost Pipeline

Although it is not listed in the current PHMSA statistics, there is a carbon dioxide pipeline that 

runs from the DTE gas plant in Michigan to some Niagaran Reef oil formations in Michigan. This 

pipeline operates periodically, depending on the economics of oil recovery using carbon dioxide. 

The pipeline also has capabilities to deliver to a DOE CCS demonstration project in Michigan. 

3.0 Pipeline Construction

Carbon dioxide is pumped in the supercritical state in order to maximize the efficiency of pumping

large amounts of carbon dioxide. The supercritical state has a higher density and therefore allows 

larger masses of carbon dioxide in the same diameter pipeline. Because the supercritical state 

behaves like a liquid, it can also be transported using pumps instead of compressors. Carbon dioxide 

can also be corrosive when combined with water. Some impurities found in carbon dioxide streams 

may also be corrosive. Pipelines must be designed to handle the supercritical state of the carbon 

dioxide as well as potential corrosivity. The following section discusses various design specifications 

typical of carbon dioxide pipelines.

3.1 Pipe Material

When selecting pipe materials, the pressure experienced and the potential corrosivity are taken 

into consideration. Steel is sufficient to withstand the pressures required to transport 

supercritical carbon dioxide. Carbon steel, however, can be corroded by carbon dioxide in the 

presence of water. Stainless steel is not as susceptible to corrosion as carbon steel, but is 

considerably more expensive. According to PHMSA regulations, all carbon dioxide pipelines 

must be steel, with the exception of some grandfathered pipelines (49 CFR 195.112). PHMSA 

data indicate that all existing pipeline is steel pipe. The data do not differentiate between 

carbon steel and stainless steel. All but 9 miles of the nearly 4,500 miles of pipeline is coated 

and cathodically protected to prevent corrosion. Over 3,000 miles of that pipe were constructed 

using high frequency electric resistance welding. Data is also supplied on the date of 

construction of pipelines. Figure 3 shows the current inventory of pipeline by date of 

construction.
June 25, 2012

Draft 9

Figure 3. Percent Pipeline by Date Constructed

Source: PHMSA (2010)

As Figure 3 shows, carbon dioxide pipeline construction reached a peak in the 1980s. Significant 

pipeline construction continues, however, and additional pipelines are being planned for the 

future. Further discussion of planned pipeline projects is included in Section 6.0. The first 

pipeline built explicitly for carbon dioxide transport for oil recovery was constructed in the 

1970s. The pipelines that were constructed before that date were most likely originally

constructed for other purposes and converted for carbon dioxide transport. Such transfer of 

purpose of pipelines has occurred. For example, Denbury purchased a natural gas pipeline in 

Louisiana and converted it to carbon dioxide transport (FERC, 2006). There are also cases of the 

opposite occurring, such as Bravo converting a portion of its Slaughter carbon dioxide pipeline 

to a natural gas gathering pipeline (Texas RRC, 2012). It should be noted that pipelines cannot 

be transferred to and from carrying natural gas without approval by the Federal Energy 

Regulatory Commission (FERC), which regulates this activity and may require public hearings.

3.2 Pipe Sizes and Depth

The PHMSA data also includes information on the size of pipe. Pipeline size depends on the 

amount of carbon dioxide being transferred and the pressure and temperature of the pipeline. 

Pipeline sizes range from less than 4 inches to 30 inches in diameter. Generally, the smaller 

diameters are for lines to specific oil fields. The larger lines are generally the transmission lines. 

Figure 4 shows the percent of total pipeline represented by each size diameter. 

0.0

500.0

1,000.0

1,500.0

2,000.0

2,500.0

Before

1950

1950s 1960s 1970s 1980s 1990s 2000s 2010

Pipeline Mileage by Date Built
June 25, 2012

Draft 10

Figure 4 Percent of Carbon Dioxide Pipeline by Diameter (inches)

Source: PHMSA (2010)

The most common pipe sizes are 20 and 24 inches, representing nearly 20 percent of the total 

length of pipeline each. Pipelines of 8, 16, and 30 inches are also common. 

Federal regulations require most pipe to be buried (49 CFR 195.248). Minimum burial depths 

required by the regulation range from 30mm to 48mm, but actual burial depths are likely much 

greater. PHMSA does not have statistics on depth of burial. Some data was available in the 

incident reports provided by PHMSA as well as some project reports for specific pipelines. 

Depths were generally between 3 and 6 feet but could be as deep as 100 feet in areas such as 

river crossings. Depth is likely to vary depending on local temperature and geology, as well as 

factors such as road or stream crossings. 

3.3 Construction Guidelines

As mentioned previously, pipelines must be designed to carry the appropriate amount of 

carbon dioxide at supercritical pressures, which are greater than about 1,100 psi (Barrie et al., 

2004). Pipeline diameter is determined by the desired flow and the pressure of the pipeline. 

PHMSA regulations specify construction standards for carbon dioxide pipelines. The regulations 

are generally performance standards and also incorporate industry standards such as API and 

ASME standards. Carbon dioxide pipelines must be designed for the pressure the pipe 

experiences and pipeline must be compatible with the fluids it will carry (49 CFR 195.4, 108, 

110). One major concern with carbon dioxide pipelines is longitudinal fractures, which can 

propagate quickly over long distances. Pipelines must be designed to prevent such fractures (49 

CFR 195.111). Preventing such fractures can be achieved by specifying the proper thickness and 

toughness. Mechanical fracture arrestors are also often installed along the pipeline to prevent 

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

<=4" 6" 8" 8.5" 10" 12" 14" 16" 18" 20" 22" 24" 26" 30"

Percent Pipeline Mileage by Size
June 25, 2012

Draft 11

cracks from propagating over long distances if they start (Cosham and Eiber, 2007). Valves, 

hooked to automatic control systems, are also installed to enable isolation of leaks should they 

occur. They are required at pump stations, surface water crossings, laterals, and sensitive areas 

(49 CFR 195.260). Generally, pipelines would be buried at depths shallow enough to be above 

the saturated zone of the soil, so groundwater would not be a concern. Too many valves, 

however, can be problematic, as they can themselves fail and become sources of leaks (see 

Section 5.2). Another consideration in transporting supercritical gases is that supercritical gases 

will rapidly expand and cool if a loss of pressure occurs. Temperatures can drop quickly enough 

that the carbon dioxide can freeze. Therefore, carbon dioxide pipelines must be designed to 

resist very low temperatures (40 CFR 195.102). Theoretically the temperature could get as low 

as the freezing point of carbon dioxide which is -78.5 oC at atmospheric pressure.

Corrosion control is another concern. Carbon dioxide mixed with water can be corrosive. Other 

potential impurities in carbon dioxide streams such as nitrogen oxides and hydrogen sulfide can 

also be corrosive. The DeWaard/Milliams nomograph can be used to predict corrosion of steel 

based on carbon dioxide concentration and temperature. Typically, carbon dioxide streams are 

dehydrated and carbon steel is used for pipelines. A typical value of 50 ppm or less water 

content is a common requirement for carbon dioxide transported in pipelines (Fredet et al.,

2007). While carbon steel is often used for carbon dioxide pipes, stainless steel may be required 

for turbulent areas near valves and pumps (Barrie et al., 2004). As noted above, most carbon 

dioxide pipelines also use cathodic protection and lining to prevent corrosion problems. 

3.4 Quality Considerations

The composition of the carbon dioxide stream provides several important considerations for 

pipeline design. These include transport properties of the stream, corrosivity, and viability of the 

carbon dioxide for its final use. Mixtures of gases can often have very different properties from 

pure gases. This can be important for designing pipelines. For example, combined with water, 

carbon dioxide can form solid hydrates at low temperatures and high pressures. The solid 

hydrates can clog pipelines. These hydrates can form at temperatures as high as 10oC (Fredet et 

al., 2007). Impurities can also alter the critical temperature and pressure of the carbon dioxide 

being transported. Raising the critical pressure and temperature will require higher operating 

pressures and therefore greater costs. Lowering the critical temperature and pressure may help 

reduce costs. Nitrogen oxides can lower the critical pressure and temperature of the carbon 

dioxide stream. Hydrogen gas, on the other hand, can raise the critical temperature and 

pressure (Seevam et al., 2007). Nitrogen and methane may also increase the critical pressure 

and require higher operating pressures (IOGCC, 2010).

Water is the most significant component that can increase the corrosivity of carbon dioxide 

streams, and must be limited to avoid significant corrosion or expensive materials. Hydrogen 

sulfide is corrosive to pipeline materials and is toxic. Additional requirements are often imposed 

on pipelines with significant sulfide, although several pipelines do transport higher levels of 

hydrogen sulfide. Like carbon dioxide, sulfur and nitrogen oxides may also be corrosive in the 
June 25, 2012

Draft 12

presence of water. Oxygen can cause corrosion and is often specified to be below 10 to 20 ppm 

to prevent corrosion (IOGCC, 2010). Corrosion can be prevented or mitigated by limiting 

corrosive impurities and by specifying corrosion resistant materials and cathodic protection.

The last factor that can affect the quality of carbon dioxide shipped in pipelines is the end use. 

For existing carbon dioxide pipelines, the end use is enhanced oil recovery. Some impurities can 

change the miscibility of carbon dioxide with oil and therefore change its effectiveness in 

recovering oil. Nitrogen gas decreases the miscibility of carbon dioxide with oil and therefore 

decreases its value for recovering oil. Many pipelines have maximum specifications for nitrogen 

gas because of this. Sulfide, sulfur oxides, and nitrogen oxides, on the other hand increase the 

miscibility and make carbon dioxide more attractive for enhanced oil recovery.

Table 3 shows the purity of carbon dioxide stream specifications in some existing pipelines. The 

specifications represent agreed upon limits of the concentrations allowed in the pipelines. The 

table shows that current carbon dioxide streams generally contain 95 percent or more carbon 

dioxide. Common impurities can include methane, hydrogen sulfide, and nitrogen.

Table 3. Carbon Dioxide Stream Specifications for Several Existing Pipelines

Pipelines Carbon 

Dioxide 

Content 

(Percent)

Methane 

Content 

(Percent)

Higher 

Hydrocarbon 

Gases 

(Percent)

Nitrogen 

Content 

(Percent)

Hydrogen 

Sulfide 

Content 

(Percent)

Canyon Reef 

Carriers

95 5 - < 0.5 0.01

Central Basin 

Pipeline

98.5 0.2 - 1.3 -

Sheep 

Mountain 

Pipeline

96.8 1.7 0.6 0.9 -

Bravo Pipeline 99.7 - - 0.3 -

Weyburn 96 - 2.3 0.03 0.9

Source: Seevam et al., 2007
June 25, 2012

Draft 13

4.0 Costs

Several costs comprise the cost of transporting carbon dioxide by pipeline. These include the capital 

cost to construct the pipeline, costs to operate and maintain the pipeline, and fees charged by either 

state regulators for permitting of the pipeline or fees charged by pipeline operators for use of the 

pipeline.

4.1 Construction Costs

Capital costs for a pipeline will depend on many factors. These include the capacity of the 

pipeline, pipeline materials required, and terrain. Table 4 shows costs compiled by the Interstate 

Oil and Gas Compact Commission (IOGCC)

1

from several existing pipelines, including some 

estimates compiled by Federal Energy Regulatory Commission (FERC)

2

and the Oil and Gas 

Journal. The costs represent total capital costs for the project including installation divided by 

the length and diameter of the pipeline. Costs in 2009 ranged from about $27,000 per inch-mile3

of pipeline to nearly $94,000 per inch-mile. The costs are normalized by length and diameter of 

the pipeline as these are the biggest factors in determining pipeline cost. For example a cost 

model from Carnegie Mellon University, based on natural gas pipeline costs, found a 

relationship where cost for a pipeline in the Midwest was:

Cost = 103.112*L0.901*D1.590

Where L is the length of the pipeline and D is the diameter (Rubin et al., 2008). It can be seen 

that the diameter is the biggest factor, while length is also important. While depth may have an 

effect on costs, it was not considered in any of the cost models examined in the scope of this 

paper (MIT, 2007; Rubin et al., 2008). The only consideration of depth were general statements 

that rugged terrain and urbanized areas can increase costs. 

 

1

The Interstate Oil and Gas Compact Commission is a government agency formed by the agreement 

between 30 oil and gas producing states that makes recommendations on practices to prevent waste of 

oil and gas and to prevent damage by oil and gas activities.

2

The Federal Energy Regulatory Commission regulates energy activities in the United States. Its areas of 

oversight include transportation of oil and gas by pipeline.

3

An inch-mile is a measure of the volume of a pipe. 1 inch-mile represents a pipe 1 inch in diameter and 

1 mile long. A pipe 6 inches in diameter and 10 miles long would represent 60 inch-miles.
June 25, 2012

Draft 14

Table 4 Pipeline Capital Costs

Pipeline Location Cost (2009$/inmile)

Dakota Gasification North Dakota 46,500

Hall-Gurney Kansas 26,650

Coffeyville 

Resources

Kansas 54,000 – 83,000

Green Pipeline Louisiana, 

Mississippi

93,750

Oil and Gas Journal 

Average Cost

National 

Estimate

64,900

FERC data National 

Estimate

39,400

Source: IOGCC 2010

It should be noted that the cost of the steel pipe is approximately 15 to 35 percent of the total 

pipeline cost (IOGCC, 2010). This is significant, as the price of steel pipe greater than 24 inches

has risen from $500 per meter in 2000 to over $1,400 per meter in 2007 (CRS, 2008). 

4.2 Operating Costs

Operating costs include power costs for operating pumps and compressors, labor costs for 

pipeline operation and maintenance, and material costs for maintenance. Table 5 shows 

operating costs for several pipelines. 

Table 5 Pipeline Operation and Maintenance Costs 

Pipeline Pipeline Length 

and Size

Year O&M Costs 

($/yr)

Source

Ohio Network

(proposed)

450 miles

12 inch 

diameter

2008 2,300,000 Pew Charitable 

Trust, 2008

Russell, Kansas 

Geosequestration/EOR 

Project

7 miles 2007 1,900,000 –

2,300,000

Carr & Dubois, 

2007
June 25, 2012

Draft 15

Estimated costs for 

IGCC pipeline

300 miles 2003 480,000 –

720,000

Bock et al., 2003

Costs vary depending on length of the pipeline, the pressure at which it operates, and 

complexity of operations. A study by Pew Charitable Trust for a proposed carbon dioxide 

pipeline in Ohio estimated an annual cost of $2.3 million/year for operating costs of a 450 mile 

pipeline (Pew Charitable Trust, 2008). Several studies have estimated total costs of transporting 

carbon dioxide by pipeline. The costs include annualized capital costs and operation and 

maintenance costs. One study by the Massachusetts Institute of Technology estimated costs for 

a 100 kilometer pipeline from $1.21 per ton to $11.16 per ton with an average of $3.82 per ton 

for carbon dioxide pipelines to oil reservoirs. An NETL study estimated $0.55 per ton for carbon 

dioxide pipelines from carbon dioxide domes to oil fields in Texas (IOGCC, 2010). An IOGCC 

report estimated $1.25 per thousand cubic feet of carbon dioxide from natural sources and 

$1.30 to $1.75 for carbon dioxide from natural gas plants (IOGCC, 2010). 

4.3 Fees 

There are several kinds of fees that may apply to carbon dioxide pipelines. First, fees may be 

administered by PHMSA or States for pipeline permitting. PHMSA assesses a user fee for all 

hazardous liquid pipelines. That fee is $109.91 per mile and is used to offset costs of PHMSA and 

state programs. Usage fees are also charged by the companies that own the pipeline. Such fees 

would not apply in cases where the source, pipeline, and final use of the carbon dioxide are all 

owned by the same entity. It does apply, however, to companies that own and operate pipelines 

and transport carbon dioxide to other companies operating oil fields. Generally, such contracts 

are negotiated between the pipeline company and the purchaser of the carbon dioxide. Such 

agreements may contain provisions linking fees to the price of oil and the pressure or quality at 

which the carbon dioxide is delivered. Some carbon dioxide pipelines are considered common 

carriers, meaning they must transport carbon dioxide from any source for the same published 

price. The Bureau of Land Management has required many carbon dioxide pipelines crossing 

federal lands to be common carriers. The State of Texas requires pipelines to be common 

carriers if they want eminent domain rights in the State. While being a common carrier usually 

requires publishing of rates, administrative bodies have not required carbon dioxide common 

carriers to publically post their rates. One source found that carbon dioxide transport fees 

ranged from $2 to $3/ton for a pipeline of 50 to 100 miles in length (Bergman and Winter, 

1997). Other fees may also apply such as State, County, or Local fees. However, no listing of such 

costs or fees was found within the scope of this paper.

5.0 Pipeline Safety

Pipeline safety is a prime concern with carbon dioxide pipelines and is regulated by the PHMSA and 

State regulatory agencies. The prime concern is that carbon dioxide is an asphyxiant and is heavier 

than air. Therefore, carbon dioxide may leak and accumulate in poorly ventilated, low lying areas 
June 25, 2012

Draft 16

and potentially build up to dangerous or lethal levels. Another concern is that if high pressure 

pipelines fail catastrophically, the rapid depressurization can cause solid carbon dioxide to be 

ejected at high rates causing potential damage to property and life. While there are significant 

safety concerns with carbon dioxide pipelines, pipelines have operated safely for decades. The 

following sections include records of significant safety incidents and a summary of state and federal 

regulations governing pipeline safety.
June 25, 2012

Draft 17

5.1 Regulations

Pipeline safety is regulated by the Department of Transportation through the PHMSA. 

Regulations governing carbon dioxide pipelines fall under 49 CFR 195. The regulations cover 

topics such as material selection, construction requirements, pressure limits, and reporting 

requirements. Many of the requirements are either performance standards, such as requiring 

pipelines to be compatible with the fluids they carry (e.g. 49 CFR 195.4), or refer to other 

standards. A total of 40 standards are incorporated into the pipeline regulations by reference, 

these are listed in Appendix A. The federal regulation provides that States that have standards at 

least as stringent as the federal standard and have effective enforcement programs oversee 

pipelines within their state if their regulations are at least as strict as federal standards. For the 

most part, states have adapted the federal regulations verbatim. A brief review of the 

regulations found that where they did vary from federal requirements they were often to 

provide more specific requirements or requirements for local conditions. For example, New 

Mexico specifies certain types of leak detection tests. Other differences between state and 

federal laws can include things such as lower reporting limits for leaks or requiring more 

frequent inspection for high risk pipelines. Generally though, most states follow the federal 

regulations. 
June 25, 2012

Draft 18

Agreements between States and the Federal Office of Pipeline Safety (OPS) dictate who 

performs inspection and enforcement activities within each state. A brief review of state 

agreements was conducted for states that have existing or planned carbon dioxide pipelines. In 

many states, OPS regulates and inspects all hazardous liquid pipelines, including carbon dioxide 

pipelines. These states include: Colorado, Illinois, Kansas, Michigan, Montana, North Dakota, 

Ohio, Utah, and Wyoming. Another common agreement is for OPS to regulate interstate 

pipelines and the state to regulate intrastate pipelines. This type of agreement is in place in 

Indiana, Louisiana, New Mexico, Oklahoma, and Texas. In Arizona and California, all pipelines are 

regulated by the state. Pipelines contained entirely on the property of the pipeline owner are 

not covered by Federal OPS or State regulations. Some smaller pipelines, such as those 

extended from the main line to an individual injection well may also not fall under federal 

regulations. Such pipelines, however, would not be totally unregulated. OSHA standards may 

apply to some aspects of pipeline construction and operation. For example 49 CFR 192 covers 

transportation of natural gas and other gas by pipeline. OSHA also has regulations that would 

apply during pipeline construction. Construction will also likely be regulated by local authorities 

and may require meeting industry standards, plan review, and construction inspections. For 

example, if the pipeline is for a sequestration project, Class VI UIC regulations require submittal 

of construction plans which would include surface facilities such as pipelines (40 CFR 

146.82(a)(11). ASME B31.4 is a standard often used for pipeline construction. While local 

construction permits most likely require meeting such standards a review of such codes is 

beyond the scope of this paper. Insurance policies may also require meeting design standards 

and following best management practices. A study for the Pennsylvania Department of 

Conservation and Natural Resources stated that insurance was readily available for carbon 

dioxide pipelines and many pipelines had such insurance (Tetra Tech, 2009). In order to set 

premiums for an insurance policy insurance companies typically perform a risk assessment of 

the project. The risk assessment would include items such as age and design of the pipeline, 

whether increased design standards were used in high risk areas such as river crossings, 

company operating and maintenance procedures, and existing emergency and response plans 

(Radevsky and Scott, 2004). 

5.2 Incidents

PHMSA requires reporting of any incidents that release more than 5 gallons of supercritical 

carbon dioxide (49 CFR 195.50). Table 6 shows a list of incidents on carbon dioxide pipelines 

reported to PHMSA for the period of 1992 to 2011. 
June 25, 2012

Draft 19

Table 6 Reported Safety Incidents on Carbon Dioxide Pipelines 1992 – 2011

Source: PHMSA 

Operator Location Date Type of Failure

Release 

Amount 

(bbls)

Total

Costs ($) Cause

Denbury Sulphur, LA 2/24/2011 Leak 26.5 541 O-ring Failure

Denbury Beaumont, TX 2/14/2011 Leak 43,182.4 159,643 Weld Failure

Transpetco Union Cty, NM 2/10/2011 Leak 2,530.0 7,584 Valve Seal Failure

Denbury Brookhaven, MS 1/18/2011 Leak 1.0 2 control valve malfunction

Denbury Kinder, LA 12/20/2010 Leak 70,191.3 201,645 Weld Failure

Kinder Morgan Knox City, TX 11/29/2010 Leak 26.0 418 Gasket Failure

Kinder Morgan TX 10/21/2010 Relief Valve Operation 299.0 1,525 Pressure Surge

Kinder Morgan TX 8/9/2010 Relief Valve Operation 0.4 600 Pressure Surge

Kinder Morgan Denver City, TX 5/12/2010 Leak 0.5 23 Threaded Connection Leak

Chapparral Hayne, KS 3/1/2010 Relief Valve Operation 3.0 3,510 Relief Valve Failure

Kinder Morgan Placitas, NM 8/2/2009 Leak 0.1 115,001 Leaking Pump Mating Ring

Kinder Morgan Midkiff, TX 7/30/2009 Leak 224.0 3,050 Valve Seal Failure

Kinder Morgan Bloomfield, NM 10/19/2008 Leak 1.0 7,006 Weld Failure

Kinder Morgan Tatum, NM 8/13/2008 Leak 2.0 5 Weld Failure

Kinder Morgan Placitas, NM 8/3/2008 Leak 0.1 4,075 Weld Failure

Kinder Morgan Snyder, TX 6/4/2008 Relief Valve Operation 46.0 150 Relief Valve Malfunction

Kinder Morgan Cortex, CO 5/30/2008 Relief Valve Operation 49.0 175 Relief Valve Malfunction

Kinder Morgan Tatum, NM 5/14/2008 Leak 0.3 5 Weld Failure

Kinder Morgan Tatum, NM 5/5/2008 Leak 5.0 28 Pump Leak

Kinder Morgan Iraan, TX 4/26/2007 Relief Valve Operation 73.0 3,190 Relief Valve Malfunction

Kinder Morgan Snyder, TX 5/10/2006 Leak 0.5 1,501 Weld Failure

Kinder Morgan Yoakum Co., TX 7/5/2004 Leak 2.4 671 O-ring Failure

Anadarko Yukon, OK 3/7/2002 Puncture 0.6 8,285 Excavation Damage

Kinder Morgan Yoakum Co., TX 1/9/2002 Relief Valve Operation 3,600.0 6,600 Relief Valve Malfunction

Borger CO2 Pipeline Hutchinson, TX 2/25/2001 Leak 18.0 11,052 Failure of uncoated pipe

Dakota Gasification Company Tioga, ND 11/19/2000 Leak 83.0 371,000 Valve Packing Failure

Mobil Exploration San Juan Co., UT 1/29/1997 Relief Valve Operation 1,159.0 2,000 Relief Valve Malfunction

Enron Liquids Loving Co., TX 8/4/1996 Leak 404.0 3,000 Pipe Nipple Broke

Enron Liquids Loving Co., TX 8/1/1996 Puncture 4,000.0 30,000 Excavation Damage

Enron Liquids Upton Co., TX 1/3/1996 Relief Valve Operation 95.0 0 Icing Relief Valve

Exxon Yoakum Co., TX 5/19/1995 Relief Valve Operation 0.0 500 Relief Valve Failure

Arco Oil and Gas Garfield Co., OK 4/15/1994 Leak 0.0 16,600 Corrosion

Enron Liquids Loving Co., TX 2/27/1994 Leak 0.0 6,000 Gasket Failure

Mobil Exploration Yoakum Co., TX 1/3/1994 Leak 6.0 19,096 Weld Failure

Total 126,029.0 984,481
June 25, 2012

Draft 20

Thirty-four incidents were reported during the nearly twenty year period. This is significantly 

lower than the incidents reported for natural gas or petroleum product pipelines. For example, 

there were 3,009 incidents reported for hazardous liquid pipelines other than carbon dioxide 

during the period 2002 to 2009. No deaths or injuries were reported as a result of the reported 

incidents. The incidents resulted in the release of 126,000 barrels (5,292,000 gallons) of carbon 

dioxide and resulted in a little less than $1 million in damages. Most of the damages were for 

the loss of the carbon dioxide product and repair of the pipeline. Costs for remediation and 

cleanup were very low, indicating that little environmental damage occurred. Most of the 

incidents were either leaks or operation of a pressure relief valve, with one reported incident of 

a puncture caused by excavation. The most common causes of the incidents were failure of 

welds or of pipeline components such as valves, seals, and pumps. Malfunctioning relief valves 

were also implicated in several cases. 

6.0 Future Projects

An increase in the number and mileage of carbon dioxide pipelines is predicted for the future. 

The continued interest in using carbon dioxide to boost oil recovery is leading to new proposed 

projects to bring carbon dioxide to oil fields. GS is also moving forward, with several new 

research projects moving forward and the first commercial scale facilities being planned. Future 

projects can be divided into two categories: (1) projects that are in the planning stages and have 

permit applications or other planning documents and (2) pipelines that may be associated with 

projects that have not been planned or are only in the conceptual stages. Those in the first 

category can be identified by searching public documents such as news releases, permit 

applications, and project reports. Those in the second category must necessarily be predicted 

using assumptions of the extent of pipelines needed and the projects that will be built. Table 7 

shows a list of projects that have been proposed or are in the permitting stages. Following the 

table is a brief description of each project.

Table 7. Proposed Carbon Dioxide Pipelines.

Project –

Operator

Miles of Pipe Source Sink Anticipated 

Completion Date

GreenCore -

Denbury

232 Lost Cabin 

Natural Gas Plant, 

Medicine Bow 

Synfuel Plant, 

Riley Ridge Gas 

Plant 

Bell Creek Oil 

Field, 

2012

Midwest – 500 – 700 Gasification 

Plants in IN, IL, 

Gulf Coast Oil Uncertain
June 25, 2012

Draft 21

Project –

Operator

Miles of Pipe Source Sink Anticipated 

Completion Date

Denbury and KY Fields

Hydrogen Energy 

California

4 Rio Tinto 

Hydrogen Plant, 

CA

Elk Hills Oil Field 2015

Chapparal 70 Coffeeville 

Fertilizer Plant

Existing EOR 

pipelines

2013

Cano Milnesand 

Pipeline

40 Cortez CO2

Pipeline

Milnesand and 

Chaveroo Oil 

Fields

2015

Conestoga 

Pipeline

15 Garden City, KS 

ethanol plant

Stuart Oil Field 20114

Archer Daniels 

Midland CCS 

project #1

1.2 Decatur, IL 

ethanol plant

Mt. Simon Saline 

Aquifer

2013

Taylorville Energy 

Center

4.75 Taylorville Energy 

Center

Mt. Simon Saline 

Aquifer

2013

FutureGen 32 FutureGen Power 

Plant

Mt. Simon Saline 

Aquifer

2015

Kevin Dome 6 Kevin Dome Duperow 

Formation

2013

Williston Basin 150 Antelope Valley 

Power Plant

Williston Basin Oil 

Field

2013

Virginia City 

Hybrid Energy 

Center 

25 Virginia City 

Hybrid Energy 

Center Power 

Plant

Coal Seams and 

Saline Aquifers

2015

St. John’s Pipeline 200 – 400 St. John’s Dome, 

Cottonwood 

Denver City Hub 

or McElmo 

2016

 

4

This pipeline was listed in a 2010 reference as planning to be operational by 2011. No references to the current status of this 

pipeline could be found in the scope of this study.
June 25, 2012

Draft 22

Project –

Operator

Miles of Pipe Source Sink Anticipated 

Completion Date

Canyon Dome Pipeline

Mesaba Energy 

Project

265 – 610 Mesaba Energy 

Plant

Sequestration Site 

or Oil Fields

2014

Kimberlina 

Project

5 -10 Kimberlina Power 

Plant

Oil Fields 2015

Mountaineer 

Project

12 – 26 Mountaineer 

Power Plant

Mt. Simon Aquifer Cancelled

Future Gen 1 1 – 59 Power Plant Aquifer Unknown

C-6 Resources Unknown Local Industrial 

Sources

Aquifer Cancelled

Denbury’s Greencore Line: Denbury has started construction on this project. The first phase involves 

232 miles of pipeline from the Lost Cabin Gas plant in Colorado to the Bell Creek Oil Field. That 

phase of the project is expected to be completed in December, 2012. Denbury eventually plans on 

expanding the pipeline to take carbon dioxide from a coal to liquids plant run by DKRW near 

Medicine Bow, MT and a gas plant near Riley Ridge, WY. The Medicine Bow plant is expected to 

come on line in 2014. A date was not mentioned for the hook up with Riley Ridge. The line will also 

likely extend to other oil fields that Denbury is looking to acquire in Wyoming (Fugleburg, 2011). 

Denbury’s Midwest Line: Denbury has proposed building a carbon dioxide pipeline from several coal 

gasification plants in the Midwest. Denbury has proposed two routes—either east through Kentucky 

and Tennessee to Mississippi or west through Missouri and Arkansas into Louisiana. The pipeline 

would connect with Denbury existing pipelines from Jackson Dome. The pipeline would be 500 to 

700 miles in length depending on the route chosen. Four gasification plants have tentative 

agreements with Denbury to supply carbon dioxide: Rockport, IN; Taylorville, IL; Cash Creek, KY; and 

Edwardsport, IN. Only the Edwardsport facility has begun construction and the other three 

gasification plants are awaiting funding or permit approval. Therefore, this pipeline is tentative and 

it is difficult to predict when and if it will be constructed (Lydersen, 2012).

Hydrogen Energy of California: This facility is in the planning process. It plans to take carbon dioxide 

produced from a hydrogen plant owned by BP and Rio Tinto. It will use a 4 mile long pipeline to 

transport the carbon dioxide produced to the Elk Hills Oil Field outside of Bakersfield, CA. The plan is 

to sequester the carbon dioxide while performing enhanced oil recovery. The project is expected to 

be complete in 2015 (Hydrogen Energy California, 2009).
June 25, 2012

Draft 23

Chapparral Energy Pipeline: Chapparral Energy is planning on building a carbon dioxide pipeline that 

will tie in their existing carbon dioxide pipelines and add a source from the Coffeyville fertilizer 

plant. The pipeline would extend from the Coffeeville plant in southeastern Kansas to existing lines 

from the Koch fertilizer plant in Oklahoma, the Arkalon ethanol plant in Kansas, and the Agrium 

Fertilizer plant in Texas. It would extend to oil fields in the panhandle of Oklahoma, some of which 

are currently supplied by carbon dioxide from the Permian basin hub. The initial phase will include 

70 miles of pipe to the North Burbank unit in northeastern Oklahoma. That phase is expected to be 

complete in 2013. The pipeline to connect all the projects together is scheduled for a later, unknown 

date (Chapparal Energy, 2011).

Conestoga Energy Partners Pipeline: Conestoga Energy Partners is constructing a pipeline to bring 

carbon dioxide from a Garden City, Kansas ethanol plant to the Stuart Oil Field in Kansas. The project 

will involve a little less than 15 miles of pipeline and was expected to be operational in 2011 (Global 

CCS Institute, 2010).

Cano Pipeline: Cano has entered an agreement to take carbon dioxide from the Cortez pipeline for 

use in its Chaveroo and Milnesand oil fields. The pipeline will be 40 miles long and 8 inches in 

diameter. Completion is expected in 2015 (Investorhub, 2012).

Archer Daniels Midland (ADM) Projects: ADM is planning two carbon sequestration projects that will 

take carbon dioxide from their Decatur, IL ethanol plant and inject it into the Mt. Simon saline 

aquifer. The UIC permitting process is currently underway and injection is anticipated to begin 

sometime in 2013. The project will involve a 6,400 foot, 6 inch pipeline from the plant to the 

injection wells. It is a demonstration project and is planned to operate for three years. Its planned 

use may be extended if initial tests are successful (ADM, 2012).

Taylorville Energy Center: The Taylorville Energy Center is a proposed IGCC plant that is proposing to 

inject carbon dioxide into the Mt. Simon aquifer in Illinois for carbon sequestration. The project 

includes 4.75 miles of pipe from the plant to 3 or 4 injection wells. The main pipe will be 16 inches in 

diameter, with 12 inch pipes leading to the wells. The project is currently in the permitting process 

and will likely begin operation with one well in the next year or two (TEC, 2012).

FutureGen 2.0: The FutureGen project will retrofit an existing coal burning power plant in 

Meredosia, IL with oxycombustion technology. Carbon dioxide will be captured from the plant and 

stored in a sequestration site in the Mt. Simon Formation. The project will require a 32 mile pipeline 

and is expected to be completed in 2015 (Lee, 2011).

Kevin Dome: The Big Sky Regional Carbon Sequestration Partnership is planning a sequestration 

study project in the Kevin Dome in Montana. The project will involve 6 miles of 2 inch pipeline from 

the source in the Kevin Dome to the sequestration site. The project is currently scheduled to begin 

injection in late 2013 (BSCSRP, 2012).
June 25, 2012

Draft 24

Williston Basin: The Williston Basin project is a DOE sponsored sequestration project. It has already 

been through its preliminary test injections. The final project includes a 150 mile pipeline from the 

Antelope Valley Power Plant in North Dakota to the Williston Basin oil fields (NETL, 2008).

Virginia City Hybrid Energy Center: This project is a carbon sequestration demonstration project. It 

will involve up to 25 miles of pipeline from Dominion Power’s Virginia City Hybrid Energy Center to 

coal seams and saline aquifers in southwest Virginia. It is planned for completion in 2015 (McGee, 

2005).

St. John’s Pipeline: The St. John’s pipeline is a proposed project by Kinder Morgan. It is designed to 

take carbon dioxide from its newly acquired natural carbon dioxide sources in the St. John’s unit and 

Cottonwood Canyon unit and transport it to Kinder Morgan’s network in Texas. Testing of wells is 

currently being conducted. Depending on the production obtained from the carbon dioxide injection 

wells, either a 400 mile, 20 inch pipeline will be constructed directly to Kinder Morgan’s Denver City 

hub or a 200 mile, 10 inch pipeline will be constructed to tie-in to the McElmo Dome pipeline 

(Arizona Geology, 2012). 

Mesaba Energy Project: The Mesaba Energy Project is a planned energy plant in Minnesota. As part 

of the plan, several options for sequestration were proposed. Options ranged from a 265 mile 

pipeline to a local saline aquifer sequestration site, to a three phase pipeline to oil fields in North 

Dakota and Canada. The project was originally scheduled for completion in 2014 but its current 

schedule is unknown (DOE, 2007).

Kimberlina Project: The Kimberlina Power Plant is a planning to sequester carbon dioxide initially onsite as a research project. After approximately 4 years they anticipate building a 5 to 10 mile 

pipeline to local oil fields outside of Bakersfield, California. The original schedule was for enhanced 

oil recovery to begin in 2015. It is not known if the project is on schedule (Clean Energy Systems, 

2012).

Mountaineer Project: The Mountaineer project planned to inject 90 percent of the output of the 

Mountaineer Power Plant in West Virginia into the Mount Simon Aquifer at an injection site about 

12 miles from the plant. A total of up to 26 miles of pipeline was planned. After an initial test phase 

the project was cancelled because of unfavorable economics (DOE, 2011). 

Future Gen 1 Project: The FutureGen project proposed to build a new IGCC power plant that would 

inject all of its flue gas into a saline aquifer. Initial evaluation was done for 5 sites that required 

between 1 and 59 miles of pipeline (DOE, 2006). This initial phase was cancelled. 

C-6 Resources: The project had planned to pipe carbon dioxide from various industrial sources in the 

San Francisco Bay area to a sandstone aquifer in Solano County. Exact pipeline routes had not been 

planned. The project received initial funding from DOE for some pilot tests but the project was 

cancelled before any pipelines were planned or constructed (CIEE, 2010)
June 25, 2012

Draft 25

It should be noted that all of the above projects are planned, but not yet constructed. Some have 

been cancelled and others may not be completed. The above list, however, provides a reasonable 

estimate of the magnitude and types of projects that can be expected over the next five years.

Predicting future carbon dioxide pipeline production beyond 2015 involves making some 

assumptions and predictions regarding the number of projects planned for the future. Sequestration 

projects are not likely to be financially attractive absent carbon dioxide legislation or some other 

financial incentives. If such incentives were lacking, future carbon dioxide would likely be limited to 

a few federally funded projects along with enhanced oil recovery projects. Oil recovery projects will 

likely continue to grow, as there is economic incentive without the additional benefit of carbon 

sequestration. The increase in pipelines to oil fields will depend to some extent on oil prices but is 

more likely to proceed without federal funding or legislation. As Figure 3 demonstrates, carbon 

dioxide pipelines have been built at a rate of 500 to 1,000 miles a decade after the initial boom in 

the 1980s. Since the increase in 2010 alone is already several hundred miles, it would appear that 

pace might be picking up again. Table 7 suggests that between 1,500 and 2,000 miles of pipeline 

could be built in the next 5 years. Even without large regulatory incentives, based on the above 

planned projects, it is possible that as much as 6,000 to 8,000 miles of carbon dioxide pipeline could 

be constructed in the next 20 years.

If a large impetus for carbon sequestration develops, a larger network of carbon dioxide pipelines 

will be built. While there have been several modeling exercises to predict federal or state level 

pipeline networks connecting multiple sources to multiple sequestration sites, it seems like such an 

extensive network would likely be in the more distant future. IEA has predicted about 17 

sequestration projects by 2020 with much more significant growth to 250 projects by 2050. An 

IOGCC report predicted that about 77 percent of sequestration projects could store carbon dioxide

on the same site as it is captured. An additional 11 percent could store the carbon dioxide within 

100 miles (IOGCC, 2010). Therefore, large sequestration pipeline networks may not be needed and,

if they are, would likely be built over in the longer-term. If such a network became necessary, 

several studies have estimated the miles of pipeline that would be required to meet national carbon 

emission goals. An Interstate National Gas Association of America study found that a network of 

between 5,900 miles and 36,050 miles would be required to sequester carbon dioxide in the United 

States by 2030. The lower number presumes a 15 percent reduction in carbon dioxide emissions and 

low use of carbon dioxide for enhanced oil recovery. The higher figure assumes a 50 percent 

reduction in carbon dioxide emissions and a high use of carbon dioxide for enhanced oil recovery 

(INGAA, 2009). A Pacific Northwest National Laboratory Study estimated 11,000 miles of pipeline 

would be needed by 2050 to reach a goal of limiting atmospheric carbon dioxide concentrations to 

550 ppm, and 23,000 miles would be needed to meet a goal of limiting atmospheric carbon dioxide 

to 450 ppm (Dooley et al., 2009). Given the currently planned projects, the high end of these figures 

seems unlikely in the next 20 years; however, the lower end of these figures might represent a more 

reasonable estimate for carbon dioxide pipelines in the next 20 years.
June 25, 2012

Draft 26

References

ADM. 2012. Archer Daniels Midland Permit Application.

Arizona Geology. 2012. Accessed at: http://arizonageology.blogspot.com/2012/04/kinder-morganoutlines-plans-for-major.html

Barrie, J., K. Brown, P.R. Hatcher, and H.U. Schellhase. 2004. Carbon Dioxide Pipelines: A Preliminary 

Review of Design and Risks. Presented at GHGT 2004.

Bergman, P.P., and E.M. Winter. 1997. Disposal of Power Plant CO2 in Depleted Oil and Gas Reservoirs in 

Texas. Energy Conversion and Management. V. 38 pp. S211 – S216.

Bock, B., R. Rhudy, H. Herzog, M. Klett, J. Davidson, D.G. De La Torre, and D. Simbeck. 2003. Economic 

Evaluation of CO2 Storage and Sink Enhancement Options.

BSRCSP. 2012. Accesses at: http://www.bigskyco2.org/research/geologic/kevinstorage

Carbon Sequestration Leadership Forum. Undated. CO2 Transportation: Is it Safe and Reliable? 

http://www.cslforum.org/publications/documents/CSLF_inFocus_CO2Transportation.pdf 

Carr, T.R., and M.K. Dubois. 2007. Results of Integrated Biofuels and Value Added Sequestration Project 

in Russel, KS. Presented at the 6th Annual Conference on Carbon Capture and Sequestration.

CIEE. 2010. Background Reports for the California Carbon Capture and Storage Review Panel. 

California Institute for Energy and Environment.

Clean Energy Systems. 2012. Accessed at http://www.cleanenergysystems.com/faq.html#17

Cosham, A., and R. Eiber. 2007. Fracture Control in Carbon Dioxide Pipelines. Journal of Pipeline 

Engineering. 3rd quarter. p. 147

Chapparal Energy. 2011. Wells Fargo Energy Conference. Available at 

http://www.chaparralenergy.com/pressreleases/Wells%20Fargo%20Energy%20Conference_To%20print

%20for%208K%20and%201x1.pdf

DOE. 2006. Final Risk Assessment Report for the FutureGen Project Environmental Impact Statement. 

DOE. 2007. Mesaba Energy Project, Draft EIS. 

DOE. 2011. Mountaineer Commercial Scale Carbon Capture and Storage Project: Draft Environmental 

Impact Statement Summary. 

Dooley, J.J., R.T. Dahowski, C.L. Davidson. 2009. Comparing Existing Pipeline Networks with the Potential 

Scale of Future U.S. CO2 Pipeline Networks. Energy Procedia 1. Pp. 1595-1602.
June 25, 2012

Draft 27

EPA. 2011. Assessment of the Potential Costs, Benefits, and Other Impact of the Conditional Exclusion 

from the RCRA Definition of Hazardous Waste for CO2 Streams Managed in UIC Class VI Wells for the 

Purposes of Geologic Sequestration

FERC. 2006. 115 FERC 962,266

Fredet, A., S. Saysset, P. Odru, P. Broudin, J. Ruer, and M. Bonnisel. 2007. Technical and Economic 

Assessement of CO2 Transportation for CCS Purposes. 

Fugleburg, J. 2011. Construction of Carbon Dioxide Pipeline Starts this Year. Wyoming Star-Tribune May 

26, 2011.

Global CCS Institute. 2010. Global Status of BECCS Projects 2010.

Hydrogen Energy California. 2009. Revised Application for Certification for Hydrogen Energy California.

INGAA. 2009. Carbon Sequestration and Storage: Developing a Transportation Infrastructure.

IOGCC. 2010. A Policy, Legal, and Regulatory Evaluation of the Feasibility of a National Pipeline 

Infrastructure for the Transport and Storage of Carbon Dioxide.

Investorhub. 2012. Available at 

http://investorshub.advfn.com/boards/read_msg.aspx?message_id=72260578

Lee, D.S.W., 2011. FutureGen “Clean Coal” Project Still has Hurdles to Clear. McDonough Voice.com 

April 6, 2011.

Lydersen, K. 2012. With no sources of CO2, Midwest pipeline project in limbo. Midwest Energy News, 

April 26, 2012.

Marston Law. 2012. http://www.marstonlaw.com/index_files/CO2pipeline_regulation.htm accessed on 

5/16/2012

McGee, D. 2009. Tech, Dominion Propose Carbon-Capture Project. Richmond Times Dispatch, August 26, 

2009.

MIT. 2007. The Future of Coal: Options for a Carbon Constrained World. 

NETL. 2008. Plains CO2 Reduction Partnership, Williston Basin Demonstration Test Fact Sheet. Accessed 

at http://www.netl.doe.gov/publications/proceedings/08/rcsp/factsheets/20-

PCOR_Williston%20Basin%20Demo%20Test_PhIII_and_EOR_Demo.pdf

Oil and Gas Journal. 2010. Exxon Mobil Finishes Shute Creek Carbon Capture Expansion.

Pew Charitable Trust. 2008. The Role of CO2 Enhanced Oil Recovery in Ohio’s Economy and Energy 

Future. 
June 25, 2012

Draft 28

Radevsky, R., and D. Scott. 2004. Pipeline Insurance: Technical Aspects of Underwriting and Claims. 

Presented at the Conference on Terrain and Geohazard Challenges Facing Onshore Oil and Gas.

Rubin, E.S., M.B. Berkenpas, and S.T. McCoy. 2008. Technical Documentation: The Economics of CO2

Transport by Pipeline Storage in Saline Aquifers and Oil Reserves. Carnegie Mellon University.

Seevam, P., J.M. Race, and M.J. Downie. 2007. Carbon Dioxide Pipelines for Sequestration in the UK: an 

Engineering Gap Analysis. Journal of Pipeline Engineering 2007, 3rd quarter. pp. 133-146.

TEC. 2012. Taylorville Energy Center UIC Permit Application.

Tetra Tech. 2009. Assessment of Risk, Legal Issues, and Insurance for Geologic Carbon Sequestration in 

Pennsylvania. Pennsylvania Department of Conservation and Natural Resources.

Texas RRC. 2012. Texas RRC T-4 Permits viewed at: https://rrcsearch3.neubus.com/esd3-

rrc/index.php?_module_=esd&_action_=keysearch&profile=12 
June 25, 2012

Draft 29

Appendix A

Standards Incorporated by Reference into Federal Pipeline Regulations

AGA Pipeline Research Committee, Project PR-3-805, “A Modified Criterion for Evaluating 

the Remaining Strength of Corroded Pipe” 

ANSI/API Specification 5L/ISO 3183 “Specification for Line Pipe”

API Recommended Practice 5L1, “Recommended Practice for Railroad Transportation of 

Line Pipe” 

API Recommended Practice 5LW, “Transportation of Line Pipe on Barges and Marine 

Vessels” 

ANSI/API Specification 6D “Specification for Pipeline Valves 

API Specification 12F “Specification for Shop Welded Tanks for Storage of Production 

Liquids” 

API 510 “Pressure Vessel Inspection Code: In-Service Maintenance Inspection, Rating, 

Repair, and Alteration” 

API Standard 620 “Design and Construction of Large, Welded, Low-Pressure Storage 

Tanks” 

API Standard 650 “Welded Steel Tanks for Oil Storage” 

ANSI/API Recommended Practice 651 “Cathodic Protection of Aboveground Petroleum 

Storage Tanks” 

ANSI/API Recommended Practice 652 “Lining of Aboveground Petroleum Storage Tank 

Bottoms” 

API Standard 653 “Tank Inspection, Repair, Alteration, and Reconstruction” 

API Standard 1104 “Welding of Pipelines and Related Facilities'

API Recommended Practice 1130, “Computational Pipeline Monitoring for Liquids: Pipeline 

Segment” 

API Recommended Practice 1162, “Public Awareness Programs for Pipeline Operators” 

API Recommended Practice 1165, “Recommended Practice for Pipeline SCADA Displays,” 
June 25, 2012

Draft 30

API Standard 2000 “Venting Atmospheric and Low-Pressure Storage Tanks” 

API Recommended Practice 2003 “Protection Against Ignitions Arising out of Static, 

Lightning, and Stray Currents” 

API Publication 2026 “Safe Access/Egress Involving Floating Roofs of Storage Tanks in 

Petroleum Service” 

API Recommended Practice 2350 “Overfill Protection for Storage Tanks in Petroleum 

Facilities” 

API Standard 2510 “Design and Construction of LPG Installations”

API Recommended Practice 1162 “Public Awareness Programs for Pipeline Operators,” 

API Recommended Practice 1168 “Pipeline Control Room Management,” 

ASME/ANSI B16.9-20073 (February 2004) “Factory-Made Wrought Steel Buttwelding 

Fittings” 

ASME/ANSI B31.4-20062 (October 2002) “Pipeline Transportation Systems for Liquid 

Hydrocarbons and Other Liquids” 

ASME/ANSI B31G-1991 (Reaffirmed; 2004) “Manual for Determining the Remaining 

Strength of Corroded Pipelines” 

ASME/ANSI B31.8-20073 (February 2004) “Gas Transmission and Distribution Piping 

Systems” 

ASME Boiler and Pressure vessel Code, Section VIII, Division 1 “Rules for Construction of 

Pressure Vessels,”

ASME Boiler and Pressure Vessel Code, Section VIII, Division 2 “Alternate Rules for 

Construction of Pressure Vessels” 

ASME Boiler and Pressure vessel Code, Section IX “Welding and Brazing Qualifications,”

MSS SP-75-2004 “Specification for High Test Wrought Butt Welding Fittings” 

ASTM Designation: A53/A53M-07,04a (2004) “Standard Specification for Pipe, Steel, Black 

and Hot-Dipped, Zinc-Coated Welded and Seamless” 

ASTM Designation: A106/A106M-08,04b (2004) “Standard Specification for Seamless 

Carbon Steel Pipe for High-Temperature Service” 

ASTM Designation: A 333/A 333M-05, “Standard Specification for Seamless and Welded 

Steel Pipe for Low-Temperature Service” 

ASTM Designation: A 381-96 (Reapproved 20051), “Standard Specification for Metal-ArcWelded Steel Pipe for Use With High-Pressure Transmission Systems” 
June 25, 2012

Draft 31

ASTM Designation: A 671-06,04 (2004) “Standard Specification for Electric-Fusion-Welded 

Steel Pipe for Atmospheric and Lower Temperatures” 

ASTM Designation: A 672-0896 (Reapproved 2001) “Standard Specification for ElectricFusion-Welded Steel Pipe for High-Pressure Service at Moderate Temperatures” 

ASTM Designation: A 691-98 (Reapproved 20072), “Standard Specification for Carbon and 

Alloy Steel Pipe Electric-Fusion-Welded for High-Pressure Service at High Temperatures” 

NFPA 30(2003) “Flammable and Combustible Liquids Code” 

NACE SP0169-2007, Standard Practice, “Control of External Corrosion on Underground or 

Submerged Metallic Piping Systems” 

NACE SP0502-2008, Standard Practice, “Pipeline External Corrosion Direct Assessment 

Methodology”