Categorical Exclusion B5.13 Supporting Information for DOE Notice of Proposed Rulemaking Page 1

Experience from Geologic CO2 Storage Field Projects

Supported by DOE’s Sequestration Program

Background: The U.S. DOE’s Sequestration Program began with a small appropriation 

of $1M in 1997 and has grown to be the largest most comprehensive CCS R&D program 

in the world. The U.S. DOE’s sequestration program has supported a number of projects 

implementing CO2 injection in the United States and other countries including, Canada, 

Algeria, Norway, Australia, and Germany. The program has also been supporting a 

number of complementary R&D projects investigating the science of storage, simulation, 

risk assessment, and monitoring the fate of the injected CO2 in the subsurface. 

The program supports a number of field activities in the United States which would be 

considered small scale <1,000,000 tons of CO2 injected during the life of the projects

(typically 1-4 years). Environmental Assessments have been prepared one of the first 

small scale injection projects and large scale injection projects injecting more than 

1,000,000 tons of CO2. Most of the small scale projects underwent NEPA review and 

were granted categorical exclusions (CX). All of these projects were required to receive 

and operate their facilities according to the U.S. EPA’s Underground Injection Control 

(UIC) permit requirements to protect underground sources of drinking water (USDW). 

In addition, several of the projects located on state lands in the western United States 

received a CX only after satisfying the state agencies’ requirements to perform historical 

studies or biological impact assessments before being granted approval to perform 

surface operations.

Much of the information on these other projects is located in the 2010 Sequestration 

Project Portfolio. Additional scientific reports from the projects are available through the 

OSTI website.

Frio Brine Field Test:

The Frio Brine Sequestration Project was the first field project in the United States to 

inject CO2 into a saline formation for the sole purpose of CO2 storage. The project

injected approximately 5,000 tonnes of CO2 over two separate time periods (~2 weeks 

each) into the deep saline Frio formation in Texas. Crosswell seismic and tracers with 

U-tube fluid sampling were the primary methods used to measure, monitor, and validate 

the research team’s predictions of the fate of the injected CO2. The results of this project 

also showed that the CO2 would remain in the target formation and would be contained 

by the cap rock. The project was permitted under the Underground Injection Control 

(UIC) Program, with a Class I non-hazardous injection well permit. An Environmental 

Assessment was prepared and FONSI issued for this project prior to field operations. 

Additional information on the Frio project is available at:

http://www.netl.doe.gov/publications/others/nepa/ea.html
Categorical Exclusion B5.13 Supporting Information for DOE Notice of Proposed Rulemaking Page 2

Small Scale Field Tests - Regional Carbon Sequestration Partnerships Phase II:

The U.S. DOE has been supporting the implementation of 20 small scale projects 

(<700,000 tones) through the Regional Carbon Sequestration Partnerships (RCSP) 

Initiative. These projects began in 2005 and are focused on understanding the science 

behind CCS in different regions of the country, geologic settings (injection zones, 

caprocks, fluids, and diagenetic processes), and determining the fate of the injected CO2

in the subsurface. The projects include storage in (tons injected at each site):

• 5 unmineable coal seams (from 100 to 18,000 tons)

• 8 depleted oil fields (from 40 to 637,000 tons), and

• 7 saline formations (from 55 to 60,000 tons).

DOE’s involvement in each of these projects depends on the extent of existing CO2

injection operations at the sites. DOE was providing the various projects with support for 

well field development, drilling operations, workover of existing wells, simulation 

modeling, injection operations, monitoring of injected CO2, injection operations, and 

closure of the sites. At some of the oil field enhanced recovery sites, the DOE was only 

providing support for measurement and monitoring efforts. The projects deployed a 

portfolio of technologies to measure, monitor and verify the fate of the CO2 in these 

formations. In all cases, the CO2 remained in the subsurface with no measureable 

impacts to the surface water or underground sources of groundwater. Limited 

disturbance at the surface is necessary to drill new wells, build short spur pipelines, and 

conduct seismic and other monitoring surveys.

Fifteen (15) of the small scale projects have completed their injection operations in the 

past four years, two are currently injecting, and one is planning to begin injection 

operations in November 2010. Similar to the Frio Brine project, these tests have 

deployed a number of measurement tools, simulation packages, and monitoring protocols 

to validate that CO2 remains in the formations developed for storage. A summary of the 

partnerships’ best practices with Monitoring, Verification and Accounting (MVA) is 

available at: DOE MVA Best Practices Manual

A summary of the Phase II projects and their accomplishments is provided in 

Attachment 1 (PhaseIIProjects.xls). Project details for each site are also located in 

2010 Sequestration Project Portfolio and through OSTI website.

The partnerships are required to present to DOE the results of their injection projects at 

an annual review meeting. Each project is required to develop a summary of project 

activities and to present project findings during the meeting. From these reviews, it is 

evident that the projects have been successful in being able to validate that the CO2 is 

safely injected and stored in these deep geologic formations. Presentations and factsheets 

from each review can be viewed by clicking on each of the following years: 2006, 2007, 

2008, 2009.
Categorical Exclusion B5.13 Supporting Information for DOE Notice of Proposed Rulemaking Page 3

Large-Scale Field Tests - Regional Carbon Sequestration Partnerships Phase III:

Nine large-scale (>1,000,000 tones) CO2 injection projects through the Regional Carbon 

Sequestration Partnerships are in various stages of development and environmental 

review. Eight projects are injecting CO2 in deep saline formations and one will be 

conducting extensive MVA activities at a depleted oil field to determine the fate of the 

injected CO2. Field activities for these projects are very similar to the small-scale field 

projects, but at a larger scale. Two of the large-scale projects have completed 

Environmental Assessments, which resulted in FONSIs, and one of these projects has 

currently injected more than 1 million tones of CO2 in a saline formation. A summary of 

the Phase III projects and their accomplishments is provided in Attachment 2

(PhaseIIIProjects.xls). Project details for each site are also located in the 2010 

Sequestration Project Portfolio and at the 2009 RCSP review meeting proceedings.

International Field Tests:

DOE also supports several activities through National Laboratories and other research 

institutions that are providing support to monitoring and simulation activities for several 

international carbon sequestration projects. These projects are all considered near 

commercial-scale integrated CCS Operations, which are injecting at least 1MMT of CO2

each year for either enhanced oil recovery or storage in saline formations. The Sleipner 

and Weyburn projects have both been operating for more than 10 years without incident. 

Over 30 million tons of CO2 have been stored at these projects sites combined. Our 

collaborative efforts with these and other international projects (e.g., Snohvit, In-Salah, 

and Otway) have provided decades of cumulative operational experience to show that 

CCS is a safe and effective technology to reduce CO2 emissions to the atmosphere.
Test 

Number RP Test Name Project Goals Vendors/Utilities/Other Formation Type Test Site Source of CO2 Geologic Province Geologic Setting

Amt Scheduled for 

Injection 

metric tonnes 

(short tons)

Amt Injection 

metric tonnes 

(short tons)

Injection 

Scheduled 

Begin 

(Month/Yr)

Injection 

Completed 

(Month/Yr)

1 Big Sky Basalt and Mafic Rock Field Validation Test

▪ Assess basalt formation and adjacent formation response to injection▪ Validate CO2 dispersion, dissolution, and trapping in basalt formations

▪ Verify mineralization reactions with post- injection core sampling

▪ Pacific Northwest National Lab▪ Idaho State University▪ Idaho National Lab▪ Boise White Paper, L.L.C.▪ Shell Oil Company▪ Port of Walla Walla

▪ Portland General Electric

Saline (basalt/mafic) Walulla Township, WA Commercial Source Columbia River Basalt Group Grande Ronde Basalt Formation 1,000 (1,100 tons) 0 (2010 Injection) 2010 - Q2 2010 - Q3 

2 MRCSP Appalachian Basin Geologic Test

▪ Feasibility/safety of saline formation storage

▪ Characterization of regional saline storage opportunities▪ Information gained rock properties and formation behavior in region▪ Establish familiarity with CO2 injection operations at active power plants 

▪ Ohio Geological Survey▪ Ohio Dept. of Natural Resources Saline Shadyside, OH Commercial Source Appalachian Basin Oriskany, Salina, and Clinton Sandstone 1,000 (1,100 tons) <50 (55 tons) 2008 - Q3 2008 - Q4 

3 MRCSP Cincinnati Arch Geologic Test

▪ Inject at bottom of Mt. Simon Formation and track CO2 migration upwards

▪ Feasibility/safety of saline formation storage▪ Regional characterization of saline storage opportunities▪ Demonstration of CO2 capture from coal-fired power plant source

▪ Kentucky Geologic Survey▪ Indana Geologic Survey▪ Duke Energy

Saline Rabbit Hash, KY Commercial Source Cincinati Arch Mt. Simon Sandstone 1,000 (1,100 tons) 1,000 (1,100 tons) 2009 - Q3 2009 - Q3 

4 MRCSP Michigan Basin Geologic Test

▪ Feasibility/safety of saline formation storage▪ Regional characterization of saline storage opportunities▪ Assess feasibility of possible CO2 CCS from nearby gas processing plants

▪ DTE Energy▪ Core Energy, L.L.C.▪ Western Michigan Unviersity

Saline Ostego County, MI DTE Turtle Lake Gas Plant Michigan Basin Bass Islands Dolomite 10,000-30,000 (11,023 - 33,069 tons) 60,000 (66,000 tons) 2008 - Q3 2009 - Q3 

5 MGSC CO2 Single Well Injection/Soak/Produce Test

▪ Inject CO2 into single producing well [huff]

▪ Allow CO2 to dissipate/dissolve [soak]

▪ Measure the response [puff]▪ Feasibility/safety of EOR sequestration in mature oil fields

▪ Air Liquide▪ Petco Petroleum Corporation Oil Bearing - Heavy Fayette County, IL Commercial Source-Air Liquide Loudon Oil Field Mississippi Weiler Sandstone 272 (300 tons) 39 (43 tons) 2007 - Q2 2007 - Q2 

7 MGSC Enhanced Coalbed Methane

▪ Feasibility/safety of coal seam sequestration▪ Changes in CO2 injectivity of Illinois Coal

▪ Measurement of methane displaced by CO2 

▪ Measure amount of CO2 retained in the coal seam

▪ Gallagher Drilling Company▪ Air Liquide Coal Seam Wabash County, IL Commercial Source-Air Liquide Illinois Basin Pennsylvania Carbondale Formation 680 (750 tons) 91 (100 tons) 2008 - Q3 2008 - Q4 

8 MGSC Oil-bearing Well Conversion

▪ Employ advanced MVA protocol to understand sequestration potential▪ Understand EOR/Sequestration options in a complex reservoir

▪ Gallagher Drilling Company▪ Air Liquide Oil Bearing Hopkins County, KY Commercial Source-Air Liquide Sugar Creek Oil Field Jackson Sandstone 7,272 (8,000 tons) 5,850 (6,448 tons) injecting 2009 - Q3 2010 - Q2 

9 MGSC Oil-bearing Pattern Flood

▪ Employ advanced MVA protocol to understand sequestration potential▪ Understand EOR/Sequestration options in a complex reservoir

▪ Gallagher Drilling Company▪ Air Liquide Oil Bearing Posey County, IN Commercial Source-Air Liquide Mumford Hills Oil Field - Bald Unit Clore Formation 5,454 - 7,272 (6,000 - 8,000 tons) 2,850 (3,590 tons) injecting 2009 - Q4 2010 - Q3 

10 PCOR Williston Basin EOR Field Test

▪ Evaluate use of CO2 for EOR in a deep (>8000 ft) carbonate reservoir

▪ Test geophysical technologies to monitor CO2 in deep carbonate reservoir

▪ Determine the potential for deep carbonate rocks to permanently sequester CO2

▪ ND Oil & Gas Research Council▪ ND Dept. of Mineral Resources▪ Eagle Operating, Inc.▪ Schlumberger▪ Praxair

Oil Bearing Western North Dakota Commercial Williston Basin Mississippian Mission Canyon Formation 4536 (5,000 tons) 400 (440 tons) 2009 - Q3 2009 - Q3 

11 PCOR Zama Field Validation Test

▪ Predict, monitor, and evaluate fate of the injected acid gas

▪ Determine effect of H2S on CO2 sequestration

▪ Best practices manual for the use of H2S with EOR and CO2 sequestration 

▪ Apache Canada Ltd.▪ Alberta Energy and Utilities Board▪ Natural Resources Canada Oil Bearing Zama City, Alberta Canada Zama Gas Plant Zama Oil Field Middle Devonian Keg River Formation

208,600 metric tonnes 

CO2 72,560 metric tonnes 

H2S

25,400 

(28,000 tons) 2006 - Q4 2009 - Q4 

12 PCOR Lignite in North Dakota Field Validation Test

▪ Gauge ECBM production from coal resulting from CO2 injection

▪ Employ MVA technologies for ECBM and CO2 storage in coal

▪ Determine the potential for lignite coal to permanently sequester CO2

▪ Flatland Exploration Company▪ ND State Land Department▪ Eagle Operating, Inc.▪ Schlumberger▪ Praxair

Coal Seam Burke County, ND Commercial Source - Praxair Williston Basin Harmon Coal Fort Union Formation <907 (1,000 tons) 80 (90 tons) 2009 - Q1 2009 - Q2 

13 SECARB Saline Reservoir Test ▪ Test deep saline reservoirs near large, coal-fired power plants 

▪ Build geologic and reservoir maps and conduct reservoir simulations▪ Estimate injectivity, storage capacity, and long-term fate of injected CO2

▪ Advanced Resources International ▪ EPRI▪ Southern Company ▪ Denbury ▪ Mississippi Power ▪ Praxair ▪ Schlumberger ▪ Halliburton

Saline Jackson County, MS Jackson Dome Mississippi Gulf Coast Lower Tuscaloosa Massive Sand Unit 2,720 (3,000 tons) 2,740 (3,020 tons) 2008 - Q4 2008 - Q4 

14 SECARB Black Warrior Basin Project

▪ Feasibility/safety of CBM reservoir storage▪ Determine optimal injectivity for ECBM recovery

▪ Denbury Resources, Inc.▪ Electric Power Research Institute▪ El Paso Exploration and Production▪ Southern Company▪ Southern Natural Gas▪ Vigrinia Tech

Coal Seam Tuscaloosa County, AL Jackson Dome Black Warrior Basin Multiple Coal Zones of Pottsville Formation 907 (1,000 tons) 360 (397 tons) 2010 - Q2 2010 - Q2 

15 SECARB Central Appalachian Basin Test

▪ Identify areas for CO2 coal seam sequestration

▪ Expand ECBM production in Central Appalachian Basin

▪ Marshall Miller & Associates▪ Advanced Resources International▪ Geologic Survey of Alabama▪ Kentucky Geological Survey▪ Eastern Coal Council

▪ Vigrinia Tech

Coal Seam Russell County, VA Commercial Source Central Appalachian Basin Pocahontas and Lee Formations 907 (1,000 tons) 907 (1,000 tons) 2009 - Q1 2009 - Q1 

16 SECARB Gulf Coast Stacked Storage Project

▪ Conduct a stacked storage project: EOR and underlying brine formation▪ Employ advanced MVA protocol to understand sequestration potential

▪ Schlumberger Carbon Services▪ Advanced Resources International▪ Praxair▪ Denbury Resources▪ Etergy▪ Marathon Oil Corporation▪ Pinnacle Technologies▪ Southern Company

Oil Bearing Cranfield, MS Jackson Dome Cranfield Oilfield Tuscaloosa Formation 500,000 (551,150 tons) 637,000 ton at end of April 2009 2008 - Q3 2009 - Q2 

17 SWP Aneth Oil Field Test - I

▪ Conduct large-scale EOR project with CO2 sequestration

▪ Employ advanced MVA protocol and reservoir simulation

▪ Resolute Natural Resources Co.▪ Navajo Nation Oil and Gas Co. Oil Bearing San Juan County, UT McElmo Dome Paradox Basin Deep Creek and Ismay Zones 408,240 - 680,400 (450,000 - 750,000 tons) 630,000 (694,449 tons) 2007 - Q3 2010 - Q1 

18 SWP SACROC EOR Project

▪ Post-audit modeling of Kinder Morgan injections▪ Test efficacy of CO2 subsurface monitoring technologies

▪ Track fate of injected CO2 at SACROC

▪ CO2 storage history matched with large-scale MVA at SACROC

▪ Results will aid plans for new CO2 EOR injections in nearby Claytonville Field 

▪ KinderMorgan CO2 Company Oil Bearing Snyder, TX McElmo Dome Permian Basin Horseshoe Atoll and Pennsylvanian Reef/Bank Play 86,000 (88,184 tons) 86,000 (88,184 tons) 2008 - Q3 2009 - Q4 

19 SWP San Juan Basin ECBM Test

▪ Evaluate ECBM production efficiency with concomitant CO2 storage efficacy

▪ Identify regulatory gaps for ECBM and CO2 sequestration▪ Develop detailed risk assessment and mitigation plans

▪ ConocoPhillips▪ KinderMorgan CO2 Company Coal Seam San Juan Basin McElmo Dome San Juan Basin Upper Cretaceous Fruitland Formation 68,040 (75,000 tons) 16,700 (18,400 tons) 2008 - Q3 2009 - Q3 
Test 

Number RP Test Name Vendors/Utilities/Other Formation Type Test Site Source of CO2 Geologic Province Geologic Setting

Amt Scheduled fo

Injection 

metric tonnes 

(short tons)

1 Big Sky Large-Volume CO2 Injection on Kevin Dome

▪ Montana State University▪ University of Wyoming▪ Schlumberger▪ Los Alamos National Laboratory▪ Lawrence Livermore National Lab

Saline Northern Montana Kevin Dome - Natural Source Madison Formation Kevin Dome 2,000,000 (2,200,000 tons) 

2 MRCSP Large Scale Geologic Injection Test ▪ Core Energy Saline Otsego County, Michigan Natural Gas Processing Facility Michigan Basin St. Peter Sandstone Bass Islands Dolomite 1,000,000 (1,100,000 tons) 

3 MGSC Demonstrating CO2 Storage in the Mount Simon Sandstone of the Illinois Basin ▪ Archer Daniels Midland Saline Decatur, IL ADM's Ethanol Production Facility Illinois Basin Mt. Simon Sandstone 1,000,000 (1,100,000 tons) 

4 PCOR Fort Nelson Demonstration - British Columbia, Canada

▪ British Columbia Ministry of Energy, Mines, and Petroleum Resources▪ Natural Resources Canada▪ Spectra Energy

Saline British Columbia, Canada

Spectra Energy's Fort Nelson 

Natural Gas Processing 

Facility

Alberta Basin Elk Point Formation 6,500,000 (7,150,000 tons) 

5 PCOR Bell Creek Demonstration - southeastern Montana

▪ Denbury Resources Oil Bearing Bell Creek Oil Field Natural Gas Processing Facility Powder River Basin - Montana Cretaceous Muddy Formation 1,500,000 (1,650,000 tons) 

6 SECARB Early Test

▪ Advanced Resources International ▪ EPRI▪ Denbury Resources, Inc.▪ Southern Company ▪ Gulf Coast Carbon Center (BEG) ▪ Mississippi State University ▪ Lawrence Berkeley National Lab ▪ Schlumberger Carbon Services ▪ Lawrence Livermore National Lab▪ Southern Company▪ QEA▪ University of Mississippi▪ U.S. Geological Survey

Saline Cranfield, MS Jackson Dome (natural source) Lower Tuscaloosa Cranfield Unit 1,500,000 (1,650,000 tons)

7 SECARB Anthropogenic Test

▪ Advanced Resources International ▪ EPRI▪ Denbury Resources, Inc.▪ Southern Company ▪ Gulf Coast Carbon Center (BEG) ▪ Mississippi State University ▪ Lawrence Berkeley National Lab 

▪ Schlumberger Carbon Services ▪ Lawrence Livermore National Lab▪ Southern Company▪ QEA▪ University of Mississippi▪ U.S. Geological Survey

Saline Citronelle, AL 

Southern Company's Plant 

Barry Coal-Fired Power Plant 

(Bucks, AL)

Paluxy Formation Citronelle Field 300,000 (330,000 tons) 

8 SWP Demonstration of Storage in Deep Jurassic/Triassic Formations of the Western U.S. 

▪ Thunderbird Energy Corp.▪ Pacificorp▪ Rocky Mountain Power▪ Southern California Edison ▪ Schlumberger ▪ Baker Hughes

Saline Aquifer

Gordon Creek Field; Edge of 

Uinta Basin; < 20 miles West 

of Price, UT; <100 miles 

southeast of Salt Lake City, 

UT

Natural CO2 Colorado Plateau Intermontane Sedimentary Basin 2,600,000 (2,900,000 tons) 

9 WESTCARB California Development Phase Test

▪ California Energy Commission▪ C6 Resources, LLC▪ Shell Martinez Refinery ▪ Schlumberger Carbon Services ▪ Clean Energy Systems Inc

Saline California

Northern California or Central 

Valley, CA (Currently 

downselecting site)

TBD TBD TBD