DOE/NETL

- 2010/???? 201 4 /16 53National Energy Technology Laboratory Office of Program Performance and Benefits
2 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014



## 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 a ny 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 commer cial 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 a uthors 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 Performance and Benefits
3 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014



## Carbon Dioxide Transport and Storage Costs

in NETL Studies

DOE/NETL

- 2013 / 1614

Final Report

September 30, 2013

NETL Contact:

Tim Grant Physical Scientist Office of Program Planning and Benefits , Benefits Division

National Energy Technology Laboratory

www.netl.doe.govNational Energy Technology Laboratory Office of Program Performance and Benefits
4 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014



### Prepared by:

Tim Grant National Energy Technology Laboratory

David Morgan National Energy Technology Laboratory

Kristin Gerdes National Energy Technology Laboratory

DOE Contract Number DE

- FE0004001National Energy Technology Laboratory Office of Program Performance and Benefits
5 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014



## 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

Andrea Poe, Booz Allen Hamilton

Richard Lawrence, Advanced Resources InternationalNational Energy Technology Laboratory Office of Program Performance and Benefits

6 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014

This page intentionally left blank.National Energy Technology Laboratory Office of Program Performance and Benefits

7 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014



## Table of Contents

Executive Summary

................................ ................................ ................................ ......................... 9

1 Objective

................................ ................................ ................................ ................................ 10

2 Approach

................................ ................................ ................................ ................................ 11

2.1 Transport Costs

................................ ................................ ................................ ....................... 11

2.2 Storage and Monitoring Costs

................................ ................................ ................................ 17

3 Results

................................ ................................ ................................ ................................ .... 21

3.1 Transport Costs

................................ ................................ ................................ ....................... 21

3.2 St orage and Monitoring Costs

................................ ................................ ............................... 22
3.3 Combining Transport and Storage Costs

................................ ................................ ............... 28

4 Revision Control

................................ ................................ ................................ .................... 29

5 References

................................ ................................ ................................ .............................. 30



## List of Exhibits

Exhibit ES

- 1 Total transport and storage (T&S) costs for use in NETL system studies

................ 9

Exhibit 2

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

............... 11

Exhibit 2

- 2 Natural gas pipeline capital costs using different equations

................................ ...... 14

Exhibit 2

- 3 Kinder

- Morgan pipeline cost metrics

................................ ................................ ........ 15

Exhibit 2

- 4 Location of four basins selected for this study

................................ .......................... 18

Exhibit 2

- 5 Modeling parameters for low

- cost, base, and high

- cost cases distance

..................... 20

Exhibit 3

- 1 Sensitivity of transport costs to plant and distance assumptions

............................... 22

Exhibit 3

- 2 CO 2 cumulative storage potential cost supply curves

................................ ................ 23

Exhibit 3

- 3 St orage resource potential for four basins

................................ ................................ . 24

Exhibit 3

- 4 Potential storage cost supply curves for low

- cost, base, and high

- cost cas e scenarios in the Illinois Basin

................................ ................................ ................................ ............... 26

Exhibit 3

- 5 Breakout of project stage cost as a percent of total storage costs

.............................. 27

Exhibit 3

- 6 Cost items for reservoirs providing storage potential resource at 25 Gt

................... 28

Exhibit 3

- 7 Total transport and base case storage (T&S) costs for use in NETL system studies 28

Exhibit 4

- 1 Revision table

................................ ................................ ................................ ............ 29National Energy Technology Laboratory Office of Program Performance and Benefits

8 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014



## Acronyms and Abbreviations

AoR Area of Review

CO 2 Carbon dioxide

DOE Department of Energy

EIA Energy Information Administration

EPA Environmental Protection Agency

FE Fossil energy

GW gigawatt

Gt Gigatonne ( b illion metric tons,

10 12 kilograms )

IRROE Internal rate of return on equity

INGAA Interstate Nat u ral Gas Association of

America

mi 2 square mile Mt Million tonne , 10 9 kilograms

MVA Monitoring, Verification, and

Accounting

NETL National Energy Technology

Laboratory

O&GJ Oil and Gas Journal

O&M Operation and maintenance psia Pounds per square inch absolute

ROW Right

- of

- way T&S Transport and storage

tonne metric ton, 1000 kilogramsNational Energy Technology Laboratory Office of Program Performance and Benefits

9 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014



## Executive Summary

The values to be used in systems studies sponsored by the National Energy Technology Laboratory (NETL) for estimating the cost of C O 2 pipeline transport and storage (T&S) (rounded to the nearest whole dollar) are shown in Exhibit ES

- 1 . The basis for these values is discussed below.

Exhibit ES

- 1 Total transport and storage (T&S) costs for use in NETL system studies

Plant Location Basin T&S Value for System Studies (2011$/tonne)

Midwest Illinois 11

Texas East Texas 11

North Dakota Williston 16

Montana Powder River 24

Source: NETL

T &S cost information is used by NETL in their studies on the capture of CO 2 from electric power plants. Four geographic locations were selected ( Exhibit 2

- 4 ) to model transportation and storage of captured CO 2 : Midwest (Illinois Basin), Texas (East Texas Basin), North Dakota (Williston Basin)

, and Montana (Powder River Basin). In the base case

, 3.2 million metric tons of CO 2 are captured and transported from a source in each of the basins modeled for storage

costs

. Cost of transportation is defined by a dedicated 100 km (62 mi) pipeline connecting the source of the captured CO 2 with a storage si te. The modeled cost of transportation is $2.24 per
tonne of CO 2

.
Variability in overall T&S costs are found in the unique geology of the different reservoirs present in each of the four basins. Potential uncertainty associated with the cost of CO 2 storage in the reservoirs model ed in each basin is addressed with low

- cost, base , and high

- cost scenario s ( Exhibit 2

- 5 ) . Cost parameters for each cost scenario are m odified to reflect a savings in cost or an additional cost burden due to potentially unique operational situations ; for example

, a reduction in 3

- D seismic cost due to applied technology or an increase due to logistical challenges of seismic data acquisiti on

.
Storage potential in a subsurface reservoir of captured CO 2 represents a resource that has yet to be prove d . The cost of storage, which is the modeled cost to utilize this resource once prove d

, is the break

- even cost to store a metric ton of CO 2 . Storage costs posted in this guideline represent low

- cost, base, and high

- cost case scenario s at a cumulative storage potential of 25 billion metric

ton s ( 25 gigatonnes [ Gt ] ), 50 Gt and 75 Gt ( Exhibit 3

- 3 ). For the base case scenario and a cumulative storage potential of 25 Gt, the modeled cost to store one tonne of CO 2 in the Illinois Basin is $8.69. In the East Texas Basin this cost is $8. 83 per tonne, in the Williston Basin it is $13.95 per tonne

, and in the Powder River Basin it is $21.81 per tonne

. Combined T&S base

case scenario cost at 25 Gt of potential storage is $10.93 per tonne in the Illinois Basin, $11.07 per tonne in the East T exas Basin, $16.19 per tonne in the Williston Basin

, and $24.05 per tonneNational Energy Technology Laboratory Office of Program Performance and Benefits

10 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014

in the Pow d er River Basin. For system analysis studies at NETL, these cost values are rounded to $11 for the Illinois and East Texas Basins, $16 for the Williston Basin

, and $24 for the Powder River Basin.



## 1 Objective

The purpose of this guideline is to estimate the cost of CO 2 pipeline transport and storage ( T&S ) in a deep s aline aquifer for the plant locations used in the energy system studies sponsored by the National Energy Technology Laboratory ( NETL )

. NETL is in the Office of Fossil Energy (FE) in the United States (U.S.) Department of Energy (DOE).
Transport costs are calculated using the FE/NETL CO 2 Transport Cost Model

, [ 1 ] assuming a 100 km (62 mi) dedicated pipeline is used in each region to connect the CO 2 source (e.g., a power plant) to the CO 2 storage site. The FE/NETL CO 2 Transport Cost Model determines the pipeline diameter needed to transport a specified CO 2 mass flow rate (in this case an annual average of 3.2 million tonnes of CO 2 ) with or without boost pumps along the pipeline. The model then determines which combination of pumps and pipeline diameter gives the lowest overall cost in dollars per tonne of C O 2 transported.
Due to the variances in the geologic formations that make up saline aquifers across the U .S., the

cost to store CO 2 can vary greatly depending on location. To account for the se variances, region

specific results from the FE/NETL CO 2 Saline Storage Cost Model [ 2 ] are utilized to represent costs for the following plant locations and associated sedimentary basins used in NETL studies :

 Midwest

– Illinois Basin

 Texas

– East Texas Basin

 North Dakota

– Williston Basin

 Montana

– Powder River Basin

Variance also occurs within the geologic formations present in each of these basins. Three cost scenarios

– low

- cost , base

, and high

- cost

– were developed to reflect variance within the geologic formations in each of the basins modeled.

The costs calcula ted by the FE/NETL CO 2 Saline Storage Cost Model cover all costs including capital costs, operating costs, financing costs

, and taxes and are expressed in dollars per tonne of CO 2 stored. Costs were developed for all potential storage formations in each r egion

, and the total mass of CO 2 that can potentially be stored in each formation was also calculated. Since the cheapest formations are likely to be the first to be used for storage (all other things being equal), the costs for all formations in a region were ranked from lowest to highest

, and the cumulative mass of CO 2 that could be stored at that cost (or lower) was calculated. T&S costs were then determined for three levels of cumulative CO 2 storage in each region: 25, 50

, and 75 billion

tonnes. As a point of reference, the U.S. emits around 2 billion tonnes of CO 2 each year from the electric power sector and around 1 billion tonnes of CO 2 each year from industrial sector excluding emissions associated with electricity used by industrial operation s

. [ 3 ]National Energy Technology Laboratory Office of Program Performance and Benefits

11 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014



## 2 Approach

T&S costs are reported as first

- year costs in $/tonne of CO 2 , increasing at a nominal rate of 3 percent per year, which is consistent with the general inflation rate assumed in NETL’s baseline energy system studies . From the perspective of the CO 2 source (e.g., a power plant or other energy conversion facility), these costs are treated as a disposal cost for each tonne of CO 2 captured during the assumed 30

- year operational period. From the pipeline and storage site’s perspective, th e cos t s 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 the ir required internal rate of return on equity (IRROE). All costs are reported in 2011 dollars.

Exhibit 2

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

Source: NETL

T&S costs are based on the CO 2 flow rate of one example plant: a daily maximum 11,000 tonne/day (12,000 ton/day)

, which translates into an annual average of 3.2 million tonnes per year assuming an 80 percent capacity factor. The sensitivity of transport costs based on flow rate, capacity factor

, and pipeline length can be assessed using the FE/NETL CO 2 Transport Cost Model

. A limited sensitivity analysis is presented in Section 3.1. The sensitivity of storage costs based on flow rate and capacity factor can be determined using the FE/NETL CO 2 Saline Storage Cost Model , but the sensitivity of the model to these parameters was not investigated in this guideli ne

.


### 2.1 Transport Costs

The FE/NETL CO 2 Transport Cost Model is a mathematical model that estimates the cost of transporting liquid CO 2 using a pipeline

. The FE/NETL CO 2 Transport Cost Model is an updated version of the CO 2 pipeline cost model at NETL

. [ 4 ] Costs are estimated for a single point

- to

- point pipeline

, which may have pumps along the pipeline to boost the pressure

. The model includes the capital costs for purchasing and installing the pipeline, a surge tank, a pipeline control system and, if econ omical, the boost pumps

. The FE/NETL CO 2 Transport Cost 30

- Year Operational Period

30

- Year Operational Period

30

- Year Operational Period (Monitoring Well Drilling) 50

- Year Post

- Injection Site Care and ClosureNational Energy Technology Laboratory Office of Program Performance and Benefits

12 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014

Model accounts for the operation and maintenance (O&M) costs for the pipeline and pumps and the cost of the electricity used to power the pumps

. The FE/NETL CO 2 Transport Cost Model also has a finan cial model with debt, equity, depreciation

, and taxes

. The model can determine the price of CO 2 ( in dollars per tonne of CO 2 transported ) that provides investors with their desired minimum IRROE

. This price is referred to as the break

- even price of CO 2 i n this guideline

. The break

- even price is also the minimum cost of transporting CO 2 from the perspective of the CO 2 source

. For th e analysis in this guideline , it is assumed that CO 2 is provided by the CO 2 source at a
pressure of ( 2,200 psig )

, and the cost and energy requirements of compression are assumed by the CO 2 source . CO 2 is in a dense phase liquid state at this pressure

, which is desirable for transportation.

CO 2 exits the pipeline terminus at the CO 2 storage site at a pressure of 1,200 psig

. This exit pressure specification ensures that CO 2 remains in a dense phase liquid state throughout the length of the pipeline regardless of potential pressure drops due to pipeline elevation changes

. Cost s for additional compression that may be req uired for injection in a particular formation is included as part of storage costs.
For this analysis

, a pipeline length of 100 km (62 mi) is assumed

. The FE/NETL CO 2 Transport Cost Model can estimate the minimum pipeline diameter need ed to transport the CO 2 this distance without any pumps to boost the pressure

. The model can also determine if a smaller diameter pipe can be used if one or more pumps are used at equal intervals along the pipeline to boost the pressure from 1200 psig at the pump inlet to 2200 psig at the pump outlet.

The FE/NETL CO 2 Transport Cost Model uses an iterative procedure to determin e the diameter

necessary to sustain a 1,000 psi a pressure drop over the specified pipeline length

, o r pipeline segment length

, if pumps are installed along the pipeline. The model rounds up the diameter to the nearest standard pipe diameter. The pipeline diameter was determined based on the CO 2 output produced by the CO 2 source when it is operating at full capacity (100 percent utilization factor) rather than at average capacity.

CO 2 transport costs are broke n down into capital and operating expenses

. The capital expenses include the costs for the pipeline, a surge tank, a pipeline control system

, and the boost pumps (if used)

. The operating expenses include O&M costs for these pieces of equipment and the cost of the electricity used by the boost pumps.

The FE/NETL CO 2 Transport Cost Model provides three equations for calculating the capital costs for the pipeline

. The three equations all used pipeline capital costs reported in the Oil and Gas Journal’s (O&GJ) annual Pipeline Economics Report for existing natural gas, oil, and petroleum pipeline project s. [ 5 ] The O&GJ report ed capital costs in four categories: 1) materials, 2) labor, 3) right of way (ROW) and damages, and 4) miscellaneous. The materials category include d the cost for pipe, pipe coating, and cathodic protection

. The miscellaneous category include d costs for surveying, engineering, supervision, contingencies, telecommunications equipment, freig ht, taxes, allowances for funds used during construction (AFUDC), administration and overheads, and regulatory filing fees

. One set of equations for pipeline capital costs was developed by Parker [ 6 ] using cost data from 1991 to 2003 ; these equations give costs in 2000 dollars

. A second set of equations for pipeline capital costs wasNational Energy Technology Laboratory Office of Program Performance and Benefits

13 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014

developed by McCoy and Rubin [ 7 ] using cost data from 1995 to 2005 ; these equations give costs in 2004 dollars

. The third set of equations for pipeline capital costs was dev eloped by Rui et al. [ 8 ] using cost data from 1992 to 2008 ; these equations give costs in 2008 dollars

. While the three sets of equations have different functional forms, they all calculate capital costs as a function of pipeline length and diameter. The capital costs for all three sets of equations were adjusted to 2011 dollars using a variety of price indices . [ 1 ] The resulting capital costs are for natural gas pipelines

. CO 2 pipelines operate at higher pressures than natural gas pipelines, so they require a thicker pipe wall, which affects the cost

. The capital costs for materials and labor were adjusted, depending on the pipe diameter, using factors develope d by ICF International. [ 9 ]
The costs for a surge tank and pipeline control system were taken from an earlier NETL study

. [ 4 ] These costs were in 2000 dollars and were adjusted to 2011 dollars using appropriate price indices

. [ 1 ] The capital costs for a boost pump were determined using an equation provided by McCollum and Ogden

. [ 10 ] This equation needs the power requirements for the boost pumps and McCollum and Ogden [ 10 ] also provide an equation for estimating the power requirement based on the CO 2 mass flow rate and pressure increase through the pump

. The pump capital costs were in 2005 dollars and were adjusted to 2011 dollars using appropriate price indices

. [ 1 ]
The O&M costs for the pipeline were based on a value provided in Heddle et al. [ 11 ] These were in 1999 dollars and were adjusted to 2011 dollars usin g appropriate price indices. [1] The O &M costs for the remaining pieces of equipment were assumed to be 4 percent of the capital costs on an annual basis

. The price of electricity used to estimate the cost of the electricity used by the pumps was assumed to be the national average electricity price for electricity provided to commercial operations in 2011

. [ 12 ]

As discussed above, the FE/NETL CO 2 Transport Cost Model has a financial model with debt, equity, depreciation

, and taxes

. The model can determine the price of CO 2 ( in dollars per tonne of CO 2 transported ) that provides investors with their desired minimum IRROE

. To use the financial model, a number of parameters must be specified

. For this evaluation, it was assumed that it takes 3 years to complete the construction of the pipeli ne and that the pipeline operates for 30 years

. The following financial parameters were used, which match the low

- risk business scenario for an i nvestor

- o wned u tility [ 13 ]:

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

 Debt to equity ratio of 50%/50%

 In terest rate on debt of 4.5%/year

 Minimum IRROE of 12%

 30

- year operational period

The FE/NETL CO 2 Transport Cost Model includes a project contingency calculated for all capital costs

. NETL guidelines for cost estimating [ 14 ] recommend using a project contingency between 15 percent and 30 percent for the budgetary

- level type cost estimate that is provided by the FE/NETL CO 2 Transport Cost Model

. The lower value of 15 percent was used for th e analysis in this guideline, becaus e the pipeline costs provided by the O & GJ may include contingency and some taxes.

The FE/NETL CO 2 Transport Cost Model determines the returns to the owner using a weighted average cost of capital methodology

. [ 1 ]National Energy Technology Laboratory Office of Program Performance and Benefits

14 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014

The three sets of equations for natural gas pipeline capital costs give different results as illustrated in Exhibit 2

- 2

, which presents the cost per mile for different pipeline lengths and diameters

. In general, the equations from Parker [ 6 ] give the highest cost followed by the equations from McCoy and Rubin [ 7 ] and then Rui et al. [ 8 ] The equations from Parker [ 6 ] give significantly higher costs than the other two equations.

Exhibit 2

- 2 Natural gas pipeline capital costs using different equations

Source: NETLNational Energy Technology Laboratory Office of Program Performance and Benefits

15 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014

To determine which of these three sets of equations to use in the analysis for this guideline , a comparison was made to pipeli ne capital cost data from a variety of sources

. The capital costs for a CO 2 pipeline per inch (diameter) and mile (length) including contingency range are as follows for the different sets of equations:

• Parker: $85,000/in

- mi (12 in pipe) to $120,000/i n

- mi (42 in pipe)

• McCoy: $65,000/in

- mi (50 mile long pipe) to $46,000/in

- mi (500 mile long pipe)

• Rui: $50,000/in

- mi (50 mile long pipe) to $35,000/in

- mi (500 mile long pipe)
The capital costs per inch

- mile using the equations from Parker [ 6 ] increase with increasing diameter but are relatively insensitive to the length of the pipeline

. The capital costs per inch

mile using the equations from McCoy and Rubin [ 7 ] increase somewhat with increasing diameter but decrease with increasing pipeline length. The capital costs per inch

- mile using the equations from Rui et al. [ 8 ] show the same type of behavior as the equations from McCoy and Rubin

. [ 7 ]

These co sts were compared to contemporary pipeline costs quoted by industry experts, such as Kinder

- Morgan and Denbury Resources. Exhibit 2

- 3 details typical rule

- of

- thumb costs for various terrains and scenarios as quoted by a representative of Kinder

- Morgan at the Spring Coal Fleet Meeting in 2009

. [ 15 ] It is not known if these rule

- of thumb estimates include contingencies

. As shown, the cos ts using the equations from Parker [ 6 ] are on the high end of this range, while the costs using the equations from McCoy and Rubin [ 7 ] fall on the low end of this range

, and the costs using the equations from Rui et al. [ 8 ] tend to fall below this range.

Exhibit 2

- 3 Kinder

- Morgan pipeline cost metrics

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) $700,000National Energy Technology Laboratory Office of Program Performance and Benefits

16 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014

A further comparison was made to cost data for two Denbury CO 2 pipelines

. The first is the Green pipeline with the following characteristics.

• Location: Southeast United States

• Pipeline length: 314 miles

• Pipeline diameter: 24 inches

• CO 2 flow capacity: 42,320 tonne/day

• Capital cost: About 660 million dollars according to trade journals
About 884 million dollars excluding capitalized interest according to the annual report

• Status: Completed around 2010
Assuming the capacity factor is 80 percent for this pipeline, the FE/NETL CO 2 Transport Cost Model determines that a 24

- inch pipeline of this length would need 2 pumps

. The capital cost for this project is estimated by the model to be as follows :

• Using Parker eq.: 740 million dollars

• Using McCoy eq.: 435 million dollars

• Using Rui eq.: 370 million dollars
The result using the Parker equations [ 6 ] exceeds the value in trade journals but is less than the value in the annual report

. The results from the McCoy and Rubin [ 7 ] and Rui et a l. [ 8 ] equations are significantly less than both published capital costs.

The second CO 2 pipeline is the Greencore pipeline with the following characteristics :

• Location: Wyoming

• Pipeline length: 232 miles

• Pipeline diameter: 20 inches

• CO 2 flow capacity: 38,280 tonne/day

• Capital cost: About 285 million dollars according to trade journals
About 135 million dollars for second half of project according to annual report

• Status: Completed in 2012 or 2013
Assuming the capacity factor is 80 percent for this pipeline, the FE/NETL CO 2 Transport Cost Model determines that a 20

- inch pipeline of this length would need 4 pumps

. The capital cost for this project is estimated by the model to be as follows :

• Using Parker eq.: 430 million dollars

• Using McCoy eq.: 170 million dollars

• Using Rui eq.: 135 million dollarsNational Energy Technology Laboratory Office of Program Performance and Benefits

17 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014

The result using the Parker equations [ 6 ] exceeds the value in trade journals

. The results from the McCoy and Rubin [ 7 ] and Rui et al. [ 8 ] equations are less than the published capital costs.
These results indicate that the equations from Parker [ 6 ] and McCoy and Rubin [ 7 ] give costs that are closest to published CO 2 pipeline costs

. The equations from Parker [ 6 ] tend to give costs on the high side, while the equations from McCoy and Rubin [ 7 ] tend to give c osts on the low side

. To be conservative (i.e., to err on the side of over

- estimating CO 2 transport costs), the equations from Parker [ 6 ] were used in the analysi s for this guideline

.


### 2.2 Storage and Monitoring Costs

Storage and monitoring costs were estimated using the FE/NETL CO 2 Saline Storage Cost Model

. This model is a spreadsheet

- based tool that estimates the break

- even price for storing CO 2 in a deep saline aquifer from the perspective of the owner of a CO 2 storage site. This break

even price is also the minimum cost for storing captured CO 2

. The FE/NETL CO 2 Saline Storage Cost Model includes the cost of complying with key regulations. In order to inject CO 2 into the subsurface for the purpose of storing CO 2 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 P rogram, 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.
The majority of well, technology, and labor cost data are from EPA’s economic analysis of the Class VI and Subpart RR regulations and are in 2008 dollars. Except for groundwater wells or vadose zone wells, the cost of all wells in the model is based on the 2006 API

- Joint Association Survey

. Some cost data are based on conversations with industry personnel while at conferences. Costs posted in the model are updated as new information becomes available.

Results from the FE/NETL CO 2 Saline Storage Cost Model for storage an d 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 couples 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 2

- 4

.National Energy Technology Laboratory Office of Program Performance and Benefits

18 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014

Exhibit 2

- 4 Location of four basins selected for this study

Source: NETL Inputs to the FE/NETL CO 2 Saline Storage Cost Model that have a significant influence on cost include financial parameters, timelines for the various stages of storage

, drilling or monitoring activities in stages

, and selection of financial responsibility instruments

. The financial parameters match the high

- risk business scenario for an Investor Owned Utility and include:

 Debt to equity ratio of 45%/55%

 Interest rate on debt of 5.5%/year

 IRROE of 12%

 Escalation rate of 3%

 M odified trust fund th at grows at an annual rate over the period of injection operations

 Project contingency factor of 15%

 P rocess contingency factor o f 20% Illinois Basin Storage for Midwest Plants

East Texas Storage for Texas Plants Williston Basin Storage for ND plants

Powder River Basin Storage for MT 

### plantsNational Energy Technology Laboratory Office of Program Performance and Benefits

19 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014

In the FE/NETL CO 2 Saline Storage Cost Model

, a s torage project 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 characteriza tion, each having a 2

- D seismic

survey covering the estimated Area of Review ( AoR ) and one strat

- well drilled to collect relevant reservoir data.

o The successful site has an additional strat

- well drilled plus a 3

- D seismic survey covering the AoR; pore

- spac e rights and property access are also leased

.

 Permitting: 2 years

o Includes submittal of required plans (AoR & Corrective Action, Testing & Monitoring, Injection Well Plugging, Post

- Injection Site Care & Site Closure, Emergency & Remedial Response) for Clas s 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 CO 2

.

o Demonstrate financial responsibility.

 Operations: 30 years

o Injection of 3.2 Mt of CO 2 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 eve ry five years with 3

- D seismic

.

o Plugging injection wells at conclusion of injection operations

.

o Payment into 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 separate 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 equipme nt 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 state

sponsored trust fund that the storage operator pays into during operations.

Cost variability is also present within a basin due to the changing geologic character of a particular formation in which a CO 2 storage operation will be developed. Three cost scenarios were established to model this variability: low

- cost, base

, and high

- cost. Changes in modeling parameters between low

- cost , base

, and high

- cost case scenarios are illustrated in Exhibit 2

- 5

.National Energy Technology Laboratory Office of Program Performance and Benefits

20 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014

Exhibit 2

- 5 Modeling parameters for low

- cost , base, and high

- cost case s distance

Source: NETL

Costs increase from the low

- cost scenario to the high

- cost scenario due to changes in the following parameters listed in Exhibit 2

- 5 :

 Rate of return on the trust fund decreases

, increasing the cost to the operator to maintain a suitable balance in the modified trust fund to meet regulatory requirements.

 Storage coefficient decrease s , reducing the storage volume per unit area and increasing the plume size and associated monitoring costs.

 Post

- injection site care and site closur e period of 25 years in the low case increases to the default time period of 50 years for the base and high

- cost cases , increasing monitoring and financial responsibility costs

.

 The number of years to complete site characterization and permitting are increased in the high

- cost case , delaying operations and positive cash flow from injection revenue

.

 3

- D seismic costs increase from $100,000 per square mile to $220,000 per square mile.

 The number of monitoring wells drilled increase be cause w ell spacing for monitoring wells in the plume area decrease from low to base case, both of which utilize the opportunity to dual complete these wells in the reservoir and above the seal where possible. The high

- cost case has the well spacing of the base case but does not dual complete any monitoring wells in the plume area , increasing the number of above seal wells drilled

. All three scenarios have four dual completed monitoring wells for the pressure front area.National Energy Technology Laboratory Office of Program Performance and Benefits

21 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014

 Increasing number of wells requiring corrective action increase s the value of financial responsibility and cost to perform this activity

.

 W ater withdrawal from the storage reservoir and subsequent treatment and disposal in the high

- cost case scenario add s another level of costs to o perations

. [ 16 ] A methodology to model costs associated with water withdrawals from the storage reservoir, surface

treatment

, and subsequent disposal is under development and testing. Th is cost is included in the high

- cost case scenario to reflect the pos sibility that an operator may adopt water withdrawals to maintain suitable reservoir pressures and/or control the areal extent of the plume

. [ 17 ]



## 3 Results

3.1 Transport Costs

The FE/NETL CO 2 Transport Cost Model was used to estimate the first

- year break

- even price (also the minimum cost) for transporting a maximum daily flow of 11,000 tonne/day of CO 2 with a capacity factor of 80 percent a distance of 100 km (62 mi) with 1,000 psi pressure drop

. The model estimates that the lowest co st configuration will hav e a 12

- inch pipe diameter and one boost pump. For this configuration, the estimated capital cost i s $ 67 million in 2011 dollars

, and the estimate d annual operating and maintenance cost ( O&M ) is $1.5 million per year in 2011 dollars

. T he resulting first

- y ear break

- even price (or minimum cost ) for CO 2 transport is $ 2.24 /tonne of CO 2 in 2011 dollars.

This value will be used in NETL Energy System Studies as a reasonable approximation for CO 2 transport costs for all plants regardless of the capacity factor a nd CO 2 capture rates. Exhibit 3

- 1 shows the sensitivity of the minimum transport cost to capacity factor and CO 2 transport rate. C osts are shown for pipeline s of 1 0 0 km ( 62 mi) and 200 km (124 mi)

. The plot indicates that

t he higher the flow rate, the lower the unit cost

, although there are some small discontinuities when the pipeline configuration changes (such as at 11,000 tonne/day for the 100 km long pipeline when the number of pumps increases from zero to one)

. The plo t indicates that increasing the capacity factor decreases the cost, but this effect is relatively small

. The plot also indicates that the longer the pipeline the higher the cost, with the cost being roughly proportional to the length.National Energy Technology Laboratory Office of Program Performance and Benefits

22 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014

Exhibit 3

- 1 Sensitivity of transport costs to plant and distance assumptions

Source: NETL



### 3.2 Storage and Monitoring Costs

C ost supply curves are plotted in Exhibit 3

- 2 for the East Texas, Illinois, Powder River

, and Williston basins. This figure presents the mass of CO 2 that can be stored theoretically in each basin at a given price of CO 2

. The price is t he break

- even price of CO 2 for a storage project in each basin (i.e., the price of CO 2 where the net present value for the project is zero)

. Each basin includes two or more storage formations

. The curves in Exhibit 3

- 2 represent the storage resource potential for the Paluxy and Woodbine formations in the East Texas Basin ; the Mt. Simon

, St. Peter

, and Knox formations in the Illinois Basin ; the Red River

, Mission Canyon

, and Cambrian Sandstone formations in the Williston Basin ; and the Minnelusa, Muddy

, and Madison formations in the Powder River Basin. Also plotted in Exhibit 3

- 2 is a projection, based on EIA data

, [ 3 ] of the cumulative mass of CO 2 emissions from the electric power and industrial sectors that can be captured over the next century ( 305 G t) , assuming 90 percent of all CO 2 emissions are captured.National Energy Technology Laboratory Office of Program Performance and Benefits

23 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014

Exhibit 3

- 2 CO 2 cumulative storage potent ial cost supply curves

Source: NETL The storage potential for each formation depends upon the inherent porosity of each formation and upon a storage coefficient. The cost variability in the modeling is in part due to a change in the storage coefficient, which is the percentage of the formation’s brine

- filled pore volume that may be occupied by CO 2 . The storage coefficient depend s on the depositional environment and the structural setting

. [ 18 ] The storage resource potential for each formation in the basins shown previously in Exhibit 2

- 4 is partitioned into three structural settings : dome, anticline, and regional dip

. D epositional environme nts for the clastic formations are eolian (Minnelusa)

, shallow clastic shelf (Muddy)

, peritidal (St. Peter), strand plain (Mt. Simon), fluvial (Woodbine)

, and delta (Paluxy). D epositional environments for the carbonate formations are shallow shelf (Knox, Madison

, and Mission Canyon).
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 FE/NETL CO 2 Sal ine 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

. [ 19 ] The remaining area is regional dip ( 97 .5 percent ). Dome and anticline structures have higher storage coefficients, but the regional dip structural portion of a formation has considerably higher storage potential due to its larger areal extent. CO 2 storage potential modeled here is a resource that has yet to be proven. This process begins with site characterization for a specific storage project.National Energy Technology Laboratory Office of Program Performance and Benefits

24 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014

Each formation in each basin has a maximum theoretical capacity to store CO 2 , and this capacity signifi cantly exceeds the mass of CO 2 being stored by a single storage project

. It is assumed that institutional issues (such as obtaining property rights to store CO 2 , restrictions on storage in urban areas ) and pressure interferences from multiple storage site s will reduce the effective area of a formation to provide storage capacity. The model takes into account total storage potential and the total mass of CO 2 to be injected by a single project over the time of operations and adjust s the total mass of CO 2 st o r ed, limiting utilization of a formation to less than 60 percent.
For each basin plotted in Exhibit 3

- 2 , the cost to store at least 25 G t is shown in Exhibit 3

- 3

. A storage potential of 25 Gt presents a significant resource relative to the generating capacity of the electric power sector reflected by the gigawatt ( GW ) s torage p otential in Exhibit 3

- 3

. Choosing this point on the supply

- cost curves provides a conservative estimate of the storage cost since many decades, if not more than a century, will pass before 25 Gt of CO 2 is stored in any of the four individual basins. For example, 25 Gt of storage would be sufficient for 125 GW of coal power with 90 percent CO 2 capture operating over 30 years.

Exhibit 3

- 3 Stor age resource potential for four basins

Source: NETL
For the East Texas Basin, 25 G t 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 c ost supply curve. For the base

- cost case scenario i n the East Texas Basin, the low

- cost point is $6.20 per tonne of CO 2 stored for a dome structure in the Woodbine. A reservoir with regional dip structural setting in the Woodbine provides the storage resource potential at the 25 G t mark at a cost of $8.83 per tonne of CO 2

. At this price, within the Woodbine formation, the resource storage potential represents 40 G t of captured CO 2

. This storage resource p otential represents 11 percent of the volume of CO 2 emissions that can beNational Energy Technology Laboratory Office of Program Performance and Benefits

25 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014

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 3

- 3

. For these four basins, the base

- cost case scenario storage resource potential at the CO 2 price associated with cumulative storage of 25 G t totals 329 G t. This represents 9 2 percent of the volume of CO 2 emissions that can be captured from the electric power and industrial sectors over the next century. Assuming 6.64 million tonnes of CO 2 captured from a 1 GW power plant ( 30 years of operation, 30 percen t plant efficiency, 80 percent capacity factor, and 90 percent capture efficiency), this storage resource potential is equivalent to 1,652 GW of power generation.

Storage resource potential with respect to electric power generation ranges from 201 GW in the East Texas Basin to 522 GW in the Williston Basin. Total storage resource potential for these four basins, through the CO 2 price associated with cumulative storage of 75 G t, represents 102 percent of the volume of CO 2 emissions that can be capture d 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 3

- 3 , has the largest storage resource potential.

The range of storage costs for the low

- cost , base

, and high

- cost case scenarios for the Illinois Basin is plotted in Exhibit 3

- 4

. The regional dip portion of the Mt. Simon formation in central Illinois provides 90.2 Gt of storage potential resource. Increasing costs shifts the curves up while a reduction in storage c oefficient shifts the curves to the left. The cost to store a tonne of captured CO 2 predominately lies between the low

- cost and high

- cost curves but this does not preclude the possibility that the storage costs of any particular project may lie above high

- cost or below low

- cost curves.National Energy Technology Laboratory Office of Program Performance and Benefits

26 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014

Exhibit 3

- 4 Potential storage cost supply curves for low

- cost , base
, and high

- cost case scenarios in the Illinois Basin

Source: NETLNational Energy Technology Laboratory Office of Program Performance and Benefits

27 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014

Exhibit 3

- 5 Breakout of project stage cost as a percent of total storage costs

Source: NETL

A breakout, by project stage, of storage costs for the Mt. Simon

, along with the Woodbine, Red River

, and Madison formations

, is presented in Exhibit 3

- 5 . This cost breakout is for the regional dip structural setting for each formation. It is this reservoir formation combination that provides the storage potential resource at 25 Gt and more (see Exhibit 3

- 2 and Exhibit 3

- 4 ). For each reservoir modeled (formation and structural setting), applied costs are identical (see modeling parameters Exhibit 2

- 5 )

. V ariables impacting costs are in the reservoir. Storage capacity and the combination of formation height, porosity, storage coefficient

, an d CO 2 density determine the areal exten t of the plume. The areal extent of the plume determines the number of monitoring wells drilled and the extent of 3

- D seismic and m onitoring, v erification, and

a ccounting ( MVA ) coverage needed to monitor the plume. Plume size impacts costs for site characterization, operations

, and post

- injection site care. These costs are comparable in the Woodbine and Mt. Simon but increase for the Red River and more so for the Madison ; this is due to an increasing plume size and the number of monitoring wells drilled ( Exhibit 3

- 6 )

. The significant change in project stage costs between reservoirs in this instance is in permitting when the injection wells are drilled and completed. Formation height and permeability impact injection of CO 2 , and depth drilled impacts drilling costs

. During permitting, f our injection wells are drilled for the Mt. Simon, Woo dbine

, and Red River

, but the Red River is 3,000 feet deeper accounting for the increased costs in Williston Basin storage . In the Powder River Basin, theNational Energy Technology Laboratory Office of Program Performance and Benefits

28 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014

Madison is 2,000 feet deeper than the Red River

, and 10 injection wells are d r illed. This increasing depth also impacts drilling and completion costs for monitoring wells

.

Exhibit 3

- 6 Cost items for reservoirs providing storage potential resource at 25 Gt

Source: NETL



### 3.3 Combining Transpor t and Storage Costs

Exhibit 3

- 7 reports the base case storage cost results from the FE/NETL CO 2 Saline Storage Cost Model base

- cost case for the 25 G t of cumulative storage resource potential and transport cost for the exam ple plant parameters

. The cost from the FE/NETL CO 2 Transport Cost Model of transporting CO 2 100 km is also provided in Exhibit 3

- 7

. The resulting CO 2 T&S values (rounded to the nearest whole dollar) to be used in NETL systems studies are shown in the far right column.

Exhibit 3

- 7 Total transport and base case storage (T&S) costs for use in NETL system studies

Plant Location Basin Transport (2011$ /tonne ) Base Case

Storage (2011$ /tonne ) Total T&S

(2011$ /tonne ) T&S Value for

System Studies (2011$ /tonne )

Midwest Illinois

2.24 8.69 10.93 11

Texas East Texas 8.83 11.07 11

North Dakota Williston 13.95 16.19 16

Montana Powder River 21.81 24.05 24National Energy Technology Laboratory Office of Program Performance and Benefits

29 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014



## 4 Revision Control

Exhibit 4

- 1 Revision table

Revision Number Revision Date Description of Change Comments

1 September 30 , 201 3 Updated cost estimates

2 February 12

, 2014 Document edited and formattedNational Energy Technology Laboratory Office of Program Performance and Benefits

30 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014



## 5 References

1 National Energy Technology Laboratory (NETL). (2013 ). FE/NETL CO 2 Transport Cost Model: Description and User Guide . In preparation.

2 National Energy Technology Laboratory (NETL). (2013). FE/NETL CO 2 Saline Storage Cost Model User Guide . In preparation.

3 Energy Information Administration. (2013). Table 18 AEO2013 Energy Related Carbon Dioxide Emissions by Sector and Source United States Reference C ase

. Retrieved on January 24, 2014, from http://www.eia.gov/oiaf/aeo/tablebrowser/#release=AEO2013&subject=0

- AEO2013&table=17

- AEO2013®ion=1

- 0&cases=ref2013

- d102312a

. 4 N ational Energy Technology Laboratory (NETL). (2010). Quality Guidelines for Energy System Studies: Esti mating Carbon Dioxide Transport and Storage Costs . DOE/NETL

2010/1447, Pittsburgh, PA.

5 Oil & Gas Journal. Annual Pipeline Economics Report s for the years 1991

- 2003

. Houston, Texas : PennWell Corporation, 2004

6 Parker, N. (2004). Using Natural Gas Tra nsmission Pipeline Costs to Estimate Hydrogen Pipeline Costs. UCD

- ITS

- RR

- 04

- 35, Institute of Transportation Studies, University of California at Davis.

7 McCoy, S., & Rubin, E. (2008). An Engineering

- economic Model of Pipeline Transport of CO 2 with Applic ation to Carbon Capture and Storage . International Journal of Greenhouse Gas Control, 2, 219

- 229.

8 Rui, Z., Metz, P., Reynolds, D., Chen, G., & Zhou, X. (2011). Regression Models Estimate Pipeline Construction Costs . Oil and Gas Journal, 109 (27).

9 ICF International. (2009). Developing a Pipeline Infrastructure for CO 2 Capture and Storage: Issues and Challenges . Prepared for the INGAA Foundation, Inc., report number F

- 2009

- 01, February. Retrieved on January 24, 2014, from http://www.ingaa.org/Foundation/Foundation

- Reports/Studies/7626/8230.aspx

. 10 McCollum, D. & Ogden, J. (2006). Techno

- Economic Models for Carbon Dioxide Compression, Transport, and Storage & Correlations for Estimating Carbon Dioxide Density and Viscosity . UCD

- ITS

- RR

- 06

- 14, Institute of Transportation Studies, University of California at Davis.

11 Heddle, G., Herzog, H., & Klett, M. (2003). The Economics of CO 2 Storage . LFEE 2003

- 003 RP, Labor atory for Energy and the Environment, Massachusetts Institute of Technology.

12 Energy Information Administration (EIA). (2013). Table 5.3. Average Retail Price of Electricity to Ultimate Customers: Total by End

- Use Sector, 2003

- June 2013 (Cents per Kilo watthour) . Retrieved January 24, 2014 , from http://www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=epmt_5_ 3

.National Energy Technology Laboratory Office of Program Performance and Benefits

31 Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for Energy System Studies M ay 2014

13 National Energy Technology Laboratory (NETL). (2 011). Recommended Project Finance Structures for the Economic Analysis of Fossil

- Based Energy Projects . DOE/NETL

2011/1489, Pittsburgh, PA.

14 National Energy Technology Laboratory (NETL). (2011). Quality Guidelines for Energy System Studies: Cost Estimation Methodology for NETL Assessments of Power Plant Performance. DOE/NETL

- 2011/1455, Pittsburgh, PA.

15 Jeffrey Lane. (2009). Operating Experience with CO 2 Pipelines. Proceedings of the EPRI Coal F leet for Tomorrow: General Technical Meting, Houston, Tx, April 21

- 23, 2009.

16 Harto, C. (2013). Life Cycle Water Consumption for Carbon Capture and Storage

. Carbon Storage R&D Project Review Meeting, Pittsburgh, Pa. August 20

- 22, 23013.

17 Buscheck, T.A. , Y. Sun, M. Chen, Y. Hao, T.J. Wolery, S.J. Friedmann, R.D. Aimes. (2012). Active CO 2 Reservoir management for CO 2 Capture, Utilization, and Storage: An Approach to Improve CO 2 Storage Capacity and to Reduce Risk. Carbon Management Technology Conference, Orlando, FL. February 7

- 9, 2012. CTMC 151746.

18 International Energy Agency (IEA). (2009) Development of Storage Coefficients for CO 2 Storage in Deep Saline Formation

. IEA Greenhouse Gas R&D Programme (IEA GHG). 2009/13, October 2009.

19 Brennan, S.T., R.C. Furruss, 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/