March 2013

QUALITY GUIDELINES

FOR ENERGY SYSTEM STUDIES

Carbon Dioxide Transport and

Storage Costs in NETL Studies

DOE/NETL-2010/???? 2013/1614
National Energy Technology Laboratory Office of Program Planning and Analysis

2

Carbon Dioxide Transport and Storage Costs in NETL Studies

Quality Guidelines for Energy Systems Studies

March 2013

Disclaimer

This report was prepared as an account of work sponsored by an agency of the United States 

Government. Neither the United States Government nor any agency thereof, nor any of their 

employees, makes any warranty, express or implied, or assumes any legal liability or 

responsibility for the accuracy, completeness, or usefulness of any information, apparatus, 

product, or process disclosed, or represents that its use would not infringe privately owned rights. 

Reference therein to any specific commercial product, process, or service by trade name, 

trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, 

recommendation, or favoring by the United States Government or any agency thereof. The 

views and opinions of authors expressed therein do not necessarily state or reflect those of the 

United States Government or any agency thereof.
National Energy Technology Laboratory Office of Program Planning and Analysis

3

Carbon Dioxide Transport and Storage Costs in NETL Studies

Quality Guidelines for Energy Systems Studies

March 2013

Carbon Dioxide Transport and Storage Costs

in NETL Studies

DOE/NETL-2013/1614

Final Report 

March 14, 2013

NETL Contact:

Tim Grant

Physical Scientist

Office of Program Planning and Analysis, Benefits Division

National Energy Technology Laboratory

www.netl.doe.gov
National Energy Technology Laboratory Office of Program Planning and Analysis

4

Carbon Dioxide Transport and Storage Costs in NETL Studies

Quality Guidelines for Energy Systems Studies

March 2013

Prepared by:

Tim Grant

National Energy Technology Laboratory

David Morgan

National Energy Technology Laboratory

Kristin Gerdes

National Energy Technology Laboratory
National Energy Technology Laboratory Office of Program Planning and Analysis

5

Carbon Dioxide Transport and Storage Costs in NETL Studies

Quality Guidelines for Energy Systems Studies

March 2013

Acknowledgments

This report was prepared by the United States Department of Energy (DOE), National Energy 

Technology Laboratory (NETL). 

The authors wish to acknowledge the excellent contributions and cooperation by members of the 

Energy Sector Planning and Analysis staff, particularly:

Jason Valenstein, Booz Allen Hamilton

Richard Lawrence, Advanced Resources International

Andrea Poe, Booz Allen Hamilton

Marta Milan, Booz Allen Hamilton
National Energy Technology Laboratory Office of Program Planning and Analysis

6

Carbon Dioxide Transport and Storage Costs in NETL Studies

Quality Guidelines for Energy Systems Studies

March 2013

This page intentionally left blank.
National Energy Technology Laboratory Office of Program Planning and Analysis

7

Carbon Dioxide Transport and Storage Costs in NETL Studies

Quality Guidelines for Energy Systems Studies

March 2013

Table of Contents

1 Objective ................................................................................................................................10

2 Approach................................................................................................................................10

2.1 Transport Costs.......................................................................................................................11

2.2 Storage and Monitoring Costs................................................................................................13

3 Results....................................................................................................................................16

3.1 Transport Costs.......................................................................................................................16

3.2 Storage and Monitoring Costs ...............................................................................................17

3.3 Combining Transport and Storage .........................................................................................20

4 References..............................................................................................................................21
National Energy Technology Laboratory Office of Program Planning and Analysis

8

Carbon Dioxide Transport and Storage Costs in NETL Studies

Quality Guidelines for Energy Systems Studies

March 2013

Exhibits

Exhibit 1 Timelines for Construction and Operations of Plant, Transport and Storage ............... 10

Exhibit 2 Pipeline Cost Breakdown (2011 Dollars) [1, 2, 3]........................................................ 12

Exhibit 3 Summary of Cost Escalation Methodology .................................................................. 13

Exhibit 4 Location of Four Basins Selected for this Study........................................................... 14

Exhibit 5 Sensitivity of Transport Costs to Plant and Distance Assumptions.............................. 16

Exhibit 6 Kinder-Morgan Pipeline Cost Metrics [8] ................................................................... 17

Exhibit 7 CO2 Storage Cost Supply Curves.................................................................................. 18

Exhibit 8 Storage Resource Potential for Four Basins.................................................................. 19

Exhibit 9 Total Transport and Storage Costs for Use in NETL System Studies.......................... 20
National Energy Technology Laboratory Office of Program Planning and Analysis

9

Carbon Dioxide Transport and Storage Costs in NETL Studies

Quality Guidelines for Energy Systems Studies

March 2013

Acronyms and Abbreviations

AoR Area of Review

BLS Bureau of Labor Statistics

CEPI Chemical Engineering Plant cost 

Index

CO2 Carbon dioxide

DOE Department of Energy

EIA Energy Information Administration

EPA Environmental Protection Agency

GDP Gross domestic product

HWI Handy-Whitman Index

IRROE Internal rate of return on equity

Mt Million tonnes

NETL National Energy Technology 

Laboratory

O&GJ Oil and Gas Journal

O&M Operation and maintenance

PPI Producer Price Indices

ROW Right-of-way

T&S Transport and storage
National Energy Technology Laboratory Office of Program Planning and Analysis

10

Carbon Dioxide Transport and Storage Costs in NETL Studies

Quality Guidelines for Energy Systems Studies

March 2013

1 Objective

The purpose of this guideline is to estimate the cost of CO2 transport and storage (T&S) in a deep 

saline aquifer for the plant locations used in the energy system studies sponsored by the National

Energy Technology Laboratory (NETL).

Due to the variances in the geologic formations that make up saline aquifers across the United 

States (U.S.), the cost to store CO2 can vary greatly depending on location. To account for these

variances, region-specific results from NETL’s CO2 Saline Storage Cost Model are utilized to 

represent costs for the following plant locations used in NETL studies:

• Midwest

• Texas

• North Dakota

• Montana

Transport costs are calculated based on a generic 100 km (62 mi) dedicated pipeline for all 

regions. Storage and monitoring costs represent significant storage potential (up to 25 billion 

tonnes of CO2) in local sedimentary basins. 

2 Approach

T&S costs are reported as first-year costs in $/tonne of CO2, increasing at a nominal rate of 3

percent per year, which is consistent with the assumed general inflation rate. From the 

perspective of the CO2 source (e.g., a power plant or other energy conversion facility), these 

costs are treated as a disposal cost for each tonne of CO2 captured during the assumed 30-year 

operational period. From the pipeline and storage site’s perspective, the costs of T&S represent

the minimum price that these operators must charge so that they receive the revenue needed

across the 30-year operational period to cover all their costs and provide their required internal 

rate of return on equity (IRROE). All costs are reported in 2011 dollars.

Exhibit 1 Timelines for construction and operations of plant, transport, and storage

Source: NETL
National Energy Technology Laboratory Office of Program Planning and Analysis

11

Carbon Dioxide Transport and Storage Costs in NETL Studies

Quality Guidelines for Energy Systems Studies

March 2013

T&S costs are based on the CO2 flow rate of one example plant: 10,900 tonne/day (12,000 

ton/day) or 3.2 million tonnes per year assuming an 80 percent capacity factor. Variability of 

storage costs based on flow rate and capacity factor can be determined using the CO2 Saline 

Storage Cost Model, but is not considered here for use in the NETL system studies. 

2.1 Transport Costs

High-pressure (2,200 psig) CO2 is provided by the power plant or energy conversion facility, and 

the cost and energy requirements of compression are assumed by that entity. CO2 is in a dense 

phase liquid state at this pressure, which is desirable for transportation and storage purposes. 

CO2 exits the pipeline terminus at a pressure of 1,200 psig, and the pipeline diameter was sized 

for this to be achieved without the need for recompression stages along the pipeline length of 100 

km (62 mi). This exit pressure specification: (1) ensures that CO2 remains in a dense phase 

liquid state throughout the length of the pipeline regardless of potential pressure drops due to 

pipeline elevation change; and (2) minimizes the pipeline diameter required and, in turn, 

transport capital cost. Costs for additional compression that may be required for injection in a 

particular formation are included as part of storage costs.

The required pipeline diameter was calculated iteratively by determining the diameter required to 

achieve a 1,000 psig pressure drop (2,200 psig inlet, 1,200 psig outlet) over the specified pipeline 

distance of 100 km (62 mi) and rounding up to the nearest even-sized pipe diameter. The 

pipeline was sized based on the CO2 output produced by the power plant when it is operating at 

full capacity (100 percent utilization factor) rather than at average capacity. 

CO2 transport costs are broken down into three categories: pipeline capital costs, related capital

expenditures, and operation and maintenance (O&M) costs. 

Pipeline costs are derived from data published in the Oil and Gas Journal’s (O&GJ) annual 

Pipeline Economics Report for existing natural gas, oil, and petroleum pipeline project costs 

from 1991 to 2003. These costs are expected to be analogous to the cost of building a CO2

pipeline, as noted in various studies. [1, 2, 3] The University of California performed a 

regression analysis to generate the following cost curves from the O&GJ data: (1) Pipeline 

Materials, (2) Direct Labor, (3) Miscellaneous Costs,

1

Related capital expenditures were based on the findings of a previous study funded by the 

Department of Energy (DOE)/NETL, Carbon Dioxide Sequestration in Saline Formations –

Engineering and Economic Assessment. [2] This study utilized a similar basis for pipeline costs 

(Oil and Gas Journal’s pipeline cost data up to the year 2000) but added a CO2 surge tank and 

pipeline control system to the project. These costs are shown in Exhibit 2 as Other Capital Costs.

and (4) Right-of-way acquisition, with 

each represented as a function of pipeline length and diameter. [3] These cost categories are 

reported individually as a function of pipeline diameter (in inches) and length (in miles) in 

Exhibit 2.

 

1 Miscellaneous costs are inclusive of surveying, engineering, supervision, contingencies, allowances for funds used 

during construction, administration and overheads, and regulatory filing fees.
National Energy Technology Laboratory Office of Program Planning and Analysis

12

Carbon Dioxide Transport and Storage Costs in NETL Studies

Quality Guidelines for Energy Systems Studies

March 2013

Pipeline O&M costs, shown in Exhibit 2 as a function of pipeline length per year, were assessed 

using metrics published in a second DOE/NETL sponsored report entitled Economic Evaluation 

of CO2 Storage and Sink Enhancement Options. [1] This study was chosen due to the reporting 

of O&M costs in terms of pipeline length, whereas the other studies mentioned above either (1) 

do not report operating costs, or (2) report them in absolute terms for one pipeline, as opposed to 

as a length- or diameter-based metric. 

Exhibit 2 Pipeline cost breakdown (2011 dollars) [1, 2, 3]

Cost Type Units Cost

Pipeline Capital Costs

Materials Diameter (inches), 

Length (miles) 686.7 D 26,960) 2 $70,350 + $2.01×L × (330.5 ×D + × +

Labor Diameter (inches), 

Length (miles) 2,074 D 170,013) 2 $371,850 + $2.01×L × (343.2 ×D + × +

Miscellaneous Diameter (inches), 

Length (miles) $147,250 + $1.55×L×(8,417×D + 7,234)

Right of Way Diameter (inches), 

Length (miles) $51,200 + $1.28×L×(577×D + 29,788)

Other Capital Costs

CO2 Surge Tank $ $1,244,724

Pipeline

Control System $ $111,907

Pipeline O&M Costs

Fixed O&M $/mile/year $8,454

Four different cost escalation indices were utilized to escalate costs from the year-dollars they 

were originally reported in to June 2011-year dollars. These are the Chemical Engineering Plant 

Cost Index (CEPI), U.S. Bureau of Labor Statistics (BLS) Producer Price Indices (PPI), HandyWhitman Index (HWI) of Public Utility Costs, and the Gross Domestic Product (GDP) Chaintype Price Index. [4, 5, 6]

Exhibit 3 details which price index was used to escalate each cost metric, as well as the yeardollars in which the cost was originally reported. Note that this reporting year is likely to be 

different than the year that the cost estimate is from. 
National Energy Technology Laboratory Office of Program Planning and Analysis

13

Carbon Dioxide Transport and Storage Costs in NETL Studies

Quality Guidelines for Energy Systems Studies

March 2013

Exhibit 3 Summary of cost escalation methodology

Cost Metric Year-$ Index Utilized

Transport Costs

Pipeline Materials 2000 HWI: Steel Distribution Pipe

Direct Labor (Pipeline) 2000 HWI: Steel Distribution Pipe

Miscellaneous Costs (Pipeline) 2000 BLS: Support Activities for Oil & Gas Operations

Right-of-Way (Pipeline) 2000 GDP: Chain-type Price Index

CO2 Surge Tank 2000 CEPI: Heat Exchangers & Tanks

Pipeline Control System 2000 CEPI: Process Instruments

Pipeline O&M (Fixed) 1999 BLS: Support Activities for Oil & Gas Operations

The minimum price the CO2 pipeline operator needs to charge to cover all costs and provide the 

required IRROE was calculated in $/tonne of CO2 assuming the following, which match the lowrisk business scenario for an investor-owned utility [7]:

• 3-year capital expenditure period distributed by year as 10%, 60%, 30%

• Escalation of all costs at a rate of 3% per year

• Debt to equity ratio of 50%/50%

• Interest rate of 4.5%/year

• IRROE of 12%

• 30-year operational period

2.2 Storage and Monitoring Costs

Storage and monitoring costs were estimated using NETL’s CO2 Saline Storage Cost Model. 

This model is a spreadsheet-based tool that estimates the break-even required revenue for storing 

CO2 in a deep saline aquifer from the perspective of the owner of a CO2 storage site. The CO2

Saline Storage Cost Model includes the cost of complying with key regulations. In order to 

inject CO2 into the subsurface for the purpose of storing CO2 in a saline aquifer, the site owner 

must comply with the U.S. Environmental Protection Agency (EPA) regulations for Class VI 

injection wells under EPA’s Underground Injection Control Program, which is authorized under 

the Safe Drinking Water Act. The site owner must also comply with monitoring and reporting 

requirements under Subpart RR of the Greenhouse Gas Reporting Rule, which is authorized 

under the Clean Air Act. 

Results from the CO2 Saline Storage Cost Model for storage and monitoring costs were aligned 

with the NETL system studies by taking the four generic plant locations and overlaying them 

with possible storage basins from the cost model. This pairs generic system study plant locations 

of Midwest, Texas, North Dakota, and Montana with the Illinois, East Texas, Williston, and 

Powder River Basins, respectively, as shown in Exhibit 4.
National Energy Technology Laboratory Office of Program Planning and Analysis

14

Carbon Dioxide Transport and Storage Costs in NETL Studies

Quality Guidelines for Energy Systems Studies

March 2013

Exhibit 4 Location of four basins selected for this study

Source: NETL

Inputs to the CO2 Saline Storage Cost Model that have a significant influence on cost include 

financial parameters, timelines for the various stages of storage, and important activities in 

stages.

The financial parameters match the high-risk business scenario for an Investor Owned Utility [7]

and include:

• Debt to equity ratio of 45%/55%

• Interest rate on debt of 5.5%/year

• IRROE of 12%

• Escalation rate of 3%

• Financial responsibility is met by funding a modified trust fund over the period of 

injection operations

• Project contingency factor of 15%, and process contingency factor of 20%
National Energy Technology Laboratory Office of Program Planning and Analysis

15

Carbon Dioxide Transport and Storage Costs in NETL Studies

Quality Guidelines for Energy Systems Studies

March 2013

In the CO2 Saline Storage Cost Model, the storage process is divided into six stages. The 

timelines and important activities impacting costs for these stages are:

• Regional evaluation and initial site selection: 1 year

• Site characterization: 3 years

o Four sites simultaneously undergo characterization, each having a 2-D seismic 

survey and one strat-well drilled to collect relevant reservoir data.

o One of these four sites is selected as the eventual storage site and has an 

additional strat-well drilled plus a 3-D seismic survey covering the Area of 

Review (AoR); pore-space rights and property access are also purchased.

• Permitting: 2 years

o Includes submittal of required reports for Class VI injection well permit, 

permission to drill injection wells, drilling and completion of injection wells, 

incorporation of new data from injection wells into reports, resubmission of

reports, and final permission to inject captured CO2. 

• Operations: 30 years

o Injection of 3.2 million tonnes of CO2 per year for 30 years.

o Installation of buildings, surface equipment, monitoring wells, and other 

monitoring equipment per submitted testing and monitoring plan.

o AoR review occurs every five years with 3-D seismic every five years as part of 

the AoR review.

o Plugging injection wells at conclusion of injection operations.

o Fund-modified trust fund to cover financial responsibility requirements for

corrective action, injection well plugging and post-injection site care, and site 

closure. Emergency and Remedial Response covered by insurance.

• Post-injection site care and site closure: 50 years

o Monitoring continues per submitted testing and monitoring plan.

o Monitoring wells are plugged and other monitoring equipment removed at the 

conclusion of post-injection site care.

o Costs during this period are covered by the storage site operator’s trust fund.

• Long-term stewardship: This stage is not explicitly included in the model. The possible 

financial implication of long-term stewardship is included in the model as a statesponsored trust fund that the storage operator pays into during operations. 
National Energy Technology Laboratory Office of Program Planning and Analysis

16

Carbon Dioxide Transport and Storage Costs in NETL Studies

Quality Guidelines for Energy Systems Studies

March 2013

3 Results

3.1 Transport Costs

Transport of 10,900 tonne/day of CO2 a distance of 100 km (62 mi) with 1,000 psi pressure drop 

requires a 16-inch pipe diameter and has estimated capital costs of $106 million and O&M costs 

of $0.53 million per year. Based on the assumptions outlined in Section 2.1 above and a capacity 

factor of 80 percent, the resulting required first-year cost for transport is $3.65/tonne of CO2 in 

2011 dollars. 

This value will be used in NETL System Studies as a reasonable approximation for CO2

transport costs for all plants regardless of the capacity factor and CO2 capture rates. Exhibit 5 

shows the sensitivity of this cost to capacity factor and CO2 capture rate. In addition, costs are 

shown for 150 km (93 mi).

Exhibit 5 Sensitivity of transport costs to plant and distance assumptions

Source: NETL

Cost Comparisons

The capital cost metrics used in this study result in a pipeline cost (in 2011 dollars) ranging from 

$70,000 to $84,000/inch-Diameter/mile for pipeline lengths of 250 and 10 miles, and 3 to 4 

million metric tonnes of CO2 sequestered per year, respectively. When project and process 

contingencies of 30 percent and 20 percent (respectively) are taken into account, this range 

increases to $104,000 to $126,000/inch-Diameter/mile. These costs were compared to 

contemporary pipeline costs quoted by industry experts, such as Kinder-Morgan and Denbury 

Resources for verification purposes. Exhibit 6 details typical rule-of-thumb costs for various 

terrains and scenarios as quoted by a representative of Kinder-Morgan at the Spring Coal Fleet 

$3.65/tonne

0

1

2

3

4

5

6

7

8

9

10

4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 20,000

Transport Cost, $/tonne CO2

CO2 Capture Rate, tonne/day

150 km; 80% CF

150 km, 85% CF

100 km, 80% CF

100 km, 85% CF
National Energy Technology Laboratory Office of Program Planning and Analysis

17

Carbon Dioxide Transport and Storage Costs in NETL Studies

Quality Guidelines for Energy Systems Studies

March 2013

Meeting in 2009. [8] As shown, the base NETL cost metric falls midway between the costs 

quoted for “Flat, Dry” terrain ($50,000/inch-Diameter/mile) and “High Population” or “Marsh, 

Wetland” terrain ($100,000/inch-Diameter/mile), although the metric is closer to the “High 

Population” or “Marsh, Wetland” when contingencies are taken into account. [8] These costs 

were stated to be inclusive of right-of-way (ROW) costs.

Ronald T. Evans, formerly of Denbury Resources, Inc., provided a similar outlook, citing 

pipeline costs as ranging from $55,000/inch-Diameter/mile for a project completed in 2007, 

$80,000/inch-Diameter/mile for a recently completed pipeline in the Gulf Region (no wetlands 

or swamps), and $100,000/inch-Diameter/mile for a currently planned pipeline, with route 

obstacles and terrain issues cited as the reason for the inflated cost of that pipeline. [9, 10] Mr. 

Evans qualified these figures as escalated due to spikes in construction and material costs, 

quoting pipeline project costs of $30,000/inch-Diameter-mile as recently as 2006. [9, 10] 

A second pipeline capital cost comparison was made with metrics published within the 2008 IEA 

report entitled CO2 Capture and Storage: A key carbon abatement option. This report cites 

pipeline costs ranging from $22,000/inch-Diameter/mile to $49,000/inch-Diameter/mile (once 

escalated to June-2011 dollars), between 30 percent and 69 percent less than the lowest NETL 

metric of $70,000/inch-Diameter/mile. [11] 

Exhibit 6 Kinder-Morgan pipeline cost metrics [8]

Terrain Capital Cost

($/inch-Diameter/mile)

Flat, Dry $50,000

Mountainous $85,000

Marsh, Wetland $100,000

River $300,000

High Population $100,000

Offshore (150’-200’ depth) $700,000

3.2 Storage and Monitoring Costs

Cost supply curves are plotted in Exhibit 7 for the East Texas, Illinois, Powder River and 

Williston basins. This figure presents the mass of CO2 that can be stored theoretically in each 

basin at a given price of CO2. The price is the break-even price of CO2 for a storage project in 

each basin (i.e., the price of CO2 where the net present value for the project is zero). Each basin 

includes two or more storage formations. The curves in Exhibit 7 represent the storage resource 

potential for the Paluxy and Woodbine formations in the East Texas Basin; the Mt. Simon, and 

St. Peter formations in the Illinois Basin; the Red River and Mission Canyon formations in the 

Williston Basin; and the Minnelusa, Muddy, and Madison formations in the Powder River Basin. 

Also plotted in Exhibit 7 is a projection, based on data from the Energy Information 

Administration (EIA) (14), of the cumulative mass of CO2 emissions from the electric power and 

industrial sectors that can be captured over the next century, assuming 90 percent of all CO2

emissions are captured.
National Energy Technology Laboratory Office of Program Planning and Analysis

18

Carbon Dioxide Transport and Storage Costs in NETL Studies

Quality Guidelines for Energy Systems Studies

March 2013

Exhibit 7 CO2 storage cost supply curves

Source: NETL

The storage potential for each formation depends upon the storage coefficient, which is the 

percentage of the formation’s brine-filled pore volume that may be occupied by CO2. The 

storage coefficient depends on the depositional environment and the structural setting. (15) The 

storage resource potential for each formation in the basins shown previously in Exhibit 4 is 

partitioned into five structural settings: dome, anticline, ten-degree regional dip, five-degree 

regional dip, and flat structural setting. The depositional environments for the various formations 

are eolian (Minnelusa), shallow shelf (Muddy, Madison, Mission Canyon), peritidal (St. Peter), 

strand plain (Mt. Simon), fluvial (Woodbine), and delta (Paluxy). 

The storage resource potential for any particular formation reflects the areal extent of the 

formation as well as its thickness, porosity, and storage coefficient. In the CO2 Saline Storage

Cost Model, over the total area of any formation, only 2.5 percent of the area is assigned to 

structural closure or 1.25 percent each for dome and anticline structures. (16) The remaining area 

is split evenly between the ten- and five-degree regional dip and flat structural settings (32.5

percent each). Dome and anticline structures have higher storage coefficients, but ten- and fivedegree regional dip and flat structural settings have much higher storage potential due to their 

larger areal extent. CO2 storage potential modeled here is a resource that has yet to be proven. 

This process begins with site characterization for a specific storage project.

2000

2020

2040

2060

2080

2100

2120

$1 

$10 

$100 

$1,000 

- 50,000 100,000 150,000 200,000 250,000 300,000 350,000 400,000 450,000 

Year

First Year Break-Even Cost - $/Tonne CO2 (2011)

Cumulative Storage Potential - Million Tonnes

CO2 Storage Cost Curves for Four Basins

Cumulative Elec & Ind Sector Captured CO2 Emissions

East Texas Illinois Powder River Williston Cum Elec+Ind CO2 Captured
National Energy Technology Laboratory Office of Program Planning and Analysis

19

Carbon Dioxide Transport and Storage Costs in NETL Studies

Quality Guidelines for Energy Systems Studies

March 2013

Each formation in each basin has a maximum theoretical capacity to store CO2, and this capacity 

significantly exceeds the mass of CO2 being stored by a single storage project. In constructing 

the cost supply curves, it is assumed that multiple storage projects can be implemented in each 

formation until the total mass of CO2 injected from all the projects approaches 40 percent of the 

maximum theoretical storage capacity for each formation. It is assumed that institutional issues 

(such as obtaining property rights to store CO2, restrictions on storage in urban areas) and 

pressure interferences from multiple storage sites will prevent more than 40 percent of the 

theoretical storage capacity from being used.

For each basin plotted in Exhibit 7, the cost to store at least 25,000 million tonnes (Mt) is shown 

in Exhibit 8. For the East Texas Basin, 25,000 Mt of cumulative storage resource potential is 

provided by a combination of sedimentary depositional and structural settings in the Woodbine 

and Paluxy formations, each represented by a point on the cost supply curve. In the East Texas 

Basin, the low cost point is $4.58 per tonne of CO2 stored for a dome structure in the Woodbine. 

A reservoir with a five-degree structural setting in the Woodbine provides the storage resource 

potential at the 25,000 Mt mark at a cost of $6.34 per tonne of CO2. At this price within this 

potential reservoir of the Woodbine formation is the potential to store up to 28,860 Mt of 

captured CO2. This storage resource potential represents 7.57 percent of the volume of CO2

emissions that can be captured from the electric power and industrial sectors over the next 

century. Similar information for the Illinois, Powder River, and Williston Basins are also posted 

in Exhibit 8.

Exhibit 8 Storage resource potential for four basins

Source: NETL

For these four basins, the storage resource potential at the CO2 price associated with cumulative 

storage of 25,000 Mt totals 148,107 Mt. This represents 38.83 percent of the volume of CO2

emissions that can be captured from the electric power and industrial sectors over the next 

century. Assuming 6.64 million tonnes of CO2 captured from a 1 GW power plant (30 years of 

operation, 30 percent plant efficiency, 80 percent capacity factor, and 90 percent capture 

efficiency), this storage resource potential is equivalent to 743 GW of power generation.

Storage resource potential with respect to electric power generation ranges from 144 GW in the 

East Texas Basin to 214 GW in the Powder River Basin. Total storage resource potential for 

BASIN

25,000 Mt Storage Resource Potential 50,000 Mt Storage Resource Potential 75,000 Mt Storage Resource Potential

$/tonne to 

25,000 Mt 

(2011$)

Storage 

Resource 

Potential at 

this $/t

% of next 

100 yrs 

captured 

emissions

GW 

Storage 

Resource 

Potential

$/tonne to 

50,000 Mt 

(2011$)

Storage 

Resource 

Potential at 

this $/t

% of next 

100 yrs 

captured 

emissions

$/tonne to 

75,000 Mt 

(2011$)

Storage 

Resource 

Potential at 

this $/t

% of next 

100 yrs 

captured 

emissions

Illinois $5.98 36,931 Mt 9.68% 185 GW $6.16 66,961 Mt 17.56% $6.26 95,968 Mt 25.16%

East Texas $6.34 28,860 Mt 7.57% 144 GW $9.36 56,021 Mt 14.69% $10.28 78,991 Mt 20.71%

Williston $11.67 38,649 Mt 10.13% 194 GW $11.67 69,879 Mt 18.32% $11.81 100,308 Mt 26.30%

Powder 

River $19.84 43,667 Mt 11.45% 214 GW $20.44 75,910 Mt 19.90% $20.44 75,910 Mt 19.90%

Total 148,107 Mt 38.83% 743 GW 268,771 Mt 70.47% 351,177 Mt 92.08%
National Energy Technology Laboratory Office of Program Planning and Analysis

20

Carbon Dioxide Transport and Storage Costs in NETL Studies

Quality Guidelines for Energy Systems Studies

March 2013

these four basins, through the CO2 price associated with cumulative storage of 75,000 Mt, 

represents 92 percent of the volume of CO2 emissions that can be captured from the electric 

power and industrial sectors over the next century. The Illinois Basin, with the Mt. Simon 

Formation, is the low-cost provider. The Williston Basin, as illustrated in Exhibit 7, has the 

largest storage resource potential. 

3.3 Combining Transport and Storage

Exhibit 9 reports the storage cost results from the CO2 Saline Storage Cost Model for the 25,000 

Mt of cumulative storage resource potential and transport cost for the example plant parameters. 

The resulting CO2 T&S values (rounded up to the nearest whole dollar) to be used in NETL 

systems studies are shown in the far right column.

Exhibit 9 Total transport and storage costs for use in NETL system studies

Plant Location Basin

Transport 

(2011$ per 

tonne)

Storage 

(2011$ per 

tonne)

Total T&S

(2011$ per 

tonne)

T&S Value for 

System 

Studies 

(2011$ per 

tonne)

Midwest Illinois

3.65

5.75 9.40 10

Texas East Texas 6.06 9.71 10

North Dakota Williston 10.96 14.61 15

Montana Powder River 17.86 21.51 22
National Energy Technology Laboratory Office of Program Planning and Analysis

21

Carbon Dioxide Transport and Storage Costs in NETL Studies

Quality Guidelines for Energy Systems Studies

March 2013

4 References

1. Bock, B., R. Rhudy, H. Herzog, M. Klett, J. Davidson, D G. De La Torre Ugarte, and D. 

Simbeck. (2003). Economic Evaluation of CO2 Storage and Sink Enhancement Options, 

Retrieved on March 13, 2013, from 

http://sequestration.mit.edu/energylab/uploads/AaKal/40937R04.pdf

2. National Energy Technology Laboratory (NETL). (2001). Engineering and Economic 

Assessment of Carbon Dioxide Sequestration in Saline Formations. Retrieved on March 

13, 2013, from http://www.netl.doe.gov/publications/proceedings/01/carbon_seq/4a3.pdf

3. Parker, N. (2004). Using Natural Gas Transmission Pipeline Costs to Estimate Hydrogen 

Pipeline Costs. Institute of Transportation Studies, University of California, Davis, CA. 

4. Handy-Whitman Index of Public Utility Costs, Gas Transmission and Distribution Pipe 

Materials Indexes. (February 2008). 

5. United States Department of Labor. (February 2008). U.S. Bureau of Labor Statistics 

Producer Price Index, Support activities for oil and gas operations, Series Id: 

PCU213112213112. 

6. United States Department of Labor. (February 2008). U.S. Bureau of Labor Statistics 

Producer Price Index, Drilling Oil and Gas Wells, Series Id: PCU213111213111. 

7. National Energy Technology Laboratory (NETL). (2011). Recommended Project Finance 

Structures for the Economic Analysis of Fossil-Based Energy Projects. DOE/NETL2011/1489, Pittsburgh, PA.

8. Jeffrey Layne. (2009). Operating Experience with CO2 Pipelines. Proceedings of the 

EPRI Coal Fleet for Tomorrow: General Technical Meeting. Houston, TX, April 21-23rd, 

2009. 

United States Senate Committee on Energy & Natural Resources. (2008). Statement of 

Ronald T. Evans of Denbury Resources, Inc., before the U.S. Senate Committee on 

Energy and Natural Resources. Hearing on the Policy Aspects of Carbon Capture, 

Transportation, and Sequestration and Related Bills, S.2323 and S.2144. Retrieved on 

March 13, 2013, from http://www.gpo.gov/fdsys/pkg/CHRG-110shrg41620/pdf/CHRG110shrg41620.pdf

9. Personal communication with Ronald T. Evans of Denbury Resources, Inc. December 

30th, 2009. 

10. International Energy Agency (IEA). (2008). CO2 Capture and Storage: A Key Carbon 

Abatement Option. Available for purchase at 

http://www.oecdbookshop.org/oecd/display.asp?lang=EN&sf1=identifiers&st1=5l4cv1l2

p437

11. National Energy Technology Laboratory (NETL). (2011). FE/NETL CTS-Saline Cost 

Model. Energy Analysis Publications: Details. Retrieved on March 13, 2013, from 

http://www.netl.doe.gov/energyanalyses/refshelf/PubDetails.aspx?Action=View&PubId=456
National Energy Technology Laboratory Office of Program Planning and Analysis

22

Carbon Dioxide Transport and Storage Costs in NETL Studies

Quality Guidelines for Energy Systems Studies

March 2013

12. Ciferno, J.P. and H. McIlvried (2003). CO2 Flow Modeling and Pipe Diameter 

Determination. SAIC, McLean, VA.

13. Energy Information Administration (EIA). (n.d.). Energy-Related Carbon Dioxide 

Emissions by Sector and Source, EIA AEO2012 Early Release. Washington, D.C.

14. International Energy Agency (IEA). (2009). IEA Greenhouse Gas R&D Programme (IEA 

GHG). Development of Storage Coefficients for CO2 Storage in Deep Saline Formations, 

2009/13, October 2009.

15. Brennan, S.T., R.C. Burruss, M.D. Merrill, P.A. Freeman, and L.F. Ruppert. (2010). A 

Probabilistic Assessment Methodology for the Evaluation of Geologic Carbon Dioxide 

Storage. OFR 2010-1127. Retrieved on April 1, 2013, from

http://pubs.usgs.gov/of/2010/1127/