DOE/EA-1482 

ENVIRONMENTAL ASSESSMENT

PILOT EXPERIMENT FOR GEOLOGICAL SEQUESTRATION OF 

CARBON DIOXIDE IN SALINE AQUIFER BRINE FORMATIONS

FRIO FORMATION, LIBERTY COUNTY, TEXAS

OCTOBER 2003

U.S. DEPARTMENT OF ENERGY

NATIONAL ENERGY TECHNOLOGY LABORATORY
ii
iii

National Environmental Policy Act (NEPA) Compliance

Cover Sheet

Proposed Action:

The U.S. Department of Energy (DOE) proposes to provide funds for a field test of the geological 

sequestration of carbon dioxide (CO2). The Bureau of Economic Geology (BEG) at The University of 

Texas at Austin, under contract with DOE, has studied the potential for sequestration of CO2 in geologic 

formations of the United States as part of a broader series of DOE-sponsored research projects to 

investigate potentially practical, affordable methods to control the buildup of CO2, a greenhouse gas, in 

the atmosphere. As an outcome of the work by BEG, brine formations of the upper Texas Gulf coast 

have been identified as possessing excellent potential for geological sequestration. While CO2 injection 

is commonly used to enhance the production from some oil fields, to research technology for geological 

sequestration of CO2, BEG has proposed a controlled experiment to inject a limited quantity of CO2 into a 

brine formation of the South Liberty oil field in Liberty County, Texas, and to closely monitor and model 

the subsurface disposition of the injected CO2. If approved, DOE would provide approximately $2.5 

million for the pilot experiment.

Type of Statement: Environmental Assessment (EA)

Lead Agency: U.S. Department of Energy; National Energy Technology Laboratory (NETL)

DOE Contacts: Project Information: NEPA Information:

 Charles Byrer Lloyd Lorenzi

 U.S. Department of Energy U.S. Department of Energy

 P.O. Box 880 P.O. Box 10940

 Morgantown, WV Pittsburgh, PA 15236-0940

 304-285-xxxx; 304-285-4403 (fax) 412-386-6159; 412-386-4604 (fax)

 charles.byrer@netl.doe.gov (e-mail) lorenzi@netl.doe.gov (e-mail)

Abstract: 

DOE prepared this EA to analyze the potential environmental effects that would result from the 

proposed action. The test proposed by BEG would build on historical data covering subsurface 

geotechnical characteristics for an operating oil field and would use existing infrastructure of the 

South Liberty oil field in Liberty County, Texas, to support the experiment. At an existing well site, 

BEG would inject CO2 over a time period of less than 60 days into a brine-bearing sandstone of the 

Frio Formation in the Gulf Coast of Texas. Two existing wells would be upgraded to monitor the 

behavior of the injected CO2 for up to 1 year, and the resulting data would be used to enhance models 

for predicting the behavior of CO2 injected into brine formations. The field test would have the 

following objectives: (1) demonstrate that CO2 can be injected into a brine formation without adverse 

health, safety, or environmental effects; (2) determine the subsurface location and distribution of the 

injected CO2; (3) demonstrate an understanding of computer models for predicting CO2 behavior; 

(4) demonstrate methods for monitoring of CO2 injected into brine formations; and (5) establish a 

knowledge base for use in considering geological sequestration opportunities.

No substantive adverse environmental concerns were identified in analyzing the effects of the field test.

Public Comments: 

DOE encourages public participation in the NEPA process. A draft of this EA was distributed to 

cognizant Federal and state agencies and made available to the public for review and comment. By 

the closing date of September 12, 2003, established for receipt of comments, neither adverse 

comments nor suggestions for consideration in the environmental analysis were received.
iv
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CONTENTS

CONTENTS.............................................................................................................................v 

Figures............................................................................................................................... vii

Tables ............................................................................................................................... vii

1.0 INTRODUCTION.............................................................................................1-1 

2.0 PURPOSE AND NEED FOR THE PROPOSED ACTION.....................2-1 

2.1 Background ..........................................................................................................2-1 

2.2 DOE’s Purpose and Need ....................................................................................2-2 

2.3 BEG Proposal.......................................................................................................2-4 

2.5 DOE’s Decision...................................................................................................2-5 

3.0 ALTERNATIVES, INCLUDING THE PROPOSED ACTION ..............3-1 

3.1 Overview..............................................................................................................3-1 

3.2 Description of the Proposed Action.....................................................................3-1 

3.2.1 Project Plan......................................................................................................3-2 

3.2.2 Pre-injection Activities ....................................................................................3-3 

3.2.3 Injection Activities...........................................................................................3-8 

3.2.4 Post-injection Activities.................................................................................3-10 

3.3 Range of Reasonable Alternatives.....................................................................3-11 

3.4 The No Action Alternative.................................................................................3-12 

4.0 AFFECTED ENVIRONMENT AND THE ENVIRONMENTAL 

CONSEQUENCES OF THE PROPOSED ACTION.................................4-1 

4.1 Site Description....................................................................................................4-1 

4.1.1 Field History ....................................................................................................4-1 

4.1.2 Surface Geology and Soils...............................................................................4-2 

4.1.3 Subsurface Geology.........................................................................................4-5 

4.1.4 Groundwater.....................................................................................................4-8 

4.1.5 Climate ...........................................................................................................4-10 

4.1.6 Access ............................................................................................................4-11 

4.1.7 Historical and Archaeological Resources......................................................4-11 

4.1.8 Endangered Species .......................................................................................4-11 

4.1.9 Flood Potential...............................................................................................4-12 

4.1.10 Wetlands.........................................................................................................4-12 

4.2 Environmental Consequences............................................................................4-17 

4.2.1 Surface Impacts..............................................................................................4-17 

4.2.2 Subsurface Impacts........................................................................................4-18 

4.2.3 Potential Leakage Impacts.............................................................................4-19 

5.0 REGULATORY COMPLIANCE..................................................................5-1 

5.1 State Permitting Requirements............................................................................5-1 
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6.0 CUMULATIVE AND INDIRECT EFFECTS AND LONG-TERM 

ENVIRONMENTAL CONSEQUENCES ...................................................6-1 

6.1 Direct Cumulative Effects....................................................................................6-1 

6.2 Indirect and Indirect-Cumulative Effects.............................................................6-2 

6.2.1 Fate of Injected CO2.........................................................................................6-2 

6.2.2 Post-project Well Disposition..........................................................................6-7 

6.2.3 Increase in Sequestration Activities in the Pilot Area .....................................6-7 

6.2.4 Increase in Domestic Sequestration Activities................................................6-7 

7.0 IRREVERSIBLE AND IRRETRIEVABLE COMMITMENTS OF 

RESOURCES....................................................................................................7-1 

8.0 ENVIRONMENTAL CONSEQUENCES OF THE NO ACTION 

ALTERNATIVE...............................................................................................8-1 

9.0 SIMILAR ACTIONS AND ACTIONS BEING CONSIDERED UNDER 

OTHER NEPA REVIEWS ..........................................................................9-1 

10.0 RELATIONSHIP OF THE PROPOSED ACTION TO APPLICABLE 

LAND USE PLANS AND POLICIES ......................................................10-1 

11.0 CONSULTATION AND PUBLIC PARTICIPATION............................11-1 

11.1 Consultation.......................................................................................................11-1 

11.2 Public Participation............................................................................................11-1 

12.0 REFERENCES................................................................................................12-1 

APPENDIX A: AGENCY CONSULTATION CORRESPONDENCE

APPENDIX B: MATERIAL SAFETY DATA SHEETS
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Figures

 1. Map of the southeast Texas coastal region............................................................. 3-5 

 2. Aerial photograph of the area surrounding the project site..................................... 3-6 

 3. Photographs of the proposed project site ................................................................ 3-8 

 4. Map-view results of Tough2 numerical simulation.............................................. 3-10 

 5. Map of oil and gas wells in the South Liberty field and surrounding area ............. 4-2 

 6. Topographic map of the experiment site................................................................. 4-3 

 7. Distribution of soil units at the experiment site ...................................................... 4-4 

 8. Type log from SGH 3.............................................................................................. 4-6 

 9. Structure-contour map of the southwest flank of the South Liberty salt dome ...... 4-7 

 10. Detailed type log from SGH 3 ................................................................................ 4-8 

 11. Cross plot of residual gas saturation and porosity.................................................. 4-9 

 12. Dip-oriented regional cross section through experiment site ............................... 4-10 

 13. Distribution of mapped wetland units at the experiment site ............................... 4-14 

 14. Representative photographs of upland vegetation assemblages from the pilot

 experiment site and surroundings ......................................................................... 4-15 

 15. Representative photographs of lowland vegetation assemblages near the pilot

 experiment site ..................................................................................................... 4-16 

 16. Numerical simulation model construction parameters for the “C” sand ................ 6-3 

 17. CO2 saturation distributions around the injection well from 0.2 to 100 years

 after starting injection ............................................................................................. 6-4 

 18. CO2 saturation distributions around the injection well for low-residual

 gas saturation case from 0.2 to 100 years after starting injection........................... 6-5 

 19. CO2 saturation distributions in northeast-southwest (dip) section cross-sectional

 view of injection zone for low-residual gas saturation case at 100 years

 after starting injection............................................................................................. 6-5 

Tables

 1. Project team for the proposed pilot experiment...................................................... 2-4 

 2. Milestone description and work breakdown structure ............................................ 3-2 

 3. Work sites and activities......................................................................................... 3-3 

 4. Comparison of alternatives ................................................................................... 3-12 

 5. Tracer materials to be used and their concentrations............................................ 4-18 

 6. Agency and organization contacts ........................................................................ 11-1 
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List of Abbreviations and Acronyms

AOR Area-of-Review

bbl barrel(s)

BEG Bureau of Economic Geology at The University of Texas at Austin

cc cubic centimeter(s)

cf cubic feet

CFR Code of Federal Regulations

cm centimeter(s)

cm3 cubic centimeters

CO2 carbon dioxide

DOE U.S. Department of Energy

EA Environmental Assessment

EOR Enhanced Oil Recovery

EPA U.S. Environmental Protection Agency

EPCRA Emergency Planning and Community Right to Know Act

ft feet

ft3 cubic feet

g gram(s)

gal gallon(s)

hr hour

in inch

kg kilogram

km kilometer

km2 square kilometers

L liter(s)

lb pound(s)

LBNL Lawrence Berkeley National Laboratory

LLNL Lawrence Livermore National Laboratory

m meter(s)

M thousand

m

3

 cubic meters

md millidarcies

mg milligram

mg/L milligrams per liter

mi mile(s)

mi2 square miles

MIT Mechanical Integrity Test

mL milliliter(s)

MM million

MSDS Material Safety Data Sheet

NEPA National Environmental Policy Act

NETL National Energy Technology Laboratory
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ng nanogram(s)

ORNL Oak Ridge National Laboratory

ppb parts per billion

ppm parts per million

psi pounds per square inch

psig pounds per square inch (gauge)

RRC Texas Railroad Commission

s second(s)

SARA Superfund Amendments and Reauthorization Act

SGH Sun-Gulf-Humble

TARC Texas American Resources Company

TARL Texas Archeological Research Laboratory

TCEQ Texas Commission on Environmental Quality

TDS total dissolved solids

UIC Underground Injection Control

VSP Vertical Seismic Profile

yd3 cubic yards

yr year(s)

°C degrees Celsius

°F degrees Fahrenheit

μ micro

μg microgram

μg/mL microgram per milliliter
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PILOT EXPERIMENT FOR GEOLOGIC SEQUESTRATION OF CO2 IN SALINE AQUIFER BRINE FORMATIONS

DOE/EA-1482 INTRODUCTION

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1.0 INTRODUCTION

This Environmental Assessment (EA) provides the results of an evaluation of the 

potential environmental consequences of a proposed pilot experiment for injection of carbon 

dioxide (CO2) into a subsurface brine-bearing formation, a process known as geologic 

sequestration. The U.S. Department of Energy (DOE) is proposing to provide approximately 

$2.5 million to examine the viability of geologic sequestration of CO2 and to determine if 

geologic sequestration can be modeled, measured, and monitored.

Increasing concentrations of CO2 in the atmosphere are believed by many scientists to 

have potential for creating global change toward a warmer climate. These changes may have 

negative impacts on human systems as well as ecosystems. DOE is supporting research activities 

to develop a knowledge base and understanding of candidate options for mitigating global climate 

change.

Geologic sequestration is a potentially viable method for stabilizing the amount of CO2 

released to the atmosphere from combustion of fossil fuel. In this method, the CO2 from a 

stationary industrial source of CO2, would be captured, compressed, and injected into the 

subsurface. The injection site must possess geologic properties that would assure that the CO2 

remains trapped in the subsurface and isolated from the atmosphere. The natural capacity of the 

subsurface to trap and retain buoyant fluids such as oil and natural gas is well known. 

Technologies for injection of fluids, particularly CO2, into the subsurface to enhance recovery of 

oil and for injection of wastes for disposal are both widely applied.

This project was proposed by the Bureau of Economic Geology (BEG) at The University 

of Texas at Austin under a competitive solicitation (DE-RA26-98FT35008) issued by DOE to 

solicit research proposals on potentially practical, affordable methods to prevent carbon dioxide 

and other greenhouse gases from building up in the atmosphere. The proposal from BEG was 

selected for funding support. Initial work by BEG focused on technical studie s to identify 

optimal environmental conditions for geologic sequestration of CO2 in brine formations of the 

United States. The upper Texas Gulf coast was identified by BEG as a region with excellent 

potential for geologic sequestration.

This proposed pilot experiment would involve the controlled injection of CO2 over a 

maximum of 60 days into the sandstone brine formation of an oil field and close monitoring of 

the performance of the subsurface in holding CO2. To minimize risks, the experiment would be 

designed to inject the minimum volume of CO2 that would be required for effective subsurface 

measurement using a variety of techniques. Monitoring would be performed for up to 1 year. 

The results obtained from monitoring a small volume of injected CO2 would provide reliable 

information for determining the feasibility of safely and effectively injecting CO2 into a geologic 
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environment and the potential for subsurface retention of the CO2 over a long time frame. 

Monitoring and modeling tools developed by researchers from Lawrence Berkeley National 

Laboratory (LBNL), Oak Ridge National Laboratory (ORNL), Lawrence Livermore National 

Laboratory (LLNL), and National Energy Technology Laboratory (NETL) would be applied.

The purpose of the EA is to determine if the proposed action could potentially cause 

significant impacts to the environment. If potentially significant environmental impacts are 

identified, and if they cannot be reduced to insignificance or avoided, then a more detailed 

Environmental Impact Statement would be prepared. If no significant environmental impacts are 

identified, a Finding of No Significant Impact would be prepared and made available to the 

public, along with the EA itself, before the proposed action proceeds.

This study was prepared in accordance with the National Environmental Policy Act 

(NEPA) of 1969 (42 United States Code 4321 et seq.), the Council on Environmental Quality’s 

Regulations [Title 40, Code of Federal Regulations (CFR), Parts 1500-1508], and Department of 

Energy’s NEPA Implementing Procedures (Title 10, CFR, Part 1021).
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2.0 PURPOSE AND NEED FOR THE PROPOSED ACTION

2.1 Background

The concentration of carbon dioxide (CO2) in the atmosphere has increased by 17.4% 

over the past 60 years (Keeling and Whorf, 2002). The Intergovernmental Panel on Climate 

Change (2001) has concluded that these changes result principally from accumulation of 

anthropogenic CO2 emitted to the atmosphere from changing land use patterns and combustion of 

fossil fuels, such as coal, oil, and natural gas, to produce energy. Predictions of global energy use 

suggest that anthropogenic carbon emissions will continue to increase, resulting in continued 

increase in atmospheric concentrations of CO2 unless major changes are made in the way that 

energy is produced and used (U.S. Department of Energy, 1999, p 1-1).

Uncertainty exists regarding predictions of the effects from the change in CO2

concentration in the atmosphere. However, significant risk exists that continued increase in 

atmospheric concentrations could force changes in global climate, which may have a variety of 

serious consequences (see U.S. Climate Change Science Program / U.S. Global Change 

Research [2003] for regional summaries or the Intergovernmental Panel on Climate Change).

DOE has prepared several documents that consider U.S. energy policy and the options 

that can be evaluated in response to concerns over the impact of anthropogenic CO2 releases on 

climate change. The National Energy Policy Development Group (2001) considered a broad 

spectrum of energy issues, and in Chapter 3 (Protecting America’s Environment) states that 

“Industry and the federal government are researching various new technologies that will reduce 

greenhouse gas emissions or sequester those emissions, in geologic formations, oceans, and 

elsewhere.” The U.S. Department of Energy (1999) document “Carbon Sequestration” provides a 

detailed assessment of the role of carbon sequestration in reducing anthropogenic CO2 emissions. 

Three categories of technologically driven solutions are proposed: (1) energy conservation and 

efficiency; (2) substituting lower carbon or carbon-free energy sources for current sources - for 

example, switching to renewable energy sources, nuclear power, and low-carbon fuels; and 

(3) carbon sequestration, by which CO2 is removed from combustion emissions and stored 

directly underground or in the deep ocean or indirectly by enhanced uptake by soils, vegetation, 

and the oceans.

On June 11, 2001, the President committed the Federal Government to pursue a broad 

range of strategies to reduce greenhouse gas emissions through three initiatives: (1) a Climate 

Change Research Initiative to guide establishment of climate policy based on science; (2) a 

National Climate Change Technology Initiative to develop new technologies that address climate 

change issues; and (3) increase cooperation with other countries to engage others on climate 
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change and clean technologies. In February 2002, the President complemented these initiatives 

by establishing a goal for the U.S. to reduce greenhouse gas emissions (as a percent of gross 

domestic product) by 18% by the year 2012. This Presidential Climate Change Initiative is 

directed at using new technologies and economic incentives to slow the growth of CO2 emissions.

2.2 DOE’s Purpose and Need

In partial fulfillment of the President’s Initiatives, DOE’s need is to establish a scientific 

understanding of carbon sequestration and to develop to the point of deployment those options 

that could potentially ensure environmentally acceptable sequestration to reduce anthropogenic 

CO2 emissions and/or atmospheric concentrations. 

The purpose for the proposed action is to support rigorous testing of a potential 

technological solution for carbon sequestration within a geologic formation. This testing would 

provide key information needed to increase scientific understanding of carbon sequestration and 

to assure that this option, if successful, would be capable of providing an effective option for 

reducing atmospheric concentrations of CO2.

One option that has the potential to achieve DOE’s goal is sequestration of CO2 in unique 

geologic formations, such as oil and gas fields, coal beds, and porous brine-bearing formations. 

The history of reservoir characterization by U.S. industries has produced sufficient knowledge 

and understanding of the subsurface in containing gases and fluids to help make geologic 

sequestration an attractive option. The ability of the subsurface to store oil and gas for 

geologically significant periods is well known, lending credibility to the concept that injected 

CO2, which would be buoyant like oil and natural gas in most geological environments, could be 

sequestered for long periods (Hitchon, 1996). Technologies for introducing gas and fluids to the 

subsurface are also mature. For decades oil producers have injected CO2 into oil reservoirs to act 

as a solvent for enhanced oil recovery (EOR), a process known as CO2 EOR. In many parts of 

the U.S., surface water is protected from contamination by disposal of waste fluids into the 

subsurface using a permitted process, Underground Injection Control (UIC), which assures 

protection of the public by disposal of waste into deep subsurface formations that are below and 

hydrologically isolated from potable water. CO2 is already being sequestered geologically 

offshore in the North Sea, where approximately one million tonnes annually of CO2 are stripped 

from natural gas and reinjected into the subsurface to prevent release to the atmosphere 

(U.S. Department of Energy, 1999).

Although the processes of geologic sequestration are relatively well known, additional 

research is needed to fill gaps in the scientific understanding of carbon sequestration and to 

develop stakeholder experience with the process. Extensive laboratory and modeling studies 

have been completed to assess how CO2 geologic sequestration would work in the subsurface (for 

example, Hitchon, 1996; U.S. Department of Energy, 1999). Comparing predictions from bench 
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scale tests and numerical models with field results is necessary to validate the models and 

demonstrate that scientific understanding is correct.

The extensive experience developed in the U.S. with CO2 injection for EOR is inadequate 

to validate the models because the fate of the injected CO2 is not quantified. CO2 injected for 

EOR can be sorbed in the oil, held by capillary forces in pore space, trapped by buoyancy forces 

in stratigraphic or structural compartments, dissolved in pore water, produced and reused, or 

leaked from the injection zone. The absence of accounting for CO2 fate in the complex EOR 

system leaves a gap in scientific understanding, although leakage of CO2 from the injection zone 

is assumed to be small relative to the other fates.

Another significant experience gap between EOR and the ability to validate models is 

related to the type of reservoir host rock. Hovorka and others (2000) inventoried 21 geologic 

formations in the onshore U.S. that could potentially serve as host injection intervals for CO2 and 

identified areas where these formations are near numerous and large CO2 sources. Geologic 

formations that could most easily receive and retain large volumes of CO2 are thick, porous, and 

permeable sandstones. Such sandstones underlie CO2 sources on much of the Gulf of Mexico 

coast. Unfortunately, most experience with EOR is in lower permeability carbonate rocks in the 

interior basins distant from most anthropogenic sources.

In the North Sea, Statoil (a Norwegian oil company) is injecting CO2 into a thick, porous, 

and permeable sandstone. However, reservoir performance and CO2 fate cannot be closely 

observed because injection occurs at an offshore site where monitoring wells are not an economic 

possibility.

A third significant experience gap relates to the process of permitting an injection well 

for CO2 sequestration. Commercial and industrial disposal wells are commonly located at sites 

vertically or laterally isolated from hydrocarbon reservoirs and aquifers. All wells in the zone of 

influence are required to be properly completed or plugged to protect against leakage. In 

contrast, CO2 injection wells for EOR are located within producing oilfields and are intended to 

increase production at as many wells as possible. Regulators currently lack experience with 

combined objective projects for CO2 beneficial use plus CO2 disposal. Before CO2 sequestration 

could be implemented, regulators would require development of methods needed to assure 

stakeholders and the public that CO2 injected for dual purposes would be retained in the 

subsurface and that the beneficial uses of enhanced production could be safely achieved.

To address these experience gaps, a field experiment in a high-porosity, highpermeability formation similar to those that might be viable for consideration as sinks for 

sequestering CO2 would be necessary. The proposed pilot experiment would be performed 

onshore to facilitate adequate monitoring to determine whether the CO2 remains within the 

injection zone and to maximize scientific understanding. The proposed pilot experiment would 

be conducted at a small scale to (1) pioneer the permitting process, (2) minimize health, safety, 

and environmental risks, (3) minimize costs, and (4) obtain results quickly so that experience 
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would be available for use by others in considering future activities to meet U.S. objectives. The 

proposed location would provide subsurface conditions that are as simple as possible, thus 

maximizing the chances of matching numerical model results with field observations.

2.3 BEG Proposal

The Bureau of Economic Geology (BEG) at The University of Texas at Austin proposes 

to lead a team in conducting a well-monitored, small-scale, short-duration CO2 injection into 

brine-bearing sandstone of the Frio Formation in the Gulf Coast of Texas. The site is within the 

South Liberty oilfield, where extensive geotechnical data are currently available for use in 

modeling and predicting the expected behavior of injected CO2. Use of existing infrastructure 

and location within an operating field would minimize both cost and environmental impact. This 

site was proposed by BEG following an assessment of optimal geological environments for 

geologic sequestration in brine formations in the onshore U.S. (Hovorka and others, 2000). The 

Frio Formation along the upper Texas Gulf Coast was identified as a candidate area for 

sequestration due to (a) the large concentration of a variety of CO2 sources and (b) the presence 

of a thick, widespread, and high-permeability formation ideal for sequestration. The BEG team 

(Table 1) identified the following objectives for the injection experiment:

• Demonstrate that CO2 can be injected into a saline formation without adverse health, 

safety, or environmental effects;

• Determine the subsurface location and distribution of the CO2 cloud;

• Demonstrate understanding of conceptual models;

• Demonstrate field-test monitoring methods; and

• Establish a knowledge base for use in considering CO2 geological sequestration 

opportunities.

Table 1. Project team for the proposed pilot experiment

Participant Responsibility Objective(s)

Bureau of Economic Geology 

(BEG), The University of Texas 

at Austin

Prime contractor. Coordination 

and reporting of all activities. 

Subsurface characterization.

Improve understanding of 

subsurface behavior and fate of 

injected CO2.

Texas American Resources 

Company (TARC)

Operator of existing well and 

lessee of subsurface minerals.

Facilitate demonstration of 

additional uses for mature oil and 

gas fields.

Lawrence Berkeley National 

Laboratory (LBNL)

Model-predicted subsurface 

results. Seismic monitoring. 

Pressure transient testing. Noble 

gas tracer modeling and 

monitoring. 

Optimize flow-modeling software 

for geologic sequestration. 

Demonstrate use of seismic tests 

to monitor CO2 plume.

Lawrence Livermore National 

Laboratory (LLNL)

Tracer geochemical modeling. Demonstrate use of tracers in 

monitoring of CO2 migration.
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Participant Responsibility Objective(s)

Oak Ridge National Laboratory 

(ORNL)

Tracer tests. Stable isotope and 

perfluorocarbon geochemistry.

Demonstrate use of introduced 

tracers and naturally occurring 

isotopes in mo nitoring CO2

migration.

National Energy Technology 

Laboratory (NETL)

Perfluorocarbon tracer 

geochemistry, and surface 

monitoring. 

Demonstrate use of tracers in 

monitoring CO2 migration. 

Alberta Research Council) Geochemical sampling plan. Advise on basis of past 

subsurface experience.

Sandia Technologies, LLC Field-services engineering, 

safety, oversight, and 

coordination.

Apply experience in deep 

injection of wastes to CO2

sequestration.

W.A. Flanders, Transpetco 

Engineering of the Southwest, Inc.

Injection: engineering and 

oversight.

Apply CO2 EOR engineering to 

sequestration projects. 

BP Industry advisor. Supplier of CO2

from Texas City refinery through 

Praxair.

Advise on the basis of 

experience. Explore sequestration 

options. 

Schlumberger Industry sponsor. Support sequestration projects 

and apply completion and logging 

techniques to sequestration.

U.S. Department of Energy, 

National Energy Technology 

Laboratory (NETL)

Project sponsor. Demonstrate technologies for 

safe and effective geologic 

sequestration.

The BEG project team is diverse, consisting of staff at a State geologic survey, four 

national laboratories, a nonprofit Canadian research company, a small independent oil and gas 

producer, a major oil and gas producer and refiner, a large oilfield service company, and experts 

in the fields of deep subsurface waste disposal and EOR operation. Project staff would include 

geologists, geophysicists, and engineers experienced in detailed subsurface characterization and 

numerical description as well as in waste-isolation projects; experts in geochemical tracer testing; 

specialists in numerical modeling of CO2 subsurface behavior and flow simulation; engineers and 

petrophysicists experienced in well drilling, completion, logging, and log interpretation; and 

geophysicists experienced in seismic and other geophysical methods of detection of CO2.

2.5 DOE’s Decision

The decision to be made by DOE is whether to commit funds totaling approximately 

$2.5 million to conduct the “Pilot Experiment for Geologic al Sequestration of Carbon Dioxide in 

Saline Aquifer Brine Formations” in Liberty County, Texas.
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2.6 Scoping

Internal scoping discussions were conducted to identify significant issues associated with 

the proposed project. Reviews of the proposed technology, experimental requirements, the scope 

of injection requirements and monitoring, the proposed project site and the environmental setting 

for the project, environmental information from BEG, and other information available on the 

project were evaluated.

2.7 Scope of the Environmental Assessment

The scope of the Environmental Assessment was determined after reviewing the 

proposed technology, the extent of testing that would be performed, the changes that would be 

required, the proposed setting for the project, and available environmental information related to 

the proposed action. Based on internal scoping studies, the key issues for the proposed action 

were determined to be associated with surface land use, groundwater issues, health and safety of 

employees and the public, and transportation impacts.
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3.0 ALTERNATIVES, INCLUDING THE PROPOSED ACTION

3.1 Overview

Several alternatives are available for satisfying DOE’s need for developing information 

on potential technological solutions for carbon sequestration. The proposed pilot experiment 

would be conducted in an oilfield, where drilling and other subsurface activities familiar to the 

surrounding communities have occurred for many decades, where well-work-over and 

maintenance companies are headquartered, where a mature oilfield setting provides abundant 

subsurface data, and where many well bores are idle and, thus, potentially available for injection 

or monitoring activities. The short duration (less than 1 year) proposed for field activities, to 

minimize costs and impacts to the environment, would be appropriate for providing the scientific 

data needed to assess the feasibility of geologic sequestration. 

Alternatives to the proposed pilot experiment include: (1) conducting the experiment at 

another field site in the same sedimentary basin, (2) conducting the experiment in another 

geographic area (different sedimentary basin), and (3) conducting the experiment in an oil- or 

gas-bearing interval. All are reasonable alternatives, but for various reasons are less attractive 

from an operational, scientific, or long-term need perspective. 

3.2 Description of the Proposed Action

The proposed action is for the U.S. Department of Energy (DOE) to provide funding to 

the team led by the Bureau of Economic Geology (BEG) at The University of Texas at Austin to 

prepare the site, modify two existing wells, drill a new injection well, conduct pre-injection 

baseline monitoring and testing, inject CO2 over a period of less than 60 days, conduct 

monitoring activities during and after the injection, monitor until subsurface conditions begin to 

stabilize (expected within nine months of injection), and close and restore the site. The overall 

work activities would require about 2 years to complete.

The pilot experiment would result in injecting 3,750 tons (2 million m3 or 71.2 million ft3) 

of CO2 into a brine-bearing Frio sandstone at a depth of about 1,500 m (5,000 ft). The site is within 

an existing oilfield on the flank of a salt dome approximately 56 km (35 mi) northeast of Houston, 

Texas. Other nearby land uses include timber production and sparse rural residences, although no 

dwellings lie within a 0.5-km (0.3-mi) radius of the site. Numerous existing geophysical well logs 

and a 3-D seismic survey are available for characterizing the injection interval. A numerical 

simulation model created by LBNL would be used to predict subsurface results for planning 

purposes. Baseline surface and subsurface seismic and geochemical surveys would be completed 
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before injection; repeat surveys would be completed during and after injection to monitor CO2

distribution, and the integrity of structural and stratigraphic seals of the injection interval would be 

assessed.

The proposed activities would be consistent with current land use. No endangered 

species occur in the study area, and no known archeological sites are located within the study 

area. Direct impacts would include (1) clearing up to 2 hectares (5 acres) of upland habitat for 

minor expansion of the well pad and for providing narrow pathways to allow truck-mounted 

drilling-rig access for seismic studies and drilling 3 shallow groundwater monitoring wells; 

(2) transporting 75 truckloads of CO2 over 79.2 km (49.1 mi) of public roads through 

commercial, industrial, and rural areas; and (3) transporting 30 truckloads of produced brine and 

60 truckloads of drilling mud less than 32 km (<20 mi) over mostly rural roads to permitted 

disposal wells. Modeling studies suggest that the injected CO2 would be likely to remain within 

the injection zone and migrate less than 200 m (<656 ft) from the injection well. Based on 

modeling studies, subsurface pressure increases under maximum injection rate scenarios would 

be expected to be 35% below fracture-pressure limitations and 22% below pressures that might 

affect nearby growth faults. Monitoring of formation pressure, temperature, and near-well-bore 

CO2 saturation would continue until changes become minimal, indicating significant stabilization 

of the subsurface physical environment, which would be anticipated to occur less than 1 year after 

the end of injection.

3.2.1 Project Plan

During most of the time associated with the proposed 2-year-project, from preparing 

environmental applications through final reporting, office activities involving geologic

interpretation, engineering design, procedure planning, post-experiment analysis, and publication 

and presentation of results would be performed. During about a 7-month period, field activities 

with potential for environmental and social impacts and low-impact monitoring activities would 

be conducted. Table 2 provides a milestone description, work breakdown structure, and 

anticipated timeline for the experiment. The timeline depends on State regulatory approval, 

CO2 availability, favorable weather, and drilling-rig availability. Initial site examination and 

conceptual planning began in 2002. Reviews by two State agencies, the Railroad Commission of 

Texas (RRC—petroleum resource protection) and the Texas Commission on Environmental 

Quality (TCEQ—groundwater protection and engineering review) would be performed in 2003, 

and field activities would begin upon completion of environmental planning and review 

requirements. Two existing wells would be modified for use as monitoring wells and a new 

injection well would be drilled in 2003. The injection event would occur in a window between 

February 2004 and April 2004, depending on seasonal availability of compressed food-grade CO2

and other logistical considerations. Post-injection tests, analyses, and synthesis of results would 

continue through October 2004. Documentation and presentation of project results would begin 
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in September 2004. The project would be completed by January 2005. Site closure and 

restoration could begin as early as May 2004 and be completed by January 2005.

Table 2. Milestone description and work breakdown structure

Description Initiation 

date*

Completion 

date*

Task 1 – Environmental Permitting

1. Prepare and submit UIC Class V application to TCEQ 2/2003 9/2003

2. Secure TCEQ review and approval 9/2003 10/2003

Task 2 – Pre-Field Mobilization Characterization

1. Characterize field site 3/2002 8/2002

2. Identify candidate geochemical sampling and tracer methods 6/2002 3/2003

3. Computer-simulate CO2 subsurface behavior 6/2002 3/2003

4. Identify geophysical monitoring requirements 6/2002 3/2003

5. Establish preliminary field procedures and engineering plans 6/2002 3/2003

6. Assess safety requirements and training needs 4/2003 5/2003

Task 3 – Pre-injection Field Activities

1. Prepare site 10/2003 11/2003

2. Prepare monitor wells 10/2003 11/2003

3. Drill and complete injection well 10/2003 11/2003

4. Conduct baseline geophysical survey, fluid sampling 11/2003 11/2003

5. Conduct pressure-transient test 11/2003 1/2004

Task 4 – CO2 Injection Experiment

1. Implement safety plan 11/2003 11/2003

2. Install CO2 storage and injection equipment 1/2004 2/2004

3. Inject CO2 2/2004 4/2004

4. Perform post-injection testing 5/2004 1/2005

5. Analyze and interpret results 5/2004 08/2004

6. Site closure and restoration 5/2004 1/2005

6. Synthesize observations and results 8/2004 10/2004

7. Project final reporting and technology transfer 9/2004 1/2005

* Tentative dates, based on start of field activities in October 2003,contingent upon completion of the 

NEPA review, State regulatory approval, CO2 availability, weather conditions, and rig availability.

3.2.2 Pre-injection Activities

Analysis of geologic and geophysical data acquired to characterize the site would be 

conducted at the Bureau of Economic Geology in Austin, Texas. Project activities (Table 3) 

would include literature review, computer workstation use, and limited transportation to and from 

offices of team members and the field site. Geochemical tracer design, geophysical monitoring 

design, simulation of CO2 subsurface behavior, and field planning/engineering design would 

require similar activities at Oak Ridge National Laboratory (ORNL) in Oak Ridge, Tennessee; 
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Lawrence Berkeley National Laboratory (LBNL) in Berkeley, California; Lawrence Livermore 

National Laboratory (LLNL) in Livermore, California; National Energy Technology Laboratory 

(NETL) in Pittsburgh, Pennsylvania and Morgantown West Virginia; Alberta Research Council 

in Calgary, Alberta, Canada; and Sandia Technologies, LLC, in Houston, Texas. Project 

planning, data collection, engineering design, and administrative support would occur in Texas 

American Resources Company’s offices in Austin and Houston, Texas. Log engineering design 

and data interpretation would occur in the Ridgefield, Connecticut, offices of Schlumberger-Doll 

Research. Field-support services (well logging) would originate from the Schlumberger Oilfield 

Services office in Liberty, Texas, approximately 11.25 km (7 mi) from the field site. BEG’s 

Houston Core Research Center (1611 West Little York Road, Houston, Texas) would serve as a 

nearby facility during field activities for office work and staging/handling of geochemical 

samples. BP project advisors would be located in Houston, Texas. Project oversight would be 

provided from DOE’s National Energy Technology Laboratory (NETL) offices in Pittsburgh, 

Pennsylvania, and Morgantown, West Virginia. 

Table 3. Work sites and activities

Location Team member Activity

Liberty County, Texas All Field activities

Austin, Texas Bureau of Economic Geology Office activities

Berkeley, California LBNL Office activities

Livermore, California LLNL Office activities

Oak Ridge, Tennessee ORNL Office and laboratory activities

Houston, Texas Sandia Technologies, LLC Office activities

Houston, Texas Bureau of Economic Geology;

Houston Core Research Center

Office and laboratory activities

Austin and Houston, Texas Texas American Resources Company Office activities

Calgary, Alberta, Canada Alberta Research Council Office activities

Ridgefield, Connecticut Schlumberger-Doll Research Office activities

Liberty, Texas Schlumberger Oilfield Services Office and laboratory activities

Houston, Texas BP Office activities

Pittsburgh, Pennsylvania

Morgantown, West Virginia

NETL Office and laboratory activities

Texas City, Texas BP, Praxair Refinery and gas processing

The proposed field site is located in Liberty County, Texas, about 56 km (35 mi) 

northeast of Houston (Figure 1), near the town of Dayton. The site lies on a 30 m × 30 m 

(100 ft × 100 ft) clearing within a low-relief upland area dominated by small deciduous trees and 

is 400 m (1,312 ft) west of wetlands of the Trinity River floodplain margin (Figures 2 and 3). 

The area has been an active oilfield from 1951 to present and is sparsely populated. Residential 

neighborhoods have been developed over the past 2 decades to the north, southwest, and south of 

the site (Figure 2), but no residences lie within 0.5 km (0.3 mi) of the site. Approximately 250 

land blocks within 2 km (3.2 mi) of the site are platted for residences. Intermittent logging has 
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occurred in the vicinity for decades; an idle lumber mill lies about 0.4 km (0.25 mi) north of the 

site. The area west of highway FM 1409 (Figure 2) is primarily agricultural. The project would 

impact less than 2 hectares (5 acres) within an oilfield where oil and gas activities have impacted 

6,980 hectares (17,280 acres). State and Federal records indicate no known archeological sites or 

endangered species at or near the site. Groundwater is within a few meters of the ground surface. 

Figure 1. Map of the southeast Texas coastal region (showing the location of the CO2 pilot project, 

including the transportation route).

Site preparation would include improving about 1 km (~0.6 mi) of unpaved lease road by 

adding road base and grading and incrementally expanding one well pad, which would require 

clearing of no more than 0.4 hectares (1 acre) of vegetation. Expansion of the well pad and 

associated loss of vegetation would be minimized by directionally drilling the injection well from 
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the margin of an existing pad, rather than clearing a new pad and building an access road within 

the vegetated upland.

Figure 2. Aerial photograph of the area surrounding the project site, showing major land features, 

roads, residential areas, the South Liberty oilfield outline, and the 402 m (0.25 mi) radius of the Area 

of Review. Aerial photo base modified from Texas Natural Resources Information System.

Soil gas, pore water, and shallow groundwater would be sampled and analyzed prior to 

CO2 injection to establish background CO2 concentrations. Because background values vary 

seasonally with changes in biologic activity, a sample grid would be established and re-sampled 

over several months before and after injection. These points would also be monitored throughout 

the injection and post-injection phases. Shallow auger holes would be used to sample soil gas. 

Three shallow water wells would be drilled to sample groundwater in accordance with TCEQ 

monitoring well protocols.

Two existing wells, Sun-Gulf-Humble #4 and #3 (SGH 4 and SGH 3; Figures 3 and 6) 

would be converted to monitoring wells, requiring mobilization of a truck-mounted work-over rig 

to the well pad along lease roads. SGH 4 would be the primary monitoring well; the new 

injection well would be drilled 30 m (100 ft) south of SGH 4. SGH 3 is 135 m (440 ft) southeast 

of SGH 4. Minor modifications would be made to this well to facilitate limited CO2 plume 

monitoring. Standard oilfield techniques would be implemented to determine casing condition, 

cement the well-bore annulus in the injection zone, and perforate that same zone to prepare for 

monitoring. These activities would occur at depth, within the saline aquifer, well below and 

isolated from potentially potable groundwater. 
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Standard oilfield techniques and equipment would be employed to drill and complete an 

injection well on the same pad as SGH 4 (Figure 3A). A shallow drilling-mud pit would be

constructed adjacent to the well pad and lined in accordance with TCEQ requirements to prevent 

subsurface infiltration. The drilling mud would be water based. The volume of well cuttings 

(natural earth materials extracted during well drilling) would be about 400 m3 (550 yd3). Cuttings 

would be buried on site as municipal solid waste in accordance with Texas Administrative Code 

Chapter 330. Drilling fluids, estimated to be less than 7,000 barrels, would be trucked to an 

RRC-authorized disposal well within 48 km (30 mi) of the project site. The new well would be 

cemented and perforated according to oil-industry standards. Minor amounts of excess 

nonhazardous material and debris would be removed from the site to a municipal landfill.

Newly established perforations in the injection well and monitor well would undergo 

Mechanical Integrity Tests (MIT) to verify casing-to-formation bond and ensure that injected 

materials escape from the intended zone through the well annulus. Part of the routine MIT 

involves injection into the perforated zone at 1,500 m (5,000 ft) depth of 20 cc of 131I solution 

containing a total of 20 millicuries of radiation. This isotope has an 8-day half-life. The wells 

would sit idle for at least 2 weeks before production or injection of fluids begins, thus preventing 

return of hazardous levels of radioactivity to the surface. Radioactivity of produced fluids would 

be tested to assure that exposure levels conform to acceptable levels in Article 213 of the DOE 

Radiological Control Manual.

A series of extraction and injection tests would be conducted to evaluate subsurface fluid 

characteristics and pressure response within the injection interval. Brine produced during each 

pumping test, equaling no more than 3,000 barrels (351 m3), would be sampled, temporarily 

stored on site, and then re-injected with a groundwater tracer into the original well in a 

subsequent injection test.

Two baseline geophysical surveys – a crosswell seismic survey and a 3-D vertical 

seismic profile (VSP) – would be conducted before injecting CO2. The crosswell survey would 

consist of a downhole seismic source (high-frequency oscillating) in the SGH 4 monitoring well 

and seismic detectors placed in the injection well. The 3-D VSP would employ a surface seismic 

source and the injection-well detectors. As many as sixty-six (66) 18-m-deep (60-ft) shot holes 

would be drilled along four lines passing through the injection well and extending up to 400 m 

(1,312 ft) from the well (see Section 4.2). A small jeep-mounted rig would be used to drill the 

shot holes near existing lease roads wherever possible, impacting less than 0.8 hectares 

(<2 acres). A maximum charge of 1.5 kg (3 lb) of biodegradable explosive (Dynoseis®, 

consisting of sodium perchlorate and diethylene glycol [MSDS in Appendix B]) would be used to 

produce the seismic energy for the survey. After detonation, shot holes would be filled with soil 

and the areas would be compacted.
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A

B

Figure 3. Photographs of the proposed project site. (A) View, looking north, of well pad where 

existing well SHG 4 is located. New well would be drilled on a southward extension of this pad. (B) 

View, looking northwest, of well pad where existing well SHG 3 is located—the two water-storage 

tanks were used when the well was a salt-water disposal well.

3.2.3 Injection Activities 

A maximum of 3,750 tons (71.2 MMcf) of CO2 would be injected intermittently into the 

subsurface over a maximum period of 60 days at rates not exceeding about 8.5 tons/hr 

(161 Mcf/hr). Downhole pressure increases would not exceed 116.4 bar (1,688 psi), which is 

established by TCEQ regulation and is about 7 bar (100 psi) below the calculated fracture 

pressure of the formation. TCEQ regulations also require that pressure increases within a 402-m 
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(one-quarter-mi) radius area of review (AOR) not exceed a calculated value of 11.4 bar (165 psi), 

assuming a hydraulic gradient of 0.098 bar/m (0.433 psi/ft). Flow simulations by LBNL using 

TOUGH2 (Pruess and others, 1999; Hovorka and others, 2001) and formation-specific 

petrophysical properties were used to calculate pressure response under proposed injection rates 

and durations. Figure 4 provides a map view of the modeled pressure increase for a conservative 

scenario that assumes CO2 injection of 5,000 tons, rather than the proposed 3,750 tons, over a 

shorter time period of 20 days. The northeast, northwest, and southeast model boundaries are 

faulted and considered no-flow boundaries. The southwest boundary is open (unfaulted) and 

allows pressure dissipation. Maximum pressure increase at the injection well would be 20.8 bar 

(304 psi), which is less than 20% of the regulated limit. Maximum pressure increase within the 

fault block at 402 m (0.25 mi) from the well would be less than 6 bar (<87 psi), about ha lf of the 

regulated limit. Subsequent models to be constructed before injection would be refined to include 

more detailed geologic information from an existing 3-D seismic volume, hydrologic tests of the 

injection formation, and information from core and log data in the new injection well. These 

model refinements, combined with pressure monitoring during injection, would ensure that the 

experiment would be performed within regulatory requirements.

CO2 for injection would be delivered to the site by commercial truck and temporarily 

stored in a 1,000-barrel pressure tank placed on a 6 × 24 m (20 ×80 ft) concrete pad. The CO2, at 

15 bar (220 psig) and –19°C (–3°F), would be compressed prior to injection by a pad- or skidmounted pump that would occupy an area of less than 3 × 6 m (10 ×20 ft). Both the tank and 

pump would be removed following injection.

The injection of CO2 would be suspended several times during the experiment to allow 

for downhole logging, sampling, and geophysical measurements. During these suspensions, 

produced formation brine would be injected to prevent return of CO2 gases to the surface through 

the well bore. Standard oilfield procedures would be used to log and sample the well. To 

monitor CO2 plume behavior, 3-D VSP surveys would be repeated during injection.

The focal point of the proposed activity would be monitoring of the injected CO2 to 

understand subsurface flow paths. Formation temperature and pressure would be recorded nearly 

constantly to determine formation response. Additionally, tracers would be injected with the CO2

in minor amounts, and both the injection and monitoring wells would be sampled to identify the 

tracer and CO2 concentrations. Geochemical tracer techniques would include (1) isotopic profiles 

of injected CO2, (2) introduced noble gases, and (3) introduced perfluorocarbons. A maximum of 

3,000 barrels of fluid in one monitoring well (SGH 4) would be produced by nitrogen lift during 

the injection period to monitor tracer and CO2 concentration. These fluids would not be reinjected into the formation because of their potential to interfere with long-term monitoring. 

These fluids would be trucked to a TCEQ-permitted UIC Class 1 non-hazardous well within 32 

km (20 mi) of the site for disposal into a subsurface formation.
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Figure 4. Map-view results of Tough2 numerical simulation, showing incremental pressure increases 

in the injection interval after 20 days of injecting CO2 at a rate of 250 tons per day. Note that the total 

injection quantity of CO2 modeled is 5,000 tons rather than the proposed amount of 3,750 tons, in 

order to investigate upper limits of pressure increase, which was calculated to be 20.8 bars (304 psi).

3.2.4 Post-injection Activities

Following CO2 injection, downhole fluid samples would be taken from the injection zone 

and the immediately overlying zone in both the injection well and primary monitoring well 

(SGH 4). Purging of the well bore to obtain fresh samples from the formation could yield up to 

172 barrels of formation brine, which would be transported to a TCEQ-permitted disposal well. 

The existing completions would remain open in the injection and monitoring wells for a 

period anticipated to be less than 1 year to allow extended monitoring. Monitoring would include 

pressure and temperature measurements and other activities that could include well logging, 

crosswell or surface seismic surveys, or geochemical sampling and analyses. Monitoring of CO2

in the wells would decrease in frequency as changes in pressures and concentrations become 

minimal, indicating significant stabilization of the subsurface physical environment. This 
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stabilization would be expected to occur less than 1 year after the end of injection. Shallowgroundwater dissolved gas and soil-gas concentrations would be monitored throughout this time 

at sample points established during pre-injection field activities. Impacts of surface seismic 

surveys and geochemical sampling (waste formation brine) would be treated as previously 

described in Section 3.2.2.

Following the completion of downhole logging and sampling, the injection and 

monitoring zone perforations would be plugged by cement following standard oil-industry 

practices. The wells would either be plugged and abandoned according to RRC rules or 

converted to a use approved by the appropriate agency.

Other post-injection activities would include additional office work to analyze and 

interpret results at the various team members’ sites (Table 3). Results and interpretations would 

be synthesized by the Bureau of Economic Geology, and a final project report would be prepared. 

Technology transfer to interested parties would continue sporadically until project completion in 

January 2005.

3.3 Range of Reasonable Alternatives

Reasonable alternatives to the proposed action, including the no-action alternative, are 

listed in Table 4, along with comments on each. Action alternatives range from siting the 

experiment in an adjacent area to conducting the experiment in a hydrocarbon-bearing formation.

Table 4. Comparison of alternatives

Alternative Comments

Alternate location in 

same basin

Need oilfield setting. Would need to find other operators to host the experiment 

and supply data.

Injection in a different 

basin

Other large basins having significant CO2 sources would require comparable 

subsurface data and service-industry infrastructure.

Injection in an oil or gas 

reservoir

Presence of hydrocarbons in even minor concentrations would interfere with 

critical fluid flow characteristics and rock-water interactions, which would 

require investigation.

No action Development of information on sequestration alternatives would suffer 

increased risks or substantial delays, thus reducing options available for 

consideration by the U.S. for climate change mitigation.

Considering the Frio Formation in the upper Texas Gulf Coast as an advantageous 

setting, one action alternative would be to conduct the experiment in another area of dense 

subsurface control. The small fault blocks associated with salt domes in this basin would offer 

significant benefits by providing a more closed compartment. The small volumes of material 

injected into a more closed compartment would have a larger pressure response because the 

pressure would not be as rapidly dispersed as in unnecessarily large pore volume. Similarly, 

flanks of salt domes commonly have steeper dips that would accentuate the response of the 

buoyant injected CO2 plume to the effects of gravity, which would be a key parameter for 

evaluation as part of any experiment to examine geological sequestration. The effects of 
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conducting the pilot experiment in a comparable alternate location within the same geologic basin 

would not be substantially different from the effects of the proposed action. 

Many other basins across the U.S. contain formations suited to CO2 sequestration 

(Hovorka and others, 2000). Few of these basins, however, are characterized by a high 

concentration of CO2 sources and an abundance of available subsurface data in the form of well 

logs and 3-D seismic data. Fewer still have a robust well-servicing industry, which would reduce 

experiment cost through a competitive business climate and relatively low mobilization costs.

Another alternative would be to conduct the experiment in the same basin as that 

proposed but use existing infrastructure and completed wells in an oil or gas reservoir. This 

option would reduce well-construction costs and potentially add value by enhancing hydrocarbon 

production as a result of the injection. The daily activity in such settings, however, would 

substantially increase the difficulty of detailed scientific monitoring. Background 

electromagnetic and seismic noise would reduce the achievable resolution of geophysical surveys. 

Additionally, the pilot experiment would require periods in which wells would need to be idle, 

which would result in loss of revenue for producers. Most important, the presence of 

hydrocarbons would substantially affect CO2 sorption, pressure response, and flow processes that 

are the experimental objectives of the project. The presence of a native gas phase in the 

formation would significantly increase the compressibility of the formation fluid, making 

response to injection difficult to predict and interpret. The presence of oil in the formation fluid 

would complicate multiphase flow effects.

3.4 The No Action Alternative

No action, meaning that DOE funds to support the proposed experiment would not be 

provided, regardless of setting or project scope, would delay by several years the development of 

information needed to assess technological options for carbon sequestration. From a national 

perspective, therefore, the no action alternative would adversely affect the ability to provide 

options to help meet the President’s objective for greenhouse gas emissions reductions by 2012. 

The increased understanding of subsurface behavior of CO2 would not be gained, and an example 

of successful and safe sequestration, on any scale, could not be offered for consideration by the 

public, policy makers, and regulators during any future consideration of CO2 sequestration 

proposals. In the absence of an adequate base of knowledge, the complexities of future projects 

could result in long delays for public and regulatory approval, thereby jeopardizing goals for 

action on climate change issues. Delays of 3 years, for example, in development of technological 

options for CO2 sequestration would result in increased CO2 emissions of approximately 5% and 

increased atmospheric concentrations of CO2 before any stabilization effort would be started. 
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4.0 AFFECTED ENVIRONMENT AND THE ENVIRONMENTAL 

CONSEQUENCES OF THE PROPOSED ACTION

4.1 Site Description

The pilot experiment is proposed for the South Liberty field in southern Liberty County, 

Texas, a largely rural county with an estimated population of 72,620 in 2001 (U.S. Census 

Bureau, 2001). The site would be located on an upland area adjacent to the Trinity River valley 

on the coastal-plain physiographic province. The site and the sparsely populated, immediately 

surrounding area are within an oilfield that has been active since 1951. Low-density residential 

neighborhoods have developed over the past 2 decades to the north, southwest, and south of the 

site (Figure 2). No residences lie within 0.5 km (0.3 mi) of the site. Approximately 250 land 

blocks within 2 km (1.25 mi) of the site are platted for residences. Timber has been harvested 

sporadically in the vicinity for many decades; an idle lumber mill is located about 0.4 km 

(0.25 mi) north of the site. The area west of highway FM 1409 (Figure 2) has historically been 

used for agriculture.

The project site would be about 25 km (~15.5 mi) upstream of Trinity Bay, about 65 km 

(40.3 mi) inland from the Gulf of Mexico, about 60 km (37 mi) northeast of downtown Houston 

(Figure 1), and nearest to the small communities of Dayton (7.5 km, or 4.5 mi, to the northwest) 

and Liberty (9 km, or 5.5 mi, to the northeast). Liberty County is on the northeast margin of the 

heavily populated Houston metropolitan area. Harris County, home of most of Houston’s 

residents, had an estimated 2001 population of 3,460,589; populations estimated for adjacent 

counties within the regional impact area are 255,865 for Galveston County and 26,859 for 

Chambers County (U.S. Census Bureau, 2001).

4.1.1 Field History

The South Liberty field was discovered in 1925. The first commercial production was 

from the Oligocene Frio Formation shallow on the east flank of a piercement salt dome, and a 

significant drilling boom followed (Halbouty, 1962). Attention was drawn to the area in 1901 by 

surface shows of sulfur, oil, and gas, and by the discovery of Spindletop Dome. The cumulative 

production from the South Liberty field in 1925 was 4,416,000 barrels of oil. Production steadily 

declined through the mid 1940’s, but discoveries of oil in the deeper Eocene Yegua and Cockfield 

Formations on all flanks of the dome in 1948 and 1949 reinvigorated the field (Halbouty, 1962). 

A large number of the wells in the area of the proposed pilot experiment were drilled in 1950 and 

1951 as a new drilling boom spread. Annual production peaked at 5,271,847 barrels in 1958 and 
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has been gradually declining since then. Annual production for 2001 was 253,000 barrels of oil 

and 437 million ft3 of gas (Railroad Commission of Texas, 2002).

No production has been found over the top of the dome (caprock area), where salt rises to 

within 84 m (275 ft) of the surface (Halbouty, 1962). According to a Texas Railroad Commission 

database, the South Liberty field contains 654 wells (Figure 5). About 55 leases are currently 

producing (with multiple oil wells but only one gas well possible per lease), with a large number 

of wells, perhaps several hundred, standing idle. From January 1, 1998, through January 1, 2003, 

only 11 wells were permitted within the field, all on the east and north flanks of the dome, with at 

least 5 of those permits granted in 2002. Exploration for deeper oil or gas objectives continues, 

as evidenced by the increase in well permits in 2002 and the recent completion of a large 

3-dimensional seismic reflection survey in the area.

Figure 5. Map of oil and gas wells in the South Liberty field and surrounding area. Modified from 

Railroad Commission of Texas (2002).

4.1.2 Surface Geology and Soils

The proposed new CO2 injection well and existing monitoring wells would be located on 

the Beaumont Formation (Aronow and Barnes, 1982), a Pleistocene fluvial-deltaic depositional 

system composed of fine sandy channels and interchannel muds. Fisher and others (1972) 

mapped the site as a heavily to sparsely tree-covered meander-belt sand. The pilot experiment 

site would be about 300 m (~1,000 ft) west of the erosional bluff marking the geomorphic 
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boundary between the Pleistocene upland at surface elevations of about 20 m (~66 ft) above sea 

level and the floodplain of the Trinity River at elevations of 2 to 6 m (6.6 to 20 ft) above sea level 

(Figure 6). The main channel of the Trinity River passes about 2,700 m (~1.7 mi) east of the site. 

Depositional units within the floodplain, mapped as Quaternary alluvium by Aronow and Barnes 

(1982), include tree-covered meander-belt sand, overbank flood-basin mud, and mud-filled 

abandoned channels (Fisher and others, 1972).

Figure 6. Topographic map of the experiment site, showing bluff to east of the site and a small lake 

(stippled area) within the Trinity River valley. Note also locations of existing wells to be converted 

to monitor wells, SGH 4 and 3, and location of the new CO2 injection well, about 30 m (100 ft) south 

of SGH 4. Gray shading designates vegetated areas. The contour interval is 5 ft. Modified from U.S. 

Geological Survey Moss Bluff 7.5-minute quadrangle.
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The Natural Resources Conservation Service has mapped three soil units at and near the 

site (U.S. Department of Agriculture, 1996), as shown in Figure 7. On the upland is the AldineAris complex, a thick soil with texture ranging from very fine sandy loam to clay (Aldine) and 

sandy clay loam to clay (Aris). Geologic maps indicate that the dominant soil texture at the site is 

sandy loam rather than clay. This soil unit is considered to be very slowly permeable and has a 

high water-holding capacity. The depth to water, where present, is less than 1 m (<3 ft). Organic 

matter content is 2 percent or less.

Figure 7. Distribution of soil units at the experiment site. Soil units are those of the Natural 

Resources Conservation Service (U.S. Department of Agriculture, 1996). W = water; Ae = AldineAris complex; Kf = Kaman clay; and WvD = Woodville fine sandy loam. Aerial photo base modified 

from Texas Natural Resources Information System.

Soils of the Woodville fine sandy loam are mapped for the bluff separating the upland 

site for the pilot experiment and the Trinity River floodplain. This soil, with a surface slope of 

5 to 8 percent, has a thin sandy surface layer overlying clay substrata. Permeability is classified 
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as very slow; water-holding capacity is high. The depth to water, where present, is 2 m (6.6 ft) or 

more.

The Trinity River floodplain adjacent to the proposed experiment site is classified as 

either Kaman clay or open water. The Kaman clay is a very deep, wet, and poorly drained unit 

that is frequently flooded. This soil is classified as clay to silty clay with an organic content of 

3 percent or less and with a high water-holding capacity.

4.1.3 Subsurface Geology

The proposed injection would occur in brine-bearing sandstones near the top of the 

approximately 600-m-thick (~2,000-ft) Oligocene Frio Formation at about 1,500 m (~5,000 ft) 

below ground surface, on the southwest flank of the South Liberty salt dome. Hydrocarbon 

production in this part of the field comes from sandstones of the Eocene-age Yegua/Cockfield 

and Cook Mountain Formations between 2,500 and 2,750 m (8,200 and 9,000 ft) below ground 

level (Figure 8). The interval between the production (Yegua/Cockfield) and injection (Frio) 

formations is a shale -dominated section that includes the Eocene Jackson and Oligocene 

Vicksburg formations (Figure 8). The Frio is overlain by the 75-m-thick (250-ft) Oligocene 

Anahuac Shale, which, in turn, is overlain by an approximately 1,300-m-thick (~4,200-ft) interval 

of Miocene interbedded sandstones and shales (projected from cross sections in Morton and 

others, 1985). These include, in order of oldest (deepest) to youngest (shallowest), the Oakville 

(~470 m [~1,500 ft] thick), Fleming (~565 m [~1,850 ft] thick), and Goliad Formations (~245 m 

[~800 ft] thick). Above these units is the sand-dominated interval extending to the surface and 

including the Pliocene Willis Formation (~60 m [~200 ft] thick; Galloway and others, 1991; 

Guevara-Sanchez, 1974), the Pleistocene Lissie (~45 m [~150 ft] thick), and the Beaumont (~25 

m [~80 ft] thick; Guevara-Sanchez, 1974) Formations.

Typical structure within the central and upper Texas Gulf Coastal Plain dips gently 

toward the Gulf of Mexico and is cut every few kilometers by northeast-trending, down-to-thecoast growth faults. Along the upper Texas coast (including the study area), the growth-fault 

pattern is disrupted by numerous salt domes. The area proposed for the pilot experiment lies on 

the south flank of the South Liberty salt dome. The Frio Formation dips southerly to slightly 

southeasterly at high angles (greater than 30°) near the salt-dome flank, decreasing south and 

west of the pilot location to a dip of less than 5°. The salt flank is cut by a series of normal faults 

that radiate from the salt dome and typically dip and throw to the west-northwest (Figure 9). 

Major fault offsets vary from 90 to more than 120 m (300 to >400 ft), decreasing away from the 

dome as dips flatten. Minor fault offsets detectable with well logs and seismic correlation range 

from 15 to 45 m (50 to 150 ft), with many of these faults dying out not far south of the pilot area 

(Figure 9).
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Figure 8. Type log from SGH 3 showing depth to the injection interval, underlying oil and gas 

production, and fresh-water aquifers substantially above the injection interval.

Figure 9. Structure-contour map of the southwest flank of the South Liberty salt dome, showing the 

relationship of experiment well locations to faults and the edge of the salt dome. The white rectangle 

indicates the extent of the numerical model. The contour interval is 50 ft.
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Individual sandstones at the top of the Frio (the injection zone) range from less than 3 to 

more than 15 m (<10 to >50 ft) thick and are separated by laterally continuous shale beds from 1 

to more than 4 m (3 to >15 ft) thick. Sandstones at the project site have been given informal 

letter designations, with “A” being the shallowest (Figure 10). CO2 would be injected into the 

thicker “C” sandstone, and both the “C” and “B” sandstones would be monitored for response. 

Although hydrocarbons have been encountered in the “A” and “B” sandstones in nearby fault 

blocks adjacent to the salt dome, no indications of hydrocarbons have been found in logs from the 

“C” sandstone. 

Figure 10. Detailed type log from SGH 3 showing interval nomenclature, correlated horizons, and 

sandstones (yellow on curve).

Sandstones are generally laterally continuous over 1 km (0.6 mi) or more and were 

deposited in fluvial and deltaic settings (Galloway and others, 1982). Sandstone framework 

compositions are dominantly subarkose to lithic arkose, having quartz compositions between 45 

and 80 percent (Loucks and others, 1984). Regional formation-water salinity trends (Morton and 

Land, 1987) and log-derived, site-specific data indicate that these sandstones contain waters with 

more than 120,000 ppm of total dissolved solids. Log-derived porosities range from about 20 to 

more than 30 percent, averaging about 29 percent. Although no core from the area immediately 

surrounds the injection site, sandstones with similar log character but deeper depths in a cored 

well in adjacent Chambers County have permeabilities ranging from 50 millidarcies (md) to 

several darcies. Frio sandstones in the pilot area would be expected to have permeabilities of 

several hundred to nearly 1,000 md. Permeabilities would have a large impact on pressure 
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response and distribution of the injected CO2, as would residual gas saturations. On the basis of 

log-derived porosities and a porosity–residual-saturation relationship derived from the literature 

(Figure 11), residual-gas saturations for the injected CO2 of approximately 30 percent would be 

anticipated. Residual saturations could be as low as 5 percent, which would be an end-member 

possibility in modeling. Pressures and temperatures in the injection interval would be expected to 

be about 151 bar (2,195 psi) and 66°C (151°F) on the basis of regional gradients of 0.099 bar/m 

(0.439 psi/ft) and 3.32°C/100 m (1.82°F/100 ft). Values would be measured in project wells 

during initial field activities to verify these estimates.

Figure 11. Cross plot of residual gas saturation and porosity, showing 140 data points collected from 

the literature and 4 data points from a Frio sandstone core recovered from a well about 32 km (~20 

mi) south of the experiment site. The accumulated points indicate a logarithmic relationship with a 

high correlation coeffic ient of 0.85.

4.1.4 Groundwater

Fresh-water aquifers in the pilot area include the Alluvium and Beaumont, upper and 

lower Chicot, and Evangeline Formations (Dutton, 1990). The first and uppermost extends to the 

base of the Beaumont (see Dutton, 1990). The upper Chicot extends to the upper part of the 

Lissie, and the lower Chicot includes the remainder of the Lissie and Willis Formations 

(Figure 12; Carr and others, 1985). The Evangeline aquifer includes the Goliad and the upper 

part of the Fleming Formation (Dutton, 1990). The base of usable -quality water, defined as 

containing less than 3,000 mg/L (<3,000 ppm) total dissolved solids (TDS), is at a depth of about 

670 m (~2,200 ft) (Baker, 1979). Below the Evangeline aquifer is the Burkeville confining unit 

near the middle of the Fleming Formation. Below this is the Jasper aquifer, which includes the 
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lower part of the Fleming Formation and the upper part of the Oakville Formation (Figure 12; 

Baker, 1979). The base of potentially usable -quality water (also referred to as the base of the 

lowermost U.S. Drinking Water standard), defined as containing less than 10,000 mg/L (<10,000 

ppm) TDS, is at a depth of about 1,035 m (~3,400 ft), which would be about 500 m (~1,600 ft) 

above the injection zone and separated from the injection zone by more than 75 m (>250 ft) of 

Anahuac Shale Formation.

Figure 12. Dip-oriented regional cross-section through experiment site, showing relationship of 

stratigraphic units to hydrologic units. Modified from Baker (1979). Some stratigraphy and 

thicknesses for units above the Anahuac taken from Morton and others (1985), Galloway and others 

(1991), and Guevara-Sanchez (1974).
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Depth to groundwater is uncertain and would be investigated prior to CO2 injection. The 

amount of unsaturated section in the shallow subsurface would act as a buffer if CO2 were to leak 

from the deep subsurface (see Section 4.2.3). Saturation profile most likely varies across the site 

area depending on season, geomorphic position, and surface elevation. Information from mapped 

soil types suggests that water-saturated soil lies less than 1 m below ground level at the sites for 

the injection and monitoring wells. With the interbedded sand/clay nature of the shallow 

subsurface, this shallow water would like ly represent a perched water table. The nearest 

residential water well (well 64-02-102) would be about 1,250 m (~4,100 ft) northwest of the 

injection well. This well, which was drilled in 1972 to a depth of 73 m (240 ft), produces water 

from the Chicot aquifer. Water level in this well bore is 8 m (26 ft) below ground surface. If this 

aquifer is unconfined in this location, a substantial unsaturated zone could exist. Finally, the level 

of standing water in the adjacent Trinity River floodplain, commonly about 10m (~30 ft) below 

the project area, may indicate the approximate top of the saturated zone. Depth to water would be 

determined during drilling of initial shot holes for seismic data acquisition.

4.1.5 Climate

As part of the upper coast climatic province (Bomar, 1983), Liberty County experiences a 

warm, temperate, and humid climate. In January, historically the coldest month, temperatures 

range from an average low of 4.9°C (41°F) to an average high of 16.6°C (62°F) (Bomar, 1983). 

In July, historically the warmest month, temperatures range from an average low of 22.5°C 

(72°F) to an average high of 34.2°C (94°F) (Bomar, 1983). Temperatures fall below the freezing 

point of water an average of 11 times each year between the average date of the first freeze 

(December 6) and the average date of the last freeze (February 15). Recorded temperature 

extremes are a low of –15°C (5°F) in January 1940 and a high of 41.7°C (107°F) in August 1980.

Average wind vectors are from the north-northwest at 13 km/hr (8 mi/hr) in January, 

from the south-southeast at 14 km/hr (8.7 mi/hr) in April, from the south at 11 km/hr (6.8 mi/hr) 

in June, and from the east-southeast at 10 km/hr (6.2 mi/hr) in October (Bomar, 1983). Highest 

wind speeds occur during the approach and passage of cold fronts, which are most common from 

October through March. Extreme weather conditions are associated with the occasional tropical 

storm, which brings torrential rains, high-sustained winds, and tornadoes to the area. Hurricane 

season begins on June 1 and ends on December 1. Tropical storms are most common in the 

months of June, August, and September.

Average annual rainfall in the Houston area is 114 cm/yr (44.5 in/yr) (Bomar, 1983). The 

months of May and September have the highest historical rainfall averages. 
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4.1.6 Access

The pilot experiment site would be located on existing well sites accessed using privately 

owned lease roads in the active South Liberty oilfield. Access to the field would be provided 

from Texas Farm-to-Market Road 1409 between Dayton, where FM 1409 intersects 

U.S. Highway 90, and Mont Belvieu. The major transportation routes in this area are Interstate 

Highway 10, which passes about 15 km (~9.3 mi) south of the site, and U.S. 90, which passes 

about 7 km (~4.3 mi) north of the site. At the nearest point, FM 1409 would be about 1.3 km 

(~0.8 mi) southwest of the pilot experiment site.

The planned transport route for trucks carrying CO2 to the pilot experiment site for 

injection would be from the supply plant in Texas City (Galveston County) onto Texas 146 

(Figure 1). This major state highway passes through the cities of Texas City and Kemah in 

Galveston County, Seabrook, La Porte, and Baytown in Harris County, and Mont Belvieu in 

Chambers County, for a cumulative route distance of 55 km (34 mi). At Mont Belvieu, the route 

turns east onto Loop 207 for 1.3 km (0.8 mi) before turning east again onto FM 565 for a distance 

of 6 km (3.7 mi) to the intersection with FM 1409. The route turns north onto FM 1409 and 

continues to the lease road entrance 16.9 km (10.5 mi) from the intersection with FM 565. The 

total distance from the CO2 supply plant to the pilot experiment site would be 79.2 km (49.1 mi).

4.1.7 Historical and Archaeological Resources

The Texas Archeological Research Laboratory (TARL), The University of Texas at 

Austin, is the curator of archaeological and historical sites for the State of Texas. Upon review of 

site maps and the location of the proposed experiment, TARL staff determined that, within one 

kilometer (0.6 mi) of the proposed delineated project area, no recorded archaeological or 

historical sites exist. TARL staff also confirmed that no sites registered as State Archeological 

Landmarks or listed in the National Register of Historic Places would be affected by the proposed 

project. A copy of the review request and the determination response letter are included in 

Appendix A. For additional assurance that neither historical nor archaeological resources would 

be affected by the pilot experiment, all work areas associated with the drilling pad, mud pit, and 

seismic tests would be surveyed by project archaeologists to ensure the absence of such resources 

before work is initiated.

4.1.8 Endangered Species

Staff from the Clear Lake Ecological Services Field Office of the U.S. Fish and Wildlife 

Service reviewed the experiment location and have determined that “no federally listed or 

proposed threatened or endangered species are likely to occur at the project site. The project site 
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would not be located within officially designated critical habitat.” Copies of the review request 

and the determination letter are included in Appendix A.

4.1.9 Flood Potential

The western margin of the floodplain from the Trinity River, which would provide the 

principal risk for flooding at the pilot experiment site, lies about 400 m (~1,300 ft) east of the site. 

The current channel of the river is about 2.7 km (~1.7 mi) east of the site. Normal and peak 

stream flows of the Trinity River in this area are relatively well known from operation of a 

stream-gauging station on the Trinity River at Liberty (U.S. Geological Survey station 08067000) 

since 1940.

The drainage area for the Trinity River above the Liberty stream-gauging station totals 

45,242 km2 (17,644 mi2) (Dougherty, 1980). Maximum discharge measured at the Liberty gauge 

was 3,230 m3/s (114,084 ft3/s) on May 12, 1942, which corresponded to a gauge height of 

8.955 m (29.37 ft). The gauge datum is 0.68 m (2.23 ft) below mean sea level. Thus, the peak 

flood elevation at Liberty, as reported by Dougherty (1980), since 1940 was 8.275 m (27.14 ft) 

above sea level. Dougherty (1980) stated that the 1942 discharge maximum was the greatest 

since at least 1903. The most recent discharge data in Dougherty (1980) are from 1975. In 1994, 

more recent data reported from the U.S. Geological Survey’s National Water Information System 

(http://waterdata.usgs.gov/nwis/) show that peak discharge since 1975 was 3,823 m3/s (135,028 

ft3/s), corresponding to a gauge height of 9.45 m (31.00 ft) and an elevation of 8.77 m (28.77 ft) 

above the 1929 National Geodetic Vertical Datum. Over the century represented by the pre- and 

post-1975 monitoring, the peak flood elevation was sufficient to inundate the lowland floodplain 

adjacent to the pilot experiment site at typical elevations of 2 to 6 m (6.5 to 20 ft) above sea level. 

However, water elevations of the Trinity River during the extreme floods of 1942 and 1994 were 

more than 10 m (>33 ft) below the land-surface elevation of about 20 m (~66 ft) above sea level 

at the pilot experiment site on the upland.

4.1.10 Wetlands

The pilot experiment site, which would be located in a low-relief, high-rainfall area on 

the upland adjacent to the Trinity River valley, would be near wetlands identified both in the 

Atlas of the Submerged Lands of Texas (White and others, 1985) and on wetland maps published 

by the U.S. Fish and Wildlife Service. White and others (1985) depicted the area around the pilot 

experiment site as an upland environment that is about 400 m (~1,300 ft) west of the Trinity 

River floodplain margin and elevated 14 to 18 m (46 to 59 ft) above it. Wetlands on the modern 

floodplain nearest the site are classified as WL (woodlands in fluvial areas), where water-tolerant 

trees and shrubs are found on river floodplains and in poorly drained areas, and as FH (high 

marsh), where fresh-water plants make up the vegetation assemblage.
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National Wetlands Inventory maps (U.S. Fish and Wildlife Service, 1997; see Cowardin 

and others, 1979, for basis) depict the wetlands habitats at the pilot experiment site (Figure 13, at 

the 7.5-minute quadrangle scale). Mapped units at the site are classified as U (upland); adjacent 

and nearby mapped units are PFO1A, PEM1C, and PUBFx on the upland, PFO1C on the bluff, 

and PFO1/2F and PEM1F on the Trinity River floodplain adjacent to the site. The “U” 

classification, which encompasses the pilot experiment site (Figure 14A), denotes an upland 

environment (non-wetland). Unit PFO1A is mapped on the topographic upland adjacent to the 

“U” (upland) unit but is classified as a palustrine forested unit with broad-leaf deciduous trees 

(Figure 14B). The Palustrine System designation (units beginning with the letter P) includes “all 

non-tidal wetlands dominated by trees, shrubs, persistent emergents, emergent mosses or lichens” 

(Cowardin and others, 1979). Unit PEM1C is classified as a palustrine, emergent, persistent, and 

seasonally flooded wetland. Unit PUBFx, which is located about 200 m (~650 ft) west of the site, 

is classified as an excavated, semi-permanently flooded palustrine wetland with an 

unconsolidated bottom.

On the bluff between the upland and the Trinity River floodplain, unit PFO1C designates 

a palustrine wetland composed of broad-leaf deciduous trees that is seasonally flooded 

(Figure 15A). On the Trinity floodplain, unit PFO1/2F designates a forested palustrine wetland 

with broad- and needle-leaf deciduous vegetation that is semi-permanently flooded. The other 

nearby floodplain unit, PEM1F, denotes a persistent, semi-permanently flooded palustrine 

emergent habitat (Figure 15B).
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Figure 13. Distribution of mapped wetlands units at the experiment site. Wetlands units are those of 

the National Wetlands Inventory (U.S. Fish and Wildlife Service, 1997). PEM1C = palustrine, 

emergent, seasonally flooded; PEM1F = palustrine, emergent, semi-permanently flooded; PFO1A = 

palustrine, forested, broad-leaf deciduous trees; PFO1C = palustrine, forested, broad-leaf deciduous 

trees, seasonally flooded; PFO1/2F = palustrine, forested, broad- and needle-leaf deciduous trees, 

semi-permanently flooded; PUBFx = palustrine, excavated, semi-permanently flooded, 

unconsolidated bottom; and U = upland (non-wetland). Aerial photo base modified from Texas 

Natural Resources Information System.
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A

B

Figure 14. Representative photographs of upland vegetation assemblages from the pilot experiment 

site and surroundings. (A) Upland environment (“U” classification) at the injection site. (B) Mixture 

of broad-leaf deciduous trees and evergreen trees (Unit PF01A) about 100 m (~330 ft) north of the 

pilot experiment site. Photos taken during February 2002.
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A

B

Figure 15. Representative photographs of lowland vegetation assemblages near the pilot experiment 

site. (A) Unit PF01C, a palustrine wetland on the bluff between the upland area of the experiment 

site and the Trinity River floodplain. (B) Unit PEM1F, a semi-permanent flooded palustrine 

emergent habitat within the Trinity River floodplain, at the Sun Fee Lot 45 #1 well pad. Raised well 

platform accommodates occasional flooding. Photos taken during February 2002.
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4.2 Environmental Consequences

Direct environmental effects at the Liberty County pilot experiment site could potentially 

result from (1) surface activities, (2) injection of agents into the subsurface environment, and 

(3) leakage of injected agents back to the surface or groundwater. As noted in Section 4.1, 

environmental resources associated with historic or archaeological properties; endangered, 

threatened, or listed species; critical habitat; wetlands; and floodplains do not exist at areas that 

would be affected by the proposed pilot experiment; thus, no adverse impacts on such resources 

would be anticipated. The description of pre-injection activities in Section 3.2.2 provides 

information on project requirements related to land disturbance and on materials that would be 

used and produced during well drilling activities, as well as disposition plans for produced 

materials. The well drilling operations required for the proposed pilot experiment would be 

identical in nature to ongoing activities within the South Liberty oilfield and would be performed 

by experienced personnel in full accordance with Texas Administrative Code and TCEQ 

requirements. No adverse effects would result. The risks of adverse impacts from proposed 

activities at the pilot experiment site would be low.

4.2.1 Surface Impacts

Traffic impacts from delivery of CO2 to the site and removal of wastes to disposal 

facilities would be minor and similar to on-going drilling activities that occur in the South Liberty 

oilfield. Although the risks of significant surface leaks of CO2 would be minor, the effects on 

human health if a release would occur could be significant. The presence of large volumes of 

compressed CO2 during relatively short duration of CO2 injection activities would represent a 

significant health and safety risk because of the high injection pressures (up to 168 bar or 

2,454 psi) and asphyxiation hazard. 

CO2 is a nontoxic inert gas that is essential for fundamental biological processes in all 

living things (Benson and others, 2003). Exposure to elevated concentrations can cause adverse 

reactions. At exposures to concentrations between 3 and 5% (30,000 and 50,000 ppm), humans 

experience discomfort and impacts on respiratory rate. Loss of consciousness can occur from 

exposures to concentrations above 5% (50,000 ppm) and would occur within seconds from 

exposures to concentrations above 25 to 30%, at which point death would be imminent (Benson 

and others., 2003). CO2 is denser than air and can concentrate in low-lying or confined areas if 

not dispersed or mixed with air by winds. Contingency plans in the unlikely event of a largescale CO2 leak would be prepared by Sandia Technologies, complete with an audible and visual 

warning system, escape procedures, and emergency notification plans. A site-safety training plan 

designed by a safety expert with substantial experience in CO2 EOR operations would be 

administered to all on-site personnel. In addition, activities at the pilot experiment site would be 

staffed by trained personnel at all times when CO2 is being stored or injected at the site. Relevant 
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health and safety procedures, such as the Emergency Planning and Community Right-to-Know 

Act (EPCRA, or SARA Title III), would be followed.

Land use, air emissions associated with equipment operations, aesthetics, and noise 

related to project activities would occur over a short time duration, be intermittent in nature, or be 

consistent with previous and on-going activities at the South Liberty oilfield. No adverse impacts 

by the proposed pilot experiment from these environmental interactions would be anticipated.

4.2.2 Subsurface Impacts

Direct effects to the subsurface environment from introduction of CO2 would have 

minimal environmental impact because of the relatively small volume introduced and the isolated 

nature of the setting. Introduced tracer materials would have negligible impacts because of the 

small volumes and benign nature of the materials. Table 5 lists the chemicals that could be used 

as tracers and identifies potentially harmful effects. The candidate tracers include 

perfluorocarbons and noble gases. MSDS sheets for these materials are provided in Appendix B. 

None of the tracer materials are listed in 40 CFR 261 Subpart D as hazardous materials.

Table 5. Tracer materials to be used and their concentrations

Tracer Concentration

(Injectate)

Concentration

(Produced 

Fluids)

Maximum total 

weight

Comments

FLUTEC-TG PMCH

(perfluoromethylcyclohexane)

30 μg/mL

(30 ppm)

1 ng/mL

(1 ppb)

Perfluoro-carbons: 

60 kg total.

No known humanor eco-toxicity

FLUTEC-TG PTMCH

(perfluoro-1,3,5-

trimethylcyclohexane)

30 μg/mL

(30 ppm)

1 ng/mL

(1 ppb)

Perfluoro-carbons: 

60 kg total.

No known humanor eco-toxicity

FLUTEC-TG o-PDMCH

(perfluoro-1,2-

dimethylcyclohexane)

30 μg/mL

(30 ppm)

1 ng/mL

(1 ppb)

Perfluoro-carbons: 

60 kg total.

No known humanor eco-toxicity

FLUTEC-TG m-PDMCH

(perfluoro-1,3-

dimethylcyclohexane)

7 μg/mL

(7 ppm)

0.2 ng/mL

(0.2 ppb)

Perfluoro-carbons: 

60 kg total.

No known humanor eco-toxicity

FLUTEC-TG p-PDMCH

(perfluoro-1,4-

dimethylcyclohexane)

7 μg/mL

(7 ppm)

0.2 ng/mL

(0.2 ppb)

Perfluoro-carbons: 

60 kg total.

No known humanor eco-toxicity

FLUTEC-TG PMCP

(perfluoromethylcyclopentane)

30 μg/mL

(30 ppm)

1 ng/mL

(1 ppb)

Perfluoro-carbons: 

60 kg total.

No known humanor eco-toxicity

FLUTEC-TG PDMCB

(perfluorodimethylcyclobutane)

7 μg/mL

(7 ppm)

0.2 ng/mL

(0.2 ppb)

Perfluoro-carbons: 

60 kg total.

No known humanor eco-toxicity

FLUTEC-TG PECH

(perfluoroethylcyclohexane)

7 μg/mL

(7 ppm)

0.2 ng/mL

(0.2 ppb)

Perfluoro-carbons: 

60 kg total.

No known humanor eco-toxicity

20Ne (Neon 20) 30.3 ppm Variable 0.63 kg No known humanor eco-toxicity

36Ar (Argon 36) 164 ppm Variable 3.42 kg No known humanor eco-toxicity
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84Kr (Krypton 84) 7.64 ppm Variable 0.16 kg No known humanor eco-toxicity

132Xe (Xenon 132) 0.4 ppm Variable 0.01 kg No known humanor eco-toxicity

Eosin 1 ppm 5 ppb 10kg No known humanor eco-toxicity

Perfluorocarbons are used in human medical treatments, and noble gases are chemically 

inactive. A maximum total of 60 kg (132 lb) of perfluorocarbon tracers would be used during the 

experiment, with maximum concentrations in the injectate of 30 μg/mL (30 ppm) and 

concentrations at the monitoring well at the radial distance of 30 m (100 ft) expected to be lower 

than 1 ng/mL (1 ppb). A maximum of 4.22 kg (9.33 lb) of noble gases would be used. 

Concentrations in the injectate would range from 0.04 to 164 ppm, depending on the gas type. 

Concentrations at the monitor well would vary from 100% of the gas phase initially to no 

measurable concentration several days after injected gases reach the monitor well. Eosin 

fluorescent dye has been approved for use in groundwater tracing and has been widely used in 

drinking water and environmentally sensitive areas. Less than 10 kg would be added to the 

hydrologic test brine before re-injection to the subsurface and would result in concentrations 

ranging from ppm levels in the injectate to ppb levels at the monitoring well.

Shot holes used for the 3-D VSP would leave minor amounts of residue within shallow 

saturated zones. A biodegradable explosive such as Dynoseis®, which contains sodium 

perchlorate and diethylene glycol, would be used instead of more traditional and less expensive, 

but potentially more harmful, explosives such as Pentalite. Shot holes would be filled following 

use, and the soil would be compacted.

4.2.3 Potential Leakage Impacts

Risks associated with return of injected CO2 to groundwater or the surface would be low. 

The injection zone would be overlain by a 75-m-thick (250-ft) shale seam and approximately 

1,375 m (~4,500 ft) of interbedded sandstone and shale that would serve as alternating barriers to 

vertical migration and sinks for any escaped CO2. Incremental pressures throughout the injection 

phase would be controlled and below regulatory limits established by TCEQ, in adherence to 

U.S. Environmental Protection Agency rules. The limits are designed to prevent migration of 

injected fluids out of the injection zone over a 10,000-year period. Numerical modeling indicates 

that CO2 would not travel more than 200 m (>650 ft) from the injection well. Under pilot 

experiment conditions, faults would not be conduits for fluid or gas escape. Monitoring, which 

would be the central focus of the pilot experiment, would be performed to assure that the CO2 in 

the subsurface would behave as predicted. Pre-injection engineering and during-injection 

monitoring would be conducted to provide assurance that the wells would perform as planned and 
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would not leak fluids or gases. In the unlikely event of a leak, project activities and well data 

would be re-examined to identify causes and apply corrective measures.

To evaluate the potential impact of a leak at a theoretical site where these assurances 

would not be present, the fate and transport of a release from the injection interval equivalent to 

10% of the total CO2 injected was investigated. The most likely scenario is that the rising gas 

would be retained by capillary forces and residual saturation effects in the pores of the sandstones 

through which it ascends. If the gas was to rise along a conduit in which little contact with 

porous rock occurred, a significant percentage could reach either the groundwater or the ground 

surface. 

If the CO2 were to ascend into an aquifer, impacts would be minor. Dissolution of CO2 in 

water would decrease pH (increases acidity) slightly. Chemical reactions between the acid waters 

and the surrounding rock would moderate this reaction, thus limiting pH changes. Modeling by 

LLNL (K. Knauss, LLNL, personal communication) indicates that pH would be reduced from 

6.74 to 5.28 for a radial distance of less than 20 m (<65 ft) from the leak point, assuming an 

aquifer of 6-m (20-ft) thickness, salinity of <1,000 ppm, and rate of leakage equivalent to rate of 

injection. A statewide database of water well locations maintained by the Texas Water 

Development Board records no water wells within 1 km (0.6 mi) of the proposed injection well. 

The nearest known residential water well (well 64-02-102) is located on the Pleistocene upland, 

about 1,250 m (~4,100 ft) northwest of the injection well. This well, which was drilled in 1972 to 

a depth of 73.2 m (240 ft), produces water from the Chicot aquifer. A field survey would be 

conducted prior to injection operations to locate any undocumented water wells within a 402-m 

(0.25 mi) radius of the inje ction well. Any wells within this area would be monitored for changes 

in pH during the pilot experiment. Three monitoring wells would be drilled near the injection 

well to monitor shallow groundwater.

In the unlikely event that CO2 were to ascend to the ground surface, impacts would be 

minor. Numerical modeling by Oldenburg and others (2002a, b) demonstrates that CO2 rising 

from the subsurface would collect in the unsaturated zone and spread laterally, accumulating to 

nearly 100% vapor concentration in the shallow soil because the density of CO2 is greater than 

the density of air. Only when the unsaturated-zone pore space becomes filled with CO2 would 

significant flux to the atmosphere occur (Oldenburg, 2002a). Under conditions of significant 

leakage, topographic lows and enclosed subsurface structures such as basements could 

accumulate significant concentrations of CO2 from the unsaturated zone. Any such points within 

400 m (0.25 mi) of the experiment site would be identified and monitored during and following 

CO2 injection. 

Increasing concentrations of CO2 in soil gas could forewarn of a potential flux to the 

atmosphere. The grid of groundwater and soil-gas sample points to be established on the well 

pad and at other potential leak sites (see Section 3.2.2) would be monitored throughout the 

injection and post-injection phases.
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At the end of the chain of unlikely events is the possibility that CO2 might seep into the 

atmosphere, which could be triggered by high flux rates through groundwater or limited pore 

space in the unsaturated zone that results in filling the unsaturated zone and creating flux to the 

surface. Oldenburg and others (2002a) modeled a scenario where subsurface flux rates equivalent 

to 10% of project volumes returned to the surface over a 1-year period. Under such conditions, 

the CO2 concentrations at ground level near the leak site would be nearly 100% but would 

dissipate to background atmospheric concentrations within about 28 m (~90 ft) in wind speeds 

typical of the proposed location for the pilot experiment (7.2 km/hr).

As shown in Table 5, perfluorocarbon and noble gas tracers that would be used in the 

pilot experiment have no known toxicity. Due to their lack of toxic character and proposed low 

concentrations, tracer agents that might leak to the groundwater or the surface would be expected 

to result in negligible impacts.
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5.0 REGULATORY COMPLIANCE

5.1 State Permitting Requirements

State permitting requirements were discussed with the two Texas agencies that would be 

expected to have jurisdiction over the drilling and injection activities envisioned for the proposed 

pilot experiment. Discussions regarding State regulatory requirements were held with personnel 

responsible for regulation of Underground Injection Control (UIC) at the Railroad Commission of 

Texas (RRC) and UIC Permits at the Texas Commission on Environmental Quality (TCEQ).

The UIC program encompasses of five classes of wells, from I to V, each generally 

requiring a permit for operation under Texas Water Code, Chapter 27, and Texas Health and 

Safety Code, Chapter 361 (Class II wells fall under different codes). Federal guidelines for UIC 

wells have been established by the U.S. Environmental Protection Agency (EPA). The TCEQ 

and the RRC have been delegated authority by EPA to administer UIC programs in Texas, which 

are at least as stringent as those implemented by EPA. Additional rules governing the various 

classes can be found in Title 30 of the Texas Administrative Code, Chapter 331, with supporting 

information and rules in Chapters 1–100, 281, and 305. Class I wells are used for long-term 

injection of hazardous and non-hazardous wastes and are permitted by the TCEQ. Class II wells 

are designated for injection of water or other chemicals into existing oil and gas reservoirs or 

injection of oilfield wastes into non-reservoir intervals and are permitted by the State oil and gas 

regulatory agency (RRC). UIC Class III is reserved for wells that inject fluids for extraction of 

minerals other than oil and gas. The Class IV category applies to wells that dispose of hazardous 

wastes above formations that contain underground sources of drinking water and are generally 

prohibited. Class V wells are those that are not included in Classes I through IV. Class V wells

have numerous purposes, ranging from disposal of storm runoff and motor vehicle waste to 

aquifer recharge and remediation. One Class V category covers “experimental” wells for 

subsurface fluid distribution, under which the proposed pilot experiment would be expected to be 

permitted.

Because the injection interval would not be an oil or gas reservoir, and because the source 

of the injected CO2 would be post-refinery, the pilot experiment would fall under the jurisdiction 

of the UIC program at TCEQ. Discussions with TCEQ regarding the short duration of the 

experiment and the small volume of gas proposed for injection resulted in a request by TCEQ for 

an application for a Class V well, accompanied by a report providing relevant additional 

information typically required in Class I filings. A public information meeting, wherein local 

citizens, public officials, local and regional political representatives, and other interested 

stakeholders would be invited to review the project plan and provide nonbinding comments, 
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would be required and hosted by the Bureau of Economic Geology. Public comments would be 

considered, and any appropriate adjustments to the field activities would be made. 

The TCEQ Class V application would include responsible -party contact information, 

well-site information, downhole design, and a review of hydrogeological data, including 

information about formation water chemistry, relationship to aquifers, and locations of injection 

or water wells within a one-quarter-mile radius. The additional report required by the TCEQ 

would include the following:

• a detailed land-ownership map with contact information, 

• additional detailed site information (relationship of the site to government entities and 

jurisdictions), 

• contact information for local government agencies and political representatives,

• financial assurance for site closure, 

• a concise description of the geologic and hydrogeologic setting, 

• engineering drawings and plans for surface and subsurface equipment approved by a 

registered professional engineer, 

• a discussion of injection zone mechanics that includes flow-simulation model results 

indicating expected changes in pressure and injectate saturations through time, 

• an Area-of-Review (AOR) study documenting all wells within 402 m (0.25 mi) of the 

pilot wells and their current conditions, 

• a discussion of injected fluids and their expected reactivity with formation and 

construction materials, and 

• a letter from the RRC indicating that activities would not adversely affect any known 

hydrocarbon accumulations.
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6.0 CUMULATIVE AND INDIRECT EFFECTS AND LONG-TERM 

ENVIRONMENTAL CONSEQUENCES

Cumulative impacts result from the incremental impact of a proposed action when added 

to the impacts of other past, present, and reasonably foreseeable future actions. Cumulative 

impacts include direct impacts that occur at the same time and place as the proposed action and 

indirect impacts that can occur later in time or farther in distance from the site of the proposed 

action. Direct cumulative effects of the proposed project, as described in Section 4.2, would be 

limited because of the short duration of field activities and would be expected to span only 

several months, with CO2 injection being performed over a time period lasting less than 

2 months. Indirect cumulative effects would predominantly relate to long-term fate of the 

injected CO2.

6.1 Direct Cumulative Effects

Direct cumulative effects would include impacts of CO2 transportation, traffic and 

capacity impacts associated with disposal of produced water, impacts on flora and fauna of 

proposed field activities, and noise- and light-pollution impacts of nighttime operations.

Cumulative transportation impacts would be minimal, since the 10 CO2 truck shipments 

per day during the comparatively short injection phase would be minor in comparison to the 

moderate to heavy commercial, agricultural, industrial, and private traffic volume that is currently 

experienced on planned routes. Transport during heavy commuting hours would be avoided 

along Highway 146 between Seabrook and the east end of Baytown to further minimize effects.

Disposal of less than 30 truckloads of produced brine, a non-hazardous material, over the 

duration of the project would entail an approximately 22.5-km (~14-mi) drive along public rural

roads. A maximum of 595 barrels (5 truckloads) of produced water would undergo disposal each 

day into a commercial UIC Class I non-hazardous disposal well that has a disposal capacity of up 

to 950,000 gallons per day and that typically receives other deliveries amounting to less than 

150,000 gallons per day. A maximum of 7,000 barrels (bbl) (60 truckloads) of drilling fluids 

would undergo disposal at a TCEQ-permitted disposal facility approximately 48 km (30 mi) from 

the experiment site. Drilling-fluid disposal would be spread over at least 6 days, thus reducing 

traffic impacts. The disposal well has a capacity of 20,000 bbl/day with a typical use of 

1,200 bbl/day, or 6% of disposal capacity. Delivery of an average load of 1,166 bbl/day during 

the 6-day delivery period would approximately double the use level of the disposal well to about 

12% of daily disposal capacity, which would not create any adverse cumulative impact on the 

disposal facility.
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Cumulative effects to flora and fauna would be minor and local. The project would 

impact less than 2 additional hectares (5 acres) of land surface in an oilfield where exploration 

and development activities span an area of 6,980 hectares (17,280 acres). 

Drilling, work-over, and CO2 injection activities could occur at night. Associated light 

and noise impacts would be minimized by the 0.6-km (0.35-mi) distance between the well site 

and the nearest residence and the limited duration of intensive drilling and injection activities. 

6.2 Indirect and Indirect-Cumulative Effects

Indirect cumulative effects include the long-term fate of injected CO2, the post-project 

disposition of the three wells used, the potential for increased drilling and land use in the project 

area associated with potential project success, and the impacts of increased sequestration 

activities throughout the U.S.

6.2.1 Fate of Injected CO2

A primary goal of the proposed pilot experiment is to document the fate of injected CO2. 

Numerical modeling and accumulated knowledge on the behavior of fluids and gases in the 

subsurface suggest that the CO2 would remain within the injection zone and travel less than 

200 m (650 ft) from the injection well (Doughty and Pruess, 2003). Alternative models have 

been constructed to investigate possible but unexpected scenarios, including upward leaks that 

might occur (1) through overlying formations, (2) along well-bore annuli, and (3) along faults. 

Factors that diminish leakage risks would include (1) the presence above the injection zone of the 

75-m-thick (250-ft) Anahuac Shale, which possesses documented capability to retain gases for 

geologic time spans, and the overlying 1,475-m-thick (4,500-ft) section of interbedded sandstones 

and shales, (2) the presence in well-bore annuli of remnant drilling mud with a density sufficient 

to contain anticipated pressure increases outside the 402-m (0.25-mi) Area of Review (AOR) 

established by TCEQ, and (3) planned maximum fluid pressures that would be 22 percent below 

the pressure required to induce seismicity and fault le akage. No adverse risks to human health, 

safety, or the environment would result from these alternative scenarios. Numerical models 

would be refined using site-specific data after field activities begin but before any CO2 would be 

injected.

Subsurface numerical models were constructed at Lawrence Berkeley National 

Laboratory using the TOUGH2 code (Doughty and Pruess, 2003). The models incorporate 

reasonable scientific assumptions (Pruess and others, 1999; Holtz, 2003) and geologic 

assessments based on regional knowledge of the injection horizon (Doughty and others, 2001; 

Hovorka and others, 2000; Doughty and Pruess, 2003) and site-specific geotechnical data derived 

from well logs and a 3-D seismic survey (Figure 16). Knowledge of subsurface fluid behavior is 

available from the multitude of engineering and geologic studies conducted to determine 

subsurface-oil and gas-reservoir characteristics. 
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Figure 16. Numerical simulation model construction parameters for the “C” sand (injection interval). 

A thin shale in the middle of the sandstone separates a lower upward-coarsening sandstone deposited 

in a probable delta front setting from a dominantly upward-fining sandstone deposited in a 

distributary channel. North is toward the right side of the images. Grid refinement around well bores 

allows greater detail in imaging injection response. Simulation grid prepared by Christine Doughty, 

LBNL.
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Models show that the CO2 injected into the subsurface during the experiment would behave 

buoyantly because of its low density (0.6 grams/cm3) compared with that of native formation brines 

(1.075 grams/cm3). The buoyant plume of concentrated immiscible CO2 would migrate updip 

within the injected stratigraphic interval toward the salt dome (Figure 9). Some percentage of the 

CO2 would remain behind the migrating plume, because it would be trapped in rock pores by 

capillary behavior and relative permeability effects (Wardlaw, 1982; Holtz, 2002). Holtz (2003) 

indicated that, for the ranges of porosities in the injection interval, as much as 30% of the pore 

space would sequester the CO2 in what is termed residual saturation. Numerical flow simulation 

models constructed on this basis suggest that the plume would stop moving entirely within 5 years 

after moving less than 200 m (<650 ft) updip (Figure 17). The CO2 would remain in place at least 

until local geologic conditions change significantly, a time period expected to exceed 1,000 years.

Figure 17. CO2 saturation distributions around the injection well from 0.2 to 100 years after starting 

injection. The model uses best estimates of porosity and residual gas saturation. The model block is 

tilted up toward the northeast. Note that very little movement of the plume would occur after the 

initial injection period. Simulation results from TOUGH2 prepared by Christine Doughty, LBNL.

If the current understanding of residual saturation behavior or subsurface pressure 

conditions is inaccurate, the CO2 could continue migrating updip to the north within the injection 

interval. The faults to the northwest and southeast of the injection well would focus the CO2

plume as it moves up and is trapped against the salt dome. Such a scenario could be produced, as 
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shown by numerical modeling, if residual saturation were actually 5%, as opposed to the 30% 

estimated (Figures 18 and 19). 

Figure 18. CO2 saturation distributions around the injection well for low-residual gas saturation case 

from 0.2 to 100 years after starting injection. The model uses best estimates of porosity and a 

maximum of 5% residual gas saturation. The model block is tilted up toward the northeast. Note that 

the plume continues to migrate updip for perhaps 10 years before being immobilized by the residual 

gas saturation effect. Simulation results from TOUGH2 prepared by Christine Doughty, LBNL

Figure 19. CO2 saturation distributions in northeast-southwest (dip) section cross-sectional view of 

injection zone for low-residual gas saturation case at 100 years after starting injection. Updip is to 

the right in this section through the center axis of the model. CO2 has escaped from the lower half 

of the “C” sandstone through a theoretical break in a thin shale midway up the sandstone body. 

Only the CO2 plume in this half of the sandstone has sufficient volume to continue migrating to the 

updip end of the model. Simulation results from TOUGH2 prepared by Christine Doughty, LBNL.
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With a mobile CO2 plume, the dominant risk would be that the plume might encounter a 

conduit leading up and out of the injection zone. Possible conduits include (1) cross-formational 

flow (discontinuous seal), (2) well-bore annuli, and (3) faults, including the interface between the 

formation and the salt dome. Each possible conduit is unlikely, for the following reasons:

• In addition to the two 3-m-thick (10-ft) laterally continuous shales separating the 

injection zone from overlying sandstones in the Frio Formation, the injection zone would 

be overlain by the 75-m-thick (250-ft) Anahuac Shale. This shale has retained both oil 

and gas over geologic periods of time at the South Liberty Salt Dome, as evidenced by 

the presence of oil and gas reservoirs in the uppermost Frio sandstones (Halbouty, 1962). 

Additionally, maximum subsurface pressures during the pilot experiment, based on 

LBNL models, would be 169 bar (2,469 psi), or 35% below the fracture pressure as 

calculated by the Eaton method (Eaton, 1969).

• Well bores within the 402-m (0.25-mi) Area of Review (AOR) established by the TCEQ 

would be assessed for proper completion or abandonment using RRC file data and would 

be remediated if found to be noncompliant. Annuli of surrounding wells outside the 

AOR should be filled with 9 lb/gal drilling mud that would be present in the well before 

emplacement of casing. Incremental formation pressures outside the AOR during the 

pilot experiment of less than 10 bar or 146 psi would be 12% below the Critical 

Incremental Pressure of 11.4 bar (166.4 psi) required to overcome the hydrostatic head of 

the mud column. This rationale for assessment of upward leakage potential was 

established by TCEQ for UIC operations. Adherence to these conditions is a prerequisite 

for approval of a Class V well application. For a Class V well to qualify for a TCEQ 

permit, wells within the AOR must have cemented casing emplaced below the base of 

Usable Quality Groundwater (TDS < 3,000 ppm). In the unlikely event that CO2 pressure 

might overcome mud-column heads in the annulus of the injection well, the cemented 

casing would prevent the gas from entering aquifers.

• Ambient confining pressures keep faults at depths greater than 1 km (~ 3,000 ft) closed to 

fluid migration unless fluids are injected into the fault plane at excessive fluid pressures 

(Rasmussen, 1997) or unless the fault slips (Hooper, 1991). A lack of fault scarps at the 

surface in the vicinity of the proposed pilot experiment indicates that faults in the area 

have not been active in the recent geologic past. Injection-induced excess fluid pressures 

can reactivate faults (Wesson and Nicholson, 1987). However, the maximum fluid 

pressure of 169 bar (2,469 psi) associated with the proposed experiment would be 22% 

below the 264 bar (3,853 psi) calculated by the Wesson and Nicholoson (1987) method 

as likely to induce seismicity.
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• If unforeseen events were to occur and the CO2 gradually escaped to an aquifer or to the 

surface, the impacts would be minor and limited in geographic extent. The conditions of 

immediate escape of CO2 were addressed previously in Section 4.2. Events that occur 

over longer periods of time would have reduced impact compared to the impacts 

previously described in Section 4.2. Following completion of injection, subsurface 

pressure anomalies would decay as the pressure pulse becomes absorbed by the 

surrounding formation volume. Any potential for rapid leakage would be reduced as the 

CO2 plume spreads and pressure declines. Gradual leakage, if it occurs, would be at 

substantially reduced rates, increasing chances for broad, slow dispersion in watersaturated sediments or near-surface soils, thus reducing the possibility for CO2 buildup to 

dangerous levels in the air around the pilot experiment site. 

As discussed previously in Section 4.2, groundwater-dissolved gases and soil gases 

would be monitored for increases in CO2 above baseline values. This monitoring would be 

decreased in frequency as measurable pressure and temperature effects in the subsurface decay 

over time. Monitoring would cease when asymptotic values of change occur, which would be 

expected to occur within 1 year after the end of injection.

6.2.2 Post-project Well Disposition

Following project completion, the three wells used during the pilot experiment would be 

abandoned, in accordance with Rule 14, section 3.14 of the RRC “Statewide Rules for Oil, Gas, 

and Geothermal Operations,” or converted to another use authorized by RRC and TCEQ. Neither 

of these alternatives would have adverse indirect or cumulative effect on the South Liberty 

oilfield, where similar activities are routine for the hundreds of existing wells in the field.

6.2.3 Increase in Sequestration Activities in the Pilot Area

The site proposed for the pilot experiment was selected because it possesses suitable 

technical attributes for a small-scale project. Success of the pilot experiment could increase 

interest in larger projects, perhaps in the same geographic area. Any such project would require 

considerable further study, including assessing potential environmental impacts and obtaining 

appropriate permits. 

6.2.4 Increase in Domestic Sequestration Activities

With successful conduct and completion of the proposed experiment and other 

sequestration studies, government and industry would be expected to have access to sufficient 

information for considering future activities involving management of atmospheric CO2
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concentrations through geologic sequestration. Estimates of operating costs dictate that any 

large-scale CO2 sequestration activity would need to occur in an area near major CO2 sources. 

Many of these areas would be likely to involve existing oil and gas fields, where impacts would 

be incremental and minimal. At locations where CO2 sources are present but oil and gas fields 

are absent, sequestration options could include (1) piping or trucking the CO2 to some distant 

location where an existing oil or gas field could be used for sequestration or (2) drilling a well to 

inject CO2 into a brine-bearing formation locally. Economic and logistical lessons learned from 

the proposed pilot experiment would help determine the comparative feasibility of these 

approaches.

 
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7.0 IRREVERSIBLE AND IRRETRIEVABLE COMMITMENTS OF 

RESOURCES

Principal resources required for the proposed CO2 injection and monitoring experiment 

would comprise: (1) the materials (steel, water, and cement) needed to drill a new injection well 

and refit the existing monitoring wells; (2) the CO2 required to create the subsurface plume; (3) 

the fossil fuels consumed in drilling, refitting, and sampling wells and in transporting CO2 and 

wastes; and (4) minor amounts of land surface clearing during extension of well pads and drilling 

of shot holes for the 3-D VSP. For the new injection well, several truckloads of caliche road base 

would be applied to expand the existing well pad for drilling the new well, up to 6,000 barrels of 

water for drilling mud would be used to advance the drill bit to an estimated depth of 1,820 m 

(6,000 ft) and return cuttings to the surface, steel surface and injection casing would be installed 

to protect shallow, fresh groundwater and permit injection at the selected stratigraphic interval, 

and steel wellhead valves and pipes would be used to control CO2 injection. The 3,750 tons of 

CO2 proposed for use would possess a commercial market value of approximately $375,000. The 

CO2 to be used for the project, however, would be obtained from a source that would have vented 

the CO2 to the atmosphere as a waste. Fossil fuels, primarily diesel fuel, would be used by the 

drilling and work-over rigs and by the trucks hauling 165 loads of CO2, produced water, and 

drilling fluids. Based on the relatively small quantities of common and widely available materials 

that would be used, no adverse effects on material resources would be expected.
PILOT EXPERIMENT FOR GEOLOGIC SEQUESTRATION OF CO2 IN SALINE AQUIFER BRINE FORMATIONS

RESOURCE COMMITMENTS DOE/EA-1482

7 - 2

 
PILOT EXPERIMENT FOR GEOLOGIC SEQUESTRATION OF CO2 IN SALINE AQUIFER BRINE FORMATIONS

DOE/EA-1482 NO ACTION ALTERNATIVE

8 - 1

8.0 ENVIRONMENTAL CONSEQUENCES OF THE NO ACTION 

ALTERNATIVE

Under the No Action Alternative, no change in current hydrocarbon extraction or other 

activities at the South Liberty Oilfield would result. The minimal local environmental 

consequences associated with drilling a new well (well-pad expansion, mud-pit excavation, and 

well drilling) would be avoided. The experiment to inject 3,750 tons of CO2 into a subsurface 

saline aquifer, monitor the lateral migration of the CO2 plume, and assess the performance of 

stratigraphic sealing horizons in sequestering CO2 underground would not be conducted. The 

3,750 tons of CO2 that would have been injected into the subsurface would be released to the 

atmosphere. Because underground CO2 injection into saline aquifers is one of the candidate 

approaches being evaluated for technical viability as a possible method for CO2 sequestration, the 

No Action Alternative would result in a lost opportunity to develop information on a potentially 

viable approach for helping to avoid the climate-altering effects from increases in the atmospheric 

concentration of greenhouse gases.
PILOT EXPERIMENT FOR GEOLOGIC SEQUESTRATION OF CO2 IN SALINE AQUIFER BRINE FORMATIONS

NO ACTION ALTERNATIVE DOE/EA-1482

8 - 2

 
PILOT EXPERIMENT FOR GEOLOGIC SEQUESTRATION OF CO2 IN SALINE AQUIFER BRINE FORMATIONS

DOE/EA-1482 SIMILAR ACTIONS

9 - 1

9.0 SIMILAR ACTIONS AND ACTIONS BEING CONSIDERED 

UNDER OTHER NEPA REVIEWS

The proposed action, for DOE support in evaluating the suitability of CO2 sequestration 

in deep saline aquifers, is not similar to any other action being considered (or currently being 

implemented) by DOE and is not a segment of any other action for which review under NEPA 

would be required.
PILOT EXPERIMENT FOR GEOLOGIC SEQUESTRATION OF CO2 IN SALINE AQUIFER BRINE FORMATIONS

SIMILAR ACTIONS DOE/EA-1482

9 - 2

 
PILOT EXPERIMENT FOR GEOLOGIC SEQUESTRATION OF CO2 IN SALINE AQUIFER BRINE FORMATIONS

DOE/EA-1482 RELATIONSHIP TO LAND USE PLANS

10 - 1

10.0 RELATIONSHIP OF THE PROPOSED ACTION TO 

APPLICABLE LAND USE PLANS AND POLICIES

The proposed pilot experiment would not require any change in the current land use of 

the Liberty County site as an operating oilfield. The proposed incremental enlargement of an 

existing well pad, the drilling of a new well, injection of CO2, and monitoring of CO2 at existing 

wells would represent no substantive changes to current land use plans and policies. Similar 

drilling and fluid-extraction activities have been ongoing in the area since hydrocarbon 

production began in the 1920s.
PILOT EXPERIMENT FOR GEOLOGIC SEQUESTRATION OF CO2 IN SALINE AQUIFER BRINE FORMATIONS

RELATIONSHIP TO LAND USE PLANS DOE/EA-1482

10 - 2

 
PILOT EXPERIMENT FOR GEOLOGIC SEQUESTRATION OF CO2 IN SALINE AQUIFER BRINE FORMATIONS

DOE/EA-1482 PUBLIC PARTICIPATION

11 - 1

11.0 CONSULTATION AND PUBLIC PARTICIPATION

11.1 Consultation

The agencies and organizations identified in Table 6 were contacted as part of the 

environmental evaluation process for the proposed pilot experiment. Copies of correspondence 

exchanged with the two resource agencies, the Texan Archeological Research Laboratory and the 

U.S. Fish and Wildlife Service, that have authorities over historic properties and endangered 

species, respectively, are provided in Appendix A.

Table 6. Agency and organization contacts

No. Agency contacted Date Author Response 

Date

Author

1 Texas Archeological 

Research Laboratory

10/4/2002 Paine 10/7/2002 Azulay

2 U.S. Fish and Wildlife 

Service

10/9/2002 Paine 10/30/2002 Morgan

3 U.S. Army Corps of 

Engineers

10/9/2002 Paine 10/9/2002 Dunn

4 Texas Commission on 

Environmental Quality 

(Underground Injection 

Control Section)

Varied Knox Varied Fred Duffy

5 Texas Commission on 

Environmental Quality 

(surface casing and 

groundwater protection)

12/6/2002 Paine, Knox Traylor

6 Railroad Commission of 

Texas

Varied Hovorka, Knox Varied Ginn

7 Liberty County Knox

8 City of Dayton Knox

9 City of Liberty Knox

10 Texas Department of 

Health (Radiation 

Control Section)

3/24/03 Knox 3/24/03 R. Cortez

11.2 Public Participation

A draft EA was distributed for review and comment to Federal and State agencies and to 

the public; copies were made available for review at both the Dayton Library in Dayton, Texas, 

and the Liberty Municipal Library in Liberty, Texas. The draft EA was also posted on the 

National Energy Technology Laboratory’s web site for public review and comment. Public 
PILOT EXPERIMENT FOR GEOLOGIC SEQUESTRATION OF CO2 IN SALINE AQUIFER BRINE FORMATIONS

PUBLIC PARTICIPATION DOE/EA-1482

11 - 2

notices announcing availability of the draft EA for review and comment were published in the 

Liberty Gazette on August 27 and September 3, 2003, and in The Vindicator on August 24 

and 27, 2003. Both newspapers are printed in Liberty, Texas, and are generally circulated within 

Liberty County. By the close of the public comment period on September 12, 2003, no adverse 

comments regarding the proposed action were received; only one comment was received, 

indicating interest in using CO2 for commercial purposes. Since closing of the comment period, 

no comments were received.
PILOT EXPERIMENT FOR GEOLOGIC SEQUESTRATION OF CO2 IN SALINE AQUIFER BRINE FORMATIONS

DOE/EA-1482 REFERENCES

12 - 1

12.0 REFERENCES

Aronow, S., and Barnes, V.E., 1982, Geologic atlas of Texas: Houston Sheet: The University of 

Texas at Austin, Bureau of Economic Geology, scale 1:250,000.

Baker, E.T., Jr., 1979, Stratigraphic and hydrogeologic framework of part of the coastal plain of 

Texas: Austin, Texas, Texas Department of Water Resources, Report No. 236, 43 p.

Benson, S.M., Hepple, R., Apps, J., Tsang, C.F., and Lippmann, M., 2003, Lessons learned from 

natural and industrial analogues for storage of carbon dioxide in deep geological 

formations: Lawrence Berkeley National Laboratory LBNL-51170, 134 p.

Bomar, G.W., 1983, Texas weather: Austin, University of Texas Press, 265 p.

Carr, J.E. Meyer, W.R., Sandeen, W.M., and McLane, I.R., 1985, Digital models for simulation 

of ground-water hydrology of the Chicot and Evangeline aquifers along the Gulf Coast of 

Texas: Austin, Texas Department of Water Resources, Report No. 289, 101 p.

Cowardin, L.M., Carter, Virginia, Golet, F.C., and LaRoe, E.T., 1979, Classification of wetlands 

and deepwater habitats of the United States: Washington, Office of Biological Services, 

Fish and Wildlife Service, U.S. Department of the Interior, FWS/OBS-79/31, 103 p.

Dougherty, J.P., 1980, Streamflow and reservoir-content records in Texas, compilation report, 

January 1889 through December 1975, Volume 1: Texas Department of Water 

Resources, 382 p.

Doughty, C.A., and Pruess, K., 2003, Modeling Supercritical CO2 Injection in Heterogeneous 

Porous Media: Proceedings, TOUGH Symposium, May 12-14, 2003, in press.

Doughty, C.A., Pruess, K., Benson, S.M., Hovorka, S.D., Knox, P.R., and Green, C.T, 2001, 

Capacity investigation of brine-bearing sands of the Frio Formation for geologic 

sequestration of CO2: in Proceedings, First National Conference on Carbon 

Sequestration, May 14-17, Washington, DC, sponsored by National Energy Technology 

Laboratory, 16 p. on CD.

Dutton, A.R., 1990, Regional geohydrology of the Gulf Coast aquifer in Matagorda and Wharton 

Counties: development of a numerical model to estimate the impact of watermanagement strategies: The University of Texas at Austin, Bureau of Economic 

Geology, contract report prepared for Lower Colorado River Authority, Austin, Texas, 

under Contract IAC (88-89)0910, 116 p.

Eaton, B.A., 1969, Fracture gradient prediction and its application in oilfield operations: Journal 

of Petroleum Technology, v. 246, p. 1353-1361.

Fisher, W.L., McGowen, J.H., Brown, L.F., Jr., Groat, C.G., 1972, Environmental geologic atlas 

of the Texas Coastal Zone: Galveston–Houston sheet: The University of Texas at Austin, 

Bureau of Economic Geology, 91 p.

Galloway, W.E., Bebout, D.G, Fisher, W.L., Dunlap J.B., Jr., Cabrera-Castro, R., Lugo-Rivera, 

J.E., and Scott, T.M., 1991, Chapter 11: Cenozoic, in Salvador, A., ed., The Gulf of 

Mexico Basin: The Geology of North America Volume J, The Geological Society of 

America, Boulder, Colorado, p. 245-324.

Galloway, W.E., Hobday, D.K., and Magara, K., 1982, Frio Formation of the Texas Gulf Coast 

Basin—depositional systems, structural framework, and hydrocarbon origin, migration, 
PILOT EXPERIMENT FOR GEOLOGIC SEQUESTRATION OF CO2 IN SALINE AQUIFER BRINE FORMATIONS

REFERENCES DOE/EA-1482

12 - 2

distribution, and exploration potential: The University of Texas at Austin, Bureau of 

Economic Geology Report of Investigations No. 122, 78 p.

Guevara-Sanchez, E.H., 1974, Pleistocene facies in the subsurface of the southeast Texas Coastal 

Plain: The University of Texas at Austin, Ph.D. dissertation, 133 p.

Halbouty, M.T., 1962, South Liberty Field; Liberty County, Texas, in Denham, R.L., ed., Typical 

oil & gas fields of southeast Texas: Houston, Texas, Houston Geological Society, p. 200-

206.

Hitchon, Brian, ed., 1996, Aquifer disposal of carbon dioxide: hydrodynamic and mineral 

trapping-proof of concept: Sherwood Park, Alberta, Canada, Geoscience Publishing Ltd..

Holtz, M.H., 2002, Residual gas saturation to aquifer influx: a calculation method for 3-D 

computer reservoir model construction: Society of Petroleum Engineers, Inc., Paper SPE 

75502, 10 p.

Holtz, M.H., 2003, Pore-scale influences on saline aquifer CO2 sequestration: American 

Association of Petroleum Geologists Annual Convention Official Program, v. 12.

Hooper, E.C.D., 1991, Fluid migration along growth faults in compacting sediments: Journal of 

Petroleum Geology, v. 14, no. 2, p. 161-180.

Hovorka, S.D., Doughty, C., Knox, P.R., Green, C.T., Pruess, K., and Benson, S.M., 2001, 

Evaluation of brine-bearing sands of the Frio Formation, upper Texas gulf coast, for 

geological sequestration of CO2: in Proceedings, First National Conference on Carbon 

Sequestration, May 14-17, Washington DC, sponsored by National Energy Technology 

Laboratory, 16 p. on CD.

Hovorka, S.D., Romero, M.L., Treviño, R.H., Warne, A.G., Ambrose, W.A., Knox, P.R., and 

Tremblay, T.A., 2000, Project evaluation: phase II: optimal geological environments for 

carbon dioxide disposal in brine-bearing formations (aquifers) in the United States: The 

University of Texas at Austin, Bureau of Economic Geology, final report prepared for 

U.S. Department of Energy, National Energy Technology Laboratory, under Contract No. 

DE-AC26-98FT40417, 222 p., 

http://www.beg.utexas.edu/environqlty/co2seq/dispslsaln.htm.

Intergovernmental Panel on Climate Change, 2001, Climate change 2001: working group I: the 

scientific basis, Chapter 3, The Carbon Cycle and Atmospheric Carbon Dioxide, 

http://www.grida.no/climate/ipcc_tar/

Keeling, C.D., and Whorf, T.P., 2002, Atmospheric CO2 records from sites in the SIO air 

sampling network, in Trends: a compendium of data on global change: Oak Ridge, TN, 

U.S. Department of Energy, Oak Ridge National Laboratory, Carbon Dioxide 

Information Analysis Center, http://cdiac.esd.ornl.gov/trends/co2/sio-mlo.htm.

Loucks, R.G., Dodge, M.M., and Galloway, W.E., 1984, Regional controls on diagenesis and 

reservoir quality in Lower Tertiary sandstones along the Texas Gulf Coast, in McDonald, 

D.A., and Surdam, R.C., Clastic diagenesis: American Association of Petroleum 

Geologists Memoir 37, p. 15-45.

Morton, R.A., Jirik, L.A., and Foote, R.Q., 1985, Structural cross sections, Miocene Series, Texas 

Continental Shelf: The University of Texas at Austin,

Bureau of Economic Geology, Cross Section Series No. 5, 8 p.

Morton, R.A., and Land, L.S., 1987, Regional variations in formation water chemistry, Frio 

Formation (Oligocene), Texas Gulf Coast: American Association of Petroleum 

Geologists Bulletin v. 71, no. 2, p. 191-206.
PILOT EXPERIMENT FOR GEOLOGIC SEQUESTRATION OF CO2 IN SALINE AQUIFER BRINE FORMATIONS

DOE/EA-1482 REFERENCES

12 - 3

National Energy Policy Development Group, 2001, 

http://www.fe.doe.gov/general/energypolicy/chapter3.pdf

Oldenburg, C.M., Unger, A.J.A., and Hepple, R.P., 2002a, On atmospheric dispersion of CO2

seepage from geologic carbon sequestration sites: Berkeley, California, Lawrence 

Berkeley National Laboratory LBNL-51734, 34 p.

Oldenburg, C.M., Unger, A.J.A., Hepple, R.P., and Jordan, P.D., 2002b, On leakage and seepage 

from geologic carbon sequestration sites: Berkeley, California, Lawrence Berkeley 

National Laboratory LBNL-51130, 29 p.

Pruess, K., Oldenburg, C.M., and Moridis, G., 1999, TOUGH2 user’s guide, version 2.0: Rep. 

LBNL-43134: Lawrence Berkeley National Laboratory. 

Railroad Commission of Texas, 2002, Texas ACTI oil & gas production database: 

http://driller.rrc.state.tx.us/Apps/WebObjects/acti.

Rasmussen, Birger, 1997, Fluorescent growth bands in irradiated-bitumen nodules: evidence of 

episodic hydrocarbon migration: American Association of Petroleum Geologists Bulletin, 

v. 81, no. 1, p. 17-25. 

U.S. Census Bureau, 2001, Table CO-EST2001-06-48: Texas counties ranked by population size, 

July 1, 2001: Population Division, http://www.census.gov/.

U.S. Climate Change Science Program / U.S. Global Change Research, 2003, U.S. national 

assessment of the potential consequences of climate variability and change educational 

resources, http://www.usgcrp.gov/usgcrp/nacc/education/default.htm.

U.S. Department of Agriculture, 1996, Soil survey geographic database for Liberty County, 

Texas: Fort Worth, Texas, U.S. Department of Agriculture, Natural Resources 

Conservation Service, http://www.ftw.nrcs.usda.gov/ssur_data.html.

U.S. Department of Energy, 1999, Carbon Sequestration—Research and Development, 

http://www.fe.doe.gov/coal_power/sequestration/reports/rd/index.shtml.

U.S. Fish and Wildlife Service, 1997, National wetlands inventory—Moss Bluff quadrangle: St. 

Petersburg, U.S. Fish and Wildlife Service, National Wetlands Inventory, 

ftp://ftp.nwi.fws.gov/arcdata/houston/mossbl.e00.

Wardlaw, N.C., 1982, The effects of geometry, wettability, viscosity, and interfacial tension on 

trapping in single pore-throat pairs: Journal of Canadian Petroleum Technology, MayJune, p. 21-27.

Wesson, R.L., and Nicholson, C., 1987, Earthquake hazard associated with deep well injection: 

U.S. Geological Survey Open File Report 87-331, 107 p.

White, W.A., Calnan, T.R., Morton, R.A., Kimble, R.S., Littleton, T.G., McGowen, J.H., Nance, 

H.S., and Schmedes, K.E., 1985, Submerged lands of Texas, Galveston-Houston area: 

sediments, geochemistry, benthic macroinvertebrates, and associated wetlands: The 

University of Texas at Austin, Bureau of Economic Geology, Special Publication, 145 p.
PILOT EXPERIMENT FOR GEOLOGIC SEQUESTRATION OF CO2 IN SALINE AQUIFER BRINE FORMATIONS

REFERENCES DOE/EA-1482

12 - 4
MATERIAL SAFETY DATA SHEET

PRODUCT NAME: ARGON

MSDS: G-6

Revised: 6/7/96 Page 1 of 6

1. Chemical Product and Company Identification

BOC Gases,

Division of

The BOC Group, Inc.

575 Mountain Avenue

Murray Hill, NJ 07974

TELEPHONE NUMBER: (908) 464-8100

BOC Gases

Division of

BOC Canada Limited

5975 Falbourne Street, Unit 2

Mississauga, Ontario L5R 3W6

TELEPHONE NUMBER: (905) 501-1700

24-HOUR EMERGENCY TELEPHONE NUMBER:

CHEMTREC (800) 424-9300

24-HOUR EMERGENCY TELEPHONE NUMBER:

(905) 501-0802

EMERGENCY RESPONSE PLAN NO: 20101

PRODUCT NAME: ARGON

CHEMICAL NAME: Argon

COMMON NAMES/SYNONYMS: Argon, compressed

TDG (Canada) CLASSIFICATION: 2.2

WHMIS CLASSIFICATION: A

PREPARED BY: Loss Control (908)464-8100/(905)501-1700

PREPARATION DATE: 6/1/95

REVIEW DATES: 6/7/96

2. Composition, Information on Ingredients

INGREDIENT % VOLUME PEL-OSHA1 TLV-ACGIH2 LD50 or LC50

Route/Species

Argon

FORMULA: Ar

CAS: 7440-37-1

RTECS #: CF2300000

100.0 Simple Asphyxiant Simple Asphyxiant Not Available

1 As stated in 29 CFR 1910, Subpart Z (revised July 1, 1993)

2 As stated in the ACGIH 1994-95 Threshold Limit Values for Chemical Substances and Physical Agents

3. Hazards Identification

EMERGENCY OVERVIEW

Simple Asphyxiant - This product does not contain oxygen and may cause asphyxia if released in a

confined area. Maintain oxygen levels above 19.5%. Nonflammable.
PRODUCT NAME: ARGON

MSDS: G-6

Revised: 6/7/96 Page 2 of 6

ROUTE OF ENTRY:

Skin Contact

Yes

Skin Absorption

No

Eye Contact

Yes

Inhalation

Yes

Ingestion

No

HEALTH EFFECTS:

Exposure Limits

No

Irritant

No

Sensitization

No

Teratogen

No

Reproductive Hazard

No

Mutagen

No

Synergistic Effects

None reported

Carcinogenicity: -- NTP: No IARC: No OSHA: No

EYE EFFECTS:

No adverse effects anticipated.

SKIN EFFECTS:

No adverse effects anticipated.

INGESTION EFFECTS:

No adverse effects anticipated.

INHALATION EFFECTS:

Product is a non-toxic simple asphyxiant. Effects of oxygen deficiency resulting from simple asphyxiants may

include: rapid breathing, diminished mental alertness, impaired muscular coordination, faulty judgement,

depression of all sensations, emotional instability, and fatigue. As asphyxiation progresses, nausea, vomiting,

prostration, and loss of consciousness may result, eventually leading to convulsions, coma, and death.

Oxygen deficiency during pregnancy has produced developmental abnormalities in humans and experimental

animals.

NFPA HAZARD CODES HMIS HAZARD CODES RATINGS SYSTEM

Health: 0 Health: 0 0 = No Hazard

Flammability: 0 Flammability: 0 1 = Slight Hazard

Reactivity: 0 Reactivity: 0 2 = Moderate Hazard

3 = Serious Hazard

4 = Severe Hazard

4. First Aid Measures

EYES:

Never introduce ointment or oil into the eyes without medical advice! If pain is present, refer the victim to an

ophthalmologist for treatment and follow up.

SKIN:

None anticipated.

INGESTION:

Ingestion is unlikely as product is a gas at room temperature.

INHALATION:
PRODUCT NAME: ARGON

MSDS: G-6

Revised: 6/7/96 Page 3 of 6

PROMPT MEDICAL ATTENTION IS MANDATORY IN ALL CASES OF OVEREXPOSURE. RESCUE

PERSONNEL SHOULD BE EQUIPPED WITH SELF-CONTAINED BREATHING APPARATUS. Victims

should be assisted to an uncontaminated area and inhale fresh air. Quick removal from the contaminated area is

most important. Unconscious persons should be moved to an uncontaminated area, and if breathing has stopped,

administer artificial resuscitation and supplemental oxygen. Further treatment should be symptomatic and

supportive.

5. Fire Fighting Measures

Conditions of Flammability: Nonflammable

Flash point:

None

Method:

Not Applicable

Autoignition

Temperature: None

LEL(%): None UEL(%): None

Hazardous combustion products: None

Sensitivity to mechanical shock: None

Sensitivity to static discharge: None

FIRE AND EXPLOSION HAZARDS:

None. Nonflammable

EXTINGUISHING MEDIA:

None required. Use as appropriate for surrounding materials.

6. Accidental Release Measures

Evacuate all personnel from affected area. Use appropriate protective equipment. If leak is in container or

container valve, contact the appropriate emergency telephone number listed in Section 1 or call your closest

BOC location.

7. Handling and Storage

Electrical classification:

Non-hazardous.

This gas mixture is noncorrosive and may be used with all common structural materials.

Use only in well-ventilated areas. Valve protection caps must remain in place unless container is secured with

valve protection outlet piped to use point. Do not drag, slide or roll cylinders. Use a suitable hand truck for

cylinder movement. Use a pressure reducing regulator when connecting cylinder to lower pressure (<3000 psig)

piping or systems. Do not heat cylinder by any means to increase the discharge rate of product from the

cylinder. Use a check valve or trap in the discharge line to prevent hazardous back flow into the cylinder.

Protect cylinders from physical damage. Store in cool, dry, well-ventilated area of non-combustible construction

away from heavily trafficked areas and emergency exits. Do not allow the temperature where cylinders are

stored to exceed 125 o

F (52 oC). Cylinders should be stored upright and firmly secured to prevent falling or

being knocked over. Use a "first in-first out" inventory system to prevent full cylinders being stored for

excessive periods of time.

For additional recommendations, consult Compressed Gas Association Pamphlets P-1, P-14, P-9, and Safety

Bulletin SB-2.
PRODUCT NAME: ARGON

MSDS: G-6

Revised: 6/7/96 Page 4 of 6

Never carry a compressed gas cylinder or a container of a gas in cryogenic liquid form in an enclosed space such

as a car trunk, van or station wagon. A leak can result in a fire, explosion, asphyxiation or a toxic exposure.

8. Exposure Controls, Personal Protection

EXPOSURE LIMITS1:

INGREDIENT % VOLUME PEL-OSHA2 TLV-ACGIH3 LD50 or LC50

Route/Species

Argon

FORMULA: Ar

CAS: 7440-37-1

RTECS #: CF2300000

100.0 Simple Asphyxiant Simple Asphyxiant Not Available

1 Refer to individual state of provincial regulations, as applicable, for limits which may be more stringent than

 those listed here.

2 As stated in 29 CFR 1910, Subpart Z (revised July 1, 1993)

3 As stated in the ACGIH 1994-1995 Threshold Limit Values for Chemical Substances and Physical Agents.

ENGINEERING CONTROLS:

Local exhaust to prevent accumulation of high concentrations so as to reduce the oxygen level in the air to less

than 19.5%.

EYE/FACE PROTECTION:

Safety goggles or glasses as appropriate for the job.

SKIN PROTECTION:

Protective gloves of material appropriate for the job.

RESPIRATORY PROTECTION:

Positive pressure air line with full-face mask and escape bottle or self-contained breathing apparatus should be

available for emergency use.

OTHER/GENERAL PROTECTION:

Safety shoes or other footwear as appropriate for the job.
PRODUCT NAME: ARGON

MSDS: G-6

Revised: 6/7/96 Page 5 of 6

9. Physical and Chemical Properties

PARAMETER VALUE UNITS

Physical state (gas, liquid, solid) : Gas

Vapor pressure : Not Available

Vapor density (Air = 1) : 1.38

Evaporation point : Not Available

Boiling point : -302.6

: -185.9

o

F

o

C

Freezing point : -308.9

: -189.4

o

F

o

C

pH : Not Applicable

Specific gravity : Not Available

Oil/water partition coefficient : Not Available

Solubility (H20) : Slight

Odor threshold : Not Applicable

Odor and appearance : Colorless, odorless gas

10. Stability and Reactivity

STABILITY:

Stable

INCOMPATIBLE MATERIALS:

None

HAZARDOUS POLYMERIZATION:

Does not occur.

11. Toxicological Information

Oxygen deficiency during pregnancy has produced developmental abnormalities in humans and experimental

animals.

No data given in the Registry of Toxic Effects of Chemical Substances (RTECS) or Sax, Dangerous Properties

of Industrial Materials, 7th ed.

12. Ecological Information

No data given.

13. Disposal Considerations

Do not attempt to dispose of residual waste or unused quantities. Return in the shipping container PROPERLY

LABELED, WITH ANY VALVE OUTLET PLUGS OR CAPS SECURED AND VALVE PROTECTION CAP

IN PLACE to BOC Gases or authorized distributor for proper disposal.
PRODUCT NAME: ARGON

MSDS: G-6

Revised: 6/7/96 Page 6 of 6

14. Transport Information

PARAMETER United States DOT Canada TDG

PROPER SHIPPING NAME: Argon, compressed Argon, compressed

HAZARD CLASS: 2.2 2.2

IDENTIFICATION NUMBER: UN 1006 UN 1006

SHIPPING LABEL: NONFLAMMABLE GAS NONFLAMMABLE GAS

15. Regulatory Information

SARA TITLE III NOTIFICATIONS AND INFORMATION

SARA TITLE III - HAZARD CLASSES:

Sudden Release of Pressure Hazard

16. Other Information

Compressed gas cylinders shall not be refilled without the express written permission of the owner. Shipment of

a compressed gas cylinder which has not been filled by the owner or with his/her (written) consent is a violation

of transportation regulations.

DISCLAIMER OF EXPRESSED AND IMPLIED WARRANTIES:

Although reasonable care has been taken in the preparation of this document, we extend no warranties and make

no representations as to the accuracy or completeness of the information contained herein, and assume no

responsibility regarding the suitability of this information for the user’s intended purposes or for the

consequences of its use. Each individual should make a determination as to the suitability of the information for

their particular purpose(s).
MSDS

DYNOSEIS®
MSDS

DYNOSEIS®
MSDS

DYNOSEIS®
MSDS

EOSIN

**** SECTION 1 - CHEMICAL PRODUCT AND COMPANY IDENTIFICATION   

MSDS Name: Eosin Y

Catalog Numbers:

 S71268, S71268-1, S71271-1, BP2419-100, BP2419-25, E511 100, E511 25,

 E511-100, E511-25, E511100, E51125, NC9487912, NC9671661, S712681, S712711,

 XXE51110KG

Synonyms:

 Acid Red 87; Bromoeosine; Disodium Eosine; Eosine Yellowish;

 Tetrabromfluorescein, CI 45380.

Company Identification: Fisher Scientific

 1 Reagent Lane

 Fairlawn, NJ 07410

For information, call: 201-796-7100

Emergency Number: 201-796-7100

For CHEMTREC assistance, call: 800-424-9300

For International CHEMTREC assistance, call: 703-527-3887 

 ** ** SECTION 2 - COMPOSITION, INFORMATION ON INGREDIENTS   

+----------------+--------------------------------------+----------+-----------+

| CAS# | Chemical Name | % | EINECS# |

|----------------|--------------------------------------|----------|-----------|

| 17372-87-1 |ACID RED 87 | 100 | 241-409-6 |

+----------------+--------------------------------------+----------+-----------+

 Hazard Symbols: None Listed.

 Risk Phrases: None Listed. 

 ** ** SECTION 3 - HAZARDS IDENTIFICATION   

 EMERGENCY OVERVIEW

Appearance: red to brown.

Caution! The toxicological properties of this material have not been

fully investigated. May cause eye and skin irritation. May cause

respiratory and digestive tract irritation.

Target Organs: No data found. 

Potential Health Effects

 Eye:

 May cause eye irritation. This product contains an anionic dye.

 Similar dyes have not caused injury to the cornea or conjunctiva in

 documented exposure cases with human or rabbit eyes.

 Skin:

 May cause skin irritation.

 Ingestion:

 May cause gastrointestinal irritation with nausea, vomiting and

 diarrhea. The toxicological properties of this substance have not

 been fully investigated.

 Inhalation:

 May cause respiratory tract irritation. The toxicological properties

 of this substance have not been fully investigated.

 Chronic:

 No information found. 
MSDS

EOSIN

 ** ** SECTION 4 - FIRST AID MEASURES   

 Eyes:

 Flush eyes with plenty of water for at least 15 minutes,

 occasionally lifting the upper and lower eyelids. Get medical aid.

 Skin:

 Flush skin with plenty of soap and water for at least 15 minutes

 while removing contaminated clothing and shoes. Get medical aid if

 irritation develops or persists.

 Ingestion:

 If victim is conscious and alert, give 2-4 cupfuls of milk or water.

 Get medical aid immediately.

 Inhalation:

 Remove from exposure to fresh air immediately. If not breathing,

 give artificial respiration. If breathing is difficult, give oxygen.

 Get medical aid.

 Notes to Physician:

 The use of sodium chloride as antidotal treatment for bromine salt

 overdose should be made only by qualified medical personnel (Medical

 Toxicology, 

 ** ** SECTION 5 - FIRE FIGHTING MEASURES   

 General Information:

 As in any fire, wear a self-contained breathing apparatus in

 pressure-demand, MSHA/NIOSH (approved or equivalent), and full

 protective gear. During a fire, irritating and highly toxic gases

 may be generated by thermal decomposition or combustion.

 Extinguishing Media:

 In case of fire, use water, dry chemical, chemical foam, or

 alcohol-resistant foam.

 Autoignition Temperature:Not available.

 Flash Point: Not available.

 Explosion Limits, lower:Not available.

 Explosion Limits, upper:Not available.

 NFPA Rating: (estimated) Health: 1; Flammability: 0; Reactivity: 0 

 ** ** SECTION 6 - ACCIDENTAL RELEASE MEASURES   

 General Information: Use proper personal protective equipment as indicated

 in Section 8.

 Spills/Leaks:

 Sweep up, then place into a suitable container for disposal. Avoid

 generating dusty conditions. 

 ** ** SECTION 7 - HANDLING and STORAGE   

 Handling:

 Wash thoroughly after handling. Remove contaminated clothing and

 wash before reuse. Use with adequate ventilation. Minimize dust

 generation and accumulation. Avoid contact with skin and eyes. Keep

 container tightly closed. Avoid ingestion and inhalation.

 Storage:

 Store in a cool, dry, well-ventilated area away from incompatible

 substances. 
MSDS

EOSIN

 ** ** SECTION 8 - EXPOSURE CONTROLS, PERSONAL PROTECTION   

 Engineering Controls:

 Use adequate ventilation to keep airborne concentrations low. 

 Exposure Limits

+--------------------+-------------------+-------------------+-----------------+

| Chemical Name | ACGIH | NIOSH |OSHA - Final PELs|

|--------------------|-------------------|-------------------|-----------------|

| ACID RED 87 |none listed |none listed |none listed |

+--------------------+-------------------+-------------------+-----------------+ 

 OSHA Vacated PELs:

 ACID RED 87:

 No OSHA Vacated PELs are listed for this chemical. 

 Personal Protective Equipment 

 Eyes:

 Wear appropriate protective eyeglasses or chemical

 safety goggles as described by OSHA's eye and face

 protection regulations in 29 CFR 1910.133 or European

 Standard EN166.

 Skin:

 Wear appropriate protective gloves to prevent skin

 exposure.

 Clothing:

 Wear appropriate protective clothing to minimize

 contact with skin.

 Respirators:

 Follow the OSHA respirator regulations found in 29CFR

 1910.134 or European Standard EN 149. Always use a

 NIOSH or European Standard EN 149 approved respirator

 when necessary. 

 ** ** SECTION 9 - PHYSICAL AND CHEMICAL PROPERTIES   

Physical State: Solid

Appearance: red to brown

Odor: none reported

pH: Not available.

Vapor Pressure: Negligible.

Vapor Density: Not applicable.

Evaporation Rate: Negligible.

Viscosity: Not available.

Boiling Point: Not applicable.

Freezing/Melting Point: Not available.

Decomposition Temperature: Not available.

Solubility in water: Soluble in water.

Specific Gravity/Density: Not available.

Molecular Formula: C20H8Br4O5.2Na

Molecular Weight: 693.6486 
MSDS

EOSIN

 ** ** SECTION 10 - STABILITY AND REACTIVITY   

 Chemical Stability:

 Stable under normal temperatures and pressures.

 Conditions to Avoid:

 High temperatures, incompatible materials.

 Incompatibilities with Other Materials:

 Strong oxidizers.

 Hazardous Decomposition Products:

 Carbon monoxide, carbon dioxide, hydrogen bromide.

 Hazardous Polymerization: Has not been reported. 

 ** ** SECTION 11 - TOXICOLOGICAL INFORMATION   

 RTECS#:

 CAS# 17372-87-1: LM5850000

 LD50/LC50:

 CAS# 17372-87-1: Oral, mouse: LD50 = 2344 mg/kg.

 Carcinogenicity:

 ACID RED 87 -

 Not listed by ACGIH, IARC, NIOSH, NTP, or OSHA.

 Epidemiology:

 No information available.

 Teratogenicity:

 No information available.

 Reproductive Effects:

 No information available.

 Neurotoxicity:

 No information available.

 Mutagenicity:

 Please refer to RTECS# LM5850000 for specific information.

 Other Studies:

 None. 

 ** ** SECTION 12 - ECOLOGICAL INFORMATION   

 Other

 No information available. 

 ** ** SECTION 13 - DISPOSAL CONSIDERATIONS   

Chemical waste generators must determine whether a discarded chemical

is classified as a hazardous waste.

US EPA guidelines for the classification determination are listed in

40 CFR Parts 261.3. Additionally, waste generators must consult state

and local hazardous waste regulations to ensure complete and accurate

classification.

RCRA P-Series: None listed.

RCRA U-Series: None listed. 

 ** ** SECTION 14 - TRANSPORT INFORMATION   

 US DOT

 No information available
MSDS

EOSIN

 Canadian TDG

 No information available. 

 ** ** SECTION 15 - REGULATORY INFORMATION   

US FEDERAL

 TSCA

 CAS# 17372-87-1 is listed on the TSCA inventory.

 Health & Safety Reporting List

 None of the chemicals are on the Health & Safety Reporting List.

 Chemical Test Rules

 None of the chemicals in this product are under a Chemical Test Rule.

 Section 12b

 None of the chemicals are listed under TSCA Section 12b.

 TSCA Significant New Use Rule

 None of the chemicals in this material have a SNUR under TSCA.

 SARA

 Section 302 (RQ)

 None of the chemicals in this material have an RQ.

 Section 302 (TPQ)

 None of the chemicals in this product have a TPQ.

 SARA Codes

 CAS # 17372-87-1: acute.

 Section 313

 No chemicals are reportable under Section 313.

 Clean Air Act:

 This material does not contain any hazardous air pollutants.

 This material does not contain any Class 1 Ozone depletors.

 This material does not contain any Class 2 Ozone depletors.

 Clean Water Act:

 None of the chemicals in this product are listed as Hazardous

 Substances under the CWA.

 None of the chemicals in this product are listed as Priority

 Pollutants under the CWA.

 None of the chemicals in this product are listed as Toxic Pollutants

 under the CWA.

 OSHA:

 None of the chemicals in this product are considered highly hazardous

 by OSHA.

STATE

 ACID RED 87 is not present on state lists from CA, PA, MN, MA, FL, or

 NJ.

 California No Significant Risk Level:

 None of the chemicals in this product are listed.

European/International Regulations

 European Labeling in Accordance with EC Directives

 Hazard Symbols: Not available.

 Risk Phrases:

 Safety Phrases:

 WGK (Water Danger/Protection)

 CAS# 17372-87-1: 1

 United Kingdom Occupational Exposure Limits 

 Canada

 CAS# 17372-87-1 is listed on Canada's DSL List.

 This product has a WHMIS classification of D2B.
MSDS

EOSIN

 CAS# 17372-87-1 is not listed on Canada's Ingredient Disclosure List.

 Exposure Limits 

 ** ** SECTION 16 - ADDITIONAL INFORMATION **** 

 MSDS Creation Date: 12/12/1997 Revision #2 Date: 8/02/2000 

 The information above is believed to be accurate and represents the best

 information currently available to us. However, we make no warranty of

 merchantability or any other warranty, express or implied, with respect to

 such information, and we assume no liability resulting from its use. Users

 should make their own investigations to determine the suitability of the

 information for their particular purposes. In no way shall the company be

 liable for any claims, losses, or damages of any third party or for lost

 profits or any special, indirect, incidental, consequential or exemplary

 damages, howsoever arising, even if the company has been advised of

 the possibility of such damages.
FLUTEC TG m-PDMCHTM

Product Flutec TG m-PDMCH 8

th December 1999 PAGE 1/4

Trade Name: Flutec TG m-PDMCH

Material Type: Perfluorocarbon

Company: F2 Chemicals Ltd

Address: Lea Lane

 Lea Town

Preston

Lancashire

PR4 0RZ

UK

Telephone: +44 (0) 1772 775804

Fax: +44 (0) 1772 775809

Emergency Telephone: +44 (0) 1772 775833

a) Substances Predominantly Perfluoro-1,3-dimethylcyclohexane

b) CAS Number 335-27-3

a) Hazard Symbols: Not applicable 

b) Risk and Safety Keep container tightly closed.

Caution, avoid prolonged and repeated breathing of 

concentrated vapour.

 Thermal decomposition may produce toxic products.

Small amounts of decomposition may occur above 400oC.

When using do not smoke.

Do not empty into drains.

a) Inhalation: In case of severe exposure; remove from exposure , rest and 

keep warm. Apply artificial respiration if breathing has ceased. 

Obtain medical attention if effects are other than slight. 

b) Skin contact: Remove contaminated clothing and wash off with soap and 

water. Obtain medical attention if adverse symptoms arise.

c) Eye contact: Irrigate thoroughly with water. Obtain medical attention if 

adverse symptoms arise. 

d) Ingestion: Wash out mouth with water. Obtain medical attention if adverse 

symptoms persist.

1 – SUBSTANCE IDENTIFICATION

2 - COMPOSITION

3 – HAZARD IDENTIFICATION

4 – FIRST AID MEASURES
PRODUCT: Flutec TG m-PDMCH 8

th December 1999 PAGE 2/4

a) Suitable Extinguishers: Carbon dioxide

 Alcohol resistant foam 

Powder 

Halons 

 Water Fog 

Water Jets

Inert material – Sand, earth, etc

 Non-combustible material

b) Unsuitable Extinguishers: Not applicable.

c) Hazardous Decomposition: Toxic fumes may be produced on thermal decomposition.

In the presence of other reactive substances and in a fire 

situation where hydrogen containing compounds are 

present, Hydrogen Fluoride and other toxic products may 

be formed.

d) Special Procedures: Use water spray to cool containers.

Contact with flames gives rise of toxic vapours, avoid 

inhalation of these vapours.

Use approved self contained breathing apparatus.

Non-essential personnel should be evacuated from the 

area until any fumes have dispersed.

Handle contaminated fluid in a ventilated area, avoiding 

inhalation of vapour.

a) Exposure Controls Flutec liquid spillages produce very slippery surfaces 

which may be hazardous to personnel.

Evacuate area.

Do not allow spillage to enter drains and watercourse.

If water is contaminated inform relevant authority 

immediately.

b) Personnel Protection: Wear laboratory coat.

 Respiratory protection not normally required.

Wear impermeable gloves.

Wear chemical safety spectacles or goggles.

c) Disposal Considerations: Absorb in inert material eg. sand, vermiculite absorbent 

granules, place in plastic container for transfer.

Do not allow spillage to enter drains/sewers/water 

courses.

Dispose of in accordance with local authority regulations.

 

5 – FIRE FIGHTING MEASURES

6 – ACCIDENTAL RELEASE MEASURES
PRODUCT: Flutec TG m-PDMCH 8

th December 1999 PAGE 3/4

a) Handling

a) Handling Do not smoke when handling.

Avoid contact of vapour or liquid with red hot surfaces, 

flames or electrical arcs as this may give rise to toxic 

gases such as Hydrogen Fluoride. 

Do not use sodium or similar metals or their hydrides for 

removing water from the liquid; other desiccants are 

acceptable.

Allow sufficient ullage when drum filling to allow for 

thermal expansion.

b) Storage Store in original, tightly closed, labelled container.

 Incompatible with Lithium, Sodium, Potassium, Calcium 

 and Barium.

a) Occupational Exposure Limit: None

b) Biological Exposure Limit: None

Appearance: Clear colourless liquid

Odour: Odourless

Boiling Point: 102oC

Pour Point: -70oC

Vapour Pressure: 48 mbar

Density: 1.828 kg/l @25oC

Solubility in Water: Insoluble

Solubility in Organic Solvents: Sparingly soluble in most common solvents. Miscible 

with CFCs.

a) Stability: Extremely stable.

b) Conditions to Avoid: Naked flames, hot surfaces.

c) Materials to Avoid: Lithium, Sodium, Potassium, Calcium, and Barium.

a) Chronic Effects: None known

b) Inhalation: No irritation or anaesthetic effects.

c) Skin Contact: Non-irritating but hot liquid or vapour may cause thermal 

burns.

d) Eye Contact: Non-irritating but hot liquid or vapour may cause thermal 

burns.

e) Routes of Exposure Inhalation, skin and eye absorption, ingestion.

7 – HANDLING AND STORAGE

8 – EXPOSURE CONTROLS

9 – PHYSICAL AND CHEMICAL PROPERTIES

10 – STABILITY AND REACTIVITY

11 – TOXICOLOGICAL INFORMATION
PRODUCT: FLUTEC TG m-PDMCH 8

th December 1999 PAGE 4/4

a) Ecotoxicity: No specific data available

 Contact manufacturer.

Dispose of through an authorised contractor to a 

licensed landfill site. 

Do not discharge into drains or watercourses.

Large quantities should be incinerated by a waste 

disposal organisation.

Non-hazardous liquid not regulated for transport 

services.

UN Number – not applicable

IATA/ICAO – not regulated

ADR – not regulated

IMDG – not regulated

Transport name – not applicable

Hazchem code – not applicable.

a) Hazard symbols: None

b) Risk and Safety phrases: S41: In case of fire and / or explosion do not breathe 

fumes.

c) Other regulations: Health and Safety at Work Act 1974.

d) Transport Information: See 14. Transport Information. 

a) Suitability for purpose: F2 Chemicals Ltd cannot guarantee the suitability of 

this material for any particular purpose. It is the 

responsibility of the customer to satisfy himself that the 

product is suitable for his purpose. In the event of 

doubt the customer may contact F2 Chemicals for 

advice.

 

12 – ECOLOGICAL INFORMATION

13 – DISPOSAL CONSIDERATIONS

14 – TRANSPORT INFORMATION

15 – REGULATORY INFORMATION

16 – OTHER REGULATION
FLUTEC-TG o-PDMCH Page 1 of 4 

Material Safety Data Sheet 

FLUTEC-TG o-PDMCH 

Last updated: 20th May 2002 

1 – SUBSTANCE IDENTIFICATION 

Trade Name: FLUTEC-TG o-PDMCH 

Material Type: Perfluorocarbon 

Company: F2 Chemicals Ltd 

Address: Lea Lane 

 Lea Town 

 Preston 

 Lancashire 

 PR4 0RZ 

 UK 

Telephone: +44 (0) 1772 775804 

Fax: +44 (0) 1772 775809 

Emergency Telephone: +44 (0) 1772 775833 

2 - COMPOSITION 

a) Substances Predominantly perfluoro-1,2-dimethylcyclohexane 

b) CAS Number 306-98-9 

3 – HAZARD IDENTIFICATION 

a) Hazard Symbols: Not applicable 

b) Risk and Safety Keep container tightly closed. 

Caution, avoid prolonged and repeated breathing of 

concentrated vapour. 

Thermal decomposition may produce toxic products. 

Small amounts of decomposition may occur above 400°C. 

When using do not smoke. 

Do not empty into drains. 

4 – FIRST AID MEASURES 

a) Inhalation: In case of severe exposure; remove from exposure , rest and 

keep warm. Apply artificial respiration if breathing has ceased. 

Obtain medical attention if effects are other than slight. 

b) Skin contact: Remove contaminated clothing and wash off with soap and 

water. Obtain medical attention if adverse symptoms arise. 

c) Eye contact: Irrigate thoroughly with water. Obtain medical attention if 

adverse symptoms arise. 

d) Ingestion: Wash out mouth with water. Obtain medical attention if 

adverse symptoms persist. 
FLUTEC-TG o-PDMCH Page 2 of 4 

5 – FIRE FIGHTING MEASURES 

a) Suitable Extinguishers: Carbon dioxide 

Alcohol resistant foam 

 Powder 

 Halons 

Water Fog 

 Water Jets 

Inert material – Sand, earth, etc 

 Non-combustible material 

b) Unsuitable Extinguishers: Not applicable. 

c) Hazardous Decomposition: Toxic fumes may be produced on thermal decomposition. 

In the presence of other reactive substances and in a fire 

situation where hydrogen containing compounds are present, 

Hydrogen Fluoride and other toxic products may be formed. 

d) Special Procedures: Use water spray to cool containers. 

Contact with flames gives rise to toxic vapours; avoid inhalation 

of these vapours. 

Use approved self-contained breathing apparatus. 

Non-essential personnel should be evacuated from the area 

until any fumes have dispersed. 

Handle contaminated fluid in a ventilated area, avoiding 

inhalation of vapour. 

6 – ACCIDENTAL RELEASE MEASURES 

a) Exposure Controls FLUTEC liquid spillages produce very slippery surfaces which 

may be hazardous to personnel. 

 Evacuate area. 

Do not allow spillage to enter drains and watercourse. 

If water is contaminated inform relevant authority immediately. 

b) Personnel Protection: Wear laboratory coat. 

Respiratory protection not normally required. 

Wear impermeable gloves. 

Wear chemical safety spectacles or goggles. 

c) Disposal Considerations: Absorb in inert material eg. sand, vermiculite absorbent 

granules, place in plastic container for transfer. 

Do not allow spillage to enter drains/sewers/water courses. 

Dispose of in accordance with local authority regulations. 
FLUTEC-TG o-PDMCH Page 3 of 4 

7 – HANDLING AND STORAGE 

a) Handling Do not smoke when handling. 

Avoid contact of vapour or liquid with red-hot surfaces, flames 

or electrical arcs as this may give rise to toxic gases such as 

Hydrogen Fluoride. 

Do not use sodium or similar metals or their hydrides for 

removing water from the liquid; other desiccants are 

acceptable. 

Allow sufficient ullage when drum filling to allow for thermal 

expansion. 

b) Storage Store in original, tightly closed, labelled container. 

Incompatible with Lithium, Sodium, Potassium, Calcium and 

Barium. 

8 – EXPOSURE CONTROLS 

a) Occupational Exposure Limit: None 

b) Biological Exposure Limit: None 

9 – PHYSICAL AND CHEMICAL PROPERTIES 

Appearance: Clear colourless liquid 

Odour: Odourless 

Boiling Point: 102 °C 

Pour Point: -30 °C 

Molecular Weight: 400 

Density: 1.828 kg/l 

Surface Tension: 16.6 mN/m 

Vapour Pressure: 48 mbar 

Specific Heat: 0.85* kJ/kg °C 

Critical Temperature: 241* °C 

Critical Temperature: 514* K 

Critical Pressure: 19* bar 

Critical Volume: 1.5* l/kg 

Solubility in Water: Insoluble 

Solubility in Organic Solvents: Sparingly soluble in most common solvents. 

Miscible with CFCs. 

10 – STABILITY AND REACTIVITY 

a) Stability: Extremely stable. 

b) Conditions to Avoid: Naked flames, hot surfaces. 

c) Materials to Avoid: Lithium, Sodium, Potassium, Calcium, and Barium. 
FLUTEC-TG o-PDMCH Page 4 of 4 

11 – TOXICOLOGICAL INFORMATION 

a) Chronic Effects: None known 

b) Inhalation: No irritation or anaesthetic effects. 

c) Skin Contact: Non-irritating but hot liquid or vapour may cause thermal burns. 

d) Eye Contact: Non-irritating but hot liquid or vapour may cause thermal burns. 

e) Routes of Exposure Inhalation, skin and eye absorption, ingestion. 

12 – ECOLOGICAL INFORMATION 

a) Ecotoxicity: No specific data available

13 – DISPOSAL CONSIDERATIONS 

 Contact manufacturer. 

Dispose of through an authorised contractor to a licensed 

landfill site. 

Do not discharge into drains or watercourses. 

Large quantities should be incinerated by a waste disposal 

organisation. 

14 – TRANSPORT INFORMATION 

Non-hazardous liquid not regulated for transport services. 

UN Number – not applicable 

IATA/ICAO – not regulated 

ADR – not regulated 

IMDG – not regulated 

Transport name – not applicable 

Hazchem code – not applicable. 

15 – REGULATORY INFORMATION 

a) Hazard symbols: None 

b) Risk and Safety phrases: S41: In case of fire and/or explosion do not breathe fumes. 

c) Other regulations: Health and Safety at Work Act 1974. 

d) Transport Information: See 14. Transport Information. 

16 – OTHER REGULATION 

a) Suitability for purpose: F2 Chemicals Ltd. cannot guarantee the suitability of this 

material for any particular purpose. It is the responsibility of the 

customer to satisfy himself that the product is suitable for his 

purpose. In the event of doubt the customer may contact F2 

Chemicals Ltd. for advice. 

 
FLUTEC TG-PECHTM

Product Flutec TG-PECH 13th November 1999 PAGE 1/4

Trade Name: Flutec TG-PECH

Material Type: Perfluorocarbon

Company: F2 Chemicals Ltd

Address: Lea Lane

 Lea Town

Preston

Lancashire

PR4 0RZ

UK

Telephone: +44 (0) 1772 775804

Fax: +44 (0) 1772 775809

Emergency Telephone: +44 (0) 1772 775833

a) Substances Predominantly Perfluoroethylcyclohexane

b) CAS Number 335-21-7

a) Hazard Symbols: Not applicable 

b) Risk and Safety Keep container tightly closed.

Caution, avoid prolonged and repeated breathing of 

concentrated vapour.

 Thermal decomposition may produce toxic products.

Small amounts of decomposition may occur above 400oC.

When using do not smoke.

Do not empty into drains.

a) Inhalation: In case of severe exposure; remove from exposure , rest and 

keep warm. Apply artificial respiration if breathing has ceased. 

Obtain medical attention if effects are other than slight. 

b) Skin contact: Remove contaminated clothing and wash off with soap and 

water. Obtain medical attention if adverse symptoms arise.

c) Eye contact: Irrigate thoroughly with water. Obtain medical attention if 

adverse symptoms arise. 

d) Ingestion: Wash out mouth with water. Obtain medical attention if adverse 

symptoms persist.

1 – SUBSTANCE IDENTIFICATION

2 - COMPOSITION

3 – HAZARD IDENTIFICATION

4 – FIRST AID MEASURES
PRODUCT: Flutec TG-PECH 13th November 1999 PAGE 2/4

a) Suitable Extinguishers: Carbon dioxide

 Alcohol resistant foam 

Powder 

Halons 

 Water Fog 

Water Jets

Inert material – Sand, earth, etc

 Non-combustible material

b) Unsuitable Extinguishers: Not applicable.

c) Hazardous Decomposition: Toxic fumes may be produced on thermal decomposition.

In the presence of other reactive substances and in a fire 

situation where hydrogen containing compounds are 

present, Hydrogen Fluoride and other toxic products may 

be formed.

d) Special Procedures: Use water spray to cool containers.

Contact with flames gives rise of toxic vapours, avoid 

inhalation of these vapours.

Use approved self contained breathing apparatus.

Non-essential personnel should be evacuated from the 

area until any fumes have dispersed.

Handle contaminated fluid in a ventilated area, avoiding 

inhalation of vapour.

a) Exposure Controls Flutec liquid spillages produce very slippery surfaces 

which may be hazardous to personnel.

Evacuate area.

Do not allow spillage to enter drains and watercourse.

If water is contaminated inform relevant authority 

immediately.

b) Personnel Protection: Wear laboratory coat.

 Respiratory protection not normally required.

Wear impermeable gloves.

Wear chemical safety spectacles or goggles.

c) Disposal Considerations: Absorb in inert material eg. sand, vermiculite absorbent 

granules, place in plastic container for transfer.

Do not allow spillage to enter drains/sewers/water 

courses.

Dispose of in accordance with local authority regulations.

 

5 – FIRE FIGHTING MEASURES

6 – ACCIDENTAL RELEASE MEASURES
PRODUCT: Flutec TG-PECH 13th November 1999 PAGE 3/4

a) Handling

a) Handling Do not smoke when handling.

Avoid contact of vapour or liquid with red hot surfaces, 

flames or electrical arcs as this may give rise to toxic 

gases such as Hydrogen Fluoride. 

Do not use sodium or similar metals or their hydrides for 

removing water from the liquid; other desiccants are 

acceptable.

Allow sufficient ullage when drum filling to allow for 

thermal expansion.

b) Storage Store in original, tightly closed, labelled container.

 Incompatible with Lithium, Sodium, Potassium, Calcium 

 and Barium.

a) Occupational Exposure Limit: None

b) Biological Exposure Limit: None

Appearance: Clear colourless liquid

Odour: Odourless

Boiling Point: 101.7oC

Melting Point: -70oC

Vapour Pressure: 28.7 mbar

Density: 1.829 kg/l @25oC

Solubility in Water: Insoluble

Solubility in Organic Solvents: Sparingly soluble in most common solvents. Miscible 

with CFCs.

a) Stability: Extremely stable.

b) Conditions to Avoid: Naked flames, hot surfaces.

c) Materials to Avoid: Lithium, Sodium, Potassium, Calcium, and Barium.

a) Chronic Effects: None known

b) Inhalation: No irritation or anaesthetic effects.

c) Skin Contact: Non-irritating but hot liquid or vapour may cause thermal 

burns.

d) Eye Contact: Non-irritating but hot liquid or vapour may cause thermal 

burns.

e) Routes of Exposure Inhalation, skin and eye absorption, ingestion.

7 – HANDLING AND STORAGE

8 – EXPOSURE CONTROLS

9 – PHYSICAL AND CHEMICAL PROPERTIES

10 – STABILITY AND REACTIVITY

11 – TOXICOLOGICAL INFORMATION
PRODUCT: FLUTEC TG-PECH 13th November 1999 PAGE 4/4

a) Ecotoxicity: No specific data available

 Contact manufacturer.

Dispose of through an authorized contractor to a 

licensed landfill site. 

Do not discharge into drains or watercourses.

Large quantities should be incinerated by a waste 

disposal organisation.

Non-hazardous liquid not regulated for transport 

services.

UN Number – not applicable

IATA/ICAO – not regulated

ADR – not regulated

IMDG – not regulated

Transport name – not applicable

Hazchem code – not applicable.

a) Hazard symbols: None

b) Risk and Safety phrases: S41: In case of fire and / or explosion do not breathe 

fumes.

c) Other regulations: Health and Safety at Work Act 1974.

d) Transport Information: See 14. Transport Information. 

a) Suitability for purpose: F2 Chemicals Ltd cannot guarantee the suitability of 

this material for any particular purpose. It is the 

responsibility of the customer to satisfy himself that the 

product is suitable for his purpose. In the event of 

doubt the customer may contact F2 Chemicals for 

advice.

 

12 – ECOLOGICAL INFORMATION

13 – DISPOSAL CONSIDERATIONS

14 – TRANSPORT INFORMATION

15 – REGULATORY INFORMATION

16 – OTHER REGULATION
FLUTEC-TG PMCP Page 1 of 4 

Material Safety Data Sheet 

FLUTEC-TG PMCP 

Last updated: 20th May 2002 

1 – SUBSTANCE IDENTIFICATION 

Trade Name: FLUTEC-TG PMCP 

Material Type: Perfluorocarbon 

Company: F2 Chemicals Ltd 

Address: Lea Lane 

 Lea Town 

 Preston 

 Lancashire 

 PR4 0RZ 

 UK 

Telephone: +44 (0) 1772 775804 

Fax: +44 (0) 1772 775809 

Emergency Telephone: +44 (0) 1772 775833 

2 - COMPOSITION 

a) Substances Predominantly perfluoromethylcyclopentane 

b) CAS Number 1805-22-7 

3 – HAZARD IDENTIFICATION 

a) Hazard Symbols: Not applicable 

b) Risk and Safety Keep container tightly closed. 

Caution, avoid prolonged and repeated breathing of 

concentrated vapour. 

Thermal decomposition may produce toxic products. 

Small amounts of decomposition may occur above 400°C. 

When using do not smoke. 

Do not empty into drains. 

4 – FIRST AID MEASURES 

a) Inhalation: In case of severe exposure; remove from exposure , rest and 

keep warm. Apply artificial respiration if breathing has ceased. 

Obtain medical attention if effects are other than slight. 

b) Skin contact: Remove contaminated clothing and wash off with soap and 

water. Obtain medical attention if adverse symptoms arise. 

c) Eye contact: Irrigate thoroughly with water. Obtain medical attention if 

adverse symptoms arise. 

d) Ingestion: Wash out mouth with water. Obtain medical attention if 

adverse symptoms persist. 
FLUTEC-TG PMCP Page 2 of 4 

5 – FIRE FIGHTING MEASURES 

a) Suitable Extinguishers: Carbon dioxide 

Alcohol resistant foam 

 Powder 

 Halons 

Water Fog 

 Water Jets 

Inert material – Sand, earth, etc 

 Non-combustible material 

b) Unsuitable Extinguishers: Not applicable. 

c) Hazardous Decomposition: Toxic fumes may be produced on thermal decomposition. 

In the presence of other reactive substances and in a fire 

situation where hydrogen containing compounds are present, 

Hydrogen Fluoride and other toxic products may be formed. 

d) Special Procedures: Use water spray to cool containers. 

Contact with flames gives rise to toxic vapours; avoid inhalation 

of these vapours. 

Use approved self-contained breathing apparatus. 

Non-essential personnel should be evacuated from the area 

until any fumes have dispersed. 

Handle contaminated fluid in a ventilated area, avoiding 

inhalation of vapour. 

6 – ACCIDENTAL RELEASE MEASURES 

a) Exposure Controls FLUTEC liquid spillages produce very slippery surfaces which 

may be hazardous to personnel. 

 Evacuate area. 

Do not allow spillage to enter drains and watercourse. 

If water is contaminated inform relevant authority immediately. 

b) Personnel Protection: Wear laboratory coat. 

Respiratory protection not normally required. 

Wear impermeable gloves. 

Wear chemical safety spectacles or goggles. 

c) Disposal Considerations: Absorb in inert material eg. sand, vermiculite absorbent 

granules, place in plastic container for transfer. 

Do not allow spillage to enter drains/sewers/water courses. 

Dispose of in accordance with local authority regulations. 
FLUTEC-TG PMCP Page 3 of 4 

7 – HANDLING AND STORAGE 

a) Handling Do not smoke when handling. 

Avoid contact of vapour or liquid with red-hot surfaces, flames 

or electrical arcs as this may give rise to toxic gases such as 

Hydrogen Fluoride. 

Do not use sodium or similar metals or their hydrides for 

removing water from the liquid; other desiccants are 

acceptable. 

Allow sufficient ullage when drum filling to allow for thermal 

expansion. 

b) Storage Store in original, tightly closed, labelled container. 

Incompatible with Lithium, Sodium, Potassium, Calcium and 

Barium. 

8 – EXPOSURE CONTROLS 

a) Occupational Exposure Limit: None 

b) Biological Exposure Limit: None 

9 – PHYSICAL AND CHEMICAL PROPERTIES 

Appearance: Clear colourless liquid 

Odour: Odourless 

Boiling Point: 48 °C 

Pour Point: -70 °C 

Molecular Weight: 300 

Density: 1.707 kg/l 

Viscosity (kinematic): 0.58 mm2/s 

Viscosity (dynamic): 0.993 mPa s 

Surface Tension: 12.4 mN/m 

Vapour Pressure: 451 mbar 

Heat of Vaporisation at b.p.: 90.5* kJ/kg 

Specific Heat: 0.563 kJ/kg °C 

Refractive index: 1.2650 ND

20

Oxygen Solubility: 45* ml per 100g 

Solubility in Water: Insoluble 

Solubility in Organic Solvents: Sparingly soluble in most common solvents. 

Miscible with CFCs. 

10 – STABILITY AND REACTIVITY 

a) Stability: Extremely stable. 

b) Conditions to Avoid: Naked flames, hot surfaces. 

c) Materials to Avoid: Lithium, Sodium, Potassium, Calcium, and Barium. 
FLUTEC-TG PMCP Page 4 of 4 

11 – TOXICOLOGICAL INFORMATION 

a) Chronic Effects: None known 

b) Inhalation: No irritation or anaesthetic effects. 

c) Skin Contact: Non-irritating but hot liquid or vapour may cause thermal burns. 

d) Eye Contact: Non-irritating but hot liquid or vapour may cause thermal burns. 

e) Routes of Exposure Inhalation, skin and eye absorption, ingestion. 

12 – ECOLOGICAL INFORMATION 

a) Ecotoxicity: No specific data available

13 – DISPOSAL CONSIDERATIONS 

 Contact manufacturer. 

Dispose of through an authorised contractor to a licensed 

landfill site. 

Do not discharge into drains or watercourses. 

Large quantities should be incinerated by a waste disposal 

organisation. 

14 – TRANSPORT INFORMATION 

Non-hazardous liquid not regulated for transport services. 

UN Number – not applicable 

IATA/ICAO – not regulated 

ADR – not regulated 

IMDG – not regulated 

Transport name – not applicable 

Hazchem code – not applicable. 

15 – REGULATORY INFORMATION 

a) Hazard symbols: None 

b) Risk and Safety phrases: S41: In case of fire and/or explosion do not breathe fumes. 

c) Other regulations: Health and Safety at Work Act 1974. 

d) Transport Information: See 14. Transport Information. 

16 – OTHER REGULATION 

a) Suitability for purpose: F2 Chemicals Ltd. cannot guarantee the suitability of this 

material for any particular purpose. It is the responsibility of the 

customer to satisfy himself that the product is suitable for his 

purpose. In the event of doubt the customer may contact F2 

Chemicals Ltd. for advice. 

 
MATERIAL SAFETY DATA SHEET DATE: 2005 January 12

 SECTION 1 MATERIAL IDENTIFICATION For Internal Use Only

HAZARD

RATING

LABEL

CHEMICAL NAME Sodium Iodide Iodine 131 (I-131) Solution

CHEMICAL 

SYNONYMS

Na131I in Na0H containing 0.02M Na2S04 pH-9-13

CHEMICAL FAMILY Base; Sodium Iodide in dilute sodium hydroxide solution

MANUFACTURER

/SUPPLIER NAME

MDS Nordion Inc.

447 March Road

Kanata, Ontario

K2K 1X8

Telephone: (613) 592-2790 - Radiation Safety

 SECTION 2 HAZARDOUS INGREDIENTS

INGREDIENT Activity or % Radiation Category % TLV

High Radioactivity 200-10000 mCi/ml High energy gamma and high energy beta

Half-Life: 8.02 days

Sodium Hydroxide < 2.8 mg/ml (< 0.3% w/v) 

AECB Permitted Exposures: 50 mSv/y for Radiation Workers; 5 mSv/y for Public

 SECTION 3 PHYSICAL DATA

BOILING POINT: 760 mm Hg (°C) 100-105°C SOLUBILITY IN WATER, % by weight 

@ 25°C

100

VAPOUR PRESSURE: 20°C (mm 

Hg)

N/A SPECIFIC GRAVITY (H2O = 1) 1.003

VAPOUR DENSITY (air = 1) > 1.0 EVAPORATION RATE (butylacetate = 

1)

N/A

pH MELTING POINT

APPEARANCE AND ODOUR: Product appears like water and is contained in a shielded and securely sealed package. No odour.

 SECTION 4 FIRE AND EXPLOSION HAZARD DATA

FLASH POINT (°C); TEST METHOD: None FLAMMABLE LIMITS LEL

N/A

UEL

N/A

AUTOIGNITION TEMPERATURE (°C) None

EXTINGUISHING MEDIA: N/A

SPECIAL FIREFIGHTING PROCEDURES: N/A

UNUSUAL FIRE AND EXPLOSION HAZARDS: None

 SECTION 5 REACTIVITY DATA

STABILITY:

STABLEX CONDITIONS TO AVOID: None

UNSTABLE ®

INCOMPATIBILITY: N/A

HAZARDOUS DECOMPOSITION PRODUCTS: 

HAZARDOUS 

WILL NOT OCCURX CONDITIONS TO AVOID: Not identified.
POLYMERIZATION:

MAY OCCUR ®

N/A - Not Applicable
MATERIAL SAFETY DATA SHEET- Sodium Iodide Iodine 131 Solution (cont'd)

 SECTION 6 HEALTH HAZARD DATA

EFFECTS OF

OVEREXPOSURE:

INHALATION: Will result in heavy thyroid radiation dose. No respiratory symptoms.

INGESTION: Will result in heavy thyroid radiation dose. Sodium hydroxide concentration low, may cause throat irritation 

and burning sensation.

EYES: Sodium hydroxide will have irritation effect; wash immediately.

SKIN: Corrosive effect and high radiation on contact; wash immediately.

EMERGENCY 

FIRST

AID 

PROCEDURES:

INHALATION: Remove to fresh air and stand upwind if outside. Ascertain if individual has allergies to iodine. If not, 

administer stable iodine (eg. Lugol’s solution). Seek medical attention for radiation intake.

INGESTION: Ascertain if individual has allergies to iodine. If not, administer stable iodine (eg. Lugol’s solution). Do not 

induce vomiting, due to corrosive effect of solution. Remove from source. Seek medical aid for radiation intake.

EYES: Flush open eye(s) continuously for 15 minutes with clean water. Remove from source. See Physician for external 

radiation or if irritation persists.

SKIN: Wash well with soap and water to remove contamination. Remove contaminated clothing. Remove from source. 

See Physician for external radiation or if irritation persists.

NOTE: IN ALL CASES, OBTAIN MEDICAL AID PROMPTLY.

 SECTION 7 SPECIAL PROTECTION INFORMATION

VENTILATION: With I-131 local ventilation is very important, if I-131 gasses off. Wear respiratory protection, and stand upwind (if outside).

RESPIRATORY

PROTECTION:

Air purifying respirator with combination radio-nuclide cartridge or SCBA where spill has occurred.

PROTECTIVE 

CLOTHING:

If package is damaged, wear lead-lined gloves before handling.

EYE

PROTECTION:

® NOT NORMALLY NECESSARY ® SAFETY GLASSES WITH SIDE SHIELDS ® SAFETY GLASSES

® GASTIGHT GOGGLES OR EQUIVALENT X CHEMICAL WORKERS GOGGLES ® OTHER

 SECTION 8 SPECIAL PRECAUTIONS

PRECAUTIONS IN

HANDLING AND 

STORAGE:

All shippers and consignees must possess radioisotope license and conform with all conditions of license.

OTHER 

PRECAUTIONS:

 SECTION 9 SPILL OR LEAK PROCEDURES

STEPS TO BE TAKEN IF MATERIAL SPILLED OR LEAKED: Note also Section 7. If wet spill occurs, isolate contaminated area using vermiculite 

or charcoal. When acidified this material will release I-131. If in transport mode, call CANUTEC at (613) 996-6666 in Canada or National Response 

Centre at 1-800-424-8802 in USA.

WASTE DISPOSAL METHOD: If on site, follow instructions on site license or as directed by local Radiation Control Officer.

THE FOREGOING IS PROVIDED FOR THE INFORMATION OF MDS NORDION INC. CUSTOMERS ONLY. MDS NORDION MAKES NO 

REPRESENTATION WHATSOEVER REGARDING THE COMPLETENESS OR ACCURACY OF THE INFORMATION CONTAINED IN THIS 

DOCUMENT AND ASSUMES NO LIABILITY RESULTING FROM ITS USE. USERS SHOULD MAKE THEIR OWN INVESTIGATIONS TO 

DETERMINE THE SUITABILITY OF THE INFORMATION FOR THEIR PARTICULAR PURPOSES.
MATERIAL SAFETY DATA SHEET

PRODUCT NAME: KRYPTON

MSDS: G-54

Revised: 6/7/96 Page 1 of 6

1. Chemical Product and Company Identification

BOC Gases,

Division of

The BOC Group, Inc.

575 Mountain Avenue

Murray Hill, NJ 07974

TELEPHONE NUMBER: (908) 464-8100

BOC Gases

Division of

BOC Canada Limited

5975 Falbourne Street, Unit 2

Mississauga, Ontario L5R 3W6

TELEPHONE NUMBER: (905) 501-1700

24-HOUR EMERGENCY TELEPHONE NUMBER:

CHEMTREC (800) 424-9300

24-HOUR EMERGENCY TELEPHONE NUMBER:

(905) 501-0802

EMERGENCY RESPONSE PLAN NO: 20101

PRODUCT NAME: KRYPTON

CHEMICAL NAME: Krypton

COMMON NAMES/SYNONYMS: Krypton, compressed

TDG (Canada) CLASSIFICATION: 2.2

WHMIS CLASSIFICATION: A

PREPARED BY: Loss Control (908)464-8100/(905)501-1700

PREPARATION DATE: 6/1/95

REVIEW DATES: 6/7/96

2. Composition, Information on Ingredients

INGREDIENT % VOLUME PEL-OSHA1 TLV-ACGIH2 LD50 or LC50

Route/Species

Krypton

FORMULA: Kr

CAS: 7439-90-9

RTECS #: Not Available

99.95 to 99.995 Simple Asphyxiant Simple Asphyxiant Not Available

1 As stated in 29 CFR 1910, Subpart Z (revised July 1, 1993)

2 As stated in the ACGIH 1994-95 Threshold Limit Values for Chemical Substances and Physical Agents

3. Hazards Identification

EMERGENCY OVERVIEW

Simple Asphyxiant - This product does not contain oxygen and may cause asphyxia if released in a

confined area. Maintain oxygen levels above 19.5%. Nonflammable.

ROUTE OF ENTRY:

Skin Contact

No

Skin Absorption

No

Eye Contact

No

Inhalation

Yes

Ingestion

No
PRODUCT NAME: KRYPTON

MSDS: G-54

Revised: 6/7/96 Page 2 of 6

HEALTH EFFECTS:

Exposure Limits

No

Irritant

No

Sensitization

No

Teratogen

No

Reproductive Hazard

No

Mutagen

No

Synergistic Effects

None reported

Carcinogenicity: -- NTP: No IARC: No OSHA: No

EYE EFFECTS:

None known.

SKIN EFFECTS:

None known.

INGESTION EFFECTS:

None known. Ingestion is unlikely as product is gas at room temperature.

INHALATION EFFECTS:

Product is a non-toxic simple asphyxiant. High concentrations may exclude an adequate supply of oxygen to the

lungs. Effect of oxygen deficiency resulting from simple asphyxiants may include: rapid breathing, diminished

mental alertness, impaired muscular coordination, faulty judgement, depression of all sensations, emotional

instability, and fatigue. As asphyxiation progresses, nausea, vomiting, prostration, and loss of consciousness

may result, eventually leading to convulsions, coma, and death.

Oxygen deficiency during pregnancy has produced developmental abnormalities in humans and experimental

animals.

NFPA HAZARD CODES HMIS HAZARD CODES RATINGS SYSTEM

Health: 0 Health: 0 0 = No Hazard

Flammability: 0 Flammability: 0 1 = Slight Hazard

Reactivity: 0 Reactivity: 0 2 = Moderate Hazard

3 = Serious Hazard

4 = Severe Hazard

4. First Aid Measures

EYES:

None required.

SKIN:

None required.
PRODUCT NAME: KRYPTON

MSDS: G-54

Revised: 6/7/96 Page 3 of 6

INGESTION:

None required.

INHALATION:

PROMPT MEDICAL ATTENTION IS MANDATORY IN ALL CASES OF OVEREXPOSURE. RESCUE

PERSONNEL SHOULD BE EQUIPPED WITH SELF-CONTAINED BREATHING APPARATUS. Victims

should be assisted to an uncontaminated area and inhale fresh air. Quick removal from the contaminated area is

most important. Unconscious persons should be moved to an uncontaminated area, and if breathing has stopped,

administer artificial resuscitation and supplemental oxygen. Further treatment should be symptomatic and

supportive.

5. Fire Fighting Measures

Conditions of Flammability: Nonflammable

Flash point:

None

Method:

Not Applicable

Autoignition

Temperature: None

LEL(%): None UEL(%): None

Hazardous combustion products: None

Sensitivity to mechanical shock: None

Sensitivity to static discharge: None

FIRE AND EXPLOSION HAZARDS:

None. Nonflammable

EXTINGUISHING MEDIA:

None required. Use as appropriate for surrounding materials.

6. Accidental Release Measures

Evacuate all personnel from affected area. Use appropriate protective equipment. If leak is in container or

container valve, contact the appropriate emergency telephone number listed in Section 1 or call your closest

BOC location.

7. Handling and Storage

Electrical classification:

Non-hazardous.

This gas mixture is noncorrosive and may be used with all common structural materials.

Use only in well-ventilated areas. Valve protection caps must remain in place unless container is secured with

valve protection outlet piped to use point. Do not drag, slide or roll cylinders. Use a suitable hand truck for

cylinder movement. Use a pressure reducing regulator when connecting cylinder to lower pressure (<3000 psig)

piping or systems. Do not heat cylinder by any means to increase the discharge rate of product from the

cylinder. Use a check valve or trap in the discharge line to prevent hazardous back flow into the cylinder.
PRODUCT NAME: KRYPTON

MSDS: G-54

Revised: 6/7/96 Page 4 of 6

Protect cylinders from physical damage. Store in cool, dry, well-ventilated area of non-combustible construction

away from heavily trafficked areas and emergency exits. Do not allow the temperature where cylinders are

stored to exceed 125o

F (52oC). Cylinders should be stored upright and firmly secured to prevent falling or being

knocked over. Use a "first in-first out" inventory system to prevent full cylinders being stored for excessive

periods of time.

For additional recommendations, consult Compressed Gas Association Pamphlets P-1, P-14, P-9, and Safety

Bulletin SB-2.

Never carry a compressed gas cylinder or a container of a gas in cryogenic liquid form in an enclosed space such

as a car trunk, van or station wagon. A leak can result in a fire, explosion, asphyxiation or a toxic exposure.

8. Exposure Controls, Personal Protection

EXPOSURE LIMITS1:

INGREDIENT % VOLUME PEL-OSHA2 TLV-ACGIH3 LD50 or LC50

Route/Species

Krypton

FORMULA: Kr

CAS: 7439-90-9

RTECS #: Not Available

99.95 to 99.995 Simple Asphyxiant Simple Asphyxiant Not Available

1 Refer to individual state of provincial regulations, as applicable, for limits which may be more stringent than

 those listed here.

2 As stated in 29 CFR 1910, Subpart Z (revised July 1, 1993)

3 As stated in the ACGIH 1994-1995 Threshold Limit Values for Chemical Substances and Physical Agents.

ENGINEERING CONTROLS:

Local exhaust to prevent accumulation of high concentrations so as to reduce the oxygen level in the air to less

than 19.5%.

EYE/FACE PROTECTION:

Safety goggles or glasses as appropriate for the job.

SKIN PROTECTION:

Protective gloves of material appropriate for the job.

RESPIRATORY PROTECTION:

Positive pressure air line with full-face mask and escape bottle or self-contained breathing apparatus should be

available for emergency use.

OTHER/GENERAL PROTECTION:

Safety shoes or other footwear as appropriate for the job.
PRODUCT NAME: KRYPTON

MSDS: G-54

Revised: 6/7/96 Page 5 of 6

9. Physical and Chemical Properties

PARAMETER VALUE UNITS

Physical state (gas, liquid, solid) : Gas

Vapor pressure at STP : Not Available

Vapor density (Air = 1) : 2.92

Evaporation point : Not Available

Boiling point : -244

: -153.3

o

F

o

C

Freezing point : -250.9

: -157.2

o

F

o

C

pH : Not Applicable

Specific gravity : Not Available

Oil/water partition coefficient : Not Available

Solubility (H20) : Negligible

Odor threshold : Not Applicable

Odor and appearance : An odorless, colorless gas

10. Stability and Reactivity

STABILITY:

Stable

INCOMPATIBLE MATERIALS:

None

HAZARDOUS POLYMERIZATION:

Does not occur

11. Toxicological Information

Oxygen deficiency during pregnancy has produced developmental abnormalities in humans and experimental

animals.

No data given in the Registry of Toxic Effects of Chemical Substances (RTECS) or Sax, Dangerous Properties

of Industrial Materials, 7th ed.

12. Ecological Information

No data given.

13. Disposal Considerations

Do not attempt to dispose of residual waste or unused quantities. Return in the shipping container PROPERLY

LABELED, WITH ANY VALVE OUTLET PLUGS OR CAPS SECURED AND VALVE PROTECTION CAP

IN PLACE to BOC Gases or authorized distributor for proper disposal.
PRODUCT NAME: KRYPTON

MSDS: G-54

Revised: 6/7/96 Page 6 of 6

14. Transport Information

PARAMETER United States DOT Canada TDG

PROPER SHIPPING NAME: Krypton, compressed Krypton, compressed

HAZARD CLASS: 2.2 2.2

IDENTIFICATION NUMBER: UN 1056 UN 1056

SHIPPING LABEL: NONFLAMMABLE GAS NONFLAMMABLE GAS

15. Regulatory Information

SARA TITLE III NOTIFICATIONS AND INFORMATION

SARA TITLE III - HAZARD CLASSES:

Sudden Release of Pressure Hazard

16. Other Information

Compressed gas cylinders shall not be refilled without the express written permission of the owner. Shipment of

a compressed gas cylinder which has not been filled by the owner or with his/her (written) consent is a violation

of transportation regulations.

DISCLAIMER OF EXPRESSED AND IMPLIED WARRANTIES:

Although reasonable care has been taken in the preparation of this document, we extend no warranties and make

no representations as to the accuracy or completeness of the information contained herein, and assume no

responsibility regarding the suitability of this information for the user’s intended purposes or for the

consequences of its use. Each individual should make a determination as to the suitability of the information for

their particular purpose(s).
MATERIAL SAFETY DATA SHEET

PRODUCT NAME: NEON

MSDS: G-59

Revised: 6/7/96 Page 1 of 6

1. Chemical Product and Company Identification

BOC Gases,

Division of

The BOC Group, Inc.

575 Mountain Avenue

Murray Hill, NJ 07974

TELEPHONE NUMBER: (908) 464-8100

BOC Gases

Division of

BOC Canada Limited

5975 Falbourne Street, Unit 2

Mississauga, Ontario L5R 3W6

TELEPHONE NUMBER: (905) 501-1700

24-HOUR EMERGENCY TELEPHONE NUMBER:

CHEMTREC (800) 424-9300

24-HOUR EMERGENCY TELEPHONE NUMBER:

(905) 501-0802

EMERGENCY RESPONSE PLAN NO: 20101

PRODUCT NAME: NEON

CHEMICAL NAME: Neon

COMMON NAMES/SYNONYMS: Neon, compressed

TDG (Canada) CLASSIFICATION: 2.2

WHMIS CLASSIFICATION: A

PREPARED BY: Loss Control (908)464-8100/(905)501-1700

PREPARATION DATE: 6/1/95

REVIEW DATES: 6/7/96

2. Composition, Information on Ingredients

INGREDIENT % VOLUME PEL-OSHA1 TLV-ACGIH2 LD50 or LC50

Route/Species

Neon

FORMULA: Ne

CAS: 7440-01-9

RTECS #: QP4450000

75.0 to 99.9999 Simple Asphyxiant Simple Asphyxiant Not Available

Helium

FORMULA: He

CAS: 7440-59-7

RTECS #: MH6520000

0 to 25.0 Simple Asphyxiant Simple Asphyxiant Not Available

1 As stated in 29 CFR 1910, Subpart Z (revised July 1, 1993)

2 As stated in the ACGIH 1994-95 Threshold Limit Values for Chemical Substances and Physical Agents

3. Hazards Identification

EMERGENCY OVERVIEW

Simple Asphyxiant - This product does not contain oxygen and may cause asphyxia if released in a

confined area. Maintain oxygen levels above 19.5%. Nonflammable.

ROUTE OF ENTRY:

Skin Contact

No

Skin Absorption

No

Eye Contact

No

Inhalation

Yes

Ingestion

No
PRODUCT NAME: NEON

MSDS: G-59

Revised: 6/7/96 Page 2 of 6

HEALTH EFFECTS:

Exposure Limits

No

Irritant

No

Sensitization

No

Teratogen

No

Reproductive Hazard

No

Mutagen

No

Synergistic Effects

None reported

Carcinogenicity: -- NTP: No IARC: No OSHA: No

EYE EFFECTS:

None known.

SKIN EFFECTS:

None known.

INGESTION EFFECTS:

None known. Ingestion is unlikely as product is gas at room temperature.

INHALATION EFFECTS:

Product is a non-toxic simple asphyxiant. Effects of oxygen deficiency resulting from simple asphyxiants may

include: rapid breathing, diminished mental alertness, impaired muscular coordination, faulty judgement,

depression of all sensations, emotional instability, and fatigue. As asphyxiation progresses, nausea, vomiting,

prostration, and loss of consciousness may result, eventually leading to convulsions, coma, and death.

Oxygen deficiency during pregnancy has produced developmental abnormalities in humans and experimental

animals.

NFPA HAZARD CODES HMIS HAZARD CODES RATINGS SYSTEM

Health: 0 Health: 0 0 = No Hazard

Flammability: 0 Flammability: 0 1 = Slight Hazard

Reactivity: 0 Reactivity: 0 2 = Moderate Hazard

3 = Serious Hazard

4 = Severe Hazard

4. First Aid Measures

EYES:

None required.

SKIN:

None required.

INGESTION:

None required.
PRODUCT NAME: NEON

MSDS: G-59

Revised: 6/7/96 Page 3 of 6

INHALATION:

PROMPT MEDICAL ATTENTION IS MANDATORY IN ALL CASES OF OVEREXPOSURE. RESCUE

PERSONNEL SHOULD BE EQUIPPED WITH SELF-CONTAINED BREATHING APPARATUS. Victims

should be assisted to an uncontaminated area and inhale fresh air. Quick removal from the contaminated area is

most important. Unconscious persons should be moved to an uncontaminated area, and if breathing has stopped,

administer artificial resuscitation and supplemental oxygen. Further treatment should be symptomatic and

supportive.

5. Fire Fighting Measures

Conditions of Flammability: Nonflammable

Flash point:

None

Method:

Not Applicable

Autoignition

Temperature: None

LEL(%): None UEL(%): None

Hazardous combustion products: None

Sensitivity to mechanical shock: None

Sensitivity to static discharge: None

FIRE AND EXPLOSION HAZARDS:

None. Nonflammable.

EXTINGUISHING MEDIA:

None required. Use as appropriate for surrounding materials.

6. Accidental Release Measures

Evacuate all personnel from affected area. Use appropriate protective equipment. If leak is in container or

container valve, contact the appropriate emergency telephone number listed in Section 1 or call your closest

BOC location.

7. Handling and Storage

Electrical classification:

Non-hazardous.

This gas mixture is noncorrosive and may be used with all common structural materials.

Use only in well-ventilated areas. Valve protection caps must remain in place unless container is secured with

valve protection outlet piped to use point. Do not drag, slide or roll cylinders. Use a suitable hand truck for

cylinder movement. Use a pressure reducing regulator when connecting cylinder to lower pressure (<3000 psig)

piping or systems. Do not heat cylinder by any means to increase the discharge rate of product from the

cylinder. Use a check valve or trap in the discharge line to prevent hazardous back flow into the cylinder.

Protect cylinders from physical damage. Store in cool, dry, well-ventilated area of non-combustible construction

away from heavily trafficked areas and emergency exits. Do not allow the temperature where cylinders are

stored to exceed 125o

F (52oC). Cylinders should be stored upright and firmly secured to prevent falling or being

knocked over. Use a "first in-first out" inventory system to prevent full cylinders being stored for excessive

periods of time.

For additional recommendations, consult Compressed Gas Association Pamphlets P-1, P-14, P-9, and Safety

Bulletin SB-2.
PRODUCT NAME: NEON

MSDS: G-59

Revised: 6/7/96 Page 4 of 6

Never carry a compressed gas cylinder or a container of a gas in cryogenic liquid form in an enclosed space such

as a car trunk, van or station wagon. A leak can result in a fire, explosion, asphyxiation or a toxic exposure.

8. Exposure Controls, Personal Protection

EXPOSURE LIMITS1:

INGREDIENT % VOLUME PEL-OSHA2 TLV-ACGIH3 LD50 or LC50

Route/Species

Neon

FORMULA: Ne

CAS: 7440-01-9

RTECS #: QP4450000

75.0 to 99.9999 Simple Asphyxiant Simple Asphyxiant Not Available

Helium

FORMULA: He

CAS: 7440-59-7

RTECS #: MH6520000

0 to 25.0 Simple Asphyxiant Simple Asphyxiant Not Available

1 Refer to individual state of provincial regulations, as applicable, for limits which may be more stringent than

 those listed here.

2 As stated in 29 CFR 1910, Subpart Z (revised July 1, 1993)

3 As stated in the ACGIH 1994-1995 Threshold Limit Values for Chemical Substances and Physical Agents.

ENGINEERING CONTROLS:

Local exhaust to prevent accumulation of high concentrations so as to reduce the oxygen level in the air to less

than 19.5%.

EYE/FACE PROTECTION:

Safety goggles or glasses as appropriate for the job.

SKIN PROTECTION:

Protective gloves of material appropriate for the job.

RESPIRATORY PROTECTION:

Positive pressure air line with full-face mask and escape bottle or self-contained breathing apparatus should be

available for emergency use.

OTHER/GENERAL PROTECTION:

Safety shoes or other footwear as appropriate for the job.
PRODUCT NAME: NEON

MSDS: G-59

Revised: 6/7/96 Page 5 of 6

9. Physical and Chemical Properties

PARAMETER VALUE UNITS

Physical state (gas, liquid, solid) : Gas

Vapor pressure : Gas, above crit. temp.

Vapor density at 70 o

F, 1 atm (Air = 1). : 0.70

Evaporation point : Not Available

Boiling point : -410.9

: -246.1

o

F

o

C

Freezing point : -415.5

: -248.6

o

F

o

C

pH : Not Applicable

Specific gravity : Not Available

Oil/water partition coefficient : Not Available

Solubility (H20) : Negligible

Odor threshold : Not Applicable

Odor and appearance : Colorless, odorless gas

10. Stability and Reactivity

STABILITY:

Stable

INCOMPATIBLE MATERIALS:

None

HAZARDOUS POLYMERIZATION:

Does not occur.

11. Toxicological Information

Oxygen deficiency during pregnancy has produced developmental abnormalities in humans and experimental

animals.

No data given in the Registry of Toxic Effects of Chemical Substances (RTECS) or Sax, Dangerous Properties

of Industrial Materials, 7th ed.

12. Ecological Information

No data given.

13. Disposal Considerations

Do not attempt to dispose of residual waste or unused quantities. Return in the shipping container PROPERLY

LABELED, WITH ANY VALVE OUTLET PLUGS OR CAPS SECURED AND VALVE PROTECTION CAP

IN PLACE to BOC Gases or authorized distributor for proper disposal.
PRODUCT NAME: NEON

MSDS: G-59

Revised: 6/7/96 Page 6 of 6

14. Transport Information

PARAMETER United States DOT Canada TDG

PROPER SHIPPING NAME: Neon, compressed Neon, compressed

HAZARD CLASS: 2.2 2.2

IDENTIFICATION NUMBER: UN 1065 UN 1065

SHIPPING LABEL: NONFLAMMABLE GAS NONFLAMMABLE GAS

15. Regulatory Information

SARA TITLE III NOTIFICATIONS AND INFORMATION

SARA TITLE III - HAZARD CLASSES:

Sudden Release of Pressure Hazard

16. Other Information

Compressed gas cylinders shall not be refilled without the express written permission of the owner. Shipment of

a compressed gas cylinder which has not been filled by the owner or with his/her (written) consent is a violation

of transportation regulations.

DISCLAIMER OF EXPRESSED AND IMPLIED WARRANTIES:

Although reasonable care has been taken in the preparation of this document, we extend no warranties and make

no representations as to the accuracy or completeness of the information contained herein, and assume no

responsibility regarding the suitability of this information for the user’s intended purposes or for the

consequences of its use. Each individual should make a determination as to the suitability of the information for

their particular purpose(s).
MSDS

Perfluorodimethylcyclobutane

Material Safety Data Sheet

acc. to OSHA and ANSI 

Printing date 05/30/2000Reviewed on 05/05/2000 

1 Identification of substance:

Product details: 

Trade name: Perfluorodimethylcyclobutane 

Stock number: 43036 

Manufacturer/Supplier: 

Alfa Aesar, A Johnson Matthey Company 

Johnson Matthey Catalog Company, Inc. 

30 Bond Street 

Ward Hill, MA 01835-8099 

Emergency Phone: (978) 521-6300 

CHEMTREC: (800) 424-9300 

Web Site: www.alfa.com 

Information department: Health, Safety and Environmental Department 

Emergency information: 

During normal hours the Health, Safety and Environmental Department. After 

normal hours call Chemtrec at (800) 424-9300. 

2 Composition/Data on components:

Chemical characterization: 

Description: (CAS#) 

Perfluorodimethylcyclobutane (CAS# 28677-00-1), 100% 

Identification number(s): 

EINECS Number: 249-145-3 

3 Hazards identification

Hazard description: · Not applicable 

Information pertaining to particular dangers for man and environment 

Not applicable 

4 First aid measures

After inhalation 

Supply fresh air. If required, provide artificial respiration. Keep patient 

warm. Seek immediate medical advice. 

After skin contact 

Immediately wash with water and soap and rinse thoroughly. Seek immediate 

medical advice. 

After eye contact 
MSDS

Perfluorodimethylcyclobutane

Rinse opened eye for several minutes under running water. Then consult a 

doctor. 

After swallowing Seek medical treatment. 

5 Fire fighting measures

Suitable extinguishing agents 

Use carbon dioxide, extinguishing powder or foam. Water may be ineffective 

but may be used for cooling exposed containers. 

Special hazards caused by the material, its products of combustion or 

resulting gases: 

In case of fire, the following can be released: 

Carbon monoxide (CO) 

Hydrogen fluoride (HF) 

Protective equipment: 

Wear self-contained respirator. Wear fully protective impervious suit. 

6 Accidental release measures

Person-related safety precautions: 

Wear protective equipment. Keep unprotected persons away. Ensure adequate 

ventilation 

Measures for environmental protection: 

Do not allow material to be released to the environment without proper 

governmental permits. 

Measures for cleaning/collecting: 

Absorb with liquid-binding material (sand, diatomite, acid binders, 

universal binders, sawdust). 

Additional information: 

See Section 7 for information on safe handling 

See Section 8 for information on personal protection equipment. 

See Section 13 for disposal information. 

7 Handling and storage

Handling 

Information for safe handling: 

Keep container tightly sealed. Store in cool, dry place in tightly closed 

containers. No special precautions are necessary if used correctly. 

Information about protection against explosions and fires: 

The product is not flammable 

Storage 

Requirements to be met by storerooms and receptacles: 

No special requirements. 

Information about storage in one common storage facility: 
MSDS

Perfluorodimethylcyclobutane

Store away from oxidizing agents. 

Further information about storage conditions: 

Refrigerate 

Keep container tightly sealed. 

Store in cool, dry conditions in well sealed containers. 

8 Exposure controls and personal protection

Additional information about design of technical systems: 

Properly operating chemical fume hood designed for hazardous chemicals and 

having an average face velocity of at least 100 feet per minute. 

Components with limit values that require monitoring at the workplace: 

Not required. 

Additional information: No data 

Personal protective equipment 

General protective and hygienic measures 

The usual precautionary measures for handling chemicals should be followed. 

Keep away from foodstuffs, beverages and feed. Remove all soiled and 

contaminated clothing immediately. Wash hands before breaks and at the end 

of work. 

Breathing equipment: 

Use suitable respiratory protective device in case of insufficient 

ventilation. Use suitable respirator when high concentrations are present. 

Protection of hands: Impervious gloves 

Eye protection: Safety glasses 

Body protection: Protective work clothing. 

9 Physical and chemical properties:

Form: Liquid 

Color: Colorless 

Odor: Nearly odorless 

Value/Range Unit Method

Melting point/Melting range: Not determined 

Boiling point/Boiling range: 45 ° C 

Sublimation temperature / start: Not determined 

Flash point: Not applicable 

Ignition temperature: Not determined 

Decomposition temperature: Not determined 

Danger of explosion: 

Product does not present an explosion hazard. 

Explosion limits: 

Lower: Not determined 

Upper: Not determined 
MSDS

Perfluorodimethylcyclobutane

Vapor pressure: Not determined 

Density: at 20 ° C 1.62 g/cm3 

Solubility in / Miscibility with Water:

Not miscible or difficult to mix 

10 Stability and reactivity

Thermal decomposition / conditions to be avoided: 

Decomposition will not occur if used and stored according to specifications. 

Materials to be avoided: Oxidizing agents 

Dangerous reactions No dangerous reactions known 

Dangerous products of decomposition: 

Carbon monoxide and carbon dioxide 

Hydrogen fluoride (HF) 

11 Toxicological information

Acute toxicity: 

Primary irritant effect: 

on the skin: May cause irritation 

on the eye: May cause irritation 

Sensitization: No sensitizing effects known. 

Subacute to chronic toxicity: 

Other than potential irritation (see above), no information on illness or 

injury from acute or chronic exposure to this product is available. 

Additional toxicological information: 

To the best of our knowledge the acute and chronic toxicity of this 

substance is not fully known. No classification data on carcinogenic 

properties of this material is available from the EPA, IARC, NTP, OSHA or 

ACGIH. 

12 Ecological information:

General notes: 

Do not allow material to be released to the environment without proper 

governmental permits. 

13 Disposal considerations

Product: 

Recommendation 

Consult state, local or national regulations for proper disposal. 

Uncleaned packagings: 

Recommendation: 

Disposal must be made according to official regulations. 
MSDS

Perfluorodimethylcyclobutane

14 Transport information

Not a hazardous material for transportation. 

DOT regulations: 

Hazard class: None 

Land transport ADR/RID (cross-border) 

ADR/RID class: None 

Maritime transport IMDG: 

IMDG Class: None 

Air transport ICAO-TI and IATA-DGR: 

ICAO/IATA Class: None 

Transport/Additional information: 

Not dangerous according to the above specifications. 

15 Regulations

Product related hazard informations: 

Observe the general safety regulations when handling chemicals 

National regulations 

This product is not listed in the U.S. Environmental Protection Agency Toxic 

Substances Control Act Chemical Substance Inventory. Use of this product is 

restricted to research and development only. 

Information about limitation of use: 

For use only by technically qualified individuals. 

16 Other information:

Employers should use this information only as a supplement to other 

information gathered by them, and should make independent judgement of 

suitability of this information to ensure proper use and protect the health 

and safety of employees. This information is furnished without warranty, 

and any use of the product not in conformance with this Material Safety Data 

Sheet, or in combination with any other product or process, is the 

responsibility of the user. 

Department issuing MSDS: Health, Safety and Environmental Department. 

Contact: Darrell R. Sanders