U.S. DEPARTMENT OF COttilEXCE
National Technical information Service
PB-260 646
11° tsntial Environmenta!
Consequences of
Tertiary Oi! Recovery
Energy Resources Co., Inc., Cambridge, Mass
July 1976
J

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/"
U.S. DEPARTMENT OF COMMERCE
National Technical Information Service
PB-260 646
Potential Environmental
Consequences of
Tertiary Oil Recovery
Energy Resources Co., inc., Cambridge, Mass
July 1976

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POTFMTI Al
ENVIRONMENTAL
CONSEQUENCES
OF TERTIARY
OIL RECOVERY
FINAL REPORT
JULY, 1976
U.S. ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF PLANNING AND EVALUATION
WASHINGTON, D.C. 20460

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BIBLIOGRAPHIC DATA
SHEET
1. Report No.
3. Recipient's Accession No.
PB-260 646
4. Title and Subtitle
Potential Environmental Consequences of Tertiary Oil
Recovery
5. Report Date
Jul 1976
7. Amhor
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TECHNICAL REPORT DATA
(Pleau read buiructtont on iht rerene btfort completing)
1. REPORT NO. 2.
3. RECIPIENT'S ACCESSION NO.
4. TITLE ANaSUSTI-LE
Potential Environmental Consequences of
Tertiary Oil Recovery
S. REPORT OATe
July 1976
S. PERFORMING ORGANIZATION COOE
7. AUTHORISI
C. Braxton, R. Stephens/ C. Muller, J. White,
J. Post, J. Norton, M. Goldberg, P. Stevenson
». PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND AOORSSS
Energy Resources Company Inc.
185 Alewife Brook Parkway
Cambridge, Massachusetts 02138
10. PROGRAM 4lEM*WT
11. CONTRAWfiRANY NO.
68-01-1912
12. SPONSORING AGENCY NAME ANO AOORESS
Office of Planning and Evaluation
U.S. Environmental Protection Agency
Washington, D.C. 20461
13. TYPE OF REPORT ANO PERIOD COVERED
Final, 6/75 - 4/76
14. SPONSORING AGENCY CODE
is. supplementary notes
IE. ABSTRACT
Potential environmental problems associated with the so-called tertiary
or enhanced oil recovery methods (micellar-polymer flooding, polymer
flooding, surfactant flooding, hydrocarbon miscible displacement,
carbon dioxide miscible displacement, steam displacement (or drive),
cyclic steam stimulation, and in-situ combustion (or fireflooding))
are identified. Possible impacts on ambient air quality, groundwater
supplies and water quality are assessed qualit- ively, and where
possible quantitatively, using dispersion modeling and risk estimates.
The report examines those potential problems which are unique to
enhanced oil recovery as well as post-operational problems such as
chemical degradation products. Forecasts of enhanced oil recovery
activity are allocated by process and region for use in impact
analysis. Research needs are described to evaluate the problem areas.
t T. key words ano oc
>CUMENT ANALYSIS
1. DESCRIPTORS
b. 1OENTIFlERS/OPEN ENOED TERMS
c. COSATI FfeUi/Group
Tertiary Oil Recovery
Enhanced Oil Recovery
Petroleum Production
Air Quality
Water Quality & Water Supplies
Groundwa ter


18. DISTRIBUTION ST/ TEMINT
19. SECURITY CLASS (ThuHtport)
U

30. SECURITY CLASS (THIl p*f)
u
32. PRICE
CM farm 1220-1 (•.»)
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potential environmental consequences
of tertiary oil recovery
CONTRACT NO: 68-01-1912
FINAL REPORT
BY
ENERGY RESOURCES CO. INC.
185 ALEWIFE BROOK PARKWAY
CAMBRIDGE, MA 02138
C. Braxton
R. Stephens
C. Muller
J. White
J. Post
0. Norton
M. Goldberg
P. Stevenson
FOR .
U.S. ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF PLANNING AND EVALUATION
WASHINGTON, O.C. 20460
Project officer: John Butler
JULY 1976
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This report has been reviewed by Energy
Resources Co. Inc., EPA, and approved for
publication. Approval does not signify that
the contents necessarily reflect the views
and policies of the Environmental Protection
Agency, nor does mention of trade names or
commercial products constitute endorsement
or recommendation for use.
The authors wish to express their apprecia-
tion to Mr. John C. Butler, EPA Project
Officer, for his guidance, direction and
comments throughout the study and during the
preparation of this report.
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TABLE OP CONTENTS
PAGE
CHAPTER ONE INTRODUCTION AND SUMMARY	I
1.0	Introduction	1
1.1	Conclusions	1
1.1.1	Water Supplies and Water Quality Conclusions	4
1.1.2	Air Quality Conclusions	6
1.1.3	Recommendations	6
1.2	Methodology and Scope of Report	9
1.2.1 Geographic Limits	9
X. 2.2 Problems Addressed	9
1.3	Limits of the Analysis	11
1.3.1	Technical Factors	11
1.3.2	Political Factors	12
1.3.3	Economic Factors	12
1.4	Research Needs	13
CHAPTER TWO TERTIARY OIL RECOVERY METHODS	15
2.0	Introduction	15
2.1	Micellar-Polymer Flooding	16
2.1.1	Introduction	16
2.1.2	Oil Displacement Mechanism	18
2.1.3	Process Description	21
2.1.3.1	Preflush	23
2.1.3.2	Micellar Solution	23
2.1.3.3	Mobility Control Solution and	25
Water Drive
2.1.4	Process Efficiency	26
2.1.5	Adsorption, Partitioning and Dilution	30
* 2.1.5.1 Adsorption	30
2~1*5»2 Partitioning	31
2.1.5.3 Dilution	31
i d.
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TABLE OP CONTENTS (CONT.)
PAGE
2.1.6 Outputs of the Process	33
2.1.6.1	Water Consumption	33
2.1.6.2	Chemical Consumption	35
2.1.6.3	Reservoir Material Balance	35
2.1.6.4	Chemical Manufacturing	39
2.1.6.5	Processing of Produced Fluids	42
2.2	Thermal Methods	43
2.2.1	Introduction	43
2.2.2	Steam Injection Methods	44
2.2.2.1	Steamflooding	44
2.2.2.2	Cyclic Steam Stimulation	46
2.2.2.3	Outputs of the Process	46
2.2.3	In-Situ Combustion Methods	48
2.2.3.1	Process Description	48
2.2.3.2	Outputs of the Process	50
2.3	Carbon Dioxide Methods	54
2.3.1 Outputs of the Process	55
CHAPTER THREE THE PETROLEUM INDUSTRY AND TERTIARY OIL	56
RECOVERY
3.0	Introduction	56
3.1	Current Operations	57
3.2	Future of the Industry	63
3.2.1	Forecasts of Tertiary Oil Production	63
3.2.2	Development and Growth	69
3.2.2.1 Location of Technically Feasible	69
Projects
3.2.3	Limitations to Development	82
3.2.3.1	Chemicals	85
3.2.3.2	W-ter Supplies	89
3.2.3.3	Current Regulations	93
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TABLE OF CONTENTS (CONT.)
PAGE
CHAPTER FOUR HAZARDS OF TERTIARY OIL RECOVERY	96
4.0	Introduction	96
4.1	Chemical Hazards	96
4.1.1 Compounds and Degradation Products	121
4.2	Carcinogenicity of Chemicals	128
CHAPTER FIVE EFFECTS OF TERTIARY OIL RECOVERY ON	133
GROUNDWATER
5.0	Introduction	133
5.1	Mechanisms of Contamination	134
5.1.1	hydrology	134
5.1.2	Sources of Pollutants	135
5.1.3	Mechanisms of Pollution	135
5.1.3.1	Bypassing the Natural Filter	137
5.1.3.2	Overwhelming the Natural Filter	137
5.1.3.3	Changing the Formation	141
5.2	Estimates of Probability of Contamination	141
5.3	Analysis of Factors Affecting Risk	151
5.4	RElative Regional Ri3k Levels	157
CHAPTER SIX IMPACT OF TERTIARY OIL RECOVERY ON	163
AMBIENT AIR QUALITY
6.0	Introduction	163
6.1	Summary	164
6.2	Methodology and Rationale	165
6.2^1 Description of Cases Modeled	165
6.2.1.1	Large Project Case	167
6.2.1.2	"Small•• Project Case	16J
6.2.1.3	Development Patterns	169
6.2.1.4	Geographic Locations	170
6.2.2 Pollutant Emission Rates	170
6.2.2.1 Sulfur Dioxide	1'1
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TABLE OF CONTENTS (CONT.)
PAGE
6.2.2.2	Oxides of Nitrogen	174
6.2.2.3	Particulates	174
6.2.2.4	Hydrocarbons	175
6.2.2.5	Carbon Monoxide	175
6.2.3 Modeling Procedure	175
6.3	Discussion of Results	176
6.3.1	Dispersion of Pollutants (Uncontrolled	176
Case)
6.3.2	Emission Control to Meet National Ambient	187
Air Quality- Standards
6.4	Regulations and Emission Control Strategies	189
6.4.1	Present Source Regulation	1-89
6.4.2	Emission Control Strategies	189
6.5	Limits of Analysis	190
G.5.1 Terrain	190
6.5.2	Sulfur Content in Fuel	191
6.5.3	Development Pattern	191
6.5.4	Modeling	191
6.5.5	Site Classification	192
CHAPTER SEVEN POLICY RECOMMENDATIONS	193
7.1	Summary of Problem Areas	193
7.1.1	Water Supplies and Quality	193
7.1.2	Air Quality	194
7.2	Current Environmental Regulatory Framework	194
7.2.1	Water Pollution	194
7.2.2	Air Pollution	196
7.2.3	State Oil Production Codes	198
7.3	Policy Recommendations	198
7.4	Research Needs	199
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TABLE OF CONTENTS (CONT.)
APPENDIX A GLOSSARY	A-l
APPENDIX B METHODOLOGY AND RATIONALE	B-l
B.l Estimation of Water Usage	B-l
B.2 Chapter Two — Fate of Sulfur Compounds and
Nitrogen Compounds Created During In-Situ
Combustion	B-l
B.3 Identification of Technically Feasible Projects	B-3
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LIST OF TABLES
PAGE
CHAPTER ONE
1-1
1-2
INTRODUCTION AND SUMMARY
Potential Environmental Problem Areas
Emission Reduction Required To Meet
National Ambient Air Quality Standards
for Full-Scala Development of Thermal
Recovery for a "Typical" Large Field
in Inland California
2
7
CHAPTER TWO
2-1
2-2
2-3
2-4
2-5
2-6
2-7
2-8
2-9
2-10
TERTIARY OIL RECOVERY METHODS
Some Typical Microeraulsion Compositions	24
Typical Operating Range of Important	28
Technical Parameters for Micellar-
Polymer Flooding
Efficiency of Micellar-Polymer Flooding	29
Water Comsumption in Micellar-Polymer	34
Flooding
Example Calculation of Chemical Concen-	36
trations in Produced Floods
Percentage of Oil Produced Per Mechanism	45
in a Steam Flood
Emissions Factors for Fuel oil Combustion 47
Composition of Produced Gas Stream from	51
In-Situ Combustion
Average Emissions of Gaseous Compound?	52
from In-Situ Combustion
Trace Elements in U.S. Crude Oil	53
CHAPTER THREE THE TERTIARY OIL RECOVERY INDUSTRY
3-1	Tertiary Oil Recovery Projects for	58
Firms Among the Top Twenty
3-2	Location of Tertiary Oil Recovery Projects 59
3-3	Profitability of Tertiary Processes	64
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LIST OF TABLES (CONT.)
PAGE
3-4	Forecasts of Tertiary Oil Recovery	65
3-5	Proportional Contributions of Recovery	67
Methods
3-6	Forecasts of Total Oil Production by	68
Recovery Methods
3-7	Estimated Cumulative Production from	83
Known Oil Fields in the U.S.
3-8	Availability of Chemicals for Tertiary	86
Oil Recovery
3-9	Options in Manufacturing Sulfonates	88
3-10	Oil Field Manufacture of Sulfonates	91
CHAPTER FOUR HAZARDS OF TERTIARY OIL RECOVERY
4-1	Chemicals Proposed for Use as Surfactants	97
4-2	Materials Proposed for Use as Mobility	98
Buffers
4-3	Hydrocarbons Proposed for Use as Fraction "?9"
of Micellar Slug
4-4	Chemicals Proposed for Use as Electrolytes 100
4-5	Chemicals Proposed for Use to Block	101
Exchange Sites in the Formation
4-6	Chemicals Proposed for Used as Cosurfactants 102
4-7a	Chemicals Proposed for Use to Initiate	103
Ignition of In-Situ Combustion
4-7b	Chemicals Proposed for Use to Increase	103
Efficiency of Thermal Methods
4-8	Minimum Concentration of Surfactant	106
Required to Produce a Perceptible Taste
and Odor
4-9	Chemicals Used as Bactericides and	HI
Biocides
4-10	Comparison of Chemicals Which May Be	113
Present in Processes with Water Quality
Criteria
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LIST OF TABLES (CONT.)
PAGE
4-11	Possible Degradation Reactions of	12:i
Materials Proposed for Use in
Tertiary Oil Recovery
4-12	Carcinogenic chemicals which May Be	129
Used in Tertiary Oil Recovery Operations
CHAPTER FIVE
5-1A	Tabulation of Contamination Incidents	144
Reported in Texas Railroad Commission
District III, 1970-1975
5-1B	Contamination Complaints Since Require-	144
ments of Impervious Brine Dispolal Pits,
Texas Railroad Commission District III,
1970-1975
5-2	United States Well Failures - 1974	146
5-3	Expectation of Pollution Incidents in	150
District III, Texas
5-4	Maximum Operating Conditions in Some	152
Typical Processes
5-5	Relative Corrosiveness of Recovery Methods 155
5-6	Fraction and Number of Wells in Major Oil 156
Fields of Each Region Where Tertiary
Recovery is Feasible
5-7	Relative Regional Risk of Well Failrre	158
for Micellar-Polymer Flooding
5-8	Relative Regional Risk of Well Failure for 159
Carbon Dioxide Miscible Methods
5-9	Relative Regional Risk of Well Failure	160
for Thermal Methods of Oil Recovery
5-10	Relative Regional Risk of Well Damage	162
Due to Seismic Activity
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LIST OP TABLES (CONT.)
PAGE
CHAPTER SIX IMPACT OF TERTIARY OIL RECOVERY
ON AMBIENT AIR QUALITY
6-1	Thermal Oil Recovery "Typical"	166
Oil Field
6-2	Areal Size of Major Central Valley	168
California Oil Field
6-3	Summary of Oilfield Steam Generators	172
Operating Characteristics
6-4	Summary of Emission Rates for Steam	173
Generators
6-5	Emission Reduction Required to Meet	18S
National Ambient Air Quality Standards
for Full-Scale Development of Thermal
Recovery for a "Typical" Large Field
in Inland California
APPENDIX B METHODOLOGY AND RATIONALE
B-l	Assumed Oil and Micellar Flood	-B-2
Characteristics for Estimation
of Water Usage
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LIST OF FIGURES
PAGE
CHAPTER ONE
1-1
CHAPTER TWO
2-1
2-2
2-3
2-4
2-5
2-6
INTRODUCTION AND SUMMARY
Physical and Chemical Mechanisms Which
May Act on Material Between the Source
of Spill and Water Supply
TERTIARY OIL RECOVERY METHODS
Ternary Diagram of Phase Relationships
When Oil, Brine and Surfactant are
Combined
Micellar-Polymer Flooding Process
Amount of Surfactant Produced Related
to the Amount of Surfactant Injected
into the Reservoir
Concentration of Surfactant and
Cosur fact ant in Produced Oil and Water
Effluent Stream Concentrations of
Surfactant and Cosurfactant
Mass Balance of Chemicals Used in a
Micellar-Polymer Flood
19
22
37
38
40
41
CHAPTER THREE
3-1
3-2
3-4
3-5
3-6
TERTIARY OIL RECOVERY AND THE PETROLEUM
INDUSTRY	"				
Location of Completed or Ongoing
Chemical Flooding Projects
Location of Completed or Ongoing
Thermal Tertiary Recovery Projects
3-3	Location of Completed or Ongoing
	jli _ aa	a
Miscible-C02 Injection Projects
Location of Oil and Gas Fields in U.S.
Location of Oil Fields in S. California
Location of Oil Fields in Texas Railroad
Commission Districts
60
61
62
70
71
72
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LIST OF FIGURES (CONT.)
PAGE
3-7	Location of Technically Feasible
Micellar-Polymer Flooding Projects
in Major Oil Fields in the U.S.
3-8	Location of Technically Feasible	74
Micellar-Polymer Flooding Projects
in Major Oil Fields in S. California
3-9	location of Technically Feasible	75
Micellar-Polymer Flooding Projects
in Major Oil Fields of Texas
3-10	Location of Technically Feasible	76
Thermal Tertiary Recovery Projects
in Major Oil Fields
3-11	Location of Technically Feasible	77
Thermal Tertiary Recovery Projects
in Major Oil Fields of S. California
3-12	Location of Technically Feasible	78
Thermal Tertiary Recovery Projects
in Major Oil Fields of Texa3.
3-13	Location of Technically Feasible	79
Miscible-CO- Injection Projects
in Major Oil Fields in the U.S.
3-14	Location of Technically Feasible	80
Miscible-CO_ Injection Projects
in Major Oil Fields of S. California
3-15	Location of Technically Feasible	81
Miscible-CO- Injection Projects in
Major Oil Fields of Texas
3-16	Relative Amount of Oil Expected to be	84
Produced in Each Region
3-17	Existing Oil Refineries Where New	90
Sulfonation Units Could be Constructed
CHAPTER FIVE EFFECTS OF TERTIARY OIL RECOVERY ON
GROUNDWATER
5-1	Physical and Chemical Mechanisms Which	136
May Act on Material Between the Source
of Spill and Water Supply
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LIST OP FIGURES (CONT.)
PAGE
5-2	The Contamination of Fresh Water Through	138
Bypass of the Hatural Filter System
5-3	The Potential Paths of Fresh Water	139
Contamination Resulting From Well Failure
5-4	The Contamination of Fresh Water	140
by Brine through (1) Overwhelm of
Natural Filter System and (2) Eressure
5-5	The manner in Which Differences in	142
Pressure, Temperature, and Chemical
Concentrations Affect the Flows of
Water in Aquifers
5—6	A Cross Section of a Typical Well in the 149
Conroe Field, Montgomery County, Texas
Showing the Location and Thicknesses of
the Important Aquifers and their
Relationship to the Oil-Bearing Zone
5-7	A Seismic Probability Map of the United	161
States
CHAPTER SIX IMPACT OF TERTIARY OIL RECOVERY ON
AMBIENT AIR QUALITY
6-1	Annual SO- Isopleths for Full Scale	177
Development of a "Typical" Large Project
for Thermal Oil Recovery in Inland
California
6-2	Annual SO- Isopleths for Full Scale	178
Development of a "Typical" Large Project
for Thermal Oil Recovery in the N. Rockies
6-3	Annual SO- Isopleths for Full Scale	179
Development of a "Typical" Large Project
for Thermal Oil Recovery in the Inland
Gulf Coast
6-4	Annual SO- Isopleths for Thermal Oil	180
Recovery tor "Typical" Small Project
Field in Inland California
6-5	Annual SO- Isopleths for Thermal Oil	181
Recovery for "Typical" Small Project Field
in the Inland Gulf Coast
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LIST OF FIGURES (CONT.)
PAGE
6-6	Annual SO, Isopleths for Thermal Oil	182
Recovery for "Typical" Small Project
Field in Northern Rockies
6-7	Annual S02 Isopleths for Full Scale	183
Development of a "Typical" Small Project
for Thermal Oil Recovery in N. Rockies
6-8	Annual NO Isopleths for Thermal Oil	184
Recovery In a "Typical** Small Project
Field in Inland California
6-9	Annual NO Isopleths for Thermal Oil	185
Recovery In a "Typical" Small Project
Field in N. Rockies
6-10	Annual NO Isopleths for Thermal Oil	186
Recovery In a "Typical" Small Project
Field in the Inland Gulf Coast
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CHAPTER ONE
INTRODUCTION AND SUMMARY
0 Introduction
Tertiary oil recovery processes may contribute 20 to 60
billion barrels of additional reserves to the Nation's
domestic supplies in known oil fields within the next 25
years.1 The resource potential of tertiary or enhanced
recovery is likely to play an important supplementary role
in fulfilling the country's needs for petroleum.
Because the techniques will usually be applied in
previously delineated and well-developed oil fields, the
economic risks of recovering tertiary oil are different from
the xxsJcs faced In off-shore and continental shelf oil and
gas exploration. Tertiary oil recovery processes will be
applied in the field on the basis of favorable expected
economic returns for a given project.
Certain environmental risks are associated with the
implementation of tertiary oil recovery; one goal in the
development of this technology should be to minimize its
environmental cost. A cost/benefit analysis of the environ-
mental impacts and economic gains is not possible until the
potential risks have been identified. This report delineates
the types of environmental problems which may occur.
1.1 Conclusions
As identified in Chapter Two, the processes for tertiary
oil recovery may pose the types of problems to the environment
shown on Table 1-1. In addition, the application of each
process may result in secondary impacts such as off-site
manufacture of chemicals, transportation of bulk chemicals,
and refinery load shifts to handle the higher average sulfur
content in lower gravity crudes.
In comparison with exploratory and developmental dril-
ling and conventional oil production, tertiary oil recovery
^Production forecasts for enhanced oil recovery which
-are summarized hera are discussed in detail in Chapter Throe.
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TABLE 1-1
TERTIARY OIL RECOVERY
POTENTIAL ENVIRONMENTAL PROBLEM AREAS
PROCESS
PROBLEM
CAUSES
Steam Displacement Air Quality
Water Quality
Water Supplies
In-Situ Combustion Air Quality
Water Quality
Micellar-Polyraer Water Quality
Flooding
Air Quality
Solid Wastes
Carbon Dioxide
Water Supplies
Air Quality
Water Quality
SO and particulates
from steam generators.
Hydrocarbons from pro-
ducing wells and other
field sources
Spills, leaks of
chemical foaming
agents (if used)
Process water demand
Hydrocarbons and CO
from producing wells
Spills, leaks of low
pH water with heavy
metals
Spills, reservoir and
well leaks, disposal
of chemically-loaded
brines
On-site manufacturing
of chemicals
On-site manufacturing
of chemicals
Process water demand
Fugutive emissions of
H2S combined with C02>
Low pH water with H2S
Spills, leaks
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projects pose different environmental problems. Much more
is known about the subsurface geology by the time an enhanced
recovery project is started. Delineation of the reservoir
has resulted from in-fill drilling following the original
discovery and additional detailed geologic data are compiled
and analyzed before the project. The high pressures which
may cause "blow-outs" in exploratory wells have been reduced
during earlier petroleum production operations so that this
risk is essentially eliminated in tertiary recovery. In
terms of potential magnitude of environmental problems, the
tertiary recovery processes examined in this study can be
roughly ranked as follows in descending order of environ-
mental concern: steam displacement, in-situ combustion,
micellar-polymer flooding, miscible carbon dioxide.
The thermal methods of enhanced oil recovery may pose
air quality problems if large-scale development occurs in an
oil field. A high density development oil field steam
generator burning 1 percent sulfur fuel can exceed National
Ambient Air Quality Standards for sulfur dioxide. Such
impacts may represent a stumbling block to the full realiza-
tion of the resource potential by thermal oil recovery
methods. Unanswered questions remain regarding emissions of
hydrocarbons from steam displacement and in-situ combustion.
Potential sources of these emissions may Include wellheads
and produced water treatment systems as well as fugitive and
area sources. Further data are required to characterize the
emissions from these sources in order to identify control
technology needs. In some cases the recovery of casing blow
gases containing oil condensate can be accomplished profitably,
thus improving the economic return of the project while
protecting the environment from these emissions.
Micellar-polymer floods involve large quantities of
expensive chemicals some of which could have an adverse
affect on the environment if improperly handled. Economic
factors should tend to mitigate environmental risks during
the operations phase of a micellar-polymer flood. Well
failures or improper injection profiles which could result
in the loss of expensive chemicals or poor reservoir re-
sponse must be prevented if the project is to be profitable.
Engineering studies are carried out in the early phases of a
project to identify and appraise these problems. Since the
front-end investment in such projects is large and the
returns in many cases are marginal, every effort would be
made to minimize foreseeable fluid losses and thus risks to
the subsurface environment. Disposal of chemically-laden
3-
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produced water should also be carried out in an environ-
mentally acceptable manner. Field data on the concentra-
tions of chemicals in the produced fluid streams is needed
to determine the need for effluent control systems.
1.1.1 Water Supplies and Water Quality Conclusions
Operational chemical flooding projects such as micellar-
polymer flooding pose few hazards to underground water
supplies because numerous physical and chemical processes
as shown in Figure 1-1 mitigate chemical leaks or spills.
At present, petroleum sulfonate surfactants are the commonly-
used materials which could have the most adverse impact on
water supplies and water quality. However, these materials
are susceptible to adsorption and precipitation within the
oil reservoir as much or more than any other chemical used.
Subsurface leaks from miscible carbon dioxide projects using
CC>2 containing some H2S could contaminate groundwater supplies.
Although no known problems of this type have occurred to date
as a result of enhanced oil recovery operations, hydrogen
sulfide contamination of groundwater supplies has occurred 1
as a result of conventional petroleum production operations.
Future hazards from compl ;ed chemical flood projects
should be of the same small magnitude as the risks from
ongoing recovery projects despite the fact that additional
mechanisms associated with well age tend to increase the
chances of leaks.
The two most significant potential causes of water
quality deterioration during tertiary oil recovery are:
(1) spills of chemicals as a result of transportation and
handling, and (2) improper disposal of chemically-loadad
produced water. Both sources are difficult to control by
further regulation. Considerable volumes of fresh water
from existing or potential water supplies may be required
to carry out large-scale projects for steam displacement
and to a greater extent for chemical methods of oil recovery
such as micellar-polymer flooding. Although this does not
appear to be a barrier to early development activities,
impacts on water supplies may occur due to local shortages
or encroachment of salt water into some aquifers.
^¦Personal communication with Mr. Love, City Secretary,
Lulling, Texas.
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Figure 1-1. This figure shows that between the source of a spill or leak of
chemicals used in tertiary oil recovery and a water supply there are a number of
physical and chemical mechanisms which may act on the material.
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1.1.2 Air Quality Conclusions
Widespread development of steam displacement projects
to recover low gravity crude oils in shallow reservoirs
could have a significant impact on air quality. The limits
on sulfur content in fuels set forth in some state implemen-
tation plans are not adequate to prevent regional standards
for sulfur dioxide from being exceeded. Table 1-2 illus-
trates the impact of a "typical" large recovery project. A
variety of control strategies are available which may make
it possible to keep regional air quality within the standards.
These strategies include advanced steam generator
designs, installation of stacks, use of low sulfur fuels,
combining emissions from several generators into one stack
and flue gas desulfurization. Further analysis and dispersion
modeling is required to assess the relative merits of each
strategy.
The cost/benefit assessment of each of these strategies
has a high priority for making environmental policy choices
regarding tertiary oil recovery. The selection of required
control strategies should consider the limitations imposed
on the development of this petroleum resource and balance
the benefits achieved with the reduction, if any, in the
quantity of oil economically recoverable by steam displace-
ment.
Air quality problems may also arise as a result of on-
site manufacture of petroleum sulfonates. However, further
research is required to characterize discharges, if any,
from field-scale units and to identify needed control tech-
nologies for emissions as well as solid wastes.
Emissions from many sources in tertiary oil recovery
projects have not been adequately characterized. It is
important to consider reservoir characteristics and recovery
process variables in the development of emission factors and
the drafting of environmental policies to control pollutant
discharges.
1.1.3 Recommendations
The thermal methods of tertiary oil recovery require
early attention at the environrtental regulatory level. In
particular, new source performance standards need to be
6-
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TABLE 1-2
TEfiTlARV OIL RECOVERY
EMISSION REDUCTION REQUIRED TO KflET NATIONAL AMBIENT AIR QUALITY STANDARDS FOR	,
FULL-SCALE DEVELOPMENT OF THERMAL PI :OVERir FOR A "TYPICAL" LARGE F1FLD IN INLAND CALIFORNIA
(Case Case is burning 1 percent sulfur fuel oil, USPS case assumes that the generators
discharge not more than 0*8 pounds of sulfur dioxide per million Btu's)2
l'OLtU-.-ANT
STANDARD
MAXIMUM PREDICTED
CONCENTRATION FROM
THB FIELD Cug/n3!
NATIONAL AMBIENT AIR
QUALITY STANDARDS
(wg/ra3)
POLLUTANT EMISSION
REDUCTION TO HLET
REGULATION (Percent}
MAXIMUM FUEL SULFUH COMTENT
TO MEET STANDARD
(Percent Height)
Base Case USPS
Sulfur Dioxide
Annual
140
(961
so
J4-Hour*
460
(315|
365
3-:iaura
662
(452 \
1,100
Base Case USPS	Base Case USPS
41
(17)
0.57
(0.571
21
<—)
0.79

-W-*
(">
—

dThe 24-hour and 3-hour standards are not to be exceeded more than once a year.
^Typical largo field la 9-section square 19 squere aiiles) with uniform distribution of 36-20 Mil Btu/hr
and 72-5G HH Btu/hr steam generators with 4-meter ani 6-meter vent heights respectively and no stacks,
iurnins 1*23 percent sulfur fuel at DO percent efficiency and 90 percent stream factor.
2At present there are no new source performance standards (USPS) for oilfield steam generators.
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developed for oilfield steam generators. EPA policy should
support research to characterize discharges from tertiary
oil recovery and monitoring of the types of chemicals
planned for use in recovery processes in the future.
Unanswered questions regarding the possible environ-
mental impacts of the other recovery processes should be
addressed during the demonstration projects sponsored by
the Energy Research and Development Administration (ERDA).
Through cooperative EPA/ERDA research, environmental data
should be obtained from such projects in sufficient detail
so that variations in compositions of the discharges from
tertiary oil recovery can be correlated over time with
reservoir characteristics and process variables. The types
of data which need to be collected are discussed below.
The following research areas are listed in order of
recommended priority:
1.	Cost/benefit analyses of air quality control
strategies for thermal oil recovery projects
assessing the levels of control attainable and oil
reserves lost due to (1) exclusionary zones
delineated by significant deterioration standards,
and (2) shorter economic life of production as a
result of the incremental costs associated with
emission control.
2.	Identification and prioritization of all point-and
area-sources of hydrocarbon emissions in thermal
oil recovery.
3.	Characterization of and emissions factors for
organic pollutants (particularly photochemically
reactive species) from in-situ combustion and
steam displacement as functions of process
variables, reservoir parameters, time and oil
characteristics.
4.	Measurement of chemical concentrations in produced
water from each of the processes, especially
micellar-polymer flooding and in-situ combustion
as functions of process variables, time, reservoir
characteristics and oil composition.
5.	Characterization of and emissions factors for
inorganic pollutants such as oxides of sulfur and
nitrogen irom in-situ combustion as functions of
process variables, reservoir parameters and oil
characteristics.
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1.2 Methodology and Scope of Report
The objective of this report is to set forth the
potential environmental problems which may result from
tertiary oil recovery processes. In this first-order
analysis, statistics from the limited experience with
tertiary oil recovery are used to extrapolate the problems
that may occur during full-scale enhanced recovery. To
date; field experience with the processes has been limited
because of uncertain economic returns resulting from high
costs and large technical uncertainties. Many processes
which have been proposed remain untested, and there is
insufficient field data on the others to readily determine
the environmental impact of large-scale tertiary oil recovery
on the basis of past activities. Where these data are un-
available, information from conventional petroleum extraction
operations is employed. It is recognized that this approach
may well overstate the future.problems associated with
tertiary oil recovery.
Therefore, as a preliminary environmental assessment of
tertiary oil recovery, this report reviews the processes
proposed in technical and patent literature as well as the
state-of-the-art to identify areas of environmental concern
which may require further quantitative definition and study.
1.2.1 Geographic Limits
The report is limited to oil fields amenable to tertiary
oil recovery which are located on-shore within the "lower
48" states. While tertiary oil recovery may be carried out
off-shore in some cases, lack of space on the platforms,
logistical problems and oth^r factors will generally preclude
early development of tertiary oil recovery there. Primary
and secondary recovery will be dominant in Alaska in the
immediate future.
1.2.2 Problems Addressed
The focus of the study is upon those potential environ-
mental problems which are unique to tertiary oil recovery as
opposed to the environmental problems which have the same
types and incidence as in conventional petroleum production
9
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operations. A comparative analysis of the industry's past
performance in environmental protection was not within the
scope of the effort. In addition to problems which may
arise during the tertiary recovery activity, the report
examines post-operational problems such as chemical degrada-
tion products and the failure of abandoned wells. The
initial project scope encompassed potential water quality
impacts and air quality impacts were included in this
framework as the results of analysis became available. The
report is organized in the following manner.
Chapter Two describes the processes, identifies the
sources of possible environmental problems and indicates the
process variables which may affect the magnitude of those
problems at a given project site. In this chapter the
following processes are examined (in order of emphasis):
micellar-polymer flooding, steaic displacement, in-situ
combustion, miscible carbon dioxide injection. "Tjilute
surfactant flooding and polymer flooding are discussed
briefly as distinct techniques in comparison with micellar-
polymer technology. Cyclic steam stimulation is included
with the advanced thermal methods of oil recovery because it
is sometimes used as part of a project applying these
advanced techniques. Due to the shortage of natural gas and
the present outlook for curtailed gas availability in the
future, miscible hydrocarbon slug processes and miscible
flue gas injection processes were not examined. The relative
emphasis on the processes in Chapter Two is based upon the
forecast potential for additional oil recovery by each
technology.
Chapter Three examines the past and ongoing recovery
activities and considers forecasts of future activity.
Future recovery activities sure assessed by process type and
a rough first-order estimate is made of activities by
process within regions of the country. Limits to the
attainment of tertiary oil recovery forecasts are discussed.
Chapter Four presents details on the toxicity and
carcinogenicity of chemicals which are proposed for use or
which have been used for tertiary oil recovery operations.
Chapter Five develops some order-of-magnitude estimates
of the probabilities that these chemicals will be released
into groundwater and surface water systems as a result of
well failure during or after tertiary oil recovery.
-10
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Chapter Six examines the impacts on air quality of
enhanced oil recovery operations. Chapter Seven presents
recommendations for further research and policy actions as
indicated by the report.
1.3 Limits of the Analysis
The terras "tertiary oil recovery," "enhanced oil
recovery," and "advanced oil recovery" are used inter-
changeably throughout this report. These terms refer co
recovery of additional oil from fields which might have been
produced by primary and conventional secondary means. In
the case of low gravity oils these terms refer to production
of oil which was technically or economically unrecoverable
by conventional extraction methods.
The so-called tertiary oil recovery techniques may be
most effectively utilized early in the life of an oil
field rather than following other primary or secondary
production techniques. Thus, the use of these methods could
become much more widespread them estimated in Chapter Three.
However, extended oil production from currently known
domestic on-shore reservoirs is the most likely initial
application of these techniques. In any case, these fields
represent the largest potential for tertiary oil recovery.
If the techniques are proven by extensive experience in the
older fields, tertiary oil recovery projects in the fields
of Alaska and off-shore may follow.
The application of tertiary oil recovery processes will
depend upon a complex interaction of technical, political,
and economic factors. The limits of this analysis of the
potential environmental problems associated with the pro-
cesses may also be grouped into technical, political and
economic aspects. All of these factors may cause shifts in
the relative importance of each process/ the materials
utilized, the level of activity, and therefore, the environ-
mental problems which have been identified in the report.
1.3.1 Technical Factors
The technologies c" tertiary oil recovery are in a
phase of rapid evolution. New materials are being con-
sidered, and earlier concepts are being re-examined, and it
-11-
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is impossible to foresee what developments will arise in the
future. As these processes evolve, the relative importance
of different environmental problems may change.
Research is continuing to define the mechanisms which
take place in the reservoir during tertiary recovery. This
new knowledge will gradually supplant the differences of
opinion which exist today regarding the functioning of the
processes. Better technical understanding of the process
mechanisms may provide a clearer insight into the environ-
mental problems.
The reservoir data which is required to assess the
feasibility of tertiary oil recovery is available only to a
limited extent. The simple approach used here to identify
the regional impact of tertiary oil recovery processes will
need to be refined as better information becomes available.
This review may result in interregional shifts in the types
and amount of recovery activity.
1.3.2 Political Factors
Federal policies regarding energy sources, reduction in
foreign supplies, petroleum pricing, incentives fox applica-
tion of new technologies, structure of the petroleum industry
and environmental matters may affect the choices of recovery
processes to be applied and the level of activity in tertiary
recovery. To a lesser extent state and local regulations
may influence the development and, hence, the environmental
impacts of tertiary oil recovery.
1.3.3 Economic Factors
The limitations to development of tertiary oil recovery
cited in Chapter Three are primarily economic. Chemicals
and water supplies may not be available. Oil prices may not
reach levels which are adequate to justify fieldwide pro-
grams. Excessive investment in redrilling and recompleting
aged fields may sour the prospective returns. Conversely,
in the case of chemicals, the demand for a paticular chemical
may not be large enough to justify large-scale, efficient
manufacturing units, thereby stifling the incentives to
invest in needed capacity.
-12-
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1.4 Research Needs
This study has sought to identify the potential environ-
mental problems which may result from tertiary recovery. In
many areas data are either lacking or incomplete with respect
to environmental questions. Many of the answers may be
sought in conjunction witn the Energy Research and Develop-
ment Administration field demonstration projects if environ-
mental studies under EPA guidance are integrated into the
demonstration programs. These research needs are:
° Characterization of and emissions factors for
inorganic pollutants such as oxides of sulfur
and nitrogen from in-situ combustion as functions
of process variables, reservoir parameters and
oil characteristics.
*	Characterization of and emissions factors for
organic pollutants (particularly photochemically
reactive species) from in-situ combustion as
functions of process variables, reservoir parameters,
time and oil characteristics.
•	Identification and prioritization of all point-
and area-sources of hydrocarbon emissions in
thermal oil recovery.
0 Cost/benefit analyses of air quality control
strategies for thermal oil recovery projects
assessing the levels of control attainable and
oil reserves lost due to (1) exclusionary zones
delineated by significant deterioration standards,
and (2) shorter economic life o! production as a
result of the incremental costs associated with
emission control.
° Evaluation of field sulfonation processes for
manufacture of petroleum sulfonates to assess
environmental and economic impacts of processes.
4 Evaluation of environmental impact of processes
and chemicals used to treat oilfield production
emulsions from tertiary recovery.
° Case studies and modelling of regional groundwater
systems to assess the impact of well failure on
•ater supply quality. The Chiquot formation in
'.exas is recommended as one of the areas for
further study.
-13-
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Measurement of chemical concentrations in
produced water from each of the processes, es-
pecially micell&r-polymer flooding and in-situ
combustion as functions of process variables,
time, reservoir characteristics and oil composi-
tion.
Assessment of environmental impact of a change
in refinery loads to process and desulfurize a
greater proportion of low gravity crude oils
resulting from production by thermal methods.
Quantification of the physical and chemical
factors which may act upon leaks or spills of
tertiary oil recovery chemicals. Define limits
to degradation processes which may act upon
chemicals used in tertiary recovery.
Evaluation of the synergistic toxicity (plant
and animal) and carcinogenicity of petroleum
sulfonates and other materials.
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CHAPTER TWO
TERTIARY OIL RECOVERY METHODS
-2.0 Introduction
Initially, moft oil fields have sufficient natural
forces to push oil c
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production may result from miscible gas injection. Chemicals
have been injected to overcome the forces holding the oil in
the rock and to improve the efficiency of waterflooding.
Certain chemicals are used which "wash" the oil out of the'
reservoir rock the same way that laundry detergent acts on
greasy stains.1 Chemical techniques such as micellar-polymer
flooding may produce about half of the recoverable tartiary
oil. Bach of these processes is described in terms of its
inputs and its outputs and the efficiency and limitations of
each method are analyzed. Appendix A is a glossary of some
important technical terms used in tertiary oil recovery.
2.1 Micellar-Polymer Flooding
2.1.1 Introduction
In setting up waterflood projects, the field is drilled
usually in a regular pattern consisting of a series of
injection wells surrounded by production wells or vice
versa. When water is injected into the formation, oil is
driven toward the production wells, where it is produced.
Initially, the movement of oil is caused by the water push-
ing it through the formation. Following water breakthrough,
however, the oil must be produced by being mechanically
entrained in the water drive. Since oil and water are
immiscible (they do not mix but rather form two phases), the
water will tend to bypass oil which is trapped and held by
capillary forces within the interstices of the formation.
Only the oil which is within or directly adjacent to the
flow paths of the water will be drawn into the fluid migration.
The technology of micellar-polymer flooding is similar
in operation to a waterflood (although considerably more
complicated), but it relies on chemical and physical forces
to effect oil displacement. In a miceliar flood, a "slug"
containing a high concentration of surfactant is injected
into the reservoir. The "slug" is called a micellar solu-
tion because the large concentration of surfactant causes
the formation of micelles. One of the unique properties of
an oil-external microemulsion is that it is miscible with
tho oil and, therefore, displaces the oil in the formation
by dissolving it in the slug.
^Shell Oil Company, Shell Reports — Enhanced Recovery,
(Houston, Tax., July 1975T"!
-16-
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A second displacement: mechanism, common to low tension
floods (dilute surfactant) or to the leading edge of the
micellar flood is related to the reduction of the interfacial
tension between oil and water as a result of the presence of
the surfactant in the micellar slug. As the interfacial
tension is reduced, the capillary forces acting hold the
oil within the reservoir are reduced. When the interfacial
tension is reduced to a very low value,3- the capillary
forces are no longer sufficient to retain the oil and,
consequently, it flows freely out of the pores.
One of the operational problems relating to micellar-
polymer flooding is that of mobility control. If the mobility
of the injected fluid is significantly greater than that of
the reservoir oil (as in the case of waterflooding), flow
channels (fingering) will develop causing a significant
portion of the oil to be bypassed. In the case of micellar
flooding, the problem is even greater because the large
difference between the slug and oil mobilities result in a
rapid dispersion of the micellar slug, thereby reducing its
effectiveness in displacing oil.
The environmental consequences of micellar-polymer
flooding depend on the answers to the following questions:
1 What is the nature of the chemicals being used
in this technology?
2.	How much of each chemical is expected to be used
at a given project as well as nationwide?
3.	What is the final disposition of chemicals which
are injected into an oil reservoir?
Although petroleum sulfonate surfactants may have a
deleterious effect on water quality, none of the chemicals
that are currently being used exhibit toxic or hazardous
properties sufficiently severe to raise serious environ-
mental concerns over present operations. A greater
potential for environmental impact, however, may come from
future developments. As the development of this technology
proceeds, other chemicals will be developed which are less
expensive, more effective, or more readily available. To be
J.J. Taber found that it would be necessary to lower
interfacial tension to pbout 10"^ dyne/cm to recover almost
all of the residual oil. Society of Petroleum Engineers
Journal 9(1) (1969).
-17-
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able to identify the environmental consequences of using
these materials, specific toxicology data will be required.
Many of the chemicals cited in the patent literature as
being possible substitutes for the materials currently being
used are discussed ir. Chapter Four regarding the hazards of
tertiary oil recovery. Many other materials may be developed
over the next several years, some of them hazardous and some
of them not.
The use of hazardous materials for enhanced oil recovery
dees not imply a direct environmental consequence. Rather,
it suggests *.ne existence of a potential threat of which EPA
should be aware if it is to adequately assess the risks to
the environment as opposed to the economic benefits to be
gained by this technology.
The extent of any potential threat is, of course,
difficult to assess, because there is very little published
data on enhanced oil recovery and no hard fast rules govern-
ing the design of micellar flood projects. Within the scope
of this preliminary assessment, however, it is important to
attempt to quantify what the risks and hazards might be. To
do this, first-order estimates are made of how much of each
class of chemicals is used and where these chemicals go
during "normal" recovery operations.
In the following sections a more detailed description
of the physical mechanism governing micellar displacement of
oil is given. The reader is cautioned that micellar-
polymer flooding is still developing and differences of
opinion concerning process details can be found throughout
industry. In this work, representative numbers based on an
analysis of published reports are presented. Although there
may be some disagreement over the numbers presented in this
and following chapters, the orders of magnitude of these
numbers are intended to be representative of current tech-
nology which are of sufficient accuracy for this preliminary
assessment of environmental consequences.
2.1.2 Oil Displacement Mechanism
The unique thing about oil-external microemulsions is
that they achieve miscible displacement of the oil similar
to the action of solvents on heavy grease. Consider for
example, the ternary phase diagram shown in Figure 2-1.
Each comer of the triangle represents a pure component in
-18-
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SURFACTANT
Figure 2-1. This ternary diagram illustrates the
phase relationships which may exist when oil, brine and
surfactant are combined.
-19-
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a three-component system. The components shown are oil,
water and the surfactant. The solid line on the ternary
diagram separates the single phase region above and a two-
phase region below. The unique property of this system is
that for a wide range of compositions, a microemulsion forms
such that oil and water co-exist in the single phase (i.e.,
they are miscible). In particular, a mixture of oil, water,
and surfactant which forms a microemulsion would oe miscible
with oil found in a reaservoir. Therefore, the microemulsion
would solubilize or dissolve the oil. Once solubilized, the
oil would be incorporated with the microemulsion and driven
toward the production well with the slug.
The process is actually more dynamic than described
above in that:
1.	The actual boundary between the one-phase and
two-phase region depends upon the physical
properties of the system such as temperature,
pressure, the nature of the surfactant, the
amount and nature of cosurfactant, the amount
and nature of electrolyte, and perhaps a few
other variables; and also
2.	The micellar slug will change composition
within the reservoir as oil and water are
inc* -porated into the microemulsion or as
adsorption of surfactant or cosurfactant
occurs on the rocks and r rerals.
Once the phase diagram for the system is known, the
behavior of the slug within the reservoir becomes more
predictable. For example, a micellar slug having the
composition shown as point A on the ternary diagram (Figure
2-1). As the micellar slug mixes with the reservoir fluid
shown as composition B in the diagram, the resulting compo-
sition of the mixtures falls along line AB on the diagram.
Eventually, the composition of the micellar slug will be
shifted into the two-phase region and will separate into a
predominately oil phase and a predominately water phase. At
this point, the micellar slug will no longer exhibit the
miscible characteristics which allow the micellar solution
to disolve the oil. However, oil will still be entrained ir.
the mobilired fluids due to a reduction in the interfacial
tension between reservoir oil and the surfactant-containing
slug. Because the mobility of the predominately water phase
is much greater than that of the oil phase, it will move
-20-
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more rapidly toward the production well leaving the oil
phase behind to form an oil bank in front of the leading
edge of the micellar slug.
In reality the physical chemistry of the surfactant/
oil/brine system is considerably more complicated. The
existence of many more than two phases within a single
ternary system ha3 been observed.! This is pointed out to
caution the reader that actual systems are not nearly as
nimple nor as predictable as described above. However, this
simple description is an adequate model for use in identify-
ing environmental consequences of micellar flooding within
the scope of this preliminary assessment.
2.1.3 Process Description
A typical micellar flood project proceeds in four
distinct phases as shown schematically in Figure 2-2. They
are:
1.	Preflush which is injected into the reservoir
to adjust salinity of the formation to be
compatible with the optimum surfactant system.
Final information on flew patterns may be
obtained at this time. Chemical control of
bacterial action may also be applied in this
and subsequent steps in the process;
2.	Micellar Solution (slug) including surfactant,
cosurfactaat, hydrocarbons, electrolytes, which
in combination accomplish the miscible displace-
ment of oil from the formations;
3.	Mobility Control Solution (buffer), a low salinity
water/polymer solution used to uniformly push
the micellar slug through the formation in as
close to a piston-like flow as possible; and
4.	Water drive which pushes the micellar slug
and mobility buffer through the reservoir to
the production well.
Each of these steps is discussed below.
^R.N. Healy and R.L. Reed, "Physicochemical Aspects of
Microemulsion Flooding," Society of Petroleum Engineers
Journal 10 11974): 337.
-21-
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IN:
1.	Water (Preflush)
2.	Microemulsion
3.	Polymer-Water
4.	Water
OUT;
1.	Water (brine)
2.	011-Water-Poiymer-
Surfactant
'vXvM
>KvwJ
v.v.v!
<~>>>«
v%%%vXvI%%%vX%v*%w^^
011
reservoir
Figure 2-2. This figure illustrates the micellar-
polymer flooding process.
-22
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2.1.3.1 Preflush
In preparation for a miceliar £lood, the reservoir
engineer must be concerned with how the slug and buffer
solution will move through the reservoir. Selection of the
surfactant systsm that will be most appropriate for the
reservoir being flooded is also of concern. Initially, core
samples are studied to determine the optimum micellar system
which may include cosurfactant and electrolyte. Once this
is known, a brine solution having the optimum concentration
of electrolyte is .injected into the well to (1) provide a
tracer analysis of the project flow characteristics, (2) to
adjust salinity if necessary, and (3) to reduce the concen-
tration of divalent ions in the reservoir which may adversely
affect the slug. In the presence of a high concentration of
these divalent ions, the surfactant in the slug quickly
loses its effectiveness through complexing or through
formation of precipitates within the reservoir. Adsorption
on selective ions within the reservoir clays has also been a
problem.
2.1.3.2 Micellar Solution (slug)
At this stage in the development of micellar-polymer
flooding, the design of the surfactant system for a par-
ticular reservoir is still very much an empirical art. The
slug is composed of hydrocarbon, brine and surfactant. A
cosurfactant, such as alcohol, and salts are also added
to control stability and viscosity of tiie fluid. All of
these compounds will have an effect on the system phase
diagram.
In Table 2-1, typical recipes for microemulsions are
given. The surfactant systems are generally classed as
either low- or high-water and oil-external or water-external.
Such a classification system is used more for convenience
than for providing a chemical description of the microemul-
sion system. For example, a given surfactant could be used
to form both oil-external and water-external emulsions
depending upon the concentrations of brine and hydrocarbon
included in the initial mixture. In the ternary diagram
shown in Figure 2-1, the mixture represented by point A is
^"Healy and Reed, "Physicochemical Aspects," 1974.
-23-
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TABLE 2-1
TERTIARY OIL RECOVERY
SOME TYPICAL MICROEMULSIOM COMPOSITIONS*'**

"VOLUME PERCENT
CONSTITUENT
LOW WATERC
OIL EXTERNAL
HIGH WATERd
OIL EXTERNAL
HIGH WATERd
WATER EXTERNAL
LOW WATERC
water External
Surfactant
6-10
3 - €
3-5
6-12
Cosurfactant
2-4
0.01 - 20
0.01 - 20
3-25
Hydrocarbon
30-80
4-40
2-50
20 - 60
Electrolyte
0.001 - 5®
0.001 - 4®
0.001 - 4®
3 - 5e
Water
5-55
55-80
30 - 95
25 - 40
aw.B. Bleakley. Oil & Gas Journal 69(46) (1971)s 50.
Private communication. Union Oil of California, January 13, 1976.
Q
A "loy water" emulsion slug is comprised of less than approximately 50 percent water.
Some operators believe that such slugs are not economically feasible.
dA "high water" emulsion Kluq is comprised of more than approximately 50 percent water.
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an oil-external emulsion. If, however, the proportion of
brine to oil is changed leaving the amount of surfactant
constant, the resulting mixture shown as point A. forms a
water-external micellar solution. When the micellar solu-
tion is mixed with oil and brine within the reservoir, to
the point that the composition becomes that shown as point
C, the slug will separate into two phases — one shown as
point C-l (a water-external emulsion) and the other shown as
point C-2 (an oil-external emulsion).
The choice of surfactant and cosurfactant depends upon
cost and flood design. Economic considerations usually
restrict the choice of surfactant to petroleum sulfonates
and the choice of cosurfactants to light alcohols. Natural
petroleum sulfonates used for most micellar floods have a
distribution of equivalent weights and will not be single
compounds. Petroleum sulfonates with equivalent weight
greater than 400 grams are predominantly oil-soluble and
those with equivalent weights of less- than about 400 grams
are predominantly water soluble microemulsions.
The hydrocarbon in the slug may be crude oil produced
earlier at the field (lease crude), gasoline, or kerosene,
among others. However, lease crude is qenerally chosen
because of its availability, low cost, and high compati-
bility with the reservoir.
2^1.3.3 Mobility Control Solution and Water Drive
A mobility control solution is required to push the
microemulsion slug through the reservoir. Polymer is added
to water to increase the viscosity of the mobility control
solution. The solution exhibits unique flow properties. At
high linear flow rates, such as occur ncsr the injection
well, the polymer solution gives low resistence to flow
while at low linear flow rates further from the injector it
gives high resistance to flow. The high resistance to flow
causes the polymer solution to invade a larger paction of
the reservoir and move through the reservoir more uniformly
than water alone would do. A properly chosen polymer solu-
tion will force the microemulsion ahead evenly to contact a
large part of the reservoir. The ratio of the part of the
reservoir contacted to the total reservoir volume is known
-25-
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as the "sweep" efficiency of the micellar-polymer flood. in
field operations a sweep efficiency of up to 75 percent has
been achieved. The polymer used in a mobility buffer may
also "plug off" parts of the oil reservoir by adsorbing onto
the sand grains. Polyaerylamides exert mobility control by
both methods. Polyethyleneoxides and polysaccharides only
change the viscosity of the mobility buffer.
The concentration of polymer in solution is gradually
decreased as the injection of the mobility buffer progresses.
This has helped to improve tv.e economics of micellar-polymer
flooding because less polymer can be used overall and the
process can then be completed by water injection. Polymer
consumption will average about one pound per barrel of oil
produced by the project. Very low concentrations of the
polymer will appear in the produced water because of either
adsorption or dilution.
When a polymer solution is injected alone and not in
combination with a micellar slug, polymer concentrations
will be evident in every barrel of water produced.*
However, this has not been observed in field operations to
date. The use of polymer solutions in this manner is r
expected to have as widespread application as micellar-
polymer flooding.
2.1.4 Process Efficiency
The efficiency of micellar-polymer flooding is depen-
dent upon a complexity of factors. Among the most important
variables are how much of the oil in the rock actually comes
into contact with the surfactant in the slug and how evenly
the mobility buffer pushes the oil and slug throughout the
reservoir. Although there is a growing body of knowledge on
the principles of micellar-polymer flooding, and the process
may result in recovery of substantial additional quantities
of oil from known fields, models to predict reliably the
performance in various reservoirs are still under development.
Calgon Corporation, Bulletin 14-100, p. 12. Regardless
of permeability, polymer was contained in the first drop oil
produced water. At 600 ppm concentration of polymer in the
injected slug, initial concentrations of polymer in the
effluent were 300 ppm. (Results of laboratory studies in
triple layer sand packs performed by Calgon Corporation to
assess polymer retention.)
-26-
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Many of the early laboratory studies bear little resemblance
to the field results because improper scaling or over-
simplification of the reservoir have so changed the parameters
of the experiment that no comparison is possible. Many
combinations of chemicals for micellar solutions have yet to
be studied in the field. In view of these considerations,
and the face that much of the required reservoir information
has not been measured so that the reservoirs may be evaluated,
it is nearly impossible to predict performance of micellar-
polymer solutions with any quantitative accuracy.
The difficulty of predicting micellar-polymer flooding
efficiencies has been one factor which has hindered wide-
scale adoption of this method of oil recovery. Considering
the large number of parameters which affect micellar-polymer
flooding, qualitative estimates of the efficiency of the
process can be made on the basis of important field character-
istics^ For a given oil saturation, the quality of injection,
water and the dissolved solids concentrations in the reservoir
brine is an important characteristic. Table 2-2 lists a
typical range of reservoir conditions which are suitable for
micellar-polymer flooding.
Table 2-3 illustrates the efficiency of micellar-
polymer flooding for different water quality conditions in
reservoirs where the otb ; important parameters are favorable.
The highest efficiencies of recovery are achieved when the
total dissolved solids and divalent ion concentrations in
both the formation water and the injection water are low.
Poor quality water within the formation may be overcome by
preflushing the formation with injection water of high
quality, and good efficiencies of recovery are possible.
Fair to poor efficiencies of recovery are achieved when the
quality of injection water is low due to high concentrations
of total dissolved solids and clivnlent ioi.s. Injection
water problems in this case can sometimes be overcome by
constituting the micellar slug with a higher proportion of
hydrocarbon or by counteracting the adverse effects of the
dissolved chemicals through chemical treatment. When the
quality of injection water and the formation water are low,
in terms of dissolved chetaical concentrations, poor recovery
efficiencies can be expected, and, in such cases, a fieldwide
micellar-polymer flood would not be attempted.
-27-
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TABLE 2-2
TERTIARY OIL RECOVERY
TYPICAL OPERATING RANGE OF IMPORTANT TECHNICAL
PARAMETERS FOR MICELLAR-POLYMER FLOODING**
Oil viscosity
Reservoir temperature
Permeability*5
Total dissolved solids
in brinec
Divalent ions in brine or
reservoir clays"
30 centipoise or less
up to 200° F
more than 20-50 millidarcies
less than 50,000 mg/L
less than 500 mg/L
^Factors such as oil saturation and porosity influence the
economic feasibility ox the process and laboratory studies are
necessary to determine the affect of these parameters on
technical feasibility.
bThe ratio of variation in permeability should be less
than 7 to 1.
cMr. G-sf fen's original limit of 5,000 mg/L has been
raised as a result of further research.
^Divalent ions which are typically found in oil field
waters are calcium, magnesium, barium and strontium.
Source: T.M. Geffen, Amcco Production Company, "Improved
Oil Recovery Expectations When Applying Available Technology,"
API Division of Production meeting, Denver, Colorado, April
9-11, 1973.
28-
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TABLE 2-3
TERTIARY OIL RECOVERY
EFFICIENCY OF MICELLAR-POLYMER FLOODING
(GIVEN OTHER PARAMETERS ARE FAVORABLE)
HIGH
QUALITY OF
INJECTION WATER
LOW
Low Quality ¦ Total Dissolved Solids > ^0,QOO_roy/L
and Divalent Ions > 500 rag/L
High Quality * Total Dissolved Solids < 50,000 mg/L
and Divalent Ions < 500 ing/L
Recovery Efficiency - "P e r ce n t"o f oil-in - pTa c e~ in the
reservoir before tertiary recovery
is started which is produced by the
Llood. Actual recovery efficiency
in a given reservoir will also be
Influenced cy the remaining oiT
saturation and other factors.
25	50	75
~i	i	1
FAIR	GOOD EXCELLENT
QUALITY OF FORMATION WATER
(PREFLUSH OR FLOOD)
HIGH	LOW
I
EXCELLENT
II
GOOD
III
FAIR
TO
POOR
IV
POOR
RECOVERY n-
EFFICIENCY .
POOR
-29-
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2.1.5 Adsorption. Partitioning and Dilution
The answer to the question, "Where do all the chemicals
go during a micella.- flood project?", depends upon the
following mechanisms:
1.	Retention ~ adsorption or entrapment of
chemicals in the rock formation;
2.	Partitioning — the distribution of produced
chemicals between the oil and aqueous phases;
3.	Dilution — the lowering of chemical concert
tration due to a mixing with reservoir fluids.
2.1.5.1 Adsorption
In the ideal system, only the amount of surfactant
necessary to produce a miscible microemulsion would be
injected. Except for consideration? of critical micellar
concentrations, experimental work has not been published to
indicate the minimum amount of surfactant required per
barrel of oil recovered. In reality, additional surfactant
is injected to account for material adsorbed onto the
reservoir rock and clays. Since it is difficult to estimate
in-site adsorption, at least some surfactant remains when
the slug eventually reaches the production wells. At the
present time, the amount of surfactant injected into the
well is largely dependent upon adsorption characteristics of
the reservoir formation. As the extensive development of
new surfactants continues, several new formulations ciay be
developed which would substantially reduce adsorption,
thereby reducing the amount of surfactant used in the process.
To quantify the amount of surfactant adsorbed within
the reservoir, the following data were considered. Triishenski
reported adsorption data of a range of 0.5 to 2.0 pounds per
barrel of pore volume in a preflushed Berea sand stone, core
and range of 1.0 to 3.0 pounds per barrel of pore volume in
a core which was not preflushed.^- Gilliland repor.ted data
in the same range with some samples at high alcohol |o
surfactant ratios approaching an adsorption of zexo-
^S.P. Trushenski et al., Society of Petroleum Eaqir.eers
Paper 4582, 48th SPE meeting, (Las Vegas, Nevada, 1 J/.
^Gilliland, 9th World Petroleum conference. Panel
Tokyo, Japan, May 1975.
-30
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Gale reported adsorption of approximately 1.4 pounds per
barrel of pore volume, also in agreement with the above
sources.1
2.1.5.2 Partitioning
The chemicals injected into the reservoir which are not
retained by adsorption or other forms of retention, will
eventually be produced when the oil bank and oil water
emulsion reach the production wells. Surfactants and co-
surfactants will be found in both the oil and water phases.
A partitioning coefficient has been defined as the ratio of
the weight fraction of chemicals found in the oil phase to
the weight fraction of those found in the aq»<:.&as phase. In
particular, the partitioning coefficient ranges from 0.1 and
1.5 for a sodium sulfonate with an equivalent weight of
427.2 The partitioning coefficient varied with both the
surfactant and cosurfactant concentrations and the surfactant-
to-alcoho] ratio. In addition, the alcohol partitioning
coefficient for an unidentified alcohol was shown to be
constant at approximately 0.5 over the same range of con-
centrations and sulfonate ratios as tested for the sulfonate
partition coefficient.3 In general, the partition factors
will vary depending upon the surfactant composition and
reservoir parameters. However, for this preliminary
assessment, Gilliland's published data will be used as
representative of typical partitioning to be expected.
2.1.5.3 Dilution
The environmental consequences of chemicals used in
micellar flooding are often assessed in concentrations
rather than in actual weight. Because the parameters of
micellar flood vary widely, the concentrations of surfactant
and cosurfactant found in the produced oil and water will
also vary greatly. Even so, it is possible to make estimates
of the concentrations that might be expected in the produced
W.W. Gale and E.I. Sandvik, "Tertiary Surfactant
Flooding: Petroleum Sulfonate Composition-Efficacy Studies,"
Society of Petroleum Engineers Journal, (August 1973).
Gilliland, 9th Wo*.id Conference, May 1975.
"^Gilliland, 9th World Conference, May 1975.
31-
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fluids based upon a consideration of the limited available
data from existing micellar projects.
The most difficult concentration to estimate is that of
the surfactant in the produced oil and water since a consider-
able amount of the surfactant {if not all) is retained
within the reservoir rather than being produced with the
reservoir fluids. On the other hand, the cosurfactant such
as alcohol are not expected to adsorb on to the formation
because of its high water solubility. Instead, it will be
retained in the formation only through entrapment. The
remaining amount of cosurfactant will be produced with the
reservoir fluids.
The total weight of surfactant and cosurfactant that is
produced is the injected weight less the weight of material
retained in the reservoir. When the slug materials are
exposed to reservoir fluids and mixing occurs with, the
mobility control solution, these materials are diluted by
oil or water depending upon the partitioning behavior of the
compounds. The resulting concentrations of chemicals
remaining in solution in the produced water, the reservoir
water (and similarly, oil) will depend upon the recovery
efficiency and oil saturation at the particular project.
The weight (W) of these materials going into the oil is
weight into water,
P is the partitioning
ratio of the produced
oil per pound of
(2-1)
(2-2)
is then the weight of
material divided by the volume. Using the knowledge of the
micellar-polyraer flood process and these mechanisms, the
outputs of the process and material balances will be esti-
mated in the following section.
calculated from Equation 2-1; and the
from Equation 2-2. In the equations,
coefficient and R is the oil-to-water
fluid expressed in units of pounds of
water.
Woil * "total |_ 1+P (R) J
"water " "total [ 1+P^ ]
The concentration in these two phases
-32-
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2.1.6 Outputs of the Process
2.1.6.1 Water Consumption
Water Is used in all phases of micellar-polymer oil
recovery. The water carries chemicals into the formation,
where they are left. Water produced by the process may
carry some of these chemicals and plays an important role in
diluting discharges of these chemicals to the environment.
Large volumes of water are used in preflushing, formu-
lation of the micellar slug and the polymer solution, and in
the follow-up water drive. For example, in some typical
fields suitable for micellar-polymer flooding the following
range in water usage might be expected. Table 2-4 illustrates
estimated water consumption for various micellar-polymer
flood situations. (Appendix B provides detailed data on the
estimating procedure.)
As discussed earlier, when the connate water, or-the
water used in a previous waterflood, is not compatible with
the micellar emulsion because of high ion concentrations,
preflushing of the reservoir with water containing precipi-
tating or neutralizing agents is necessary. Preflushing
will use one to six barrels of high quality water per barrel
of oil eventually recovered by the project.
Preparation of the micellar solution requires the use
of water with concentrations of salts similar to those of
the reservoir water or the preflush water. The water
constitutes 30 to 95 percent by volume of the micellar slug,
and thus, for this typical reservoir, from one-tenth to as
much as two barrels of water would be required in the slug
per barrel of oil to be recovered.
The mobility buffer consists of fresh water thickened
with polymer. Its volume is usually about 50 percent of the
total pore volume of the reservoir. The water requirement
for the mobility buffer will be approximately two to five
barrels of water per barrel of oil produced in most applica-
tions. An additional three or more barrels of water per
barrel of oil produced are then required to complete the
flood. Injection rates will vary with the permeability of
the formation and the viscosity of the injected fluids. It
is estimated that a micellar-polymer flooding project which
requires a preflush could require as much as 19 barrels of
water per barrel of oil produced of which up to 14 barrels
of water must be of 'acceptably high quality.
-33
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TABLE 2-4
TERTIARY OIL REOCVERY
WATER CONSUMPTION IN MICELLAR-POLYMER FLOODINGa
(Barrels water per barrel of oil produced)
QUALITY OF FORMATION WATERb
(BEFORE PREFLUSH)
HIGH	LOW
LCW WATER/
OIL EXTERNAL
TYPE OF SLUG®
HIGH WATER/
WATER EXTERNAL
6.5-9
-8.5 - 12
8.5 - 13
11.5 - 15
aBased on high quality water
bLow Quality, See Table 2-3
High Quality, See Table 2-3
cSee Table 2-2 for definitions. For water consumption
-estimates- see- Appendix- B—
34
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1 2
2.1.6.2 Chemical Consumption '
Surfactant usage will vary widely among projects even
within the same region and geologic basin. The range of
consumption can be expected to be 5 to 15 pounds o£ sur-
factant per barrel of oil produced in a micellar-polymer
flood. Cosurfactant consumption may range from 2 to 10
pounds per barrel of tertiary oil produced. Polymer con-
sumption will be approximately one pound per barrel of oil
produced.
2.1.6.3 Reservoir Material Balance
From the information developed above it is possible to
calculate an approximate material balance of micellar-
polymer flooding in a typical reservoir. An example of such
a calculation is shown in Table 2-5. The maximum injection
rate of surfactant and cosurfactant is assumed to be about
15 pounds per barrel of oil and 10 pounds per barrel of oil
respectively. Some of these chemicals will contact the
reservoir but will not be produced with oil and brine due to
entrapment or water breakthrough. A loss of 25 percent of
these chemicals due to entrapment has been assumed in
subsequent calculations. In addition, surfactants will be
lost to the reservoir due to adsorption. At an adsorption
rate of 2 pounds per barrel of pore volume, and an oil
saturation of 50 percent, the actual rate of loss is 4
pounds per barrel of oil produced. Considering that the
concentration of surfactant in the produced oil will
approach zero when smaller quantities of surfactant are
injected per barrel of oil ultimately produced, an adsorp-
tion curve such as the one shown in Figure 2-3 may be
constituted.
The concentrations shown in Table 2-5 represent the
maximum possible concentrations based upon the assumptions
stated. Estimates based upon different assumptions will, of
course, result in different estimates. For example, the
effect of oil/water ratios is shown in Figure 2-4. At
C.F. Poefctman cites the following example of chemical
requirements per 100,000,000 barrels of microemulsion pro-
duction which is developed: 1.7 billion pounds of surfactant,
7.24 million pounds of alcohol (13.1 million gallons at an
average of 4 lb/gal), 102 million pounds of polymer (Petroleum
Engineer 47 (1075) : 42).	~
Federal Energy Administration, Enhanced Oil Recovery
Symposium, Washington, D.C., December 1974.
-35-
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TABLE 2-5
TERTIARY OIL RECOVERY
EXAMPLE CALCULATION OF CHEMICAL CONCENTRATIONS
IN PRODUCED FLUIDS
SURFACTANT COSURFACTANT
Maximum Injection Rates, Lb/Bbl of Oil	15.00	10.00
Loss from Sweep, 75% efficiency	3.75	2.50
Loss due to entrapment, 25%	4.00
@ 50 percent saturation		
Net Produced, Lb'Bbl of Oil	7.25	7.50
Partitioning (P3»0.7, Pc»0.5, O/W»0.5)
Oil Phase	1,88	1.50
Aqueous Phase	5.37	6.00
Concentration in Produced Fluids (ppm)
Cil Ftiasa	5,360	4,280
Aqueous Phase	7,660	8,550
-36-
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OIL SATURATION
AMOUNT OF SURFACTANT INJECTED
(Lb/Bbl OF OIL)
Figure 2-3. This figure shows that the amount of
surfactant produced will vary with the amount of
surfactant injected into the reservoir (based upon a
maximum absorption of 2 Lb/Bbl Pv, 100 percent displace-
ment efficiency, 75 percent sweep efficiency.
-37-
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15.000
2 10,000
££¦
£
©
5,000
AQUEOUS
PHASE-
OIL
PHASE
0.1 0.2 °-3
0.4 0.5 0.6 0.7 0.8 0.9 1.0
OIL/WATER RATIO
(3bl/Bbl)
Figure 2-4. This figure shows that the
surfactant and cosurfactant in th-s produced rt??tration of
vary with oil:water ratio of the produced fluid ^ wat8r will
(Based on the following parameters)
Total weight (Lb/Bbl of Oil)
Partitioning Coefficient
SURFACTANT COSURFACTANT
7.25 7.50
0.7	0.5
-38-
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relatively low oil/water ratios, the concentrations produced
in the oil and aqueous phases are expected to be much lower
than those shown in Table 2-5. On the other hand, oil/water
ratios as high as 1.0 barrels of oil per barrel of water
wouLd result in concentrations of surfactants and ccsurfact-
ants considerably higher than those shown in the table. In
particular, note that if the micellar slug displaces oil in
the ideal pistonlike fashion, the oil/water ratio will
approach 1.0 rather than 0.S as assumed in the example
calculations. Hence, the assumptions on which the examples
are based are believed to be representative of present
practice and may, in fact, be somewhat conservative.
The chemical concentrations in the produced fluids will
also depend upon the initial rate of injection in that the
amount of produced chemicals increases as the injected
quantity increases. This is illustrated in Figure 2-5
showing concentration as a function of total weight produced.
The estimated concentrations shown previously in Table 2-5
are based upon a maximum injection rate of 15 pounds per
barrel of oil. Injection rates less than thia will result
in correspondingly lower exit concentrations. Though
limited published field data are available, one set of
process tests had a maximum surfactant concentration of
1,000 parts per million in both the oil and water phases at
breakthrough.1 From this preliminary analysis, it appears
that higher concentrations are Likely in the effluent* from
future tests.
Figure 2-6 summarizes the overall material balance for
a wide variety of possible outcomes based upon these analyti-
cal techniques.
2.1.6.4 Chemical Manufacturing
Manufacture of the chemicals required may create
pollutant hazards. Although on-site manufacturing facil-
ities would be subject to pollution control regulations, the
remote location of these facilities, their scale and
simplified operating procedures may result in a higher
incidence o^ uncontrolled discharges. Enforcement of
scattered facilities may be more difficult than intensified
monitoring of an increased level of output at large chemical
^C.F. Poettman, Petroleum Engineer, p. 39.
39-
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%
"S 10,000
8ff
o —
§
H
s
S:
M
5,000
OIL/WATER RATIO "0.5
AQUEOUS 7 01l/WATEK
r RATIO » 0.10
TOTAI> WEIGHT INJECTED
(Lb/Bbl OP OIL)
Figure 2—5. This figure shows the effluent stream
concentrations of surfactant and cosurfactant for various
injection quantities and two oil:water ratios. (Based on
assumptions used in Table 2-5)
-40-
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Figure 2-6. This figure is the mass balance of chemicals used
in a micellar-polyitier_fjLood. (Hydrocarbon in slug not shown for
simplification of diagram.)
-41
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plants- The production of petroleum sulfonates Tisay result
-in the emission of doin^ unreacfced gaseous sulfur dioxide and
sulfur trioxide as well as a discharge of some sludce con-
sisting of sulfonate complexes, sulfuric acid or sodium
hydroxide and oil residue. Further studies of particular
sulfonation processes are required to evaluate quantitatively
the emission and discharge loads, these loads w 11 varv
regionally depending on the choices between field-scale and
refinery-3cale sulfonation.
2.1.6.5 Processing of Produced Fluids
The produced fluids from, flood or surfactant flood are
often emulsions which are difficult to treat economically
in conventional oilfield separation systems. In order for
the crude oil to be acceptable for refining it must contain
less than 1 percent BSW (Bottoms, Settlings and Water) when
it leaves the oil field. Higher water content in the crude
oil would increase the refinery's energy usage {to boil off
the excess water) and would also create problems of foaming,
tit n^du^r;^COr'rntiQIlai field treatment invol^s
heating the produced oil and water or adding chemical deemul-
sifiers m concentrations of about 1 aallon af	Z.J1
10,000 barrels of oil £0.233 ¦J/iii.rf. ?hf¦£?SSflSSt
emulsions from tertiary oil recovery production to date have
required treating with dosages on the grder of l Sinf of
chemicals per barrel of oil (1.49 x i03 roniVuter? This
huge increase m the volumes of chemicals used for treatment
may introduce other potential environmental problems,
The presence of surfactants in the crude oil from
tertiary oil recovery has not presented serious difficulties
to refinery operations to date. A few	s IC	.
conditions are all that is usually rewire^S	gating
the materials. The amount of sulfur compounds no™*??
added to the processes by the .uifSaSTS?UtTSS^ia
relation to sulfur m most crudes.	in
-42-
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2.2 Thermal Methods
2.2.1 Introduction
The tertiary oil recovery processes based on thermal
methods improve oil recovery by two basic mechanisms. Since
the processes have been tried primarily on more viscous
crude oils, interest has focused upon reducing viscosity of
oil in the formation to enable it to flow more easily toward
the producing wells. In addition to viscosity changes,
thermal methods increase oil recovery through some form of
steam distillation of the oil in the formation. Other
methods are involved, and the actual part played by each
mechanism depends on the type of oil in the reservoir.
Two important methods of generating heat within the oil
reservoir are of interest here: the injection of steam into
the reservoir, and the burning of part of the oil in the
reservoir by in-situ combustion of "fireflooding."
The important economic consideration for the thermal
methods of tertiary oil recovery is the cost of fuel. Steam
processes are sensitive to the cost of fuel required to
generate the steam, whereas the important cost element in in
in-situ combustion is the fuel required to power compressors
wHich inject air into the formation. Similarly, most limita-
tions to the thermal methods are based upon economic ineffi-
ciencies of heat loss rather than on technical factors such
as reservoir chemistry. In particular, thin formations with
low porosity are unfavorable for the thermal methods because
too much heat is lost through the surfaces above and below
the formations and it is too difficult to inject the steam
or air into a tight formation without prior fracturing.
The environmental concerns of thermal methods arise
from the generation of the heat and the effects of that heat
on the produced fluids. Combustion products from steam
generation and light hydrocarbon vapors from the distilla-
tion mechanism may be emitted to the air. Collection and
recovery of hydrocarbon vapors is often economically
justifiable and would be carried out by the prudent oper-
ator. However, fugitive emission problems may still exist.
Chemical reactions may occur in the hot reservoir which
create or release other compounds. These compounds may
enter solution in reservoir water which may leak into
groundwater systems.
43-
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2.2.2 Steam Injection Methods
Steam drive (or stearoflooding) and cyclic steam soak
(or huff-and-puff) are two common methods of steam injection.
The oil recovery efficiency depends on the thermal properties
and compositions of the reservoir fluid of the formation.
Since the kinematic viscosity of the oil in the formation
decreases linearly as temperature is increased, oil produce
tion is directly related to the temperatures achieved in
the reservoir. The major technical limitation of steam
processes is the depth o£ the oil-bearing strata. At
greater depths, higher temperatures and pressures are needed
for maximum effective usage of the steam- Titese operating
conditions can cause damage to the well's casing and cement.
The major factor contributing to inefficiency of steam
injection processes is tne loss of heat. Oil-bearing sands
thinner than twenty feet are not favorable because too much
heat escapes to rocks above and below. There is less loss
of heat in the well when pumping into shallow formations.
Surfact losses are on the order of 5 percent? wellbore heat
losses may be in the range of 10 to 15 percent of the total
number of British Thermal Units (Btu's) injected. Unfortun-
ately, insulation is expensive and can only be justified for
long-term projects.
2.2.1.1 Steamflooding
Zn this technique, steam serves to drive the oil as
well as to reduce its viscosity. Steam is injected into the
oil reservoir through injection wells. Separate production
wells remove the oil.
The steam-saturated zone, in the reservoir whose
temperature is approximately that of the injected steam,
moves oil to the production well by steam distillation of
the oil, solvent extraction, and a gas drive. As the steam
cools and condenses a zone of hot water is formed which
floods the formation. The relative importance of these
mechanisms in the production of oil is shown on Table 2-6.
Oil recovery efficiency ranges from 35 to 50 percent of the
reservoir oil-in-place, depending on oil and reservoir
characteristics.
44
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TABLE 2-6
TERTIARY OIL RECOVERY
PERCENTAGE OF OIL PRODUCED PER MECHANISM
IN A STEAM FLOOD

TYPE
OF C
RUDE

NON
DISTILL-
ABLE
25%
DISTILL-
ABLE
50%
DISTILL-
ABLE
Hot water
87
75
68
Gas Drive
5
4
3.5
Distillation
0
14
22.5
Solvent Extraction
8
7
6
TOTAL
100
100
100
Based on an analysis of laboratory data presented
by B.T. Willman et al., Transactions of the AIME, 222,
(1961) p. 681.
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2.2.2.2 Cyclic Steam Stimulation
Cyclic steam stimulation enhances recovery by heating
the remaining oil-in-place to reduce its viscosity, enabling
it to flow toward the well. Steam is injected into the
reservoir for a period extending from two to three weeks.
The well is then shut in to allow heat to soak into the
formation before allowing it to flow and later be pumped.
The cycle is repeated once the oil production declines below
am economically acceptable level. Though stimulated pro-
duction may continue for up to six months, recovery levels
will decline relatively soon. A yield of 20 to 35 percent
of the oil-in-place is achieved, which is moderate in com-
parison to steamflood methods. This process is applicable
to small oil pools as well as large reservoirs and has the
advantage that continuous generation of steam for injection
is not required.
A variation of these thermal methods, hot water flooding,
"has not been promising. This poor performance is attributed
to a number of factors. The same capital investment in heat
generating equipment is needed as in steam injection processes.
Hence, the same environmental problems exist as for other
methods which can achieve high recovery in a given field.
Furthermore, wellbore heat losses are high — up to 30
percent — while overall heat loss has attained 60 percent.
Oil recovery efficiency has been low — generally, approxi-
mately 10 percent — though in a few fields up to 20 percent
of the remaining oil-in-place has been recovered.
2.2.2.3 Outputs from the Process
The emissions from oiL field steam boilers depend on
the size of the project, the oil recovery efficiencv of the
process, the heat losses which occur, with more than 100
boilers. Individual boilers range in size from 5 to 500
million Btu's per hour. One-third to one-fourth of the oil
recovered is generally required for use as fuel and as
reservoir production declines an economic limit is reached.
Fuels for boilers may be natural gas, fuel oils, or crude
oil from the lease. Though emissions will vary with the
content of sulfur and other compounds in the crude, Table
2-7 illustrates the composition which may be expected in
typical operations. To these emissions must be added the
particulate discharge from boiler cleaning cycles and from
trace metals in the crude oil fuel. Hydrocarbon may also be
-46-
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TABLE 2-7
TERTIARY OIL RECOVERY
JEMISSIONS FACTORS FOR FUEL OIL COMBUSTION
(Pounds/1,000 Gallons of Fuel Oil Burned)"3
POLLUTANTS
LARGE SOURCES
(1,000 hp
or more)
SMALL SOURCES
(1,000 hp
or less)
Aldehydes
Benzo (a) pyrene*3
Carbon monoxide
Hydrocarbons
Nitrogen oxides as NO2
Sulfur dioxide
Sulfur trioxide
Particulates^
5,000
(yg/1,000 gal)
3
2
105
157 Sc
2.0 Sc
8
40,000
(wg/1,000 gal)
4
40 to 80
157 Sc
2 Sc
23
aW.S. Smith, Atmospheric Emission from Fuel oil
Combustion, Public Health Service Publication No."999-
AP-2, R.A. Taft Sanitary Engineering Center, Cincinnati
Ohio, November 1962.	'
b Density of fuel Ml equals ~S lb/ga"l,* and 42 gal » 1 barrel.
cR.P. Hangebrauck, D.J. von Lehmden, and j.e. Meeker'
"Emissions of Polynuclear Hydrocarbons and Other Pollutants
from L'eat-generation and Incineration Processes," Jourr 1
of the Air Pollution Control Association 14 (July 13^4J 'f 267.
J
S a % sulfur in oil.
Source: U.S. Environmental Protection Agency, Compilation
of Air Pollutant Emission Factors, August 1975.		
47-
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released to the atmosphere at the wells during production.
The particular operating and reservoir parameters ofT oil
fields where steam displacement is carried out will determine
the actual quantity of emissions.
2.2.3 In-Situ Combustion Methods
These tertiary recovery methods are based on generating
heat in the formation by burning part of the oil there. Air
is injected into the reservoir where ignition"is induced by
an electric heating unit or by spontaneous ignition of
chemicals. The major costs of these methods are the capital
and operating expenses of the equipment used to inject air
in order to maintain the combustion process. As combustion
advances in the reservoir, oil, lighter hydrocarbons, water
and combustion gases are driven toward production wells.
Though fireflcoding is applicable to a wide range of
reservoir conditions, some oils do not form coke — which is
the fuel for the bum — in adequate quantities. Asphaltic
crudes, as a general rule, seem to burn better than para-
ffinic oils for a given gravity due to the former's high
levels of bitumen. Peculiar characteristics within the oil-
bearing strata also affect in-situ combustion. Some oils
which leave high deposits of coking fuel could make the
process uneconomic due to the large volume of air needed to
maintain combustion. An increase in the rate of input of
air produces higher combustion temperatures and therefore a
higher efficiency. At a low air input, the percentage of
the oxygen utilized is low and therefore the process is
uneconomical because unnecessary costs are incurred in
pumping air.
2.2.3.1 Process Description
A number of zones; exist in the reservoir undergoing a
"fireflood." In each of these zones, dynamic processes
occur which determine the rate and amount of additional oil
recovered. The burned region is composed primarily of
clean, finely grained sand. The action takes place at the
burning zone. Here, heat breaks down the oil into coke,
which catches fire, and lighter oils are vaporized or move
ahead of the burning region. Temperatures in this zone
range from 600° F to 1.200° P depending upon the reservoir's
48-
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physical characteristics and the operating conditions of the
project.
Just ahead o£ the burning front is where coke is produced
by craking and distillation of crude oil, which dissociates
the lighter from the heavier hydrocarbons. The coke residual
fractions are composed of high boiling point hydrocarbons
containing oxygen, sulfur, nitrogen and trace metals.
Molecular weights of these residual fractions range from 300
to 900 grams per mole. These fractions can represent up to
20 percent of the crude oil. Their exact composition is not
known.
Another zone created in a fireflood consists of light
hydrocarbons, which are vaporized by the burning front or
other hot regions of the process. As the gases are driven
through part3 of the reservoir they displace some oil and
improve the oil recovery.
An important variation of in-situ combustion method is
a process known as wet combustion.* A fire is started in
the formation. Then, water is injected alternative1'* with
air to transfer excess heat from the burned region through
and ahead of the combustion front in the form of water
vapor. The effects of added heat and steam drive further
reduce the viscosity of the oil ahead of the combustion
front. With this process it is possible to move thicker
oils than with a dry fireflood and to operate at lower
pressures with possibly less fuel. Because less fuel may be
burned, less air is required than with dry combustion.
Though the process has not had wide application in the
field, it is expected that recovery efficiency of 40 to 60
percent of the original oil-in-place will be possible for
mobile crudes and highly porous rock formations. Somewhat
lower oil recovery efficiency (on the order of 30 to 50
percent) is expected where porosities and initial oil
saturations are not as high.
One process of wet combustion known as COFCAW or
"combination of forward combustion and waterflooding" has
been patented by Amoco Production Company (formerly Pan
American Oil Company).
-49-
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2.2.3.2 Outputs of the Process
The high temperatures to which the reservoir is sub-
jected in the burning region of a fireflood enable a number
of chemical reactions to occur. The compounds created in
this manner as well as the combustion residues may be present
in the emissions at production wells. Others may be confined
in the reservoir after the process is completed.
Possible emissions from an in-situ combustion project
are varied. Some of the corcpoun2s listed in Table 2-8 may
appear at the production welis. Table 2-8 is an analysis of
the major constituents of the produced gas in a sample of
thirty one in-situ combustion projects. No data on oxides
of nitrogen or trace contaminants were developed, however.
Light hydrocarbons, comprising 1 percent of the produced gas,
appear chiefly as propane, methane and, to a lesser extent,
ethane. Table 2-9 presents an estimate of the volumes of
constituent gases produced per barrel of oil produced.
Regional differences in the operating and reservoir character-
istics of in-situ combustion projects would affect the
emissions produced. The chemical and physical process of
combustion within an oil-bearing stratum are complex and the
possible environmental effects of combustion products need
further study.
Sulfur compounds can be released in the burning of crude
oils. Sulfur content of crude oils in the Wilmington area of
California range from 1.7 to 2.5 percent below 17 degrees API
gravity. For the purposes of this investigation, it was
assumed that most of the sulfur compounds would remain in
flood water or produced water during water combustion oil
recovery processes. This assumption is based on the low pH
of produced water from projects in the sample (a discussion
of the chemistry is included in Appendix B). The typical
values of pH were 2.7 to 4.0. The acidity of the water in
the reservoir at the end of a fireflood could corrode the
casings in plugged and abandoned wells and lead to contami-
nation of aquifer3.
Another source of potential contaminants is the residue
of trace metals and metal oxides from the crude which may be
dissolved by the acidic water left in the reservoir. Table
2-10 lists the concentration of trace elements in crude oils
from various areas of the country. The residual fractions
of the coke are not soluble in water, though trace metals
may be dissolved bj wet combustion process. Further research
is required to assess this problem.
-50-
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TABLE 2-8
TERTIARY OIL RECOVERY
COMPOSITION OF PRODUCED GAS STREAM
FROM IN—SITU COMBUSTIONa
(Percent Molecular Weight)
HYDROGEN
TRACE
Carbon Monoxide;
Carbon Dioxide:
2.5 - 3.0
12 - 14
Oxygenr
1.0
Nitrogen and Oxides:*3
78 - 83
Hydrocarbons:
(Methane
(Ethane
(Propane
0.4-0.5)
0.1)
0.4-0.5)
0-1%
pH of Produced Water:
1.6 - 8.6
*Based on a survey of 31 projects.
These gas streams were measured at near
ootimum ooeratina conditions early in
the life of the flocd. As the flood
progresses the composition of emissions
may change to include oxides of sulfur.
^Formation of N0X compounds is not
favored at the typical burning tempera-
tures in a fire flood of 700-1,200° F.
Most of the emissions would probably be
nitrogen.
51
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TABLE 2-9
TERTIARY OIL RECOVERY
AVERAGE EMISSIONS OF GASEOUS COMPOUNDS
FROM IN-SITU COMBUSTION"'"
EMISSIONS
COMPOUND	(Standard cubic feet per
barrel of oil produced)
Carbon Dioxide
435
Carbon Monoxide
160
Nitrogen and NOx c
4,220
Oxygen
185
Hydrocarbons
150
aAssumes all sulfur compounds remain in solution with
produced water. However, emissions of SOx may occur in the
late phases of a fire flood.
bBased on a survey of the gas streams of 31 fire
floods (average value).
cFormation of NOx compounds is not favored at the
typical burning temperatures in a fire flood_of .700® F to
l,200a~F. Most of the emissions would probably" be nitrogen.
-52-
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TABLE 2-10
TERTIARY OIL RECOVERY
TRACE ELEMENTS IN U.S. CRUDE OIL
(Parts per Million)

ORIGIN
OF C R
U D E
ELEMENT
CALIFORNIA
LOUISIANA
TEXAS
Antimony
<0.007
0.05
<0.01
Arsenic
<0.007
0.05
<0.12
Barium
<0.06
0.09
<0.14
Manganese
0.018
0.027
<0.05
Nickel
77
4.4
3.3
Tin
<0.6
0.5
<1.0
Vanadium
48
1
1.9
Source: E~.M.~Magee et al., Potential Pollutants
in Fossil Fuels, EPA Report No. EPA-R2-73-249, June 1973.
-53-
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Uncontrolled burning of oil reservoirs is not a problem
in in-situ combustion. Electric heaters are often used to
ignite the formation. Several cases of spontaneous ignition
using air injection alone have been achieved in California
and in the Woodbine formation in Texas. However, the fire
is extinguished when air injpotion ceases.
2.3 Carbon Dioxide Methods
Though carbon dioxide is not completely miscible with
most crude oils, it is soluble with both crude oil and water
at reservoir temperatures and pressure. When carbon dioxide
is injected and mixing occurs, the viscosity of the crude
oil is reduced so that it flows more easily toward the
production wells. Three variations are presently employed
by the petroleum industry for tertiary oil recovery.
One method involves injection of carbon dioxide in a
slug, followed by water or carbonated water. The second
method involves injection of carbonated water directly. The
third method involves injection of carbon dioxide at high
pressures to achieve mixing directly with the reservoir oil
and the formation of an oil-miscible slug in the formation.
Though carbon dioxide reaches almost all of the oil in the
reservoir and can achieve high contact efficiency with the
oil, mobility control has been a continuing problem with the
floods. Economic success of carbon dioxide methods is
dependent on a nearby source of inexpensive carbon dioxide.
Injecting carbon dioxide at high pressures is also expensive,
as in the injection of air in in-situ combustion processes.
The major factors contributing to oil recovery in
carbon dioxide flooding are formation of a miscib.i e slug
in in-situ modification of viscosity and changes in oil
density and compressibility of fractions. By maintaining
the slug in a single dense phase, its solubility with crude
oil is increased considerably. Crude oil vi3cosities rang-
ing from 5 to 90 centipoise can be reduced by a factor
between 10 and 100 times under high injection pressures of
carbon dioxide. After a carbon dioxide flood has been
completed, the gas comes out of solution to some degree due
to reduction in pressure, creating a further gas drive
within the reservoir.
54-
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One problem that has also been noticed in the use of
carbon dioxide injection processes is the effect of preci-
pitation of asphalt compounds under carbon dioxide pressure.
Variations in carbon dioxide flooding have been attempted
which incorporate the use of foaming agents with the flood
to achieve more mobility control with the gaseous medium.
These techniques, however, have received few trials on a
fieldwide basis to date.
2.3.1 Outputs of the Process
Carbonic acid is formed when carbon dioxide dissociates
into the water in the reservoir. Operational problems of
carbonic acid corrosion have been reduced by injecting water
and carbon dioxide separately. Corrosion of casings may occur
after the fluids reach the reservoir and are produced.
Seepate of acidic fluids from wells at the recovery project
could affect groundwater.
Safety in handling carbon dioxide and hydrogen sulfide
is also required. On February 2, 1975, a gas leak occurred
at a carbon dioxide injection well in Texas resulting in
nine deaths by H,S poisoning. To date this is the only such
case recorded, yet it does suggest that such tragic accidents
could occur along pipelines or at the wellsite. Control
systems to detect leaks and limit the escape of carbon
dioxide to small quantities are available and are required
by regulation in some states.
55
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CHAPTER THREE
THE PETROLEUM INDUSTRY
AND TERTIARY OIL RECOVERY
3-0 Introduction
The environmental impacts/ if any, of tertiary oil
recovery projects are likely to increase or change as the
amount of recovery activity increases in number and size in
the future. To understand fully the scope of these impacts
and to place them into a national context/ the potential
sites, the processes and the structure of the industry which .
will carry out this activity will be examined in this chapter.
Although early tertiary recovery projects have been
characterized by technical difficulty and financial risk,
the potential of additional oil recovery has spurred the
development of a number of operations. At least 32 companies
have undertaken more than 200 advanced recovery projects in
this country. Over 70 percent have been located in Taxas or
California, with the remainder in 13 other states. Of those
undertaken, approximately 130 are currently active.
In addition to projects completed or underway, numerous
others are being planned or have recently begun operation.
In 1974 at least 22 enhanced recovery programs were scheduled
to commence within the year, reflecting rapid increases in
the price of international crude oil and continued interest
in tertiary recovery. Thirteen others were slated for
operation before 1980. By last year 14 companies had settled
on plans for 35 projects in 12 states. Almost half were to
be located in California, where thermal recovery methods
have proven both feasible and profitable in unlocking low-
gravity crude oils.
The following company-process analisis was developed
from a sample of planned and ongoing sophisticated recovery
projects contained in the March 25, 1974 issue of The Oil
and Gas Journal supplemented with additional reports on
Independent projects and programs supported by the Energy
Research and Development Administration.
-56
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3.1 Current Operations
Because of the financial risks involved, major domestic
crude oil producers dominate the tertiary recovery industry.
The list of projects in Table 3-1 indicates a relatively
high degree of industry concentration among the major oil
companies. Table 3-1 shows that Companies among the Top 20
initiated 80 percent o£ those projects undertaken before
1974; the Big Eight alone accounted for almost two-thirds.
To gauge more accurately the involvement of particular
companies in tertiary oil recovery, it is necessary to
separate the activities into pilot and fieldwide projects.
Genarally, fieldwide projsets require a larger investment
than pilot projects if research personnel costs are excluded.
By this criterion, the larger companies appear more active.
Roughly 60 percent of the projects operated by firms in the
Top 20 are classed as fieldwide; for Big Eight firms the
corresponding figure is 66 percent. Relatively fewer
projects of the smaller firms — 56 percent — were dubbed
fieldwide by their operators. The gap between the Big Eight
and the smaller firms is initially non-existent for projects
slated to begin in 1974 or subsequent years; both groups
expected roughly 60 percent of these to be fieldwide.
However, firms among the Top 20 but outside the Big Eight
appear to have escalated their efforts in the area; fieldwide
activities were slated for 70 percent of their new projects,
indicating an increasing commitment to processes which have
been proven on a pilot scale.
Cross-classification of tertiary recovery projects by
process and location demonstrates an uneven distribution.
For example, Texas — with slightly over one-fourth of all
projects — has had a third of all combustion projects.
Similarly, 62 percent of all miscible hydrocarbon and 75
percent of all miscible CO, sites have been located in
Texas. California has had over 80 percent of all steam
drive programs. Breakdowns of projects by location and
method are found in Table 3-2. Figures 3-1, 3-2, and 3-3
pinpoint these project locations throughout the country. An
unbalanced distribution characterizes the classification of
projects by process and company. While experimenting with a
variety of tertiary recovery methods, most firms appear to
rely heavily on two or three. Although steam soak, combustion,
steam drive and polymer flood are popular individually with
many companies, each company is involved to a different
extent in each method. Hence, regulations aimed at particu-
lar processes would unevenly affect companies within the
industry.
-j 7-
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TABLE 3-1
TERTIARY OIL RECOVERY PROJECTS FOR FIRMS AMONG THE TOP TWENTY
OVERALL
DOMESTIC	TERTIARY	PROJECTS
PRODUCTION	RECOVERY	PROJECTS COMPLETED TOTAL
RAHKa	RANKb	PLANHED OR UNDERWAY PROJECTS
Exxon
1
11*
0
2
2
Texaco
2
3*
7
»
16
Gulf
3
6
1
10
11
Shell
4
7
0
10
10
Standard of
California
5
2
4
16
20
ARCO
6
8
0
9
9
Amoco
7
5
0
14
14
Mobil
8
1
0
37
37
Getty
9
S*
6
2
ft
Union
10
11*
0
2
2
Sun
11
9*
1
7
8
Conoco
12
3*
0
16
16
Marathon
13
10*
0
3
3
Phillips
14
10*
1
2
3
Cities
15
11*
1
1
2
Skelley
13
11*
1
1
2
TOTAL


22
141
163
&
Based on the Federal Trade Commission Report released on July IB, 1973.
^Determined on the basis of projects planned and projects underway.
^Indicates more than one company in same riek.
-------
TABLE 3-2
LOCATION OF TERTIARY OIL RECOVERY PROJECTS

•
-------
I
en
0
1
Figure 3-1. This figure illustrates the location of completed or ongoing chemical
flooding projects.
-------
Figure 3-2. This figure illustrates the location of completed or ongoing
thermal tertiary recovery projects.
-------
Figure 3-3. This figure illustrates the location of completed or ongoing
miscible-C02 injection projects.
-------
The widespread popularity of certain processes may in
part be explained by examining their respective profitability
records. Evaluations o£ various methods from all companies
undertaking enhanced recovery have been combined in Table
3-3 to yield a set of profitability ratios. Processes which
have been proven and expanded to fieldwide operations generally
have the best profitability ratios. Smaller companies
appear to choose the proven processes for enhanced oil
recovery whereas the Top 20 are more involved in demon-
strating advanced techniques. Independents listed 71 percent
of reporting projects as moneymakers# whereas the comparable
figure for programs administered by companies within the Top
20 was only 55 percent. The ratios are likely to improve for
many processes as operators learn more about the best pros-
pects upon which to apply them. For example, in-situ com-
bustion, having a profitability ratio of only 23 percent,
was designated for six projects scheduled for 1974 or later.
Other methods lacking substantial profitability data such as
micellar solution flood and combinations of water and gas
injection were also slated for the same per.icd.
3.2 Future Prospects
The « advanced oil recovery projects and new tests
should provide the technical understanding necessary for
tertiary oil recovery to expand on a larger scale. The fact
that these technologies are still relatively young as regards
fieldwide applications makes it difficult to extrapolate
future oil production by tertiary methods from current
activities. This is less of a problem for thermal methods
than for micellar-polymer flooding as reflected in the
disparity of estimates for its further potential. Adding
still another estimate here of the recovery potential la not
within the scope of this investigation and would only obscure
the examination of other important issues. Instead, a
critical appraisal of other forecasts will be made to select
a basis for determining the environmental consequences of
tertiary oil recovery.
3.2.1 Forecasts of Tertiary Oil Production
Recently* a number of estimates of the potential of
tertiary oil recovery have been made (Table 3-4). There is
obviously wide disagreement among the estimates resulting
from the particular setting assumed in each forecast. The
higher estimates may be considered to be overall targets for
-63
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TABLE 3-3
TERTIARY OIL RECOVERY
PROFITABILITY OF TERTIARY PROCESSES3

# COM-
PILED OR
UNDERWAY
t REPORTING
FINANCIAL
STATUS
*
EfiCFIT-
ABLE
PERCENT
PROFIT-
ABLE
Combustion
39
30
7
23
Cyclic Steam
42
39
39
100
Steam Displacement
22
17
9
53
Polymer Flood
20
16
6
33
Kiscible Hydrocarbon
21
18
13
72
Miscible CO2
9
5
1
20
Micellar Solution
Flood
7
1
1
0
Waterflood
Alternating Ga3
4
3
3
100
Surfactant Flood
4
2
0
0
Caustic Soda Flood
2
1
0
0
Hot Waterflood
2
2
0
0
Lov Tension waterflood 1

—
—
Soluble Oil Flood
1
1
0
0
Water/Gas injection
1
1
1
100
Water/Gas Pulsing
1
1
0
0
TOTAL
176
137
80
^ased on an ^ ;aly3is of data presented in the March 25,
1974 issue of The Oil and Gas Journal.
-64-
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-TABLE~T-.r
FORECASTS OF TERTIARY OIL RECOVERY
(Billions or barrels)
SOURCE
LOW
HIGH
FEAa

65
NPCb Case I
11.4®
20d
GURCe
18.5
36.3
Mathematical'9
7.0
16.0
federal Energy Administration, Review of Secondary/
Tertiary Recovery of Crude Oil. 1974."
^National Petroleum Council, U.S. Energy Outlook Oil
and Gas Availability, 1973.
Production over next 15 years by tertiary recovery
from old and new fields, excludes 18.5 billion barrels
produced by secondary methods. Daily average production
rate estimated at 1.79 million barrels by 1985 from
tertiary methods.
^Reserve additions due to tertiary recovery projects
over next 15 years.
eGulf Universities Research Consortium, Planning
Criteria Relative to a National RDT&E Program~bj.rected
to the Enhanced Recovery of Crude Oil and Natural Gas,
November 30, 1973. Daily average production of 1.8 mi11ion
barrels by tertiary recovery estimated in 1983.
£
Mathematica, inc., The Estimated Recovery Potential
of Conventional Source Domestic Crude Oil, May 1975^
^Excluding "extended waterflooding" estimates of
8-9 billion barrels.
65-
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the future. But, in a shorter time frame, 65 billion barrels
of output estimated by the Federal Energy Administration is
probably not achievable in view of any reasonable combination
of economic, political and technical developments. The
additional production by tertiary methods which will occur
during the coining 10 to 15 years is of most interest.
During this transitional period a clearly formulated and
soundly implemented set of Federal policies and regulations
would permit the orderly development of tertiary oil production.
There is a greater variance in the forecasted proportional
application of each type of recovery technology than in the
total production estimates. Table 3-5 indicates the differ-
ences between the Mathematica and Gulf Cni/ersities Research
Consortium (GURC) forecasts. The forecasts of cumulative
oil production by recovery technique are compared in Table
3-6. An analysis of the Mathematica study reveals the
causes for its pessimistic results.
While the "Big Oil Fields" file is as good a data base
as can be compiled without access to information held by
individual companies, Mathematica1s forecasts-of the potential
of enhanced oil recovery suffer from deficiencies in the
technical understanding of the recovery processes and reser-
voirs and in the use of the data file.
The major shortcoming of the study is its analysis of
micellar-polymer flooding. Its costs are considered to be
high and the potential additional recovery is estimated at
only 250 million to 2.5 billion barrels. These discouraging
conclusions were reached because the study views the tech-
nology statically. That micellar-polymer flooding is
expensive today is indisputable. The process does not
perform well on reservoirs with high permeability sontrast
or where high concentrations of divalent cations such as
calcium, magnesium and barium exist in the rock matrix and
in the connate water. However, if reservoir inhomogeneity
and geochemistry do not pose insurmountable problems, a
decrease in the costs of materials can be expected in the
future through a learning-curve effect and economies of
scale.
A panel of the petroleum industry's experts on enhanced
oil recovery provided the GURC estimate that oil production
by micellar-polymer flooding could reasonably exceed 21
billion barrels. Their estimate seems to take into account
some of the technical advancement which should occur. The
costs of earlier mioellar-polymer flooding projects will be
large, but such high costs are not projectable indefinitely
into the future. These early costs are necessary- in order
66
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TABLE 3-5
TERTIARY OIL RECOVERY
PROPORTIONAL CONTRIBUTIONS OF RECOVERY METHODS
(Percent Total Tertiary Oil Recovery)
FORECAST SOURCE
RECOVERY METHOD
MISCELLAR-POLYMER THERMAL MISCIBLE COj
Mathematicaa
3-16c 61
23-36
GURCb
58 29
13C
aMathematica,
Inc., The Estimated Recovery
Potential
of Conventional Source Domestic Crude Oil# May 1975.
^Gulf Universities Research Consortium, Planning
Criteria Relative to a National RDT&E Program Directed
to the Enhanced Recovery of Crude Oil and Natural Gas,
November 30, 1973.
cIncludes negligible amount by miscible hydrocarbon.
-67
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TABLE 3-6
TERTIAHY OIL KJBC0V5RY
FORECASTS O." TOT.\^ OIL PRODUCTION
BY flKCOVgiUf METHOD

(Billions of
barrels)



MATHEMATICS.

GTOC
RECOVERY METHOD
LOW
HIGH
LOW
HIGH
Micallar-Polymer
0.25®
2.50c
9.2
21.1
Thermal
4.25
9.75
4.6
10.5
Miscible C02
o
in
•
N
3.75
2.0d
4.7*
Total
7.0
16.0
15.8
36.3
*"Assured" - as captioned in report.
b"Seasonable" - as captioned in report,
cIncludes miscible hydrocarbon recovery aethod.
dIncludes aiscible hydrocarbon recovery method.
-68
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to establish the reserves as a recoverable national resource.
Of course, even higher levels of recovery may be achieved
given a suitable economic climate, focused incentives and
developed technology.
Despite its shortcomings, the Mathematica study will be
used as a lower value for tertiary oil production. The GURC
forecast of "reasonable" production will be considered to be
the upper limit for the period through 1985-1990. Thus, the
production of 7 to 36 billion barrels of oil by tertiary
recovery methods can be expected during the transitional
period when the rate of development and growth will be
highest.
3.2.2 Development and Growth
The actual rates of development and growth of tertiary
oil recovery projects will depend upon the interplay of
economic, political and technical factors. Other consid-
erations may create further differences in the development
rates among regions of the country. However, given the
potential oil production as forecasted, the growth of
tertiary recovery in each region can be evaluated by identifying:
(1) the locations of oil fields in each region.in which a
project appears feasible, and ,(2) particular limitations to
growth which predate these advanced recovery methods.
3.2.2.1 Location of Technically Feasible Projects
The locations of the known oil fields in the United
States are shown in Figures 3-4, 3-5, and 3-6. Texas and
Southern-Central California are mapped separately to provide
better definition of detail. Six regions of the country are
identified — Pacific West, Rocky Mountains, South Central,
North Central, Southeastern and Northeastern. These regions
were selected on the basis of the API Reserve Subcommittee
geographic districts with some minor modifications.
The potential sites for tertiary oil recovery projects
were chosen using the methodology described in Appendix B.
For each type of recovery method the project 3ites have been
outlined in Figures 3-7 to 3-15.
Figures 3-7 to 3-9 show that micellar-polymer flooding
projects are most common in Texas. The North Central and
South Central regions also have a significant number of
€9
-------
Figure 3-4. This figure gives the location of oil and gas fields in
Continental United States.
-------
• 'Vfr
f xte t

•% SC C.0TH
' . Sc.* .X V--'<
lAwOfM

Figure 3-5. This figure illustrates the location of oil
fields in Southern California.
-71-
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figure 3-6. This figure illustrates Lhe location of oil.fields
in Texas Railroad Commission Districts.
-------
u»
I
SEE
FIGURE
3-8
SEE FIGURE
3-9
ooo;
• Completed or
Ongoing Chem-
ical Flood
Projects
O Potential
Projects
Figure 3-7. This £igure illustrates the location of technically feasible
raicellar-polymer flooding projects in major oilfields*
-------
Completed or Ongoing
• Chemical Flood Projects
O Potential Projects
Population Areas

Figure 3-3. This figure illustrates the location of
technically feasible niceliar-polymer flooding projects in
major oilfields of Southern California.
-74
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Completed or
•
Ongoing Chemical

Flood Projects
0
Potential

Projects
m
Population

Areas
Figure 3-9. This figure illustrates the location of technically feasible
roicellar-polymer flooding projects in m&jor oilfields of Texas.
-------
Ol
I
Completed
or Ongoing|
Projects
|A Potential
Projects
Figure 3- 10. This figure illustrates the location of technically feasible
thermal tertiary recovery projects in major oilfields.
-------
Completed or
A Ongoii.g Projects
A Potential Projects
fH Population Ar^as
°ts
Figure 3-11. This figure illustrates the location of
technically feasible thermal tertiary recovery projects in
major oilfields of Southern California.
-77
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I
vj
CO
I
Completed
A or Ongoing
Projects
A Potential
Projects
EH Population
Areas

Figure 3-1?. This figure illustrates the location of' technically feasible
thermal tertiary recovery projects in the major oilfields of Texas.
-------
Figure 3-13. This figure illustrates the location Of technically feasible
miscible-C02 injection projects in. major oilfields.
-------



Completed or
B Ongoing Projects
D Potential Projects
0 Population Areas

Figure 3-14. This figure illustrates the locationof
technically feasible miscible-CC>2 injection projects in
major oilfields of Southern Calfornia.
80-
-------
~
o
I
oo
Figure 3-15. This figure illustrates the location of•technically feasible
miscible-C02 injection projects in major oilfields of Texas.
-------
sites where micellar-polymer flooding is technically feasible.
The concentration of potential thermel recovery projects is
greatest in the oil provinces of California in the Pacific
West region as illustrated in Figure 3-10. The location of
other oil fields where thermal methods appear to be techni-
cally feasible is shown in Figures 3-11 and 3-12. The
fields where miscible carbon dioxide or gas recovery is
feasible are identified in Figures 3-13 to 3-15. The South
Central and Southeastera regions contain the largest concen-
tration of potential projects using thi3 technique.
The application of these tertiary recovery methods,
where technically feasible in each region, will result in
the forecasted 7 to 36 billion barrels of oil production.
Regionally, the amount of oil produced by each method is
unique. The estimated production of oil within each region
by each method is presented in Table 3-7. The Pacific West
region will obtain 39 to 96 percent of its tertiary oil
production bj thermal methods. It is estimated that as much
as 4.7 billion barrels of oil will be obtained during the
next 10 to 15 years. This production rate seems unlikely to
be achieved and it appears that these first-order estimates
have overstated the region's oil production during the
period by a factor of four. With the exception of California,
micellar-polymer flooding is likely to play a dominant role
in tertiary oil recovery in each region as shown in Figure
3-16. The proportional production in each region by this
method could exceed recovery by other methods by a factor of
three and one-half to as much as ten times. The Rocky
Mountain region shows a somewhat lower relative potential
for this method because many of the fields included in
analysis produce from reservoirs with low permeability/low
porosity sandstones or carbonates and are highly fractured.
3.2.3 Limitations to Development
Though the potential production by tertiary oil recovery
techniques is large and there are numerous locations where
viable projects could be established, there are a number of
factors limiting the rate of development to less than 36
billion barrels by 1990. During the transitional period,
these limitations may include; transient excess demand for
supplies of high quality water; shortages of chemicals,
particularly surfactants and cosurfactants for micellar-
polymer flooding; and -tate regulatory provisions. In each
case, the extent of the limitation will be assessed and
needs for change cited. The counteracting of surfactant
shortages through on-site sulfonation of lease crude oil is
a possibility which is also examined.
82-
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TABLE 3-7
TERTIARY OIL RECOVERY
ESTIMATED CUMULATIVE PRODUCTION
PROM KNOWN OIL FIELDS IN THE'UNITED STATES
INCLUDING OFF-SHORE AND ALASKA)
(Millions of barrels)

RECOVERY TECHNIQUE USED

REGION
MICELLAR-POLYMER
THF*»MAL
MISCIBLB C02
TOTAL PRODUCTION
Pacific
10-500
1,870-4,700
70-100
1,950-5,300
Rockies
30-2,500
300-700
500-1,000
830-4,200
South Central
(Texas)
80-6,600
500-1,200
800-1,300
1,380-9,300
North Central
toO-5,000
800-2,000
300-500
1,160-7,500
Southeast
60-5,300
760-1,700
800-1,500
1,560-8,500
Northeast
10-1,200
80-200
30-100
120-1,500
TOTAL
250-21,100
4,250-10,50
i 2,500-4,700
7,000-36,300
-------
PERCENT
OIL
PROOUCED 20 -
10 -
TT»«ma1
50
Mfcellar-Polymer
5° -j
40 .
30 -
40
30
PERCENT
OIL
PROOUCED ?0
N+++++++H
-	"+++++++H
~++4'5i+++H
" -++v:+++h
3+++++++H
•+++++++H
-	.+++++++H
j"T r t 5* rrTi
" .+++++++4
-	.+++++++¦(
'++++++-M
- h+++++++4
MUclbla CO?
50 -i
PERCENT
OIL
PROOUCED 20 -
PACIFIC
ROCKIES
SOUTH
CENTRAL
NORTH
CENTRAL
SOUTH
EAST
NORTH
EAST
Figure 3-16. This figure is an illustration of the
relative amount of oil expected to ba produced by tertiary
recovery methods in each region.
-84-
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3.2.3.1 Chemicals
Given the potential oil recovery by tertiary methods of
up to 36 billion barrels, the tertiary oil production rate .
has been estimated at 423 million barrels per year in 1985.
Micellar-polymer flooding techniques can be expected to
contribute 200 to 250 million barrels to the forecasted
total. The chemicals required to support this level of
activity outstrip the current manufacturing capacity for
polymers, surfactants and cosurfact.. -ts.
Table 3-8 shows the chemical availability situation for
each of the materials currently in bulk use for oil recovery.
Potential shortages could exist for each chemical and thereby
limit the start of new recovery projects. Conversely, the
demands will require newly-installed manufacturing capacity
with resultant impacts of the discharges from these processes.
The supply of water-soluble polymers, which are used as
thickening agents in the "mobility buffer" of a micellar-
polymer flood, may fall short of demand by more than 100
million pounds by 1985. However, several factors should
tend to mitigate this shortfall. The demand for polymers is
expected to grow rapidly for other markets besides oil
recovery — most notable is the use of polymers as flocculants
in wastewater treatment systems. Hence, the marketplace
for polymers is broad-based so that manufacturers can build
additional capacity without having to rely on a single type
of customer or application to support the plants. Also,
other potentially less expensive processes for producing
polymers are available. The process of injecting a monomer
into the oil-bearing formation under the proper conditions
of pressure, temperature and catalysis to induce polymeri-
zation could be applied to mobility buffer solutions for
tertiary recovery. Polymers have already been manufactured
in this manner for other oil well treatment applications.
In addition to polyacrylamide, biopolymers such as poly-
saccharide can readily be manufactured from various media.
Gulf Universities Research Consortium, Planning
Criteria Relative to a National RDT&E Program Directed to
the Enhanced Recovery of Crude Oil and Natural Gas, Report
No. 130, November 30, 1973.
2
M.C. McLaughlin, "Method of Placement of Polymer
Solutions in Primary Production and Secondary Recovery Wells,"
U.S. Patent 3,490,533 ;January 1970).
-C5-
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TABLE 3-8
AVAILABILITY OF CHEMICALS FOR TERTIARY OIL RECOVERY
»MI KMCMUS
PROCESS
SBCtxr
PRICE t/lb
CURRENT USAGE KATE
SUPPL* lb/bbl Oil.
10* ih/yr moducw>
ESTIMATED
DSMAHO
(STIMTEO
DSMAHO DBUDD AS FHYSICM.
10< lb/yr i cum, supplh row
COHKOlt.' on
AVJ^LMJl MW










toly+cr'/laai^a
(p^rUdUy hyirclixod)
JicrytmittiU
a so
"a *
Hydration w/kulfurio
neutralization,
loa-axchango.
Itolyxcrizttlon ul
tyilrolytil lp 400
Dry
powder ,
oc
liquid
Kant **par.;.or.» likeiy
to satvd i;liit
X3tir.dE.J («. |.
treJt*tont f :j-.;ulir.t»;
Ikcryanltrili; fct'.U-.oc^
capacity 1.100 f l lli/v?
-cc^ridd
Cluco&a
};ir.ti'cr,.on4«
S«:rib.:SSri5
HicrcMologlcal
action
J. Si/lb
40 «l


SM
powdar
•iti; plant c. jjclty ttJ
coaat.'ucttc:: y cu!^ *.e.J
to livnitij.Ti t-rlo-i
r.-^i: rr 1 r.-.
Suzibcziat*









Itr.car ftlltylb&DZftM
tulfcnatws
KiS&ton^
Eurjli or
circ"
SO}, oltu*
x^ou
teptntion o(
iknithc-cUiii
pjnltiiu, tUyUtlon
•ulfor.dt.ion. ncdtrtl-
lzttion
.10-.JO
lb.
700-110

14?0-U50
1W-410
Vlicoui
lltjuid
rotilblo projection s:
oil rctiner-ia a.-J en-
tice to Hue; n^Js
I:^rcpn(l
itcfi^ry
prop/ten*
«,*>,
Absorption In cane.
¦ j£At hydro lyl la «(
rsiultlaq iiaptopyl
CBljr
• OS/lb.
l.ioo


it-c;
inhydroua
liquid
C.imon alec.iil. ihoit-
ten* sl.c;tjij* fjttiMj.
Leaic
ccsutftcutt

intuit*
Hfdnttot and ydr«-
generatlon
Out) proocc* -
propylene to
a-hutyraldatryi i,
itoUtytldchydi
.lt/ib.
tie


Liquid
(oulbl< uac a»
(ubkcltiiti lutl&j
ifaortiyta
ItwStttAMl
tlop/UM
CO.Hj
Cxo proensa
(as above!
.M/lfe.
no


2S0-1.000
Liquid

4ro» citnt
-------
-The polysaccharide for tertiary oil recovery which is
manufactured by a division of Kelco Chemical Company is
produced by the microbial action of a strain of bacteria on
glucose. The high cost of polysaccharide indicated in Table
3-8 reflects the high prices for sugar and corn during
recent shortages. However, use of process materials other
than glucose is feasible which could reduce the cost of
polysaccharides. Municipal sewage sludge could serve as a
medium for the production of polysaccharides for tertiary
oil recovery applications. Though yields of polymer from
sludge are expected to be low, its low cost and large,
stable supply make sludge an attractive new medium for
producing the needed quantities of polymer.
Surfactants will show a shortfall of 600 to 2,500
million pounds by 1985 based on current capacity. Major
refiners and specialty chemical manufacturers have stated
that they will build the plant capacity needed to serve this
demand as soon as it materializes. Certainly, supply and
demand will come into closer balance in the long term.
However, large shortages may still exist during the transi-
tional period due to the time lags in the construction of
new chemical facilities. For tertiary oil production to
achieve forecasted levels during the 1985-19S0 time frame,
alternative sources of sulfonates will be required. An
important factor for petroleum sulfonates is transportation
cost. Petroleum sulfonates are highly viscous liquids which
must be transported in steam heated tankers to facilitate
loading. This fact discourages long distance multi-mode
movement of large quantities of surfactants. Trucking
charges are estimated at 3 to 4 cents per pound per 100
miles. Therefore imports of sulfonates are likely to be
limited. Yet, the typical micellar-polymer project in a
field with 5 million barrels of oil remaining in place would
require approximately 500 tanker truckloads of surfactants
over a few months of time while the slug was being prepared
and injected.
To fulfill immediate needs, sulfonation units must be
built. The process of sulfonation is basically simple and
straightforward and achieves yields of 10 to 15 percent per
treatment in large scale operations. The simplicity of the
process and the high cost and logistical difficulties of
transporting the end-product give the integrated petroleum
company a number of options for providing its own petroleum
sulfonates. As an operator of micellar-polymer flooding
projects, the company may choose the location for the
sulfonate plant and feedstock inputs. These choices are
illustrated in Table 3-9. The Option I to produce sulfonates
at a refinery will ke chosen by operators whose project oil
fields are nearby their refineries and where the capacity is
-87
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TABLE 3-9
TERTIARY OIL RECOVERY
OPTIONS IN MANUFACTURING SULFONATES
PLANT LOCATION
At Refinery	In the Field

£
II

High transporta-
tion coat
Low to High
transportation
cost
Lubricating
Stocks
High yield
Moderate yield

(Up to 15% per
pass)
(Up to 8% per
pass)
feedstock
III /
IV

High transporta-
tion cost/
Low transporta-
tion cost
Crude Oil
NOT PRACTICAL


^Lovj/^ield
Low yield
(5% per pass)
-88-
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added to serve commercial as well as "captive" demand and
where the unsulfonated crude fraction would be incompatible
with the slug. Figure 3-17 indicates the location of
existing refineries where sulfonation units might be con-
structed. Marathon has chosen this approach in Illinois
where its oil field is adjacent to the refinery. However,
refinery operating plans may not be geared to manage such a
unit or may already use the lubricant 3toc)c in another part ..
of the process. Option II may be chosen to overcome the
possible conflicts between field and refinery operations.
The sulfonation unit would be built on-site at the oil
field and would be sized to local requirements for sulfonates.
If available, lubricating stocks could be transported to
this facility from the refin6ry although savings in trans-
portation costs are sacrificed. The appeal of this option
and option IV is that on-site manufacturing may reduce
transportation costs and provide sulfonates for planned
projects quickly and independently of commercial chemical
markets. Either a lubricating stock refined on-site from
crude oil or the czude oil itself could be used <:s a feedstock.
Not all oils may prove to be suitably reactive for economic
sulfonation, or compatible with the microemulsion slug, but
as indicated on Table 3-10 the costs of sulfonating lease
crude on-sit.e might compete with market prices. Further
study and analysis is required to determine the feasibility
of field sulfonation and its impact on the environment as
micellar-polymer projects are established.
Cosurfactants are not as severe a constraint to the
development of micellar-polymer flooding. Though propanol
is preferred due to its low cost, there are alternative
alcohols available which might serve as substitutes. These
include pentanol, hexanol, butanol, phenol, and cresol.
Since sufficient supplies of a particular cosurfactant are
required to fulfill the entire "recipe" for the mic^llar
slug at a given project, regional variations in the avail-
ability and use of various cosurfactants could develop.
3.2.3.2 Water Supplies
The availability of suitable water for preflushing
preparation of the micellar slug and the mobility buffer and
follow-up injection is important to the success of a tertiary
oil recovery project. Water with low concentrations of
divalent ions and total dissolved solids is required.
Connate water in the reservoirs is rarely suitable for
reinjection without treatment to remove high concentrations
of divalent ions. Concentrations (milligrams per liter) of
-89-
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Figure 3-17. This figure illustrates sites of existing oil refineries
where new sulfonation units could be constructed to serve tertiary oil prolects.
-------
TABLE 3-10
TERTIARY OIL RECOVERY
OILFIELD MANUFACTURE OF SULFONATES
(Cents per pound of Sulfonate)
COMMERCIAL ON-SITE
MARKET PRICE COST
(DOLLARS)	(DOLLARS)
Petroleum Sulfonates
(Mahogany acid)
Raw Materials:
Sulfur Trioxide
Isopropanol
Sodium Alkaline Salts
Utilities
Transportation (250 mi)
Fixed Costs per lb.c
25 MM lb/yr
150 MM lb/yr
Cost per lb.	0.35	0.29 - 0.34
"" a"Opportunity Cost" ~ One pound of oil at $11 per barrel.
^Alcohol is used in this process and is available for
use as a cosurfactant thus cost included.
c
Two-year amortization, includes operating costs.
0.20
0.04
0.01
0.10
0.03 3
0.10
0.04*1
0.05
0.02
0.03
0.05
0.02
-91-
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calcium and magnesium, respectively, in connate waters
average 2,530 and S30 in tertiary,formations, 25,300 and
2,500 in Pennsylvania formations. These concentrations are
5 to 50 times the acceptable levels for successful micellar
flooding.
Supplies of suitable water for a large-scale micellar-
polymer flood may not be available. At present, soae strains
on water resources have occurred with pilot scale projects.
The Cities Service/Energy Research and Development Administra-
tion project near El Dorado, Kansas, has built a five-
mile long water pipeline six inches in diameter from the
town's lake (raw water supply) to the oil field. The design
water flow rate for the pilot-scale project is 6,300 barrels
per day (264,600 gallons per day). This represents ap-
proximately 20 percent of the estimated daily water consumption
by El Dorado's 13,000 residents. Since there are more than
6,200 acres of Admire sand in the El Dorado field while the
tests cover only 51.2 acres, there is a potential demand at
the field for as much as 800,000 to 1,500,000 gallons per
day of high quality water from the town's supply, assuming a
development rate of 300 to 600 acres per year and.a well
density one-half as great as the pilot test area.
Surface waters such as rivers may be unacceptably high
in- TDS and divalent ions as are shallow unconsolidated
aquifers which are subject to evaporative concentration of
salts. The difficulty of further defining the effect of
water supply availability is the need for detailed data on
local consumption trends, availability of undeveloped,
uncommitted water resources and the scale and timing of the
development of micellar-polymer oil recovery projects. These
local shortages of suitable water might lead to on-site
water treatment and recycling as part of the project plan, a
factor which would tend to reduce the amount of oil economi-
cally recoverable by micellar-polymer flooding if not making
the project economically unattractive.
*A.G. Collins, "Chemical Applications in Oil and Gas
Well Drilling and Completion Operations." (unpublished)
^Cities Service Oil Company, El Dorado Mlcellar-
Polymer Demonstration, BERC/TPR-75/1, October 1975.
If the field were controlled by a number of operators
who undertook simultaneous fieldwide development projects,
water usage would be 20 to 25 million gallons per day.
-92-
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3.2.3.3 Current Regulations
The amount of oil recovered through tertiary operations
depends upon technology and prices. Theso factors, however,
do not operate freely; governmental regulation of petroleum
production is far-reaching, indeed. Every major oil producing
state controls to some extent the operations of the petroleum
industry within its borders. Although the various state
codes are not uniform, most do have certain features in
common, in particular, they are characterized by rules
governing fluid injection, well spacing, allowables, uniti-
zation and plugging. A brief analysis of this partial list
will indicate the possible impacts on tertiary recovery
projects of current industry regulations.-
Fluid injection rules perhaps most clearly affect
tertiary recovery. Their impact, however, does not appear
to be great. Designed primarily to protect subterranean
freshwater supplies and oil reservoirs beneath adjacent land
tracts, these regulations generally require administrative
approval of all injection operations. Unless objections are
raised, however, permission is usually granted. The Illinois
rule is typical. Basically, it demands notice to all adjacent
well owners within a half mile radius, specifies a 10-day
objection period, and requires a hearing if complaints are
lodged.
Traditional well spacing requirements are less neutral.
Designed to prevent excessively rapid depletion of all
reservoirs during primary recovery, they may prove too
strict for tertiary operations. Not only do tertiary pro-
jests need nearby injection wells, but they sometimes also
require the clustering of production wells for maximum
coverage and efficiency. North Dakota's code — specifying
that wells in the same pool be located at least 1,000 feet
from each other and 500 feet from the nearest property
line — is not entirely atypical. Certainly, it does not
appear tailored for tertiary recovery projects. With this
spacing, a typical micellar-polymer flood could require
more than eight years to complete — a time frame which
adversely affects the economics of the project.
Although spacing requirements frequently may be waived
on a case-by-case basis after conu. ission hearings, a more
reasonable approach may be to establish separate guidelines
for tertiary projects. Illinois even goes to the length
of exempting fluid injection programs from spacing require-
ments altogether.
-93-
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Unlike spacing rules* allowables do not directly
prevent the drilling of new '*lls; however, indirectly
they may inhibit the drilling operations required for
successful tertiary recovery. Essentially, an allowable
is the production limit — set by the regulatory agency —
of a particular well in a particular field. If the establish-
ment of an allowable for a new tertiary production well
means that allowables for old wells in the field must
drop — to maintain the same total field allowable —
then there i3 little incentive for an overall field owner
to undertake tertiary recovery. Yet, simply eliminating
total field allowables is not necessarily the answer.
However, a sound overall conservation policy which takes
into account conventional as well as tertiary recovery
operations may demand it. More than this, an operator
is not induced to change a marginal producing well to an
injection well if he will lose the allowable of the converted
well without gaining on other wells» Texas does provide
for allowable transfers; this practice should be corsidered
elsewhere. Maximum Efficient Recovery (MER) rates £.re the
basis for these regulations, but a great deal of additional
research is needed to redefine MERs in view of the latest
technologies.
Allowables may be a problem for tertiary operations
even if their impact on the overall field is ignored. At
this early stage of development, tertiary recovery is a
risky venture. The return associated with that risk can be
increased by raising or eliminating allowables on wells in
a tertiary recovery project. Interest rates make a dollar
today worth more than a dollar a year from now. Since oil
is money, the companies that produce it want to finish their
operations as quickly and efficiently as possible. Insofar
as allowables restrict production, they defer the payoff and
hence inhibit tertiary recovery. Some states' allowables on
tertiary projects are higher than their allowables on primary
wells of the same depth, but the bonus may be insufficient
in light of the risks associated with tertiary projects.
Not only do allowables restrict the rate of cash flew
from tertiary operations; they may also restrict the ultimate
amount of cash flow. The recovery processes employed are
most effective during relatively short peak times. This
implies a corresponding high level of recovery. Restriction
placed on production by allowables will in these cases
unreasonably extend the recovery period, thus reducing the
efficiency of recovery and perhaps reducing the total
amount of recovery as well. A regulation established
presumably to conserve oil during primary stages may waste
-94-
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it during tertiary stages if a so-called tertiary recovery
method is deferred past the time of its most profitable
application.
Oil conservation perhaps most clearly emerges in the
issue of unitization. Field unitization means cooperative
development by all producers to maximize recovery. Since
fluids injected into one area of a field may migrate un-
predictably through strata to affect production in an area
controlled by other interests, the need for common develop-
ment is of particular importance. Most states require full
unitization if two-thirds to three-quarters of the royalty
owners and operators agree. However, few if any place oil
conservation on a higher plane than property rights and
demand commonality with less than substantial majority
consent. Texas has no involuntary unitization law at all.
Lack of unitization may also eliminate many smaller fields
from every undergoing tertiary recovery. This problem could
limit advanced recovery in areas such as the Denver-Julesberg
Basin with many scattered small pools, and in states such as
Illinois where oil production properties have passed through
several generations of ownership.
Concern for water conservation has led to the almost
universal adoption of plugging regulations by the states.
Though perhaps effective for this purpose, these provisions
reduce the profitability of tertiary recovery by raising the
costs of reentering old wells. For most areas those costs
are prohibitive. Plugging regulations generally leave the
design in the hands of the operator with approval by commission
inspectors.
The current regulatory framework surrounding the petro-
leum production industry appears designed largely for
problems associated with primary and secondary operations.
The emergence of a new recovery technology has created a new
set of problems, which in turn may require new regulations.
At the very least, the present codes need to be reconsidered;
very likely, they will require revision, as well.
-95
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CHAPTER FOUR
HAZARDS OF TERTIARY OIL RECOVERY
4.0 Introduction
There are several possible sources of environmental .
hazards stemmin** from tertiary oil recovery. Chemicals used
in micellar-poiymer floods represent the most clearly
identifiable group of potential hazards. These are of
special concern because many will be left behind in the
reservoirs after the recovery project is completed. The
primary reservoir remnants of carbon dioxide and thermal
methods are low pH brines. The composition of produced
gases from firefloading and steam injection is not well-
understood/ but some initial estimates of the movement of
sulfur dioxide and oxides of nitrogen have been made.
Fugitive emissions of hydrocarbon vapors from these sources
needs further study. Gaseous streams from production wells
in thermal recovery projects and emissions from steam crener-
ator stacks are two sources of potential airborne hazards
introduced by tertiary oil recovery. The sources of these
potential hazards from each recovery method are analyzed and
the toxicity and/or carcinogenicity of the materials are
presented.
4.1 Chemical Hazards
Tertiary oil recovery processes employ a variety of
chemicals. In micellar-polymer flooding, chemicals such as
surfactants, polymers and cosurfactants are used. Tables
4-1 through 4-6 list some of the compounds in each class
which are in use or have been proposed for use in U.S.
patents and the literature. Tables 4-7a and 4-7b list
chemicals used on infrequent occasions in connection with
thermal recovery processes. The choice of chemicals depends
upon: (1) availability of the chemicals, (2) costs of the
chemicals, (2) chemical compatibility with the specific
reservoir characteristics encountered, and (4) the required
concentrations of the chosen chemicals in the reservoir to
achieve additional oil recovery.
If in the recovery process chemicals escape to the
environment in sufficient quantities, their presence can
degrade water supply quality and destroy biota. The release
of chemicals may occur at the manufacturing plant, on the
-96-
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TABLE 4-1
TERTIARY OIL RECOVERY
CHEMICALS PROPOSED FOR USE AS SURFACTANTS
Ditetradecyl dimethyl aimonium chloride
Dodecyl trimethyl ammonium chloride
Hexadecyl trimethyl ammonium chloride
Alkyl phenoxypolyethoxy ethanol
p-Chloroaniline sulfate laurate^-
p-Toluidene sulfate laurate
Polyglycerol monolaurate
Glycerol disulfoacetate monomyristate
n-Methyltaurine oleamide
Monobutylphenyl phenol sodium sulfate
Polyoxyethelene alkyl phenol
Morpholine stearate
Pentaerythritol monostearate
Dihexyl sodium succinate
Diethyleneglycol sulfate
Sodium sulfate oleylethvdanilide
Alfa olefin sulfonate
Alkyl aryl sulfonate
Alkyl aryl napthenic sulfonate with monovalent cation
Hexadecylnapthalene sulfonate
Sodium lauryl sulfonate
Triethanolamine laurate
Triethanolamine myristate
Triethanolamine oleate
n-Dodecyl-diethleneglycol sulfate
Sodium glyceryl monolaurate sulfate
Halogenated compounds, though proposed in the literature*
are unlikely to be used in field operations because their
possible presence in produced oil streams would poison the
catalysts at the refinery.
97-
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TABLE 4-2
TERTIARY OIL RECOVERY
MATERIALS PROPOSED FOR USE
AS MOBILITY BUFFERS
Aldoses
B series
L series
Amines
Carboxymethylcellulose
Carboxyvinyl polymer
Dextrans
Desoxyribonucleic acid
Glycerin
Ketoses
B series
L series
Polyacrylamide*
Polyethylene oxide*
Polyisobutylene in benzene
Rubber in benzene
Saccharides
Conjugated saccharides
Disaccharides
Monosaccharides
Polysaccharides*
Tetrasaccharides
*Most commonly used
-90-
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TABLE 4-3
TERTIARY OIL RECOVERY
HYDROCARBONS PSED AS FRACTION OF MICELLAR SLUG
(Or in Miscible Displacement Processes)
Alkylated aryl compounds
Anthenic compounds
Aryl compounds with mono cyclic compounds
Alkyl phenols
Benzene
Toluene
Aryl compounds with polycyclic compounds
Crude oil*
Partially refined fractions of crude oil
Overheads from crude columns
Side cuts from crude columns
Gas oils
Straight run gasoline
Kerosene
Liquified petroleum gas
Napthas
Heavy napthas
Refined fraction of crude oil
Paraffinic compounds
Decane
Dodecane
Heptane
Octane
Pentane
Propane
Cycloparrafinic compounds
Cyclohexane
Napthenic"compounds
•Most commonly used
-99-
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TABLE 4-4
TERTIARY OIL RECOVERY
CHEMICALS PROPOSED FOR PSE AS ELECTROLYTES
Acids
Hydrochloric acid
Inorganic acids
Organic acids
Sulfuric acid
Bases
Inorganic bases
Organic bases
Sodium hydroxide
Salts
Inorganic salts
Organic slats
Sodium hydroxide
Sodium nitrate
Sodium sulfate
100-
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TABLE 4-5
TERTIARY OIL RECOVERY
CHEMICALS PROPOSED FOR USE TO BLOCK
EXCHANGE SITES IN THE FORMATION
(Preflushing)
Quarteraary ammonium salts
Fluoride solutions
Potassium permanganate
Sodium hydroxide
-101
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TABLE 4-6
TERTIARY OIL RECOVERY
CHEMICALS PROPOSED FOR USE AS COSURFACTANTS
Alcoholic liquors
Fusel oil
Alcohols
Alkaryl alcohols
Phenol
p-Nonyl phenol
Amyl alcohols
Isopentanol*
2-pentanol*
Cresol
Decyl alcohols
Ethanol
Isobutanol
n-Butanol
Cyclohexanol
1-Hexanol*
2-Hexanol*
1-Octanol
2-Octanol
Isopropanol*
Aldehydes
Formaldehyde
Gluteraldehyde
Paraformaldehyde
Amides
Amino compounds
Esters
Sorbitan fatty ester
JKe tones
*Most commonly used
-102-
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TABLE 4-7a
TERTIARY OIL RECOVERY
CHEMICALS PROPOSED FOR USE TO INITIATE
IGNITION OF IN—SITU COMBUSTION
Hydrazine
Hydrogen peroxide
TABLE 4-7b
TERTIARY OIL RECOVERY
CHEMICALS PROPOSED FOR USE TO INCREASE
EFFICIENCY OF THERMAL METHODS
Quinoline
Sodium hydroxide
Toluene
-103-
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transportation route, at the oilfield site during preparation
of the chemical for use, from the reservoir (during the
actual tertiary recovery process), and from the reservoir
(after completion of the tertiary recovery process). Many
of these activities are within the scope of existing EPA
regulations. The potential environmental hazards associated
with the handling of these chemicals on the surface are
clearly identifiable. However, the presence of coucentra-
tions of chemicals in the oil-bearing formations represents
a long-term source of pollutants that may be released under-
ground into nearby aquifers at some unknown time in the
future. Therefore, an understanding of the potential
hazards of chemicals at reservoir conditions is important.
Chemicals which reach the environment may affect it in
a number of ways. Living organisms exercise natural quality
controls, both on freshwater and seawater. Some chemicals
or their degradation products may eliminate those beneficial
organisms in certain areas, or they may deci.oate only certain
species or certain developmental stages. For example, the
adult organism may migrate into an area where reproduction
is inhibited. The food sources for these organisms may be
more sensitive to certain toxic materials than the organisms
themselves are; and the beneficial organism populations may
become reduced because of a lack of food, rather than by a
direct toxic effect upon the organisms.
All of the general types of toxic effects mentioned
above and the specific effects to be mentioned later are
concentration dependent. Chemicals which may be released
from an oil reservoir decrease in concentration because of
dilution, filtration, adsorption on both soil and clay
particles, precipitation, chemical decomposition or polymer-
ization, and biodegradation with time and distance travelled
through an aquifer. The effects of a chemical used in
tertiary oil recovery may well be negligible at the levels
actually encountered in the vicinity of the recovery site.
Furthermore, there is only a possibility that it will ever
reach a water body as discussed in Chapter Five, neverthe-
less, most of the chemicals used in tertiary oil recovery
have definite and well-documented effects on water quality,
and many others have documented toxic or carcinogenic effects
on animals. It is recognized that the synergistic effects
of certain combinations of pollutants portend greater or
lesser risks than the simple additive combination of the
effects of ¦each pollutant. However, synergistic toxicity
studies of chemicals used in micellar-polymer flooding are
not available in most instances and such work is not within
the scope of this investigation.
104—
-------
Another important aspect of toxicity is the composition
c£ the ecosystems which are contacted by the pollutants.
Definition of these ecosystems and analysis of chemical
toxicity data for each ecosystem including questions of
biodegradation and bioconcentration are also of concern/ but
have not been undertaken in this study.
The surfactants listed on Table 4-1 have been considered
for use in micellar slugs. The ones most commonly used are
Ion?-chain, linear alkyl sulfonates such as lauryl sulfonate
and duodecyl sulfonate, and alkyl aryl sulfonates. These
substances are also used as foaming agents and detergents,
and their most noticeable water quality effect, at least in
high concentrations, is tu produce rather ugly foams, both
in water bodies and at the tap (if sulronate-containing
water is used a3 a source of a public water supply). The
linear cJk\l sulfonates are biodegradable at fairly rapid
rates.. Surfactants, or surface-active agents, also may
impart tastes or odors to water as indicated in Table 4-3.
Toxic effects to aquatic life have been reported for
alkyl sulfonates at concentrations which are exceeded in
reservoir fluid3 during micellar-polymer flooding. Reservoir
concentrations may be 37S to 1,900 milligrams per litre
{mg/1}. Acute Lethal concentrations vary from 0.2 to 10.0
mg/1; chronic levels below about 0.63 mg/1 produce no
appreciable effects on minnow or bluegill populations.1
The 1973 Water Quality Criteria suggest a maximum limit for
linear alkyl sulfonates equal to 0.05 times the 96 hour
Lethal Concentration (T,C) 50 in the receiving water; such a
level would correspond to about 0.2 mg/1. Practically all
of the sulfonates {alkyl, alkyl phenyl, and naphthenic) are
included as toxic substances on the national Institute for
Occupational Safety and Health/Health, Education, and
Welfare (NIOSH/HEW) list.2 The toxicities see*n to be rather
low, however, as a high concentration is required before
effects are noted.
Another effect results from the synergistic interaction
of sulfonate surfactants with a number of known compounds
comprising crude oil, facilitating the solubilization of
^"U.S. Environmental Protection Agency, Proposed Criteria
for Water Quality, Vol. I, 1973, pp. 115-116.
National Institute for Occupational Safety and Health/
Health, Education, and Welfare, "Toxic Substances List," 1974.
-115-
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TABLE 4-8
TERTIARY OIL RECOVERY
MINIMUM CONCENTRATION OF SURFACTANT
REQUIRED TO PRODUCE A PERCEPTIBLE TASTE AND ODOR
SURFACE ACTIVE AGENT
TYPE OF
TASTE OR ODOR
Alkyl aryl sulfonates	0.6
Alkyl aryl sulfonate	0.4
Alkyl sulfate	3.0
Alkyl sulfonate	1.4
Sulfonated amide	2.5
0.7 Limey, chemical
0.3	Soapy
0.2	Solvent
0.3 Bitter, soapy,
kerosene
2.0 Chemical, soapy
Source: McKee and Wolf, Water Quality criteria,
for the California State Water Quality Control Board,
1963, p. 397.
-106-
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toxic fractions of the crude oil. Presumably, this affects
the solubilization of organic toxicants by the sulfonates,
with the result that penetration thrcugh epithelial barriers
(e.g., the intestine) is facilitated.2 Synergistic inter-
actions have been reported with the carcinogen 3, 4 benzo-
pyrene.3 Though surfactants based on alkyl banzene sulfonates
are not in common use today for tertiary recovery, it should
be noted that these compounds are of concern because they do
not break down biologically in sewage treatment plants, and
can travel long distances in streaias and through ground
water without losing their identity. The more commonly used
linear alkyl sulfonates are biodegradable; however, they are
also two to four times more toxic.4
The compounds used in mobility control solutions such
as polysaccharides, and most of the others listed on Table
4-2 are nontoxic. If discharged in excessive quantities,
they contribute to the degradation of water quality mainly
by increasing the biochemical oxygen demand (BOD) and to
oxygen depletion in a receiving water body, and by serving
as the basis of a rich nutrient medium which will encourage
the growth of bacterial species. In typical micellar-
polymer floods, very little of the materials will be returned
to the surface. However, concentrations of 100 to more than
1,000 mg/1 do occur in the produced water from Simpler
techniques of mobility control flooding * th polymers alone.
Chemical hazards resulting from the use of hydrocarbon
fractions other than crude oil in the micellar slug (Table
4-3) may be in the form of emulsified oils, or solutions of
the water-soluble fractions of these oils. Due to cost
considerations, crude oil has been the most common hydro-
carbon constituent since it can easily be recovered from the
produced fluids and requires little treatment prior to use.
In special cases, other hydrocarbon fractions will be used.
These fractions and the water soluble fractions of crude are
of concern here. The aromatic hydrocarbons are the major
group of acutely toxic compounds in oil residues. These
also cause problems of fishtainting, and the production of
^"McKee and Wolf, Water Quality Criteria, 1963, p. 397.
-
National Academy of Sciences, Committee on Water
Quality Criteria, Water Quality Criteria 1972, pp. 261-262.
^National Academy of Sciences, Water Qualitv Criteria 1972,
p. 262.
^McKee and Wolf, Water Quality Criteria, 1963, p. 397.
-107-
-------
unpleasant tastes and odors. In addition, there is a
potential carcinogenic problem associated with the intro-
duction of ill-defined petroleum fractions into water
supplies. The hydrocarbon compounds listed in Table 4-3 can
cause tainting of the fish flesh and other aquatic organisms,
and may be used in micellar-polymer flooding, thermal methods
(Table 4-7b), and other tertiary recovery processes such as
miscible hydrocarbon methods. In general, the hydrocarbons
which may have some environmental impact are already utilized
as biocides, lubricants, and corrosion inhibitors during
primary and secondary oil recovery. Tertiary recovery would
be expanding the amount, not changing the kind of chemical
used.
Some of the electrolytes (Table 4-4) and compounds used
in preflushing (Table 4-5) are potentially harmful, but the
concentrations in micellar projects average less than 10.0
mg/1. Such a concentration is within the criteria for
drinking water supplies.2 Sodium nitrate and the inorganic
phosphates are nutrients. If introduced in sufficient
quantities, they can encourage the growth of undesirable
algal slimes, and can accelerate the eutrophication of
surface water bodies. Water turbidity can be increased,
odors can be created, hydrogen sulfide gases can be produced
by bacteria attacking abundant decaying natter, and a swampy
taste can be imparted to the water. If introduced into
groundwaters or surface waters which are used as the source
of a drinking water supply, sodium nitrate can create
further problems, since nitrates in drinking water have been
linked rather convincingly to a high incidence of methemo-
globenemia among the users (especially infants under three
months of age) of the water supply.3 The magnitude of this
effect is, of course, extremely dependent upon the quantities
of nitrates actually used. Therefore, the size of the
project as well as the concentrations of electrolyte is
important. Sodium sulfate is listed as a toxic substance,
but only at extremely high concentrations which far exceed
predicted levels in tertiary oil recovery processes.
Subtoxic effects have been noted for sulfates, including
imparting a "funny" taste and a slight laxative effect; but
these, too, seem to be improbable at sulfate concentrations
expected as a result of micellar-polymer flood.
^EPA, Criteria for Water Quality, pp. 216-217
2EPA, Criteria for Water Quality, pp. 207-212.
^EPA, Criteria for Water Quality, pp. 208-209.
-108-
-------
The cosurfactants used in micellar slugs are listed on
Table 4-6. Isopropanol, isobutanol and amyl alcohol, are
all toxic in high enough concentrations. But at the levels
which may result from their escape from an oil reservoir,
they should be degradable without too much difficulty by
healthy ecosystems. In the normal course of things, they
would travel along the usual catabolic pathways, being
degraded by bacteria and contributing primarily to bio-
chemical oxygen demand (BOO).
Two compounds mentioned as possible cosurfactants,
phenol and cresol, would create significant water quality
problems if introduced into ground or surface waters. Since
these alcohols are much more dangerous in the environment,
more expensive, and just as effective as the other alcohols,
such compounds would appear to be the cosurfactants of last
resort in tertiary oil recovery. However, shortages of the
other alcohols may induce some substitution of phenol and
cresol for micellar-polymer flood projects. The ortho-,
meta- and para- forms of cresol, as well as phenol itself,
are all listed as toxic substances on the NIOSH/HEW list.1
The data on that list is limited, for the most part, to
toxic effects on mammals (excluding man), so its usefulness
to aquatic and human consumption problems might be questioned.
Of somewhat more relevance is EPA's aquatic life toxicity
data, which includes documented toxic effects on a number of
first order organisms. Concentrations of 6.5 mg/1 have been
reported to cause extensive damage to trout reproductive
systems, and concentrations of 1.0 mg/1 are reported to have
no toxic effects on trout.2
Death to humans exposed to acute phenol poisoning has
occurred in periods as short as 30 minutes. Phenol can be
absorbed through the intact skin. If death is not forthcoming,
damage to the kidneys, liver, pancreas, spleen, and lungs
may result. Skin absorption may eventually cause gangrene
in the afflicted area. Chronic phenol poisoning is character-
ized by vomiting, difficulty in swallowing, excessive
salivation, diarrhea, loss of appetite, nervous disorders
and skin eruption.3
^"NIOSH/HEW, "Toxic Substances List," 1974.
2EPA, Criteria for Water Quality, p. 122.
^N. lrving_Sax, Dangerous Properties of Industrial
Chemicals (Van Nostrand Reinhold Co., 1968) , p. 1007.
-109-
-------
Phenol is reported to be a carcinogen, but it is
difficult to extrapolate the mouse and guinea pig data used
to support that conclusion to probable effects on human or
aquatic life. Qualitatively, it is reasonable to expect
some statistical carcinogenic effect in human populations
exposed to phenol in their water supply.1
Effects other than direct toxic cnes have been noted
for those cosurfactants of last resort. Phenols impart
unpleasant tastes and odors to water (with threshold odors
being reported at 0.055 mg/1 for para-cresol, 0.25 mg/1 for
meta-cresol/ 0.26 mg/1 for cresol, and 4.2 mg/1 for phenol),
and furthermore, they are not removed effectively by most
conventional water treatment processes.2 They can react
with chlorine at public water supply disinfection plants to
produce chlorophenolics, whose toxic effects, as well as
effects on taste and odor, are much greater than those of
phenols and cresols themselves (they are also more environ-
mentally persistent than their parent phenolics). Phenol
and cresol are biodegradable, thouch the rate of degradation
is slow. Biochemical oxygen demand studies have shown that
less them one-fifth of the phenols introduced into a seeded
water sample are consumed within five days. Furthermore,
phenol is a "tainting substance"? that is, it causes distinct
unpleasant tastes in fish which have swum in waters containing
them. Phenolic compounds, including cresol, have been
reported to affect fish taste at the 0.001 mg/1 levels.3
McKee and Wolf concluded, in 1963, that phenols in a
concentration of 0.0001 mg/1 would not interfere with
domestic water supplies; in a concentration of 0.2 mg/1,
they would not interfere with fish and aquatic life; at 50.0
mg/1, they would not interfere with irrigation; and at l,Of.O
mg/1, they would not interfere with livestock watering.4
For most waters, the maximum recommended phenol concentra-
tion is 1.0 mg/1.
Most of the bacteriocides and biocides used in tertiary
oil recovery listed on Table 4-9 are nonspecific, and display
*See Section 4.2 for a discussion of carcinogenicity.
^EPA, Criteria for Water Quality, p. 223.
3EPA, Criteria for Water Quality, p. 143.
4McKee and Wol*, Water Quality Criteria. 1963, p. 240.
-110-
-------
TABLE 4-9
TERTIARY OIL RECOVERY
CHEMICALS USED AS BACTERICIDES AND BIOCIDES1
Aldehydes
Formaldehyde
Gluteraldehyde
Paraformaldehyde
Alkyl phosphates
Acetate salts of coco amines
Alkyl amines
Quaternary amines
Alkyl dimethyl ammonium chloride
Coco dimethyl benzyl ammonium chloride
Diamine salts
Acetate salts of coco diamines
Acetate salts of tallow diamines
Calcium sulfate
Sodium hydroxide
Heavy metal salts
Chlorinated phenols
Alkyl dichlorophenol
Pentachlorophenol
Sodium salts of phenols
Substituted phenols
T.J. Robichaux, "Bactercides Used in Drilling
and Completion Operations," U.S. EPA Symposium on
Environmental Aspects of Chemical Use in Well Drilling
Operations, Houston, Texas, May 1965, p. 4.
-Ill-
-------
significant toxicities to organisms other than the target
bacteria. Although in many cases chlorination and adjust-
ment in salinity and pH is often sufficient, these compounds
may be more widely used to control bacteria which may
attack surfactants and polymers used in a micellar-polymer
flood. Toxic effects of most of them on aquatic life are
well documented.1 Aldehides have been reported to have TL
50 for fish of 50 to 400 mg/1.2 Chlorinated phenols have a
TL 50 for fish of 0.2 to 1.0 mg/1.3 Quaternary amines have
TL 50 for fish of 0.2 to 5.0 mg/1 and other amines have a TL
50 for fish of 0.4 to 4.0 mg/1.4 All of these compounds can
be expected to be toxic to humans. Chlorinated hydrocarbons
are stable in the environment, toxic to some wildlife and
other non-target organisms, and have adverse physiological
effects on man. They are stored in fatty tissues rather
than being rapidly metabolized. Mild cases of poisoning
cause headaches, dizziness, gastrointestinal disturbances,
numbness, and weakness of the extremities, apprehension, and
hyper-irritability. In severe cases, there are muscular
fasciculations spreading from the head to the extremities,
followed eventually by muscle spasms, leading in some cases
to convulsions and death.5 Chlorinated hydrocarbons are not
completely removed by sewage treatment, nor by water purifi-
cation plants.
Table 4-10 compares water quality criter' for various
uses wich the maximum concentrations of the cnemicals which
might be present in the oil reservoir. Two general conclu-
sions may be drawn from these data. First, criteria are
needed for many of the chemicals which may be used in
tertiary oil recovery so that potential problems may be
identified. Second, although the pathways from the oil
reservoir to the water user involve low probabilities and
large amounts of dilution and a number of coincidental
chemical and physical occurences, the presence of some of
EPA, Criteria for Water Quality, pp. 241-304.
2
McKee and tfolf, Water Quality Criteria, 1963,
pp. 124, 191.
3Robichaux, "Bactericides Used in Drilling," p. 6.
4
Robichaux, "Bactericides Used in Drilling," p. 6.
5
National Academy of Sciences, Water Quality Criteria
1972, p. 76.	~
-112-
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TABLE 4-10
TERTIARY OIL RECOVERY
COMPARISON OP CHEMICALS WHICH MAY BE PRESENT
IN PROCESSES WITH WATER QUALITY CRITERIA
KATERIAL
HJLTER
AI
QUALITY
kL
CRITERIA
1W
a
KS
KAXIKUM
RESERVOIR WATER
AFTER TERTIARY
F.LCOVERVb
(mi Hi grama/1 iter)
PKCCESS
CODE®
Cictr iocyl dia^thyl aisnoniiin chloride
-
-
0.2
¦S/l
o.s
rI « agricultural (irrigation}: AL - Agricultural (liveitock)i FW - fresh watert HS » v;cor supply.
WjIjIco 2-C rhrou-jh 2-9.
cs * r.^rtc • cofurfaecar.t; P - mobility control] B - bactericide) £ - electrolyte) H - hydrocarbon In sluj;
T " tl.era;.!	N " naturally occuring in oil; C " gas Injection.
-------
TABLE 4-10 (CONT.)
IC.TIRIU
HATE*
M
QUALITY
U.
CRITERIA
fW HS
MAX. KtDEKVOIR
VMER AFT-11
*ERTI.*SY XECOVEKY
PROCESS
coot
Alky! *iyl sulConbta <2etergant
-
-
0.2 *g/l
0.5 ng/1
375 - 1»00
s
Alkyl *ryl tiajithcnic mlfar^ta
_
_
0.3 *g/l
O.S »j/l
175 - 1900
s
liexjdtssyl.iapthalen* vulfonate
-
-
0.2 ag/1
O.S tKf/l-
375 - 1900
s
Saiitji laJiyl aulionjto
-
-
0.3
0.5 tg/1
37S • 1900
s
Ti-i«t!i«r.olur.ina laur«to
-
-
0.2 M9/I
O.S ng/1
375 - 1900
s
Triuthar.oliiiir.c myii-iUt-i
-
-
0.2 Cg/1
C.S ugA
175 - 1900
s
Triethaaol±aine elo&te
-
-
0.2 ttg/1
O.S ma/1
375 - 1900
s
Fusdl oil
-
-
-
-
200 - 4010
c
Phenol
-
-
<1 B9/1*
1 Mg/l
200 - (000
c
p-Kiayl f.t.er.ol
-
-
-
I v%/\
200 - 4000
c
Isocoatiaol
-
-
-
-
200 - 4000
c
;-f jr.ti-ol
-
• -
-
-
200 - 4000
c
Criiiol
-
-
<0.07 ag/l*
1 M9/1
200 - 4C&4
c
Dj^-yl alcohol*
-
-
-
-
200 - 40OO
e
Etiunol
-
-
-
-
200 - 4000
c
Iocbuttncl
-
-
-
-
203 - 4000
c
n-BatJrol
-
-
-
-
200 - 4000
c
Cycloi.ux JTiOl
-
-
-
-
200 - 4000
c
1-Uexjnol
-
-
-
-
230 - 4000
c
2-t!cxunol
-
-
-
-
200 - 4000
c
1-OctjrdI
-
-
-
-
200 - 4000
c
2-Ovt.ir.ol
-
-
-
-
200 - 4000
c
4T-»ir\tlrv9 tubst&tic*
-------
TABLE 4-10 (CONT.)
MATERIAL
WATER
AX
QUALITY
AL
CRITERIA
ru ws
MAX. RESERVOIR
HATER AFTER
TCRTAIRY RECOVERY
(*g/l»
PROCESS
CODE
lioptopanol
-
-
-
-
200
-
4 GOO
C
FornulJjhyde
-
-
-
-
200
-
4000
D/C
CluVrf.-aldohyd#
-
-
-
-
200
-
4000
B/C
pjraf&rnnldehydo
-
-
-
-
200
-
4000
B/C
Acides
-
-
-
-
200
-
4000
C
Aaino compounds
-
-
-
-
200
-
4000
c
Sorbitjit fatty ester
-
-
-
-
200
-
4000
c
KdCOIIC*
-
-
-
-
200
-
4000
c
Alkylated «.ryl coopc>und*

•
(no odor
or visible
fila)
(no odor
or visible
film)
950
"
112S0
H
Anthenic compounds


(no odor
or visible
film)
(no odor
or visible
fila)
950

11250
H
Alkyl phenols

*
<1 tuj/l
(no odor
or visible
film)
950
"
11250
H
Bo.ixcnu


(no odor
or vislblo
flic)
(no odor
or visible
fils.)
9S0

11250
H
Toluene
*
•
<0.2$ B9/1*
(no odor
or visible
film)
950

11250
:i/r
Crude oil (sojr)
*

(no odor
or visible
film)
(no odor
or visible
t ilio)
950
'
11250
H
Crode oil (sweet)


(no odor
or visible
film)
(no odor
or visible
f iln)
950

11250
H
aVaintir.g subjtancor
-------
TABLE 4-10 (CONT.)
MATERIAL
KATES
AX
C 0 A L I T *
AL
CRITERIA
FM MS
KAX. RESERVOIR
WATER AFTER
tertiary fxcovery
(rag/1)
PROCESS
CODE
Overheads froa cruda coluama
-
-
(no odor
or vliiblt
£ i liu)
(no odor
or visibls
filnl
950 - 11250
H
Side cuts froa crude coitions


(no odor
or visible
tila)
(no odor
or visibls
filn)
950 " 11250
H
Cu oils

•
(no r'.at
or v 'ibis
fllnl
(no odor
or visibls
filnl
950 - 11250
H
Straight run gasoline
•

(no odor
or visit 1*
flit.)
(no odor
or visibls
filnl
950 - 11250
H
Kiroaena
•

<0.1 ng/1*
(no odor
or visibls
fila)
»S0 - H250
U
Liquified petrolcua gas

"
(no odor
or visibls
film)
(no odor
or visible
film)
9S0 - 11250
H
itapthas


(no odor
or visible
film)
(no odor
or visibls
fila)
950 - 11250
U
Heavy oapthas
'
"
(no odor
or visibi*
tila)
(no Oder
or visibls
film)
950 - 11250
H
Oocano
"
"
(no odor
or visible
tilio)
(r.n odor
or visibls
film)
950 - 11250
U
DoJacjr.e


(no odor
or visibls
film)
(nc odor
or visible
film)
950 - H2'£>
a
*Talnting substance
-------
TABLE 4-10 (CONT.)
MATERIAL
HATER
AI
QUALITY
AL
CRITERIA
rw
MS
MAX. RESERVOIR
WATER AFTEC
TERTIARY RECOVERY
tug/1)
PROCESS J
CODE
HepUM
-
•
(no odor
or visible
film)
(so odor
or visible
filn)
950 - 11250
«
1
Octane


(no odor
or visible
film)
(no odor
or visible
film)
959 - 11250
H '
Por.tano


(no odor
or visible
film)
(no cdor
or visible
filn)
950 - 11250
H
Propir.o

'
(no odor
or visible
film)
(r.o odor
or visible
filu.)
950 - 11250
H
Cyclohcxdtie
"
"
(no odor
or visible
film)
(no odor
or visible
filn)
950 - 11250
"
1
Tip top crude

"
(no odor
or visible
film)
(no cdor
or visible
filn)
950 - 11250
i
SynthusizcJ hydrocarbon*


(no odor
or visible
mm
(no odor
or visiblo
filn)
950 - 11250
u
Dijp'. hcnic conpounda
-
-
<0.1 ng/14
(n.. oior
or visible
fila)
950 - 11250
H
i
Aninos
. I 			
•
_

•
S - 100
'
'"minting substanco
-------
TABLE 4-10 (CONT.)
MATERIAL
WATER
AI
QUALITY
AL
ctiTcaik
rw
us
KAX. RESERVOIR
HATCH ATTFR
TERTIARY RECOVERY
PKOCC3S
CODE
Cartoxyaethylcellulosii

-
-
-
: -
100
p
Carboxyvlnyl polymer
-
-
-
-

100
p
Deoxyribonucleic acid
-
-
-
-

100
p
Glycerin
-
-
-
-

100
p
Poiyjc tlanide
-
-
-
-

IOC
«•
Pclyethcnu oxide
-
-
-
-

100
p
folyis-.butylena in benzene
-
-
-
-
5 -
100
p
Polysaccharide
-
-
-
-

100
p
Rhccpectic polymer
-
-
-
-

100

Klibber in bonz-ine
-
- .
-
-¦
S -
100
p
Starch
-
-
-
-
S -
100
p
Aldose* 6 series
-
-
-
-
J -
100
p
Aldoses L scrips
- '
-
-
-
s -
100
p
Dextrans
-
-
-
-
s -
100
p
Ketones B series
- •
-
-
-

100
p
KJtosc* L series
• -
-
-
-
5 -
100
p
Conjugated sacc-irides
-
-
-
-

100

Ci saccharides
-
-
-
-
s -
100
p
Monosaccharides
-
-
-
-

100
p
Polysaccharides
-
-
-
-
5 -
ioo
p
Tetra^acciiaridiis
-
-
-
T
S -
100
p
-------
TABLE 4-10 (CONT.)
MATERIAL
UtTEl
At
QUALITY
At
cut ou
FH
WS
KAX. RESEBVOIR
HATER AFTER
rCSTIAHY *EC0V£R*
taj/li
PROCESS
CODE
¦idlltiM
-
-
-
-

r
Hydrogen peroxld«
-
-
-
-

T
Qutnoltnb

"
<0.5 mq/l (no e£or
or viaibid
f i la)

T
So£lun i-.ydroxiJc
-
-
-
-

E
Quaternary ^awniu^ »alL«
-
-
-
-

E
Fluoriua solution*
2 »3/l
: b-j/i
-
-

E
?i.tasslu2 ^orsylvra cy<_ la-irUo ljurj-l# 2-Jiydrox'»
cthaleae todiua pXccihol.iit« ncthylftna
carboxylato
_
_
0.2 vq/X
0.S ng/1
313 - 1900
s
>i?di£ied aHYlolalda
-
-
0.2 ltg/1
0.5 nij/l
375 - 1100
&
Alky I iimido butane
-
-
0.2 «g/l
0.5 cg/1
375 - 1»00
s
^Tainiinij aub*tanc«
-------
TABLE 4-10 (CONT.)
MATERIAL
WXTB*
U
QUALITY
M.
CRITERIA
FW (IS
MAX. RESERVOIR
HATCft AFTCR
TEMIAKX KECOVEM
«t9/U
1
PROCESS
COt-E
c-Cotyl betano
-
-
0.1 KJ/I
0.$ mj/l
375 • 1900
S
Coconut itcthanoljBidJ
-
-
0.2 mg/l
0.5 og/l
375 - 19C0
s
tict.'lanoljnir.a supjr^ntido
-
-
0.2 H9/1
O.S 09/1
375 - 1900
s
Laurii; acid dltith-inolauina condcntato
-
-
0.1 wj/1
O.S mj/l
m - moo
s
Alkyl «tyl pol j-«:thenaxy «*tor
-
-
0.2 B9/1
O.S mg/l
ITS - 1900
s
Alfcyl polyethidntoxy othanol
-
-
0.2 tuj/l
0.5 B9/I
11s - mo
s
Polyaxyetlii>l«n(i alkylaryl ather
-
-
0.2 ng/1
O.S ag/l
J#5 - 3900
E
Condensation product of athylen* oxide
with propylene glycol
-
-
0.2 mg/l
O.S B9/I
37S - 1900
s
r«-.y jleohol aUylonin* sulfate
-
.
0 .2 xtj/l
O.S ag/1
373 - 1900
s
tladtfidd AUKiniun jlkyl suHata
-
-
0.2 mj/i
O.S ag/l
375 - 1400
5
Sodiun hydrocarbon sulfonate
-
-¦
0.2 mg/l
O.S b«j/1
37 S - 1900
3
Scdiua ljuryl sulfondte
-
-
0.2 ng/l
O.S »g/l
375 - 1900
S
n,ntiSony
-
-
-
1.0 mg/l
0.05
K/r/a
Arsjnis
0.10 *9/1
«>.S og/l
-
o.l a.j/1
<0.12
n/T/a
Sjriua
-
-
-
1.0 ttg/1
<0.14
n/t/o
IUn;aMM
0.2 ag/l
f.o Halt
-
O.as mg/l
'0.05
N/T/Q
Hickol
0.2 atj/1
-
0.02 *
«-hr. LCS0
-
7-
n/r/c
Tin
-
-
-
:
•a.o
U/1/C
Vanadium
-
t.i *9/1

-
48
M/r/o
-------
these materials at concentrations three orders of magnitude
greater than acceptable water quality criteria in abandoned
oil fields is a difficult problem in environmental protection
for the future. The actual scale of the problem will vary
from region to region depending on factors affecting the
risk of releasing these chemicals and the proximity of
important aquifers or water bodies to oil reservoirs.
4.1.1 Compounds and Degradation Products
Although many of the chemicals used in tertiary oil
recovery processes may form degradation products, such
degradation occurs only under extreme conditions of pressure
and temperature. For example, typical conditions in a
reservoir where raicellar flooding is undertaken are estimated
to be: pH of 6-8; temperatures up to 200° F; pressures up
to 3,000 pounds per square inch. Degradation occurs most
easily at more acidic (pH-3) or more alkaline (pH=ll) con-
ditions, with temperature in excess of 250° F; and pressures
in excess of 3,000 pounds per square inch.
In addition to the affect of these reservoir conditions
on the degradation process, there may be effects due to the
other compounds in the formation matrix and their interaction.
A chemical used in a micellar-polymer flood may be the
limiting factor in a degradation reaction (e.g., it must be
present for the reaction to occur), or it may serve as a
catalyst for the degradation reaction (e.g., it affects the
rate of the reaction).
The descriptions of toxic effects of chemicals ar.d
their associated degradation products is based upon Dangerous
Properties of Industrial Materials, by S. Irving Sax, Third
Edition, 1968. Definitions of the toxic effects are at the
end of Table 4-10. Due to the nature of the reactions and
the possible pathways for these pollutants, "major chronic
systemic" effects are considered most problematic.
The surfactants used in tertiary oil recovery processes
are a very important group of chemicals because the sulfona-
tion reaction by which most are manufactured is reversible.
Table 4-11 lists some degradation reactions which may occur
and the toxicity of the accompanying reaction products. Di-
tetradecyl dimethyl ammonium chloride is probably stable,
although it may undergo degradation to 1-tetradecene and
121-
-------
TABLE 4-11
POSSIBLE DEGRADATION REACTIONS OF MATERIALS PROPOSED FOR
USE IN TERTIARY OIL RECOVERY
CHEMICAL
TOXICITY
REACTION
DEGRADATION MODUCTS
TOXICITY
DiMtndscyl disc thy 1
cMoridt
Unknown
Elimination
•)1-Tetrad«cena
blDinethyl-tatrndqcyl anroniua
chlcrlda
a)Unknown
b)Unknown
CoJoey1 trlaathyl
utuaoniua chloride
Unknown
elimination
a)1-Dodecena
bITriaathyl anaoniuu chlorlda
a)Unknown
b)	Uuknotm
Hccadccyl triaathvl
araaoniua chlorida
Unknown
Elimination
a)1-Hoxadecena
bITrimcthyl ajaaoniua chloride
a)Unknown
blUnkrvown
Alkyl phtnoxy
poly«thoxy athanol
Unknown
Hydrolysis
a)Glycol
a)Ko acuta local
Malar acuta syatanlo
Minor chronic local
Minor chronic systemic
p-Chloroanilina
wlfita laurata
Unknown
Deiultona-ion
ar.
-------
TABLE 4-11 (CONT.1
CHEMICAL
TOXICITY
FZACTIW:
DEGRADATION PRODUCTS
TOXICITY
Hor.d-utyl phenyl
phenol sodiun sulfate
Unknown
Hydrolysiu
a)Sulfate	Ion
b)Monobutyl	phenyl phenol
a)Laxatlvo
b)Unknown
Folyoxyothylcmt
alkyl phenol
Unknown
ilydrolytlu
alClycol
a)No acute local
Major acute systenic
Minor chronic local
Minor chronic syttcnlc
Mcrpholene »tcarat«j
Unknown
Hydrolysit
alMorpholene
b)Stearic acid
ajllajor acute local
Major acute systolic
Unknown chronic local
Unknown chronic ry3tcnls
b] Slight
Par.taerythriol
monojtear&te
Unknown
Hydrolysis
alPentacrythrloX
bIStcric acid
a! Unknown
b) Slight
Gthexyl sodiua
succinate
Oiethyl«ne;lycol
sulfate
Unknown
Hydrolysis
a)Ethylene glycol
b>Sulfuric acid
a)!lo acuta local
tlalor acute systcaic
Minor chronic local
Minor chronic systecle
li) Lower* HI
e-Dodccy1-diethyleno
glycol sulfate
Unknown
Hydrolysis
a)Sulfate ion
tln-Doiccyl-dlithyleiw glycol
alLaxativo
b)Unknown
SoJiuo glyceryl
aior.olauryl sulfate
Unknown ,
Desulfonation
•(Glyceryl nono}aurate
b)Sulfate ion
a)Unknown
b)Laxati
-------
TABLE 4-11 (CONT.)
CHEMICAL
TOXICITY
REACTION
DEGRADATION PRODUCTS
TOXICITY
Kfcxauecyl naphthalene
sulfonate
Unknown
Dcsulfonatlor.
a)Kcxadecyl	naphthalene
b)5ulfato	ion
atUnknown
b) Laxative
Sodiua lauryl sullonate
t'nknowa
Hydrolysis
a)Lauryl alcohol
bISuliato ion
•)Unknown
b)Unknown
Trii.-thanolaalr.e laurate
Unknown
Hydrolysis
a)Triethanclaaine
b)Laurie	Acid
•)>!o acute local
Hir.ox acuta systeaic
Ko chronic local
Minor chronic syste&ic
b) Unknown
TrJothanolanlne
nyrlstate
'Jnknown
Hydrolysis
a)Triethanolaalne
b)Hyristic	acid
a)Ko	acute local
Minor acuta systeaic
Ko chronic local
Minor chronic systemic
b)Unknown
Triethanolamin* oleate
Unknown
Hydrolysis
a)Triethanolaalne
b)01e'c	acid
a)No acute local
Minor acute systemic
No chronic local
Minor chronic systeaic
blMinor acute local
Unknown acute systeaic
Unknown chronic local
Minor chronic systemic
Toluene

Stable

Major acuta local
Major acute systemic
Minor chronic local
Major chronic systeaic
Alkyl phenol*
Probable
High
Stable


Eaters
Low to
High
Hydrolysis
a)Acid
b)Alcohol

Aldehydes
Unknown
Oxidation

Major acute local
Usthal acuto systeaic
Major chronic local
Unknown chronic syatesio
-------
TABLE 4-11 (CONT.)
CHEMICAL	TOXICITY	REACTION [>£CRADATXON PHOOUCTS	TOXICITY
Ketones
Unknown
Stable
N»
in
I
Alcohols
Minor
Stable


p-Nonyl phenol
Unknown
Stable


Quaternary amines
Toxic
Elimination
Tsrtiary amine
Toxic
Mobility buffers
Hot
toxic
Stable


tkircuric chloride
Very
toxic
Stable


Hydrazine
Explosive
Lethal



Quinolina
laralysis
Stable


'Definitions of Degree of Toxicity! (N. Irving Iw, Dangerous Properties of Industrial Materials.
Third Edition, 1968. p. 21
Hi nori
Acuta loral • materials which on *• ".jle exposurei lasting seconds, minutes or hours cause only slight
effect's"on tt-.o s£in or mucous membranes Lugardltss of :he extent of the exposure.
Acute tvatgmic - utociilt which c.c be absorbed into the body by Inhalation, Ingestion or through the
¦kin and which produce only slight effects following single exposures lasting seconds, minutes, or hours, or
following ingestion of a single dose, regardless of th: quantity absorbed or the extent of exposure.
Chr-.r.ic IckmI • materials which on continuous or cepeated exposures extending over periods of days,
nonths, or years cause only slight harm to the skin or mucous membranes. The extent of exposure may be groat
or small.
Chronic jvstfcn^c - tutorials which can be absorbs) into the body by inhalation, ingestion or through the
skin an J which produce only slight effects following continuous or repeated exposures cxtt-riing over days,
nontl-.s or years. Tho extent of tho exposure may be grsat or snail, in general, those substances classified
as having "slight toxicity* produce changes in tha hunin body which are r**dily reversible and which will
disappear following termination of exposure, either wi:h or without medical treatment.
Major>
Acute local • materials which on single exposures lasting seconds or minutes cause injury to skin or
nuccus rcaibr<*.nea of sufficient severity to threaten life or to cause permanent physical impairment or
^isfigurenont.
Acuta svsttnlc - matarials which can be absorbed into the body by inhalation, ingestion or through the
skin and which can cause injury of sufficient severity to threaten life following a single exposure l*stin]
seconds, minutes or hours, or following ingestion of a.slnole dose.
Chr.wic 1 pen I ¦ materials which on continuous or repeated exposures extending over periods of days,
Eonths or years can causa injury to skin or mucous mcr.3ra.10s of sufficient severity to threaten life 'or
to cause pernanent impairment, disfigurement or irreversible change.
chronic •¦.ysvt-alc * materials which can be absorte) into the body by inhalation, ingestion or
through the skin and which can cause death or serious >l.yilcal inpairmcnt following continuous or repeated
exposures to small amounts extending over periods of diys, eonths or years.
-------
dimethyl-tetradecyl ammonium chloride. The toxicity of
1-tetradecene is unknown, although it is a probable irritant
with narcotic effects at very high concentrations. Dodecyl
trimethyl ammonium chloride is probably stable, with possible
decomposition to 1-dode'cene and trimethyl ammonium chloride.
The details of the toxicity of dodecene are unknown, although
it is a probable irritant and narcotic in high concentrations*
Hexadecyl trimethyl ammonium chloride is probably stable,
with the possible degradation to 1-hexadecene and trimethyl
ammonium chloride. The toxicity of 1-hexadecene is unknown.
Alkyl phenoxy poly-ethoxy ethanol may hydrolyze to glycol.
One hundred inillilitres of ethylene glycol is reported to be
the lethal dose for mat. in an acute dose. If ingested,
glycol causes initial central nervous system stiumlation,
followed by depression. Later, it causes kidney damage
which can terminate fatally. Para-chloraniline sulfate
laurate is probably stable, with a possible desulfonation
and hydrolysis to para-chloraniline, sulfuric acid, and
lauric acid. Para-chloraniline can produce severe systemic
disturbance. Symptoms produced include headache, weakness,
difficulty in breathing# air hunger, psychic disturbances,
and marked irritation of the kidneys and bladder. This
compound can be absorbed through the intact skin. Para-
toluidine sulfate laurate is probably stable, with a possible
desulfonation and hydrolysis to paratoluidine, sulfuric
acid, and lauric acid. Although the details concerning the
toxicity of lauric acid are unknown, animal datx suggest low
toxicity for lauric acid esters. There is soute evidence
indicating that pax-atoluidine is an irritant, an allergen,
and can show toxic effects if ingested. Polyglycerol mcno-
laurate is probably stable, with the possible hydrolysis to
polyglycerol and lauric acid. Glycerol disulfoacetate
monorayristate is probably stable, with possible desulfonation
to glycerol diacetate monomyristate and a sulfate ion. Mono
butyl phenyl phenol sodium sulfate is probably stable, with
the possible degradation to sulfate ion and mono butyl
phenol. Details concerning the toxicity of mono butyl
phenyl phenol sodium sulfate are unknown. The epoxy units
of polyoxyethylene alkyl phenol may hydrolyze to glycol.
Morpholene stearate may undergo hydrolysis to morpholene
and stearic acid. Morpholene is irritating to skin, eyes,
and mucous membranes, and has produced kidney damage in
experimental animals. However, it is al3o used is a food
additive for human consumption. Stearic acid has only
slight toxicity, and is a substance which migrates to food
from packaging materials. Pentaerythritol monostearate is
-126
-------
probably stable, with possible hydrolysis to pentaerythritol
and stearic acid. The toxicity of pentaerythritol is unknown.
Dihexyl sodium succinate is probably stable, with possible
copolymerization with polyfunctional alcohols or amines.
Diethyleneglycol sulfate is probably stable, with
possible hydrolysis to ethylene glycol and sulfuric acid.
N-dodecyl diethylene glycol sulfate is probably stable, with
possible degradation to sulfate ion and n-dodecyl diethylene
glycol. Sodium glyceryl monolauryl sulfate is probably
stable, with possible desulfonation to glyceryl monolaurate
and sulfate ion. Alpha-olefin sulfonates may suffer possible
desulfonation to a hydrocarbon and a sulfate ion. The same
degradation process may occur to alkyl aryl sulfonate deter-
gents. Alkyl aryl naphthenic sulfonates are probably stable,
with a possible desulfonation to alkyl aryl naphthlene and a
sulfate ion. Hexadecyl naphthlene sulfonate is probably
stable, with possible desulfonation to hexadecyl naphthlene
and a sulfate ion. Sodium lauryl sulfonate is probably
stable, with a possible decomposition to lauryl alcohol and
sulfate ion. Lauryl alcohol (also known as 1-dodecanol) is
relatively insoluble in water, and has unknown toxicity.
Limited animal experiments indicate low toxicity for lauryl
alcohol. Triethanol amine laurate may undergo hydrolysis to
form triethanol amine and. lauric acid. Triethanol amine
exhibits low toxicity, though liver and kidney damage have
been demonstrated in animals under chronic exposure.
Triethanol cmine myristate is probably stable, with possible
hydrolysis to triethanol amine and myristic acid. Triethanol
amine oleate is probably stable, with possible hydrolysis to
triethanol amine and oleic acid. Oleic acid ha3 low toxicity.
Among the cosurfactants, ketones and para-nonyl phenols
are both stable, as are isopropanol, n-butanol isobutanol,
1-hexanol, 2-hexanol, 2-pentanol, and cyclohexanol. Esters
may hydrolyze to an acid and an alcohol. Aldehydes are
probably stable, although they may be oxidized by strong
oxidizing agents.
Quartemary amines (used as corrosion inhibitcrs) may
eliminate the longest side chain to form a tertiary amine.
Most of the other chemicals used in tertiary oil
recovery are very stable. All mobility buffers appear to be
stable. Mercuric chloride (a biocide) is stable, and would
stay in solution in all but extreme pH increases. Quinoline
used to ignite ln-situ combustion is stable. However,
-127-
-------
hydrazine also used to ignite in-situ combustion is a very
strong reducing agent, and will probably be converted to Nj
with a transfer of its hydrogen atoms to other molecules.
Of the degradation reactions which may occur, hydrolysis
and desulfonation of surfactants such as polyoxyethylene
alkyl phenol, diethyleneglycol sulfate, alkyl phenoxy poly-
ethoxy ethanol to glycol and p-chloroanaline sulfate laurate
to p-chloroaniline are the potential largest hazards.
4.2 Carcinogenicity of Chemicals
A number of the chemicals proposed for use in tertiary
oil recovery operations have been shown either to induce the
formation of tumors in experimental animals or to accelerate
the induction of such tumors by other chemical carcinogens.1
Table 4-12 summarizes the major carcinogenic chemicals which
may be used. A number of caveats apply to estimating the
carcinogenic risk associated with tertiary oil recovery
operations:
* The experiments used to demonstrate the carcino-
genicity of particular chemicals are frequently
carried out at.,rather high dosages. For example,
a recent study" demonstrated the induction of
mammary, lung, and lymph tumors resulting from
the force feeding of mice with a 43 percent
solution of ethyl alcohol over the course of
1,020 days. Although this constitutes technical
evidence of carcenogenicity, its relevance to the
effects of ethyl alcohol at normal dosage levels
is questionable.
Documentation of these effects can be found in the
Department of Health. Education and Welfare's "Request for
Information on Certaiu Chemicals," (Federal Register 40 (121)s
26390£f (1975)), which list3 a set of chemicals identiTTed
by the NIOSH as having "reportedly produced an observed or
suspected carcinogenic response in anaimals, based upon
published articles in the literature," and in HEW's "Survey
of Compounds which have been Tested for Carcinogenic Activity,"
which summarises the recent literature on carcinogenic
properties of chemicals.
^M. Kuratsune et al., Gann. 62, (1971): 395-405.
-128-
-------
TABLE 4-12
TERTIARY OIL RECOVERY
CARCINOGENIC CHEMICALS WHICH MAY BE
USED IN TERTIARY OIL RECOVERY OPERATIONS
Surfactants (possibility of synergistic
interactions with organic carcinogens)
Alkyl aryl sulfonates
Carboxymethylcellulose
Benzene and benzene derivatives
Polycyclic hydrocarbons
Crude oil and crude oil fractions
Formaldehyde and paraformaldehyde
Phenol and phenol derivatives
-129-
-------
• The literature (except in infrequent epidemio-
logical studies of occupational or air pollution
related carcinogenesis) deals almost exclusively
with studies performed on experimental animals.
Although a priori considerations lead one to
suspect that a substance which is carcinogenic
in mice and hamsters is probably carcinogenic
in humans, procedures are needed to determine
how to extrapolate from animal data to humans.
° Even within individual species, dose-response
relationships for chemical carcinogens are not
well documented. On the basis of the literature,
it is only possible to make qualitative state-
ments regarding the human carcinogenicity of a
particular chemical.
0 The literature on chemical carcinogenisis is
highly variable with respect to dosaee, dearee
of control, and type of system used (e.g.,
testing for introduction of tumors in various
mammalian species as opposed to assaying cell
transformation in vitro).
Thus, it is almost impossible to make valid quantitative
assessments of the human carcinogenic risk associated with
the use of various chemicals. In recognition of thi3 fact,
the U.S. Environmental Protection Agency has recently defined
nine principles to be used in guiding policy making with
regard to the regulation of carcinogenic chemicals.^- Many
of these guidelines are relevant to the problem of assessing
the risks associated with the use of carcinogens in tertiary
oil recovery operations:
1.	"A carcinogen is any agent that increases tumor—
benign or malignant—induction in man and animals..."
2.	"Carcinogenesis is characterized by its irreversi-
bility and long latency period following initial
exposure to the carcinogenic agent..."
3.	"There is great variability in individual
susceptibility to carcinogens..."
^Chemical and Engineering News, November 3, "VJ, p. 17.
-130-
-------
4.	"The concept of a 'threshold' exposure level
for a carcinogenic agent has no practical
significance because there is no valid method
of establishing such a level..."
5.	"A carcinogenic agent may be identified through
analysis of tumor induction results with
laboratory animals exposed to the agent, or on
a post hoc basis by properly conducted epidemio- -
logical studies..."
6.	"Any substance that produces tumors in animals
must be considered a carcinogenic hazard to
man if the results were achieved according to
the established parameters of a valid carcino-
genesis test..."
The central thrust of these principles is to broaden
considerably the definition of "carcinogen" (e.g., tc include
materials which have been shown to induce benign tumor?) and
to assert that in the absence of meaningful procedures to
quantitatively determine human carcinogenic dose/response
relationships or thresholds, it is necessary to consider as
carcinogenic any chemicals which have been shown to induce
tumors, at any dosage, in any experimental animal. A
positive carcinogenic risk is considered to exist no matter
how low the concentration of the substance in the environ-
ment; so that threshold levels, such as have been set up for
various pesticides and other toxic substances in surface
water bodies, cannot be set up. In terms of the subject of
this report, this means that attention should be given to
any chemical which has shown carcinogenic effects in some
system, no matter what the actual concentrations nay be in
the vicinity of a tertiary oil recovery project. Thi3 is
the approach which has been adopted in this section.
Of the chemical surfactants listed in Table 4-1,
carcinogenic effects are only indicated for the alkyl aryl
sulfonates, alkyl benzene sulfonates and some derivatives of
alkyl naphthenic sulfonates. However, the synergistic
interactions of otherwise non-carcinogenic surfactants with
other chemicals will probably prove to be more important
than any direct carcinogenic effects they may produce.
Alkyl benzene sulfonates, for example, have rather low
carcinogenicities when administered alone, but they have
^See, for example, EPA, Criteria for Water Quality, 1975.
131-
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been found to increase the tumor-inducing properties of 4-
nitroquinoline-l-oxide.^ This effect is presumably due to
the solubilization of the carcinogen by the sulfonate, and
it may also be produced by other surfactants.
Among the mobility buffers, carboxymethylcellulose,
polyethylene oxide (polyethylene glycol), dextran, and
benzene are suspected carcinogens.2 High long-terra doses of
glycerin (glycerol) are also indicated as being tumorigenic.
"Crude oil" (as petr.' <-:um) is listed as a suspected
carcinogen, and some carciui^^nic activity remains in its
purified fractions such as o: l, which is listed as a carcino-
gen. Benzene is also a carcinogen, as are certain of the
benzene derivatives such as toluene, which is sometimes used
in stimulating wells prior to thermal methods of oil recovery.
A further danger exists that these compounds may interact
with chlorine in drinking water disinfection plants to
produce carcinogenic chlorinated aromatics. Extensive data
exist3 documenting the carcinogenicity of polycyclic hydro-
carbons (including benzpyrene and some of the naphthenics).3
Several alkylated aryl compounds, as well as their chlorina-
tion products, jure included in the references. Pure
paraffinics and cycloparaffinics seem to be relatively non-
carcinogenic .
The only potential carcinogen listed among electrolytes
is the category "organic acids," but inorganic salts are
most commonly used. More specific information will be
needed about the organic acids used in order to assess the
carcinogenicity of these compounds. No known carcinogens
are listed for preflushing chemicals.
Definite evidence exists supporting the carcinogenicity
of cosurfactants such as formaldehyde, paraformaldehyde, and
phenol, but these materials are not most commonly used. No
evidence exists for the carcinogenicity of pure preparations
of most of the organic alcohols, except for one or two, such
as ethanol, which are carcinogenic at extremely high doses
administered over long time periods. More information will
be needed on which amides, amino compounds or ketones are
used.
^Takahashi, Gann. 61(1), (1970): 27-33.
2U.S. Department of Health, Education and Welfare,
"Request for Information on Certain Chemicals," Federal
Register 40 (121)''<>639Iff (1975).
^HEW, "Certain Chemicals, 1975.
*O.S. Department of Health, Education^and Welfare,
Survey "of "Compounds' "WftTcH Have Been Tested for Carcinogenic
Activity, 1971.	___
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CHAPTER FIVE
EFFECTS OF TERTIARY OIL RECOVERY ON GROUNDWATER
5.0 Introduction
The chemicals used in tertiary oil recovery which may
be dissolved or entrained in water produced by the process
are of environmental concern because these chemicals may
enter and contaminate groundwater supplies. This chapter
reviews the possible causes of groundwater pollution which
may be affected by tertiary oil recovery methods.
Primary contamination of groundwater results in large
part from leaks in well casings and from seepage through the
walls of waste disposal pits. Pollution from lined pits is
rare but may have longlasting effects if brine has escaped
to permeable sands outside the lining* Direct contamination
of surface water can occur from spills or seeps to the
surface of chemicals, water or brines, or oil. Since most
water bodies flow eventually into others, pollution usually
affects more than the first body it enters. Additionally,
contaminants on the land may be washed by rain into surface
water systems. In all cases, pollution will continue as
long as contaminants remain and water supplies are' exposed
perhaps long after production and disposal operations have
ceased.
The problems of spills, surface seeps and pipeline
breaks have been recognized as a result of conventional oil
extraction operations. Regulations regarding impervious
linings for brine pits are an example of this awareness.
Because of close supervision, monitoring and modification
and upgrading of equipment, it is hoped that the likelihood
of leaks and spills during a tertiary oil recovery project
will be less than conventional operations. However, during
the recovery activity and after it is completed it is possible
for leaks to occur. Most important to understand are the
ways in which water soluble chemicals introduced into an
oil-bearing strata for tertiary recovery may escape unseen
into an aquifer. The risks of leakage of these chemicals
due to failure of a well will be determined by analyzing the
problems historically associated with oil production and
judging what additional or different effects may result from
tertiary oil recovery activity.
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This chapter will address these issues in three stages.
The first will establish the conceptual framework of the
problem. The second will examine the accident record of a
representative oil-producing region — the Texas Upper Gulf
Coast (District III of the Texas Railroad Commission) — to
provide some first-order estimates of the probability of
contamination from tertiary recovery projects. In the third
section the relative risk levels of the tertiary oil recovery
methods will be determined qualitatively for each region.
This approach provides em initial appraisal of the relevant
risk factors. The modelling of regional groundwater systems
and computation of the probabilities of well failure region-
by-region are required to understand fully the risks of
tertiary oil recovery.
5.1 Mechanisms of Contamination
5.1.1 Hydrology
Groundwater is held in permeable layers of sand (aquifers)
separated from each other and from the surface by loss
permeable layers of rock, or by impermeable layers (aquicludes).
Freshwater (less than 1,000 mg/1 total dissolved solids)
occurs in 3trata closer to the surface, with slightly saline
water (1,000 mg/13,000 mg/1 total dissolved solids) in
deeper aquifers.
Groundwater contamination is particularly bad because
it is longlasting, difficult to trace, and may be very far-
reaching. Once a layer of permeable sand has been polluted,
it may be years before dilution and percolation clear the
contaminant away. Though the actual rate of flow varies
among aquifers, 200 feet per year has been suggested as a
reasonable rate.1 At this rate of flow, 260 years would be
needed to clear an aquifer 10 miles from a river. Some
aquifers flow as slowly as 20 feet per year, and would,
therefore, require even longer to cleanse naturally, in the
absence of a study detailing local subsurface hydrology, it
A. Gene Collins, Chemical Applications in Oil- and
Gas-Well Drilling and Completion Operations. U.S. Bureau
of Mines, Bartlesville Petroleum Research Center, U.S.
Department of the Interior, Bartlesville, Oklahoma, 1975.
-134-
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is difficult to determine the source of a pollutant when one
is found, or conversely to be certain that what is placed
below the surface today will not one day contaminate a water
supply.
Other mechanisms may play a part in mitigating or
augmenting the impact of a discharge to an aquifer. These
mechanisms are discussed in detail elsewhere in the report
and are restated here in order to assess fully the incidence
of pollution which may occur from tertiary oil recovery. It
has been pointed out tha :he importance of each mechanism
Will vary with the hydrology and geology^and other character-
istics of the oil recovery project site. These mechanisms
include: leading, dilution, adsorption, partitioning,
chemical degradation, bacterial degradation, entrapment and
precipitation. Figure 5-1 illustrates the role of these
mechanisms in the fate of chemical leakage or spills result-
ing from tertiary oil recovery. The flow sheet is a general
presentation of the order in which the mechanisms may act
(if at all) on a chemical constituent in a leak. In fact,
each mechanism may act upon the material a number of times.
5.1.2 Sources of Pollutants
The most serious problems arise when produced water or
brine enters the groundwater system. Pollutioa may result
from a variety of sources. If the brine is used to displace
oil in a foreign formation, as in waterflooding, the brine
may mix with nearby water supplies. Excess brine disposed
into foreign strata may cause contamination of surrounding
aquifers. Spills at the well head and seepage from pits may
ultimately reach groundwater sources. Reinjecting brine
into its original stratum is a common and usually safe
method of disposal, but it, too, may allow contamination if
the disposal well fails.
5.1.3 Mechanisms of Pollution
Three basic mechanisms of groundwater pollution have
been distinguished: (1) bypassing the natural filtering
system, (2) overwhelming the natural filtering system, and ,
(3) altering the hydraulic or chemical balance of the system.
^U.S. Environmental Protection Agency, Ground Water
Pollution from Subsurface Excavations, EPA-430/9-73-012, 1973.
-135-
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Figure 5-1. This figure shows tl "•t between the source of a spill or leak of
chemicals used in tertiary oil recovery .id a water supply there are a number of
physical and phemical mechanisms which may act on the material.
-------
5.1.3.1 Bypassing the Natural Filler
An opening in the formation ~ such as an oil well ~
may allow pollutants to pass directly into an aquifer without -
percolating through soil/ rock, and organic matter. Bypass
has posed and is likely to continue to pose most of the
petroleum-related risks to groundwater supplies. Any break
in the impermeable layers surrounding groundwater supplies
lays open the possibility of pollution. Figure 5-2 shows
the manner in which saline water may enter fresh water*
polluted water may enter clean water, or Substances from the
surface may be washed into groundwater.
Though the bypassing of the natural filter may occur in
a number of ways, the most common route is well failure.
Any permeable stratum penetrated by a well is susceptible to
contamination by oil, brine and chemicals passing through
the well during both injection and extraction operations.
Figure 5-3 shows a producing oil well and the possible
routes of pollution into water-bearing strata. The newly-
drilled wellbore is lined with metal pipe called casing
which is cemented to the sides of the hole for rigidity and
corrosion resistance. Surface casing is installed near the
well head to keep the hole clear andto protect shallow
fresh water aquifers. Production casing runs the length of
the well. The bottom of the hole is plugged with a shoe,
and a packer set inside the casing seals off the well just
above the oil-bearing strata. Fluids pass through tubing
which is suspended inside the casing and which passes
through the packer. The result is a multiple shield between
groundwater supplies and oil field fluids.
Yet ruptures do occur. The well provides communication
among strata by conducting fluid through the cement-formation
annulus, through the casing-cement annulus and then through
a crack in the cement, through the tubing-casing annulus and
then through cracks in the casing in the cement, or through
the tubing and then through holes in tubing, casing, and
cement.
5.1.3.2 Overwhelming the Natural Filter
The^natural filtering system is overwhelmed when the
contaminants become so concentrated that percolation cannot
render the solution harmless. Seepage from brine pits
pollutes in this manner (Figure 5-4). Recently, most states
-137-
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Ter iary
Recovery
Oil Well
(Injector
not shown)
Fresh water
wel 1
Coroded
or
Improperly
plugged
wel 1
Tertiary
Recovery
Injection
Well
(Producer
not shown)
xbroken x
*casing'x
•°o°o°o°
°o°o°o°
9o2o9o9
°n°n0"°
IM-surface
J^Lfresh
r
-------
OIL
WELL
surface
casing
cement
^ Leak due to faulty tubing
@ Leak due to faulty
production casing
Leak dua to faulty cement
Figure 5-3. This figure is a diagram of an oil well
showing the potential paths of fresh water contamination
resulting from well failure.
Oeslred path of oil flow
—• Possible flow of oil leaks
Contamlnant
-139-
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Water
well
(pumped)
Chemically
Loaded
Brine
Injection
well
^surfaceN
^V.^yIWiY^.V'.V
~'v/vmw'v
: -^f resVvf::<
|o§ sal Trie"water o0o0o0o0odG^cIe^njec:te^o0o0o0o
2o2o2ogo2ogo2oOoOo2o®§2o2^^^
•§|g|g|§2S2g2§g§S§S§S§S§2§f
©
' Fissure
caused by
Injection
pressure
Contaminant
Figure 5-4. This figure illustrates the contamination
of fresh water by chemically loaded brine through (1) over-
whelm of natural filter system, and (2) pressure.
-140-
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have recognized this danger and required that all disposal
pits be impervious. The result has been a dramatic reduction
in the amount of new pollution from this source. Of the
complaints concerning brine seepage in Texas Railroad
Commission District III since this law went into effect in
1973, most have been traced to continuing seepage from
earlier disposal. The difficulty with brine seep? and
chemical spills, as with groundwater pollution in general,
is their longevity. The risk of chemical spills and seeps
is difficult to quantify because many site-specific factors
such as operator skill, systems design and construction,
modes of shipment, and weather, will interact at each
location. Spills which do occur may have longlasting
effects on groundwater.
5.1.3.3 Changing the Formation
Differences in pressure, temperature, or chemical
concentration cause the flow of groundwater; changes in
temperature and' acidity alter the sorptive properties of the
formation. Within aquifers or inter-aquifer channels (wells
or fissures) water flows from higher to lower pressure
zones; to a lesser extent, flows are affected by concentration
and temperature differentials. This can result in movement
of saltwater into freshwater zones in the same aquifer, into
other aquifers containing fresh water, or into surface water
(Figure 5-5). If the formation has held toxic substances
from another source, a disruption of the chemical balance
may cause the release of such substances into groundwater.
5.2 Estimates of Probability of Contamination
The probability that chemicals will escape after tertiary
recovery can be assessed roughly by reviewing the record of
contamination under primary and secondary processes. The
record chosen for examination is that of Texas Railroad
Commission District III. This area contains numerous fields
which are likely sites for each.of the four tertiary recovery
methods. The district has no peculiar features which might
affect the incidence of problems: the formation fluids are
not very corrosive and the risk of earthquakes within the
area is very low. District III oil fields produce_5_percent
of U.S. oil or roughly 60 million barrels per year."
-141
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Water
body
^^rfff?sh;wateV
••••«••••«•••
r-0o"xochemicanv
O o o' 0flded
Fissure in confined
aquifer releasing water
under higher pressure
Temperature or
Pressure Gradient
Temperature or
Pressure Gradient
greater than force increases diffusion
of gravity
rate
Figure 5- 5 • This figure shows the manner in which
differences in pressure, temperature and chemical concen-
trations affect the flows of water in aquifers.
-142-
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Its major oil fields produce from some 8,000 wells. Even
with this amount of production, the sample of problems is
too small to arrive at a precise number for the probability
of contamination, but it is possible to estimate the order
of magnitude of the risk.
A conservative estimate of the probability of contamina-
tion can be obtained from the frequency of recorded incidents
of a kind which could recur. The complaints of water pol-
lution from oil-producing activities filed with the Railroad
Commission over the past five years are summarized in Table
5-1A, broken down by source of pollution and type of water.
Due to a change in the law as of 1973, many past causes of
water pollution are no longer a problem, since 1973, brine
disposal in Texas has been permitted.only into impervious
subsurface pits. Therefore, the past incidence of pollution
from surface discharge or unlined brine pits is no reliable
guide to future probabilities of pollution. The past frequency
of pollution through well failures is indicative of the
expected scope of the problem.
Table 5-IB shows the number of incidents of water con-
tamination which have occurred in spite of the new regula-
tions, a measure of the future risks. Seven complaints of
groundwater pollution from well failure were filed with the
Texas Railroad Commission during 1973, 1974, and the first
half of 1975. Surface pollution has been registered eight
times in the same period. Since 1970 there have been over
90 on-lease oil spills at production, transportation, and
storage sites.
The Chiquot aquifer, for example, flows at a rate of
only 40 feet per year. Consequently, the time required for
contaminants to appear is long and the wells from which the
leakage occurs may take years to be pinpointed as offenders.
An estimate of the actual magnitude of the groundwater
pollution problem can be obtained by determining what
fraction of oil wells and disposal pits are so situated that
pollution from the well site would reach a water well within
five years. This can be calculated from a knowledge of
groundwater hydrology, and of well locations in the area.
The latter information is available from the Texas Water
Development Board. If it is estimated that 40 percent of
oil- wells- and pits are on groundwater flow routes that would
reach a water supply within five years, and groundwater
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TABLE 5-1A
TERTIARY OIL RECOVERY
TABULATION OF CONTAMINATION INCIDENTS REPORTED IN
"TEXAS RAILROAD COMMISSION DISTRICTTrr. 1970=7?"
ALL INCIDENTS*
DIRECT
CONTAMINANT	SPILLS	SEEPS	TOLL LEAKS	DISCHARGE
TO	TO TO TO	TO	TO
SUSPACE	SURFACE GROUND- SURFACE	GROUND- SURFACE
WATER	WATER
BRINE 4	5 7 2	1	4
OIL 1	2-21-
GAS -	1 -	"	4
TOTAL 5	8 7 4	6	4
aIn addition, three incidents of contamination were of undetermined causes.
Thry vsrc: 15 =urficc-=il; 2! surface-cil sr.il brine; 2! grcundwster brine. Cr.c
cause* was determined as a set-p of brine, but. the type of water affected was nut
reported.
TABLE 5-IB
TERTIARY OIL RECOVERY
CONTAMINATION CO?!PLAINTSa SItiCE REQUIRE-VE^TS OF IMPERVIOUS BRINE DISPOSAL PITS.
TOXAS RAILROAD COMMISSION DISTHICT III, 197Q-75	~~	
CONTAMINANT	GROUNDWATER	SURFACE WATER
BRINE	3 '	6
OIL	"	1
GAS	4	1
TOTAL	7	8
^hesu incidents are representative of
risks from tertiary processes, i.e., inci-
dents of a type likely to recur, and which
will cause new hazar.'.s with tertiary methods.
-144-
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contaminants originating at em oil well or brine pit have
been recorded ten times over five years, then the estimated
incidence rate for District III is:
10 violations * 5 years * 0.4 sample ¦ 5 violations
year
This gives the order of magnitude of the contamination rate.
A longer counting period would probably give more reliable
results, but good records are only available since 1970.
The failure rate of wells in District III, in fields under
tertiary recovery is:
5 violations * 8,000 well3 ¦ 0.006 violations
year	year
On a national scale this well failure rate	suggests that
approximately 175 wells in fields involved	in tertiary
recovery projects might fail each year and	release reservoir
fluids into water supplies.
Another estimate of the probability of contamination
from an oil well can be obtained from data on the frequency
of well failure and an understanding of how failures may
result in contamination. Statistics for well failures
requiring repairs in 1974 are included in Table 5-2. The
"other" category covers all noranechanical failures in opera-
ting wells, such as well-bore leaks and poor cement }obs.
The incidence of "other" repairs on Table 5-2 probably
overstates the likelihood of well leakage because mechanical
problems such as plugged lines, sanding up, etc. which are
included in the category will not necessarily result in
pollution. However, in order to obtain a first-order
estimate of what i3 perhaps the upper bound of failure risk,
it will be assumed that this figure primarily registers
failures which resulted in communication between the well
system and other formations.
From an environmental standpoint, failures of plugged
and abandoned wells are of greater concern than failures of
operating wells because there are no monitors of these
leaks. Operating wells do fail as shown in Table 5-2, but
economic incentives and environmental controls on the well
operator should minimize the amount of leakage which occurs.
Leakage from an injection well may reduce the effectiveness
of tertiary recovery or result in the needless loss of
expensive chemicals. Production well leaks may result in
loss of oil or higher than necessary pumping expense to lift
the additional water which infiltrates the well.
-145-
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TABLE 5-2
UNITED STATES WELL FAILURES - 1974
(Failure Divided By Total Hells Involved)
T.PE FAILURE
WEST
COAST
MID-
CONTINENT
PERMIAN
BASIN
ROCKY
MOUNTAINS
EAST
TEXAS
TEXAS
GULF COAST
SOUTHEAST
U.S.
SUCKER RODS
0.31
0.48
0.52
0.31
0.12
0.56
0.15
ROD PUMPS
0.58
0.51
0.52
0.44
0.20
0.35
0.54
TUBING STRINGS
0.22
0.17
0.14
0.12
0.05
0.58
0.05
OTHERS®
0.03
0.34
0.28
0.22
0.18
0.09
0.20
AVERAGE FAILURE
INCIDENCE
1.08
0.82
1.00
0.77
0.25
0.61
0.56
aAverage "OTHER" failure Incidence was 0.18 on a nationwide basis.
SOURCE: J.E. Kastrop, "Downhcle Oil Well Maintenance Costs Push Half Billion",
Petroleum Engineer, (July 1975): 22.
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Furthermore, the probability of failure in the production
veils or abandoned wells within a producing field may be
conceptualized as proportional to the depth (or distance)
between the oil reservoir and the nearest aquifer uphole.
In general, fluid level in the producing well is kept at
less than 500 feet above bottomhole (or pressures about 200
pounds per square inch gauge at bottoxnhole) though pump
capacity limitations may result in fluid levels up to
approximately 1,000 feet above bottomhole. Therefore, ~
aquifers separated by more than 1,000 feet of sediments from
the oil reservoir would be very unlikely to be exposed to
reservoir fluids.
The abandoned field leakage problem is more complex.
Geologic changes or incursion of water or fluids from
another source may force reservoir fluids through leaks in
the well which developed over time after tertiary recovery
has been complete. Many intraregional factors will affect
the actual incidence rate. The operating well data on Table
5-2 are indicative of these factors, which it is assumed,
will act in a similar way in the abandoned well. As a
"worst case" analysis of this problem, leakage from aban-
doned wells will he related to the proportional thickness of
aquifers penetrated by the well to total well depth. If the
corrosiveness, well ages and.other factors are assumed to be
uniform throughout a region, then a well four-thirds as deep
as the average for the area can be expected to have a
failure rate four-thirds as high as that listed in Table
5-2. The incidence of contamination (P ) within a field in
terms of incidents per well-year is then:
P " Regional Incidence x	Field Depth
Regional Average Well Depth
x	Aquifer Thickness
Field Depth
Regional Incidence x	Aquifer Thickness	(5-4)
Regional Average Well Depth
Operators have noted that, in fact, corrosion is
highly localized and related to the aquifer itself.
Furthermore, casing coatings, though more expensive than
cathodic protection systems used during the operating life
of the well, are sometimes employed.
147-
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The expected incidence of groundwater contamination
through well failure is the product of the expected failure
incidence and the probability of contamination given that
the well leaks. Disregarding differences in the corrosiveness
of geologic strata, the chances of a leak at any point
throughout the well's depth are equal. Whon a break occurs,
in an abandoned well the probability that an aquifer will be
polluted is roughly the fraction of the well length which
penetrates water-bearing strata.
The following example illustrates this estimation
procedur-a. Figure 5-6 depicts the Conroe field in Montgomery
County, Texas, with 727 wells and a reservoir depth of 5,200
feet. A survey of well data at the Texas Railroad Commission
shows that the average well depth in District III is 5,000
feet. Table 5-2 indicates an average failure incidence of
0.09 for tha area. Fresh water is found in the Evangeline
and Upper Jasper aquifers. Out of 5,200 feet of oil well,
1,400 feet penetrate fresh water. The primary water supply
is the Evangeline aquifer, which intersects the uppear 1,000
feet of the wells. Slightly saline to saline water is -found
in the lower part of the Jasper aquifer, and in 600 feet of
the section below 4,000 and above 6,000 feet. This make3
the total thickness of all water-bearing 3ands 4,000 feet
for a 5,200 foot well. Table 5-3 shows the estimated
contamination incidence for Conroe, and the implication for
all of District III, assuming these sections are represen-
tative. Equation 4 indicates that contamination incidence
depends only on the thickness of aquifers. Thermal methods
show a lower rate because the processes are limited to
shallow sands down to 3,000 feet. The estimated number of
incidences of groundwater contamination is calculated for
each process by multiplying the number of wells projected to
be involved by the incidence rates. This does not account
for the phased development of these projects over time. For
example, if micellar-polymer projects were conducted over a
20-year period, about three incidents of freshwater supply
contamination would be expected.
It is not possible to project this failure incidence to
other regions or to a national 3cale because data have not
been developed on the depths of all wells and the total
thicknes.. of the aquifers penetrated. Considerable risk
variation exists even among counties in the same district.
Local differences result from both natural and historical
characteristics. These aspects and the direct effect of the
tertiary recovery processes on risk are evaluated in the
following section.
-143-
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Sea Level
FEET
2 00
400
600
800
m
m
EVANGELINE AQUIFER

m
m
8URKEVILLE AQUICLU0E
«
m
1000
1200
m
•
UPPER PART OF
JASPER AQUIFER
a
1400
•

•
1600
m

m
1800
m

e
2000
2200
m
LOWER PART OF
JASPER AQUIFER
m
m
2400
m

«
2600
•

m
2800
•

m
3000
-

-
3200
.

m
3400
3600
•
•
CATAHOULA SAN0ST0NE
¦
3800
4000
•
•
JACKSON GROUP
m
4200
4400
4600
5200*
m
•
WATER 8EARING SAND
(SALINE)
-
111

*
200
400
600
800
1000
1200
1400
1600
1800
2000
2200
2400
2600
2800
3000
3200
3400
3600
3800
4000
4200
4400
4600
5200
Figure 5-6. This figure illustrates a cross section o£
a typical well in the Conroe Field# Montgomery County, Texas
(Railroad Commission# District III) showing the location and
thicknesses of the important aquifers and their relationship
to the oil bearing zone.
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TABLE 5-3
TERTIARY OIL RECOVERY
EXPECTATION OF POLLUTION INCIDENTS IN DISTRICT III, TEXASa



CONROE
MICELLAR THERMAL
C02

TYPICAL
DEPTHS
5,200'
5,000' 3,000'
(max.) (max.)
7,500

NUMBER OF WELLS
727
3,491 1,622
2,182
WATER QUALITY
DEPTH
INCIDENCE13 .
(Contamination Incidentp/well-year)

Fresh supply
1,000*
.018
14
63 29
39
All fresh
1,400'
.025
19
88 41
55
Fresh to
slightly saline
3,400*
.061
45
214
133

(3,000*
thermal)
(.054
thermal)

88
157
All water
4,000*

52
251


(3,000
thermal)
(.054
thermal)

—
—
aExpected number of incidents ¦ (number of wells) x incidence per year,
incidence calculated as (regional incidence) x	depth
For example, micellar fields incidence of contamination of fresh water
supplies = .09 x 000 = .018. The annual number of incidents is .018 x 3.491
5,000
wells = 63 incidents in micellar fields at full development.
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5.3 Analysis of Factors Affecting Risk
Risks of contamination of groundwater within a given
oil field are affected by the tertiary oil recovery process
chosen for the field, the ages of the wells drilled into or
through the formation in which the tertiary recovery will be
carried out, and the seismicity in the area.
Wells provide communication among strata by conducting
fluid along various paths in the wellbore, as shown in
Figure 5-2. Leaks can be caused by: (1) faulty casing
connections, (2) corrosion, (3) inadequate casing seal at
the shoe, (4) perforation at the wrong point, (5) fissures
in cement or casing caused by high pressure, (6) poor
cementing, and (7) earthquake damage.
Corrosion and pressure are the greatest problems. The
tertiary recovery method which is sele^ed may raise the
risk of groundwater contamination by fvirther increasing
pressure or corrosion rate. Table 5-4 lists some of the
typical operating conditions for recovery methods and compares
these conditions with operations during primary and secondary
recovery.
Increased pressure during injection of the tertiary
recovery fluids into the reservoir are unlikely to fracture
aquicludes or wellbore cement. As shown in Table 5-4, there
is a margin of safety between the operating pressures used
in tertiary recovery and a conservative estimate of the
hydraulic fracture strength cf the reservoir rock. The
safety factor ratio is smallest for the steam injection
reservoir and largest for carbon dioxide processes.
Brine disposal wells present problems for two reasons:
first, they are frequently old wells, converted to disposal
after a reservoir has been exhausted; secondly, pressure is
often used to inject brine. The pressure can fracture
aquicludes, allowing migration of brine into fresh water and
aquifers. To avoid this, bottom-hole pressure should be .
less than one pound per square inch per foot of well depth.
Pressure-induced fractures are usually horizontal in for-
mations as deep as 1,000 feet and are vertical below 1,500
feet.2 Fractures in formations deeper than 1,500 feet might
provide communication between strata.
A.G. Collins, "Oil and Gas Well3 - Potential Polluters
of the Environment," Journal of Water Pollution Control
(December 1971): 2390.
2Collins, Oil and Gas Wells," p. 2391.
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TABLE 5-4
TERTIARY OIL RECOVERY
MAXIMUM OPERATING CONDITIONS IN SOME TYPICAL PROCESSES
TERTIARY RECOVERS METHOD

MICELIAR-
PQLYMER
STEAM
COM-
BUSTION
CARBON
DIOXIDE
Assumptions: (Typical Project)




Reservoir Permeability
(millidarcies)
500
500
SCO
100
Spacing between Hells
(feet)
1000
500
1000
2000
Hell Depth (feet)
5000
3000
5000
8000
Initial Pressure (lb./in.2)
3500
1500
2500
4000
Maximum Pressure during.
Secondary Recovery4'®
(lb./in.*)
3500
1500
3000
4000b
Maximum Pressure during
Tortiary Recovery"
(lb./in.2)
3500
2500
4500
4000
Maximum Temperature during
Tertiary Recover:* (°F)
150
600
1200
200
Hydraulic Fracture Strength
of Reservoir Rockc
(lb./in.2)
5000+
3000+
5000+
8000+
Pressure Safety Factor:
/Hvdraulic Stren
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Some early steam injection projects "blew out," damaging
the formation and overburden or fracturing the cement and
rupturing or buckling the casings in injection wells. The
surface fittings broke on a carbon dioxide sulfide injection
well i:i Texas resulting in several deaths by poisoning.
The latter accident was caused by a part which failed at an
operating pressure below the 10,000 pounds- per square inch
for which it had been rated.
Though some pressure failures have occurred in the
past, they are very unlikely during tertiary recovery
operations. There is a margin of safety in the operating
pressures of the project and pressures will rarely exceed
the original pressure of the fluids confined in the oil-
bear in? strata. A high pressure is required to initiate
in-situ combustion, but it is only of brief duration.
Average operating pressures in a fireflood are 500 to 600
pounds per square inch.
Generally, chances of well failure from applying too
much pressure to the reservoir during tertiary recovery are
exploratory drilling. Drilling in a new geologic province
such as the Outer Continental Shelf, there is little know-
ledge of the geopressures that will be encountered. When
tertiary recovery is begun, a great deal of information is
available about the oil field. These data provide the basis
for sound engineering decisions in the design and operation
of tertiary oil recovery projects. The large front-end
investment required in tertiary recovery is an additional
incentive for monitoring and controlling operating pressures
of the project. In a micellaz-polymer flood, the expensive
chemicals in the slug could be lost to a fracture before any
additional oil had been recovered. Similar considerations
should raise operator awareness of chemical spills at the
surface during formulation and injection. The operator of a
carbon dioxide project or in-situ combustion project must
pay for every additional pound per square inch of injection
pressure used. Steam injection methods, applied at shallow
reservoir depths, still require caution to avoid fracturing
the overburden rocks. But problems with injection wells in
steam injection have largely been solved by improved cements
and completion methods, which compensate for the thermal
expansion of the casing.
Corrosion is more of a problem with some tertiary
recovery methods. The corrosion rate of steel well casing
is affected by the pH and conductivity of the fluids which
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contact it. Temperature also influences the rate of corrosion.
Considering the data on Table 5-4, the corrosiveness of the
recovery methods can be evaluated. Table 5-5 ranks the
relative corrosiveness of the tertiary recovery methods in
relation to primary and secondary recovery. The ranking is
based on the corrosiveness of the fluids which remain in the
reservoir after the recovery project is completed and on the
equilibrium temperature of the oil-bearing strata. Carbon,
dioxide processes and the thermal methods of tertiary oil
recovery are relatively more corrosive than micellar-polymer
flooding. The ranking is based upon the assumption that
process is the only variable. The actual effect of these
processes on corrosion of particular wells is dependent on
the completion practices# materials used in construction,
rock formations, and even the expertise of the operator.
Specific data on these factors in each region or field are
limited and an analysis of the interrelationships of these
variables is beyond the scope of this assessment.
For an initial appraisal of these factors, a method-
ology based on the ages of the reservoirs and number of
wells within the major oil fields where tertiary recovery is
feasible was developed as discussed in Appendix A. Table
5-6 displays the estimated age profile of wells which may be
involved in each tertiary recovery method within each region.
For example, the table shows that 75 percent of all oil
wells which may be involved in micallar-polyraer flooding in
the Pacific West Region are less than 35 years old. These
wells were completed with modern materials and practices
more oriented to safety and conservation. Generally, wells
or reservoirs that are older were completed in a less
sophisticated manner. The divisions of age into three
groupings mark distinct changes in the atate-of-the-art of
oil well drilling, completion and production, as well as
differences in the economic and regulatory climate affecting
the petroleum extraction industry.
It is not particularly surprising to note the skew
toward older ages in the age profile of thermal wells in
each region. Many of the shallow, low-gravity oil fields
were originally discovered by surface evidence and natural
seeps. Although most producing wells in these fields may
not date from the turn of the century since they can be
redrilled relatively cheaply, using the age profile as a
risk indicator is valid since failure of the old plugged and
abandoned wells is still possible.
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TABLE 5-5
TERTIARY OIL RECOVERY
RELATIVE CORROSIVENESS OP RECOVERY METHODS
Most Corrosive: Carbon Dioxide Miscible
In-situ Combustion
Steam Injection
Secondary Recovery Waterflood*
Least Corrosive: Miceliar-Polymer Flooding
Primary Recovery**
Assumes that a higher conductivity brine is used for
the waterflood. Actual corrosiveness will be affected by
local geochemical conditions within the oil reservoir and
penetrated formations.
v
Assumes that the brine from the oil-bearing strata
is of lower; conductivity than water used in waterflooding.
This is generally true for shallower reservoirs where
thermal methods and micellar-polymer floods are feasible.
Actual corrosivcsness will be affected by local geochemical
conditions encountered such as salt sections, high partial
pressure of naturally-occurring carbon dioxide in gas-
condensate produced, or the presence of hydrogen sulfide.
155-
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TABLE 5-6
TERTIARY OIL RECOVERY
FRACTION AND NUMBER OF WELLS IN MAJOR OIL FIELDS OF EACH REGION
WHERE TERTIARY RECOVERY IS FEASIBLE
TERTIARY
RECOVERY
METHOD
DATE
OF
WELLS
PACIFIC
ROCKIES
NORTH
CENTRAL
SOUTH
CENTRAL
SOUTH
EAST
NORTH
EAST
TOTAL

<1920
20% (512)
83% (1,656)'
21%
(2,580)
10%
(1.421)
56'.
(247)
NA
18t
(6,416)
Micellar
1921-1940
5% (1171
17% (350)
63%
(7,788)
88%
(12,222)
71%
(3,334)
NA
67%
(23,811)

>1941 .
75% (1,893)
NA
16%
(1,920)
2%
(258)
24%
(1.150)
NA
1S%
(5,221)

<1920
>6% (21,820)
100% (701)

NA
21%
(1,622)
94%
(8.S33)
.NA
68%
(32,676)
Thermal
1921-1946
20% (5,593)
NA
100%
(1,920)
79%
(6,090)
2%
(166)
NA
29%
(13,769)

>1941
4% (1,138)
NA

NA

NA
4%
(383)
NA
3%
(1.521)

<1920
20% (129)
21% (540)

NA
42%
(11,772)
62%
(8,886)
NA
42%
(20,727)
Carbon
Dioxide
1921-1940
14% (90)
79% (1,995)
98%
(5,227)
34%
(9,461)
31%
(4,067)
NA
42%
(20,840)

>1941
66% (414)
NA
16%
(53)
24%
(6,579)
7%
(912)
NA
16%
(7,958)
NA: tone yr data not available.
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Abandoned wells which have been inadequately plugged
are frequent sources of contamination at present. Once
production wells have ceased operation and have been plugged,
no one is concerned with keeping them in good condition.
Even when leaks are detected, sometimes no one can be held
responsible. The Texas Railroad Commission has about $100,000
allotted annually for replugging operations, but this sum is
hardly sufficient since it costs approximately $10,000 to
find and plug a single abandoned well. The problem of
leakage of old wells has hindered en.iar.ced recovery opera-
tions in parts of New York and Pennsylvania. Wells dating
from the late 1880's, were often crudely plugged with tree
saplings if they failed to reward the early "wildcatter"
sufficiently. Today, leakage from these old-time wells can
jeopardize the success of amy tertiary recovery project
which is otherwise potentially viable.
Most wells need casing repairs by the time they are 10
to 14 years old. In the Texas Upper Gulf Coast, for example,
such repairs were required at a rate of 0.09 repairs per
well per year, or about 11 years mean time between well
failures.1 Older wells are more likely to leak, both because
of general aging and corrosion and because earlier technolo-
gies of materials, completion, corrosion protection, and
plugging were less reliable.
5.4 Relative Regional Risk Levels
An analysis of the age profile of wells involved in
tertiary recovery yields a ranking of the relative *.isks of
well failure in each region. Tables 5-7, 5-8 and 5-9 present
the rankings. A number of factors which are complex and
interrelated have been excluded from the rankings for this
investigation. Local gcochemical conditions may affect well
failure rates. Failure incidence is also a function of the
depth of the wells involved in each recovery method in each
region. The well spacing and number of wells within an oil
field also affect the risks presented by each project. But
the data have not been developed on these variables.
Seismic activity can also cause damage to wells in a
tertiary recovery project, allowing reservoir fluids to
migrate into aquifers. Figure 5-7 is a seismic risk map of
^J.E. Kastrop, "Downhole Oil Well Maintenance Costs Push
Half Billion," Petroleum Engineer (July 1975): 22.
-157
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TABLE 5-7
TERTIARY OIL RECOVERY
RELATIVE REGIONAL RISK OF WELL FAILURE
FOR MICELLAR-POLYMER FLOODING8
(Excludes seismic risk and local
variations in geocheraical corrosiveness)
Most likely to fail: Rocky Mountain
South Central
North Central
South East
Least likely to fail: Pacific West
aNortheast Region not ranked due to lack of data but
is probably at a comparable risk level with the Rocky Mounuaj
Region.
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TABLE 5-8
TERTIARY OIL RECOVERY
RELATIVE REGIONAL RISK OF WELL FAILURE
FOR CARBON DIOXIDE MISCIBLE METHODS5
(Excludes seismic risk and local
variations in gecchemical corrosiveness)
Most likely to fail:
Least likely to fail:
Southeast
South Central
Rocky Mountain
North Cen'-ral
Pacific West
aNortheast Region not ranked due to lack of data, but
risk level is probably comparable to the South Central Region.
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TABLE 5-9
TERTIARY OIL RECOVERY
RELATIVE REGIONAL RISK OF WELL FAILURE
FOR THERMAL METHODS OF OIL RECOVERY*
(Excludes seismic risk and local
variations in geochemical corrosiveness)
Most likely to fail: Pacific West
Southeast
South Central
Least likely to fail: North Central
aNortheast and Rocky Mountain Regions not ranked due
to lack of data. Risks o£ well failure in the	Northeast
and Rocky Mountains are probably comparable to	the Pacific
West and Southeast Regions, respectively.
160-
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vw.
I
H*
CT*
M
I
fill
ZONE 0 - No Damage
ZONE 1 - Minor Damage
ZONE 2 - Moderate Damage
ZONE 3 - Major Q&jnaae
"TS
m
Figure 5-7. This figure is a seismic probability map of the United States.
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the United States. Earthquakes are virtually unknown in
District III# and throughout most of Texas. But in some
areas (e.g., Southern California) this risk is high and
tremors may contribute to a high localized well failure
rate. If localized well failure incidence is known, earth-
quakes may have contributed their share to that rate, and
need not be considered as a separate factor. Note that the
data of Table 5-2, however, give only an aggregate incidence
for the West Coast. The location of the oil fields and the
expected damage inflicted by an earthquake in each region
was examined. The relative regional risk of well damage due
to seismic activity is shown in Table 5-10.
TABLE 5-10
TERTIARY OIL RECOVERY
RELATIVE REGIONAL RISK OF WELL DAMAGE
DUE TO SEISMIC ACTIVITY
(Excludes improvements in well completion
technology to mitigate earthquate damage)
Most Severe Damage:
Minor Damage or
No Damage:
Pacific West
North Central
Rocky Mountain
Northeast
Southeast
Southcentral
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CHAPTER SIX
IMPACT OF TERTIARY OIL RECOVERY
ON AMBIENT AIR QUALITY
6.0 Introduction
Thermal methods of enhanced oil recovery could add as
much as 10 billion barrels to the Nation's recoverable'
reserves as discussed in Chapter Three. In-situ combustion
techniques are still undergoing field testing and are in an
early stage of development, but steam displacement projects
are being expanded on a commercial scale. The Energy Research
and Development Administration forecasts that nearly one-half
of the oil recovered bv advanced techniques through 1985
will be produced by st<.am injection. Since steam displacement
will play a major role in near-term enhanced recovery activity,
dispersion modeling of two "typical" sizes of projects was
carried out to evaluate their air quality impacts.
In-situ combustion projects were rot modeled because
of the following factors: (1) Uncontrolled emissions from
producing wells are released at ground level and would have
little, if any, vertical momentum vector. This would cause
the highest concentrations of pollutants to occur within
the oil field. (2) Chapter Two hypothesized the emissions
of SOx, NOx and hydrocarbons would be small on the average
and these expectations were supported by operator observa-
tions. These emissions may fluctuate over the duration of
the "burn" as operating conditions vary. With small discharge
quantities varying over time in a manner that is not fully
understood, little would be gained by carrying out extensive
dispersion modeling of these emissions. (3) A number of
the fireflood operations indicated that vapor recovery systems
to handle effluent gas and condense light hydrocarbon fractions
for sale had proven to be economically justified. Though the
scale economics of large vapor recovery systems may be less
favorable in fieldwide firefloods due to the need for extensive
gas gathering piping systems, there seemed to be little value
in simulating a situation that is less likely to occur given
the current practices in in-situ combustion projects.
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6.1 Summary
Two hypothetical cases, a \«:rge project and a small
project, were examined in three regions of the country in
which the largest resource potential amenable to thermal
oil recovery exists. These regions are: (1) the Central
Valley of California, (2) the Northern Rocky Mountains,
and (3) the Gulf Coast. Projects of two sizes were selected
to eucompass the range of projects which might be expected.
These projects are defined below. In each case, moderate
values of the operating conditions and meteorology were
assumed, so that the predicted air quality impact would not
be overstated by the computer-based dispersion modeling.
The following conclusions regarding impacts on National
Ambient Air Quality Standards are based upon an analysis of
the cases and are very much dependent upon the assumptions
used and the limits of the analysis which are discussed fully
in Section 6.5:
1.	The "typical1' small steam displacement project
in which steam generators burn approximately 1.23
percent sulfur fuel can be developed without
violating National Ambient Air Quality Standards.
2.	The "typical" large steam displacement project in
which the steam generators burn about 1 percent
sulfur fuel will violate the standard for 50-.
Crude oils in California oil fields which may
undergo thermal oil recovery average approximately
2.1 percent. Combustion of these fuels would
result in a situation worse than that represented
here.
3.	Existing fuel-burning rules in State Implementation
Plans covering parts of California and all of
Utah and Oklahoma are insufficient to insure
attainment of NAAQS for regions in which full
scale development of large oil fields by steam
displacement may occur.
4.	In order for a fully developed "typical" large
project to comply with standards for SO-» emis-
sions from steam generation would have to be
reduced to a level equivalent to burning approxi-
mately 0.57 percent sulfur fuel in current
designed units.
5.	NO„ emissions from the "typical" large projects
will not exceed standards.
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6.	Only trace amounts of hydrocarbons and CO
emissions from steam generators are expected
because of the large amount of excess air used
for combustion. A larger source of hydrocarbons
may be the fugitive emissions of steam released
at the producing wells. Control technologies for
these emissions are within the state-of-the-art.
This source and other possible point and area
sources of hydrocarbons from enhanced recovery
have not been characterized.
7.	A number of control technologies and strategies
are available to mitigate air quality impacts. An
analysis of the impact of these strategies on
regional air quality and the amount of oil which
can be economically recovered is necessary for the
development of sound environmental policy.
6.2 Methodology and Rationale
6.2.1 Description of Cases Modeled
Hypothetical steam displacement projects of two sizes
were developed for the analysis. These two cases were
selected to depict "typical" operations in the areas where"
thermal recovery is most likely to be carried out. Table
6-1 summarizes the assumptions and configurations for the
"typical" projects. The hypothetical cases are based u?on
actual oil reservoirs and forecasted development patterns.
However, the examples of existing projects are cited herein
to point out the technical validity and conservatism of the
assumptions. The results illustrate the magnitude of air
quality problems which may occur as a result of large-scale
thermal oil recovery and are not necessarily indicative of
air quality in the vicinity of the ongoing projects which
are mentioned.
For this analysis, the air quality impacts and levels
of control required to meet standards were determined by
examining the ambient air quality at and beyond the boundary
of the oil field. Concentrations of pollutants were two to
three times higher within the fields than outside the field
boundaries. The basis for excluding the oil field in deter-
mining the-maximum ambient air concentrations is that the
oil field may be considered an industrial site in most nonurban
-165-
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TABLE 6-1
THERMAL OIL RECOVERY "TYPICAL" OIL FIELDS
RESERVOIR DATA

PROJECT
LARGE
SIZE
SMALL
Area (acres)

5,760
200
Depth (feet)

1,003
1,500
Thickness (net) (feet)

100
75
Porosity

20%
25%
Permeability (Millidarcies)

1,000
500
Oil Gravity (Degree API)

12
14
Oil Saturation (Barrels per
Acre Foot)
1,500
1/300
Steam Disolacement Data



Oil Production (Gross):Fuel
Ratio3
3.5:1
2.95:1
Installed Capacity (Million
Btu/hr)
4,320
100
Recovery (% OIP)

40%
50%
Configuration 20 MM Btu/hr
units
36
—
50 MM Btu/hr
tir.it s
72
2
aDiscussed in text Sections 6»2-l^l and 6*2.2—Z.
-166-
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areas. These sites may be covered by OSHA regulation.
Tighter controls would be required to comply with NAAQS
within the boundaries of the large project. The "typical"
fields were oriented so that the shortest distance between
the generators and the boundary of the field is in the
direction of the highest predicted S02 ground concentration.
6.2.1.1 Large Project Case
California has the largest oil resource base amenable
to thermal oil recovery. Many of the oil reservoirs are
either massive or multiple lenticular sand bodies which
could result in a high density of steam generating units at
full development. This large-scale development may also
occur in Utah tar sands or in some older Gulf Coast area
oil fields.
The size of the large project was chosen from an
analysis of major oil fields in California corrected for
skew in the size distribution attributable to very large
fields (in excess of 13,000 acres). The data on the areal
size of California fields are shown in Table 6-2. Average
field size is 8,340 acres including the largest fields and
4,340 acres excluding all of the largest fields. Therefore,
a typical field of 5,760 acres of nine sections (640 acres
per section) was chosen with a 3-mile square (3 miles x 3
miles) configuration.
Steam generating capacity (for the large project) was
estimated in the following manner. A reservoir with an oil
saturation of 1,500 barrels per acre foot, a recovery
efficiency of 40 percent and other characteristics shown on
Table 6-1 requires steam input of 22,000 barrels of steam
per acre-foot of oil reservoir at an assumed peak injectivity
of 2,500 barrels steam per acre foot per year. This is the
equivalent of 9,815 Btu/hr of capacity per acre toot of
reservoir of 981,500 Btu's/hr of capacity per acre of oil
field. By comparison, the oil fields near Bakersfield,
California will have steam generator densities of 1,600,000
to 3,750,000 Btu/hr of capacity per acre of oil field at
planned full development or nearly four times the density
used in this study. Oil production is a net of two and one-
half barrels for each barrel crude oil burned in the steam
generators or a gross oil production to fuel ratio of 3.5:1.
^Personal communication with Getty Oil Company,
Bakersfield, California.
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TABLE 6-2
RECftL SIZE OF MAJOR C5HTRAL VftLLZY CftlXFQ3HXA OIL "ZELCS
FIELD SISS GRODP
FIELD
5XEB (Acres)
Less than 3,000 acres
Rio Bravo
(2,000)

McKittrick
(1,500)

Greely
(2,100)
3,000 to 7,000 acres
Kern. Front


lit. Peso
(3,500)

Lost Hi} Is
(3rJQC)

Edison
(6,600)

Fruitvale
(3,300)

Coalix.ga Noae
14,0001

Coles Levee North
(3,500}

Cymric
<3,300)
7,000 to 13,000 acres
Belridge
(9,200)

Kern River
(8,700)
Over 13#000 acres
Coalmga
(19.300)

Midway-Sunset
(24,900)

Kettleman Done
(13,700)

Elk Bills
(19,600)

Bueaa Vista
(16,300)
^J.S. Enviroiunental Protection Agency, The Estimated
Recovsrv Potential of Conventional Source Domestic Crude Oil,
Hay 1&75.	'
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In the large project, a factor o£ 70 percent was assigned
to the field to account for conditions which could tend to
limit operation in parts of the field such as shaled-out
reservoir or variations in sweep efficiency. Over the life
of a field, oil production will tend to decline and the
ratio of steam to oil produced will increase so that steam
generating capacity and output is assumed to remain constant
throughout the project.
6.2.1.2 "Small" Project Case
__ The second case represents smaller isolated oil fields
such as the domed or anticline structures amenable to thermal
oil recovery which are located throughout the Rockies.
Similar dispersed small-scale projects are also likely to
exist in oil fields elsewhere in the country. The density
of such projects would vary greatly by region.
The data shown on Table 6-1 are characteristic of ongoing
small projects. For example, Amoco operates a project at
Winkleman Dome in Fremont County, Wyoming which has boiler
capacity to process 4,180 barrels of water to approximately
111,000 barrels of steam per day.3- Assuming 1,000 psia and
80 percent quality steam is generated, 1,734 million Btu's
per day (289 barrels of oil at 6 million Btu's per barrel)
is required or 90 million Btu's per hour at 80 percent
efficiency. It is reasonable to assume that a stream factor
of 90 percent may be applied to the boilers so that 100
million Btu's per hour of installed capacity would be
required. This project produces about 850 barrels of oil
per day for each 289 barrels of fuel burned for an oil
production to fuel ratio of 2.95:1.
6.2.1.3 Development Patterns
In the large project case, it is assumed that the
density of boilers simultaneously in operation resulted from
a number of operators in the oil field independently arriving
at similar development decisions. It is recognized that the
-early phases of a steam displacement project involve empirical
application of the technology. Following pilot studies, a
few boilers are operated in project patterns and reservoir
response is determined. The data are evaluated and additional
steam generating capacity is added to the project patterns
if the economics of the expansion appear to be favorable.
Winkleman Dome Steam-Drive Project Expands," Oil and
Gas Journal, (October 21, 1974): 116.
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The locations of steam generating units were as follows
in the modeled projects. For the small project two 50
million Btu per hour boilers were located at the middle of
the field adjacent to each other. In the large project, two
50 million Btu per hour generators and a 20 million Btu per
hour generator were assumed to be located at the center of
each quarter section.
Actual development patterns of steam generators in a
particular field will depend upon the following: historical
precedent; terrain; location of existing roads, pipelines
and other facilities; shape of operator's lease or unitized
area; and the results of pilot scale development projects.
In addition, the location, of steam generators in large-scale
planned developments may be selected on the basis of a
trade-off analysis of heat losses, boiler costs, location of
water sources and other factors. Boiler sizes selected are
typical of those used in large-scale developments now under-
way at Kern River, South Belridge, Mt. Poso and elsewhere.
In these projects, 50 million Btu/hr units are the standard
unit of steam generating capacity. This size unit appears
to have become standard because of its high efficiency,
operating flexibility, and other factors. The presence of
20's in the large project case represents pilot scale
capacity which preceded full-scale development.
6.2.1.4 Geographic Locations
Meteorological conditions were selected to represent
the three regions of the country where most of the thermal
oil recovery will take place. The Central Valley of Cali-
fornia was characterized by weather data from B^kersfield,
California, supplemented with data from Los Vegas, Nevada.
The Northern Rockies were represented by meteorological data
from Lander, Wyoming. Meteorological data from Shreveport,
Louisiana was used to characterize the inland Gulf Coast
region.
6.2.2 Pollutant Emission Rates
The following discussion presents the pollutant emission
rates from steam generating units used in this assessment of
the air quality impacts and the boiler operating character-
istics upon which these rates are based.
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Data on the operating characteristics of the steam
generators for thermal displacement were obtained from dis-
cussions with staff engineers at the original equipment
manufacturers and at the oil companies currently operating
the units. The pollutant emission rates from the steam
generators were calculated from data from source sampling
reports submitted by several oil companies to state air
pollution control agencies and from design specifications of
the generators. The operating characteristics used for this
analysis are summarized in Table 6-3.
The operating characteristics used in the analysis are
representative of generators currently operating in rural
area oil fields. Almost all of the generating units burn
crude oil with a large amount of excess air. Residual
fuel oil is burned in other generators with the same
operating conditions. The units which are designed to
operate from 10 to 30 percent excess air generally operate
in the field at nearly 30 percent excess air.
The generators generally have a design efficiency of 88
percent and have both radiative and convective boiler tube
sections. The design steam output is 80 percent quality (80
percent vapor) steam at 2,000 psig and 1,045 Btu per pound.
The design flue gas temperature ranges from 350° to 400* F.
However, because particulates collect on boiler tubes, the
units operate in the field with flue gas temperatures between
400° to 600° F. The flue gas is generally released from a
"stub" directly above the convection section of the boiler.
Because of the large cross-sectional area of the stub, the
flue gas has a low exit velocity. The height of release of
the flue gas is only a. few meters above the ground. Stacks
can be added to the suh of the generating units.
The major pollutant emissions from the oilfield steam
generators are sulfur dioxide, nitrogen oxide, and particu-
lates. Hydrocarbons and carbon monoxide are emitted in
minor quantities. The pollutant emission rates assumed for
the study are summarized in Table 6-4.
6.2.2.1 Sulfur Dioxide
The sulfur dioxide emissions rate from the generators
is dependent on the sulfur content of the fuel. Crude oil
is used as fuel in most steam generators because little if
any natural, gas is produced or available for enhanced recovery
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TABLE 6-3
SUMMARY OF OILFIELD STEAM GENERATORS OPERATING CHARACTERISTICS
HE .T OUTPUT
(MM Btu/hr)
HEAT INPUT
(MM Btu/hr)
VENT HEIGHT
(M)
EQUIVALENT
STACK
DIAMETER
(M)
FLUE GAS
EXIT
(M/Sec)
STACK
TEMPERATURE
(C )
20
22.6
3.96
1.04
2.67
260
50
56.2
6.0
1.54
5.87
260
aGas Exit velocity based on firing with 30 percent excess air and fuel with a
heating value of 153,500 Btu per gallon.
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TABLE 6-4
SUMMARY OF EMISSION RATES FOR STEAM GENERATORS
STEAK GENERATOR
SIZE
HEAT INPUT
(barrels of SO2	NO;<
oil per day) (gm/sec) (gm/sec)
PARTICULATES HYDROCARBONS
(gm/sec)
(gm/sec)
CO
(gn/sec)
20 MM Btu/hr
22.6
2.98
1.33
0.22
,04
0.01
50 MM Btu/hr
56.2
7.37
3.29
1.10
,11
0.02
aThe emission rates calculated based on units combusting cil having one percent sulfur
and 153,500 Btu per gallon vith 30 percent excess air.
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operations. Furthermore, the logistics of distributing fuel
oils from the refinery back to the oil fields can be more
complicated and costly than drawing off a part of the crude
oil for use as fuel before celling the rest. In California,
the shallow reservoirs which are amenable to steam displace-
ment generally contain crude oil with a high sulfur content.
The sulfur content of low gravity crudes ranges from 0.25 to
6 percent, with an average sulfur content for all fields in
California of 2.1 percent. It is assumed that oil with a"1
percent sulfur content is characteristic of the fuel that
will be used in the typical large project in th» near future.
The sulfur content of the oil from typical small projects
was assumed to be 1.23 percent based upon the average sulfur
content in oils from Wyoming fields that appear to be
amenable to steam displacement.
6.2.2.2 Oxides of Nitrogen
The emission rate of nitrogen oxide is assumed as 3.0
pounds per barrel of oil burned. The data obtained from one
oil company gave an emission rate of 1.8 pounds of NO- per
barrel of fuel burned, rrom data on horizontally-fired
steam generators, an emission.rate of 3.0 pounds per barrel
appears to be more realistic. '
6.2.2.3 Particulates
The particulate emission rate which was observed by two
oil companies was 0.5 pounds per barrel of fuel.3 Thi3
value is used as the particulate emission rate for the
study. Several factors may affect particulate emissions
including trace matal content of the crude oil. Character-
ization of these emissions is beyond the scope of this work.
Process Research, Inc., Air Pollution from Fuel
Combustion in Stationary Sources, for the U.S. Environmental
tection Agency, Report No. EPA-R2-73-241, October 1972.
2
U.S. Environmental Protection Agency, Compilation of
Air Pollutant Emission Factors, AP-42, April 1973.	""
^Personal communication with Kern County Air Pollution
Control District, Bakersfield, California.
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6.2.2.4 Hydrocarbons
The emission rate of hydrocarbons from the oil-fired
steam generators is reported as 0.1 lbs/barrel of fuel in
source tests from one oil company.1 Fugitive emissions of
hydrocarbons from other point and area sources in oil
fields have not been characterized and are not included in
the analysis.
6.2.2.5 Carbon Monoxide
The carbon monoxide emission rate from steam generators
is approximately 0.02 lb/barrel.2 Even though the emission
rate is much lower than other similar types of oil-fired
generators, the estimate appears realistic because the oil-
field units use a large amount of excess air for combustion.
6.2.3 Modeling Procedure
The air quality impact of development of the "typical"
steam displacement projects is predicted using two EPA air
quality models: the Climatological Oisperson Model (COM)
and CRSTER. The CDM calculates the mean annual concentra-
tion from many point and/or area sources, while the CRSTER
models the 1-hour, 24-hour, aud annual concentration from a
single source. Both models use Briggs1 formulae to calculate
plume rise. The analysis assumes that the oil field and
surrounding territory is on flat terrain.
The maximum 3-hour concentration was calculated by
assuming the maximum one hour concentration persisted for
three hours. The maximum 24-hour concentration and the mean
annual concentration are calculated by the model. The
annual transport concentration of S02 is calculated by using
the CDM.	*
The increase in ambient air concentrations from the
"typical" small project was predicted by CRSTER using 1964
hour-by-hour surface observation, data and measured height
data for Lander, Wyoming.
^Chemecology Corporation, S<:eam Generator Testingt
Kern River, Bakersfield, Report Ho. 230, December 1974.
i
Chemecology Corporation, St-.eam Generator Testing,
December 1974.
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The assessment of the air quality impact of the "typical"
large project required two modeling approaches. A modular
approach is used to predict the maximum 3-hour and 24-hour
ambient air concentrations. The CRSTER calculated the SO2
and particulate ground level concentration from 0.3 to 4.3
Jan away from one group of generators. The day, direction
and location of the maximum 24-hour SO2 concentration outside
the field was determined for a group of generators nearest
to the oilfield boundary. The rows of the groups of the
generators were aligned in the direction of the maximum 24-
hour concentration. Total maximum 24-hour S02 concentration
from operation of all the generators in the field was calcu-
lated by summing contribution of all the groups of the
generators to the predicted site of maximum concentration
for the 24 hours.
The maximum 3-hour SO2 concentration from steam genera-
tors was calculated by assuming* that the conditions -that
caused the highest 1-hour concentration outside the field
persisted for three hours. The maximum 1-hour concentration
was determined using the procedure described for calculating
the maximum 24-hour concentration. The annual average con-
centration and the concentration at large distances from the
source were determined using a direct modeling approach.
The CDM predicted the mean annual SO2 and particulate con-
centrations for receptors located in telescoping grids.
6.3 Discussion of Results
6.3.1 Dispersion of Pollutants (Uncontrolled Case)
The results of the dispersion modeling are plotted on
maps to show the concentration isopleths of sulfur dioxide
at ground level in ambient air outside the oil field.
Figures 6-1 to 6-3 illustrate the isopleths from the large
project case burning 1 percent sulfur fuel under meteorologi-
cal conditions for three regions. Figures 6-4 to 6-7 show
the sulfur dioxide isopleths from CDM modeling of the small
project case. Figure 6-8 shows the results for CRSTER
modeling. Figures 6-9 and 6-10 illustrate the N0X isopleths
of the small project case.
Standard steam generating units have a low height of
emission release and low flue gas exit velocity. Because of
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Figure 6-1. This figure displays the Annual SO2 Isoplet-.hs
for Full Scale Development of a "Typical" Large Project for
Thermal Oil Recovery in Inland California. (Sulfur content in
fuel "1.0 percent; Meteorological Data: Bakersfield, CA;
Dispersion Model: CDM)
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-J- Oil Fields
Boundary
Figure 6-2. This figure displays the Annual S02 Isopleths for Full Scale
Development of a "Typical" Large Project for Thermal Oil Recovery located in the
Northern Rockies. (Sulfur content in fuel ¦» 1.0 percent; Meteorological
Conditions: Lander, NY; Dispersion Model: COM)
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N
26 yg/ra3
3.5 yg/m3
16 24 32km
Oil Field Border
Figure 6-3. This figure displays the Annual SO2 Isopleths
for Full Scale Development of a "Typical" Large Project for
Thermal Oil Recovery in the Inland Gulf Coast. (Sulfur content
in fuel » 1.0 percent; Meteorological Data: Shreveport, LA;
Disperson Model: CDM)
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0	1	2	3	4Jan
Oil Field
Boundary
Figure 6-4. This figure displays the Annual SO.
Isopleths for Thermal Oil Recovery for "Typical" Small
Project Field in Inland Calfornia. (Fuel Sulfur Content:
1.23 percent; Meteorological Data: Bakersfield, CA;
Dispersion Model: CDM)
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	 Oil Field
Boundary
Figure 6-5. This figure displays the Annual SO-
Isopleths for Thermal Oil Recovery for "Typical" Small
Project Field in the Inland Gulf Coast. (Fuel Sulfur
Content: 1.23 percent; Meteorological Data: Shreveport,
LA; Dispersion Model: CDM)
-181
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Oil Field
Boundary
Figure 6-6. This figure displays the Annual S02
Isopleths for Thermal Oil Recovery for "Typical" Small
Project Field in Northern Rockies. (Fuel Sulfur Content:
1.23 percent; Meteorological Data: Lander, WY; Dispersion
Model: CDM)
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Figure 6-7. This figure displays the Annual SO2 Iscoleths
for Pull Seal* Development of a "Typical" Small Project for
Thermal Oil Recovery in the Northern Rockies. (Fuel Sulfur
Content: 1.23 percent; Meteorological Data: Lander, WY:
Dispersion Model: CRSTER)
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N
12	3	4km
	 Oil Field Boundary
Figure 6-8. This figure displays the Annual NO
Isopleths for Thermal Oil Recovery in a "Typical"
Small Project Field in Inland California. (Fuel
Sulfur Content: 1.23 percent; Meteorological Data:
Bakersfiald, CA; Dispersion Model: CDM)
184-
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3	4km
¦«-	1
Oil Field
Boundary
Figure 6-9. This figure displays the Annual WO
Isopleths for Thermal Oil Recovery in a "Typical" Snail
Project Field in the Northern Rockies. (Fuel Sulfur
Content: 1.23 percent; Meteorological Data: Lander,
WY; Dispersion Model: CDM)
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Oil Field Boundary
Figure 6-10. This figure displays Annual NO Isopleths
for Thermal Oil Recovery in a "Typical" Small Project Field
in the Inland Gulf Coast. (Fuel in Sulfur Content: 1.23
percent; Meteorological Data: Shrevesport, LA; Dispersion
Models CEM)
186
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these characteristics, the maximum short*term ground concen-
tration occurs during neutral atmospheric stability and high
wind speed conditions at the boundary of the oil field and
during fumigation conditions caused by breaking up of ground
based inversions. The concentration rapidly decreases
further from the oil field but can be above 26.S micrograms
per cubic meter as far as 11 kilometers from the oil field
and 3.5 micrograms per cubic meter €6 kilometers fro.n the
project depending on local meteorological conditions.
The small thermal oil recovery project, was able to meet
air quality standards outside the oilfield boundary. However,
large projects exceeded the annual and 24-hour standards for
sulfur dioxide.
6.3.2 Smisslon Control to Meet National Ambient Air
Quality Standards
The analysis presents the level o£ emission control
required for two typical cases to meet the NAAQS. It
should be noted that the operation of thermal oil recovery
in an area may preclude the development of other energy
producing facilities.
The numerical limits for the National Ambient Air
Quality Standards are shown in Table 6-5. The predicted
increases in ambient air concentration of SO? and particu-
lates from the development of the two typical projects with
steora generators burning the 1 percent sulfur content crude
oil are compared to the standards. The amount of emission
reduction required is calculated as follows:
X„ _ Xa
% Reduction » -2-1	x 100	(6-1)
XP
where X equals the predicted increase in ambient air con-
centration of the pollutant and X equals the standard for
the pollutant. The sulfur contenc of the steam generators
fuel that v'ill enable the case to meet the ambient air
quality standards is calculated as ^follows:
xs
Ss - — X S	(6-2)
X	p
XP
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TABLE 6-5
EMISSION REDUCTION REQUIRED TO MEET NATIONAL AMBIENT AIR QUALITY STANDARDS FOR
FULL-SCALE DEVELOPMENT OF THERMAL RECOVERY FOR A "TYPICAL" LARGE FIELD IN INLAND CALIFORNIA
(Base Case is for % sulfur fuel, numbers in parenthesis assume steam generators must
meet a NSPS of 0.8 pounds of sulfur dioxide per MM Btu.)

MAXIMUM PREDICTED


POLLUTANT EMISSION
MAXIMUM
SULFUR

CONCENTRATION FROM
EPA AMBIENT AIR
REDUCTION TO MEET
CONTENT
IN FUEL
POLLUTANT
THE FIELD
QUALITY S1]
fANDARDS
REGULATION
TO MEET
STANDARD
STANDARD
(pg/m3)
(yrv/m-
*>
(Percent)
(Percent Weight)

Base Case NSPS


Base Case NSPS
Base Case NSPS
Sulfur Dioxide
Annual
140
(96)
80
43
(17)
0.57
(0.57)
24-Houra
460
(315)
365
21
(--)
0.79
( — )
3-Hour3
662
(452)
1,300
—
(-")
—
( — )
aThe 24-hour and 3-hour standards are not to be exceeded more than once a year.
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where S equals the sul£ur content of the £uel required to
meet the applicable air quality standard for the class and
Sp equals the assumed sulfur content o£ the oil burned in
tne generator without air pollution controls.
6.4 Regulations and Emission Controls Strategies
6.4.1 Present Source Regulation
The steam generators used in thermal oil recovery are
not required to meet New Source Performance Standards
(USPS). The largest oil field steam generator is 240 MM
Btu/hr, which is slightly less.than the minimum size (250 MM
Btu/hr) regulated by the NSPS.1, Furthermore, State Implemen-
tation Plans generally permit the use of high sulfur fuel
(2.0 percent or greater} in the fuel limitations for rural
areas in which most oil fields amenable to thermal recovery
are located. In urban areas, stricter fuel limitations are
imposed on the operators.
The NSPS for boilers in utility service is 0.80 pounds
of sulfur dioxide per million Btu's.2 As shown in Table 6-4,
the emission rates for 20 MM Btu and 50 MM Btu steam genera-
tors burning 1 percent sulfur fuel are approximately 1.17
pounds per million Btus. Therefore, if this NSPS were also
applied to oilfield steam generators, emissions would be
limited to the equivalent of about 0.68 percent sulfur fuel.
As shown on Table 6-5, such a performance standard would still
cause the annual NAAQS to be violated.
6.4.2 Emission Control Strategies
A number of control alternatives are available to the
operator of thermal oil recovery to meet National Ambient
Air Quality Standards in large oil fields where concentrated
development similar to the large project case modeled here
could occur. These strategies include: (1) installation of
taller stacks on each of the boilers to increases flue gas
exit velocity and height of emission release, (2) combining
140 CFR 60, Subpart D, 5 60.40.
240 CFR 60, Subpart D, 5 60.43(a)(1).
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emissions from several boilers into a single stack to
increase momentum flux of the plume and height of emission
release, (3) combustion of lower sulfur fuel to reduce total
SO, emissions, and (4) flue gas desulfurization to reduce
total SC>2 emissions with the possibility of also reheating
the exhaust gas to augment plume rise. These control
strategies may be employed individually or in combination to
enable the project to meet air quality standards. Each of
these control alternatives presents advantages and dis-
advantages in terms of economic, energy and environmental
impacts. The assessment of the impacts of these control
alternative®, requires site-specific analysis of the costs
and efficiency of extraction and the control systems which
is beyond cLe scope of this study.
6.5 Limits of Analysis
Assessment of the impact of individual projects for
thermal oil recovery on ambient air quality requires site-
specific analysis. The increase in ambient air concentra-
tion of pollutants in the vicinity of the field and the
dispersion of the emissions from a field into adjacent areas
will depend on terrain, local meteorology, and the operations,
the emission characteristics, and the distribution of the
steam generators in the field.
The assumptions and dispersion models were selected for
the analysis so that impact of thermal displacement oil
recovery on ambient air quality was not overstated. The
following factors were not included in this preliminary
assessment and could affect the air quality impacts of
thermal recovery.
6.5.1 Terrain
The "typical" projects are assumed to be on flat terrain.
A small increase in ground elevation in the vicinity of the
field can drastically increase the impact of the field on
local ambient air quality because the oilfield steam gener-
ators currently operated generally have low heights of
emission release (10.6 m or less) and low flue gas exit
velocities.
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6.5.2 Sulfur Content in Fuel
The impact of the SO2 emissions on ambient air quality
can be expected to be higher than predicted in the analysis
if the steam generators of present design continue to be
installed and operated. For example, the assumed SO2
emission rate for the "typical" large project is based on
fuel sulfur content of 1 percent, which is representative of
reservoirs currently being developed, whereas the average
sulfur content of crudes in all fields amenable to thermal
oil recovery in California is approximately 2 percent with a
maximum in excess of 6 percent. Present emission limitations
for rural areas in California would permit combustion of up
to 2 percent-, sulfur crude oil.
6.5.3 Development Pattern
The assumed uniform density and spacing of the gener-
ators in a large project, probably understates the impact of
the field on ambient air quality. Since the reservoir
characteristics are not uniform throughout a field, it may
be more realistic to assume that a number of generators may
be grouped in one location and/or may be placed near the
perimeter of a field. Such development patterns would
result in higher ambient air concentrations than predicted
in the analysis. Currently, several projects in California
have five to ten SO MM Btu/hr units groused for operation
and some are close to the boundary of the field.
6.5.4 Modeling
The EPA-developed gaussian models tend to overestimate
the plume rise under high wind speed conditions. The emis-
sions from steam generators have maximum impact on ambient
air quality when neutral atmospheric stability and high wind
speeds cause a small rise in the plume. Because the plume
is released close to the generator, during high wind speeds
an aerodynamic wake is formed around the generator. The
wake forces the plume toward the ground, causing much higher
ground concentrations than predicted by the gaussian disper-
sion models.
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6.5.5 Site Classification
Another issue in the assessment of the impact of thermal
displacement oil recovery on ambient air quality is whether
or not an oil field is considered an industrial site. Two
policies have been used by EPA to define the maximum ground
concentration from industrial sources. The first criterion
for calculating the maximum ambient air concentration from a
source*is to determine the highest concentration measured at
the boundary of the industrial property. The other criterion
for determining the maximum ambient air concentration from a
source is to measure or predict the maximum concentration
for any site which the population has reasonable access,
such as the road through private land.
The first criterion is difficult to apply to oil fields
because the site controlled by an oil company may not be
easily defined since surface rights and mineral rights may
belong- to different owners. In the large field in which
several oil companies operate the thermal displacement
projects, it is not clear if the first criterion is applied
at the boundary of the area owned by a specific oil company
or the boundary of all land owned or controlled by the oil
companies operating in a given oil field.
The second criterion will depend upon the specific
site. Although it is reasonable to assume that people may
have a free access to the large oil fields, it is unlikely
that people will use the fields for recreational purposes
for example. However, in some instances, houses and public
highways may be located within or traverse oil fields amenable
to thermal oil recovery such as oil fields located in the Los
Angeles Basin.
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CHAPTER SEVEN
POLICY RECOMMENDATIONS
7.1 Summary of Problem Areas
The focus of the study Is upon those potential environ-
mental problems which are unique to tertiary oil recovery as"
opposed to the environmental problems which have the same
types and incidence as in conventional petroleum extraction
operations. A comparative analysis of the industry's past
performance in environmental protection was not within the
scope of the effort. The potential impacts of tertiary oil
recovery are upon water quality, water supplies and air
quality as discussed below.
7.1.1 Water Supplies and Quality
Two potential causes of water quality deterioration
during tertiary oil recovery are most significant. These
causes are: <1) spills of chemicals as a result of trans-
portation and handling, and (2) improper disposal of chemically-
loaded produced brine to surface waters. Both of these
factors are difficult to mitigate by further regulation.
Operational tertiary recovery projects are likely to
pose few hazards to underground water supplies because
numerous physical and chemical processes such as adsorption,
partitioning, precipitation, dilution, entrapment, and bac-
terial or chemical degradation tend to reduce greatly the
concentration of chemicals from a leak or spill. At present,
among commonly-used materials, petroleum sulfonate surfactants
could have the most adverse impact on water supply quality.
However, these materials are susceptible to adsorption and
precipitation as much or more than any other chemical used.
New chemicals for use in tertiary oil recovery may have
fever adsorption tendencies and such developments should be
closely monitored by EPA.
Despite the fact that additional mechanisms associated
with well age tend to iacresse the chances of leaks, the
possibility of future impacts upon water supplies from
completed projects should be o£ the same small magnitude as
the risks from ongoing recovery projects. The mitigating
processes act upon contaminants in an aquifer.
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7.1.2 Air Quality
Widespread development of steam displacement projects
to recover low gravity crude oils in shallow reservoirs
could have a significant impact on air quality. The limits
on sulfur content in fuels set forth in many state implemen-
tation plans are not adequate to prevent ambient air quality
standards for sulfur dioxide from being exceeded. A variety
of control strategies are available which may make it possible
to keep air quality within the standards despite high-
density development of this thermal oil recovery technique.
However, the control strategy which is selected or required
may limit the development of this petroleum resource and
curtail the quantity of oil economically recoverable from
the oil field.
Air quality problems may also arise as a result of on-
site manufacture of petroleum sulfonates and due to fugitive
emissions of vaporous hydrocarbons at thermal oil recovery
projects and of hydrogen sulfide at miscible gas displace-
ment projects.
Emissions from many sources in tertiary oil recovery
project:? have not been adequately characterized. It is
important to consider reservoir characteristics and recovery
process variables in the development of emission factors and
the drafting of environmental policies to control undesirable
discharges.
7.2 Current Environmental Regulatory Framework
7.2.1 Water Pollution
EPA's present authority over tertiary oil recovery
operations is limited because o£ two provisions of the Safe
Drinking Water Act. First, the states have until December
1977 to submit programs for underground injection. Secondly,
Section 1421(b)(2) provides that regulations under this act
cannot interfere with or impede wells for oil and gas pro-
duction "unless such requirements are essential to assure
that underground socurces of drinking water will not be
endangered." However, there are still several areas, in
which EPA can exercise some authority or oversight. Section
1424 provides for interim regulation of underground injections
if an arc within a state is designated by the Administrator
as one in which no new underground injection well may be
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operated until the applicable underground injection control
program takes effect. A permit for the operation of such
wells may be issued by the Administrator. The criterion for
designating such an area is that only one aquifer is the
sole or principle drinking water source for the area and
whichr if contaminated, would create a significant hazard to
public health. For example, the Edwards aquifer may qualify
parts of South Texas under this section.
The Administrator also has the authority to issue
permits in designated areas for new injection wells. The
permit may require the use of such control measures as
necessary to assure that the operation of the well will not
contaminate the aquifer of the designated area in which the
well is located. This may not sound like a particularly
relevant provision because tertiary recovery is not often
carried out in "new wells," but a "new underground injection
well" is defined by the Act as one whose operation was not
approved by appropriate state and Federal agencies before
the date of the enactment of this title. Therefore, some of
the very c*ld wells may not have state or Federal permits,
and would qualify as "new wells."
Under Section 1424(e) operators might apply for Federal
finance assistance for projects in designated areas to
assure that the aquifer is not contaminated.
Complaints of well water contamination are filed with
various state regulatory commissions. For example, seven
complaints of groundwater pollution were filed with the
Texas Railroad Commission. If appropriate state action is
not forthcoming to deal with endangerment of health and a
contaminant is believed to be present, the Administrator may
take such actions under the Act as he may deem necessary to
protect health. In particular, the Administrator may apply
for a restraining order or temporary injunction against the
operator causing the contamination. Via Section 1431,
therefore, EPA can deal with any acute pollution situation
that may arise from tertiary recovery.
Though this provision is useful in dealing with contami-
nant_sources such as improper surface disposal of produced
brine and chemical spills, it is ineffective in mitigating
the impact of a polluted aquifer. As discussed in Chapter
Five, there can be a time lag between the polluting event
and appearance of the contaminant at a drinking water source.
An effective environmental policy must, therefore, anticipate
contaminant sources before the pollution of an aquifer
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occurs. For example, operators of tertiary oil recovery
projects could be required to investigate for old abandoned,
poorly plugged wells within the area of their project before
recovery operations can begin. Old wells which are found to
penetrate possible drinking water sources could then be
properly plugged before the project starts and the risks of
pollution would be minimized.
Finally, under Section 1445, EPA has the opportunity to
promulgate a wide variety of regulations for anyone who may
be subject to an applicable underground injection control
program or who may be subject to the permit requirement to
Section 1424. According to this section, EPA can require
such persons to maintain records, make reports, monitor and
provide information as the Administrator may reasonably
require by regulation to assist him in establishing regulations.
These requirements could be invoked in the event that a
voluntary program of information exchange to monitor the
types of materials under consideration for use in tertiary
oil recovery does not succeed.
This Section also has provisions for the confidentiality
of information collected if it would in any way divulge
trade secrets or secret processes making the legislation
particularly helpful if it is to be applied tr* petroleum
companies that may utilize proprietary tertiary recovery
processes or materials.
7.2.2 Air Pollution
It is unclear whether some enhanced recovery emissions
sources represent existing sources or a new source which
would be subject to New Source Performance Standards (NSPS).
It can be argued that some tertiary recovery sources represent
a modification to an existing source which is defined as a
new source in terms of New Source Performance Standards.
Sulfcnation unit.s present an ambiguous problem. Some sul-
fonation units are constructed as part of refineries and are
probably, therefore, covered by performance standards for
refineries. A sulfonation unit that is constructed as part
of a field operation, on the other hand., 13 probably not
covered by refinery performance standards. Similarly,
existing production wells which are subsequently utilized in
steam displacement or in-situ combustion projects lack clear
definition as type sources.
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The steam generators used in steam displacement are not
required to meet New Source Performance Standards. The
largest oilfield steam generator is 240 million Btu/hr, which
is slightly less than the minimum size (250 million Btu/hr)
source regulated by the USPS. The oil fields amenable to
thermal displacement in rural areas are generally permitted
to use of high sulfur content fuel (2.0 percent or greater)
according to the fuel limitations established by State
Implementation Plans.
Another issue in the assessment of the impact of thermal
displacement oil recovery on ambient air quality is whether
or not an oil field is considered an industrial site. Two
policies have been used by EPA to define the maximum ground
concentration from industrial sources. The first criterion
for calculating the maximum ambient air concentration from a
source is to determine the highest concentration measured at
the boundary of the industrial property. The other criterion
for determining the maximum ambient air concentration from a
source is to measure or predict the maximum concentration
for any site which the population has reasonable access to,
such as the road through private land.
The first criterion is difficult to apply to oil
fields because the site controlled by an oil company may not
be easily defined since surface rights and mineral rights
may belong to different owners. In the large field in
which several oil companies operate the thermal displacement
projectsi it is not clear if the first criterion is applied
at the boundary of the area owned by a specific oil company
or the boundary of all land owned or controlled by the oil
companies operating in a given oil field.
The second criterion will depend upon the specific
site. Although it is reasonable to assume that people may
have a free access to the large oil fields, it is unlikely
that people will use the fields for recreational purposes
for example. However, in some instances, houses and public
highways may be located within or traverse oil fields amenable
to thermal oil recovery.
Equitable development of steam displacement projects
in oil fields within a region is another issue which is
not addressed by present: environmental policy and regulations.
As discussed in the air quality impact analysis of a typical
large project, NAAQS fcr annual average concentrations of
sulfur dioxide are likejv to be exceeded before an oil
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reservoir or a number of closely-spaced similar reservoirs
can be fully developed. In the event that these resources
are controlled by a number of operators, it is possible
that the operator who first establishes steam displacement
projects using steam generators without emission controls
in a region can preempt development of projects by other
oil producers. Similarly, the development of other types
of energy facilities such as fossil fuel power plants
will also be preempted.
7.2.3 State Oil Production Codes
The report identifies at least five areas in which
state Codes impede tertiary recovery operations: (1) fluid
injection, (2) well spacing, (3) allowables, (4) unitization,
and (5) plugging. It would be useful to examine all the
state Codes applicable to tertiary recovery. This legal
survey would serve two useful purposes: (1) it would identify
variations in state Codes which encourage or exclude tertiary
recovery operations, and (2)it would point up inconsistencies
in state laws that could be changed by individual states if
they were aware of the loopholes or impediments presented to
tertiary recovery.
It might be useful to hold a conference of state regu-
latory agencies concerned with oil and gas regulations.
This conference would serve a wide variety of purposes. It
would provide an opportunity for the states to learn of the
projected future level of tertiary recovery operation to
enable them to gauge how sizable future operations within
their state may be. It will also provide a forum for EPA to
explain to state officials the potential environmental
risks that may be attributable to tertiary recovery operations.
Finally, it would provide EPA a forum to explain to state
officials steps that the states could take to ensure that
they have sufficient authority in the area of tertiary
recovery control.
7.3 Policy Recommendations
Additional research is required before specific regula-
tory measures, if any, can be identified. The involvement
of and communication with state and regional oil and gas
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agencies such as discussed above would be an effective means
of establishing regulations necessary to prevent possible
environmental damage due to tertiary oil recovery. The
forum described above will also be useful to identify areas
where new Federal legislation may be needed.
The most significant issue which requires concise
definition is a research program regarding environmental
issues in tertiary oil recovery. Unanswered questions
listed below under Research Needs regarding the possible
environmental impacts of the processes should be addressed
during the demonstration projects sponsored by the Energy
Research and Development Administration. The EPA should
obtain environmental data from such projects in sufficient
detail so that variations in compositions of the discharges
from tertiary oil recovery can be correlated with reservoir
characteristics and process variables. Current policy
should encourage research to characterize tertiary oil
recovery discharge streams and a review of the new types of
chemicals proposed for use in recovery processes in the
future.
To design the EPA research program for tertiary oil
recovery, it would be useful to convene a seminar of chemical
and petroleum industry firms, state regulatory commissions,
academic scientists in the relevant disciplines and other
Fedfcrai - mercies. The objectives of the seminar would be
numerous. Environmental research priorities could be re-
viewed and discussed perhaps using an EPA-proposed program
as working document. The seminar would provide important
channels of information and scientific interchange. EPA
could establish informal, voluntary data sources within the
industry in order to be apprised of the latest advances in
tertary oil recovery processes on a continuing basis. The
meeting would also enable EPA to explain its policy objec-
tives and the role of environmental research regarding
enhanced oil recovery to the petroleum industry and the
scientific community. Research areas to be considered in
the design of a comprehensive program are discussed in the
following section.
7.-4 Research Needs
This study has sought to identify the potential environ-
mental problems which,may result from tertiary recovery. In
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many areas data are either lacking or Incomplete with respect
to environmental questions. Many of the answers may be
sought by the Environmental Protection Agency Lhrough
monitoring and analysis cf field demonstration projects
conducted by the Energy Research and Development Administration.
To effectively accomplish this research, environmental
studies must be integrated into the ERDA demonstration
programs. These research needs are:
1.	Characterization of and emissions factors for
inorganic pollutants from in-situ combustion as
functions of process variables, reservoir para-
meters and oil characteristics.
2.	Characterization of and emissions factors for
organic pollutants (particularly photochemical
oxidants) from in-situ combustion as functions of
process variables, reservoir parameters and oil
characteristics.
3.	Identification and prioritization cf all point-and
area-sources of hydrocarbon emissions in ^ei-mal
oil recovery.
4.	Cost-benefit analyses of air quality concroi
strategies for thermal oil recovery projects
assessing the levels of co- .„ol attainable impact
on oil prices and oil reserves lost as a result of
the incremental costs associated with each strategy.
5.	Evaluation of field sulfonation processes for
manufacture of petroleum sulfonates to assess
environmental consequences and economic impact of
processes.
6.	Evaluation of environmental impact oi' processes
and chemicals used to treat oilfield production
emulsions from tertiary recovery.
7.	Case studies and modelling of regional groundwater
systems to assess the impact of well failure on
water supply quality. The Edwards formation in
Texas is recommended as one of the areas for
further study.
8.	Measurement of chemical concentrations in produced
water from each of the processes, especially
micellar-polymer flooding and in-situ combustion
as functions of process variables, reservoir
characteristics and oil composition.
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9. Assessment of the environmental impact of a change
in refinery loads to process and desulfurize a
greater proportion of low gravity crude oils
resulting frcm production by thermal methods.
10.	Quantification of the physical ar.d chemical
factors which may act upon leaks or spills of
tertiary oil recovery chemicals. Define limits .to
degradation processes which may act upon chemicals
used in tertiary recovery.
11.	Evaluation of the synergistic toxicity (plant and
animal) and carcinogenicity of petroleum sulfonates
and other materials.
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APPENDIX A
GLOSSARY
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API Gravity: The standard American Petroleum Institute
(API) metnod for specifying the density of crude oil.
It may be calculated from the following formula:
Deg API - 141.5/{Sp. gr. 60F)/ - 131.5.
Aquifer: A water-bearing layer o£ permeable rock, sand,
or gravel.
Barrel: A liquid volume measure equal to 42 U.S. gallons*
Biota: Animal and plant life; fauna and flora.
3rine: Water saturated with or containing a high concen-
tration of sodium chloride and other salts.
Btu: British thermal unit; the amount of heat needed to
raise the temperature of 1 pound of water 1*F at or near
39.2°F; a measure of energy.
Carcinogen: Substance which may induce cancer.
Cation: The positively charged particle in the solution of
an electrolyte which, under the influence of an electrical
potential, moves toward the cathode (negative electrode).
Centipoise: A unit of viscosity equal to 0.01 poise. A
poise equals 1 dyne-second per square centimeter. The
viscosity of water at 20°C is 1.005 centipoise.
Connate Water: Water that was laid down and entrapped with
sedimentary deposits, as distinguished from migratory waters
that have flowed into deposits after they were laid down.
Core: A sample of material taken from a well by means of a
hollow drilling bit. Cores are analyzed to determine their
water and oil content, porosity, permeability, e^c.
Created Fractures; Fractures induced by means of hydraulic
or mechanical pressure exerted on the formation.
Darcy: A unit of permeability. A porous medium has a
permeability of 1 darcy when a pressure of 1 atm on &
sample 1 cm long and 1 sq cm in cross section will force
a liquid of 1-cp viscosity through the sample at the rate
of 1 cu cm/sec.
Emulsion: A suspension of one finely divided liquid phase
in anotEer.
A-la^
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Firefloodinq: In-situ combustion.
Fop/ard Combustion; A thermal oil recovery process in
which air is injected, and ignition is obtained at the
wellbore in an injection well. Continued injectin of
air drives the combustion front toward producing wells.
Fracture: Any kind of discontinuity in a body of rock
if produced by mechanical failure, .whether by shear
stress or tensile stress. Fractures include faults,,
shears, joints, and planes of fracture cleavage.
Gas-Oil Ratio: The number of cubic feet of gas produced
with each barrel of oil.
In-situ Combustion: A process which heats oil in the
reservoir to increase its mobility by decreasing its
viscosity. Heat is applied by igniting the oil sar.d
or tar sand and keeping the combustion zone active by
the injection of air.
Interfacial Tension: The contractile force of an inter-
face between two phases.
Miscible: Able to mix together; refers to two or more
substances. Liquids that are not miscible separate into
layers according to their specific gravities; a substance
miscible with each of two immiscible liquids which is
used to reduce the interfacial tension between the two
immiscible liquids; in oil recovery, a substance miscible
with both oil and water.
Miscible Agent: Water is immiscible with oil, and
interfacial forces between phases lead to incomplete
displacement. Sometimes natural gas can be used as a
miscible agent; sometimes miscible agents are injected
as slugs, e.g., hydrocarbon gas enriched with LPG.
Miscible Displacement: Displacement of oil by a fluid
with which it is miscible. When such a fluid contacts
the oil, the two liquids dissolve each into the other
and form a single phase. There is no interface between
the fluids and hence there are no capillary forces
active.
Miscible Displacement Theory: The use of various sol-
vents to increase the flow of crude oil through reservoir
rock.
A-2
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Offset Well: A well drilled near the boundary of a
lease opposite a completed well on an adjacent lease.
Oil Saturation? The extent to which the voids in rocic
contain oil, usually expressed in percent related to
total void.
Oil Wet: See Wettability.
pHi A number that represents the negative logarithm,
base 10, of the hydrogen-ion activity of a solution.
pH < 7 for acid. pH > 7 for alkaline.
Permeability: Capacity for transmitting a fluid.
Degree of permeability depends upon the size and shape
of the pores and the size, shape and extent of the inter-
connections. The unit of permeability is the darcy.
Polymer: A very large molecule formed by the combina-
tion of many small molecules identical with each other.
Polysaccharide: A carbohydrate containing more than
two aldehyde or keto groups.
Pore Volume: The volume of void space in an oil reser-
voir which may contain petroleum, gas and/or brine.
Porosity: The volume of pore space expressed as a per-
centage of the total volume of the rock mass; measures
the absorbent capacity of the material or the volume
of liquid held by the pores.
Reserves: The amount of a mineral expected to be
recovered by present day methods and under present
economic conditions.
Reservoir: A discrete section of porous rock containing
an accumulation of oil or gas, either separately or as a
mixture.
Reservoir Fluids: Fluids contained within the reservoir
under conditions of reservoir pressure and temperatures;
because of this fact their characteristics are different
from the characteristics of the same fluids existing
under normal atmospheric conditions.
Res id al Oil: The -mount of liquid petroleum remaining
in tFu" formation at the end of a specified production
process.
A-3
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Secondary Recovery: Any method of augmenting the natural
energy of a petroleum reservoir to increase production
in the second stage of recovery.
Steamflooding: Steam displacement (or steam drive)
follows the same basic principle as the waterflood.
Steam under pressure is fed into special injection
wells, both to heat the oil in place and to drive it
to producing wells.
Sulfonates; A surfactant consisting of an organic chain
with an SO3H attached; used in oil recovery because
the polar SO3H end is attracted to water, while the or-
ganic end mixes with oil.
Surface Tension; The tension forces existing in the
extreme surface film of an exposed liquid surface due to
unbalanced cohesive forces within the body of the liquid.
Surfactant; A material which affects the interfacial
tension between two liquids. In oil recovery, surfactants
are used which reduce the interfacial tension between oil
and water. Each surfactant molecule has a polar end,
which is attracted to water, and an organic chain, which
is attracted to oil.
Sweep Efficiency: The ratio of the volume of rock con-
tacted by the displacing fluid to the total volume of
rock subject to invasion by the displacing fluid.
Thermal Recovery: A petroleum-recovery process that
utilizes heat to thin viscous oil in an underground
formation and allows it to flow more readily towards
producing wells.
Viscosity: The internal resistance offered by s. fluid
to flow. Attributable to the attractions between mole-
cules of a liquid, this phenomenon is a measure of the
combined effects of adhesion and cohesion to the effects
of suspended particles and to the liquid environment.
Waterflooding: A secondary-recovery operation in which
water is injected into a petroleum reservoir to create
a water drive to increase production.
Wettability: (As applied to petroleum reservoirs) the
relative affinity of the coexisting oil and water phases
to adhere to the surface of a rock. If the rock is pre-
dominantly in contact with water, it is said to be
A-4
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preferentially water-wet. Similarly, if the rock is pre-
dominantly covered with oil, it is referred to as oil-wet.
Wetting: The adhesion of a liquid to the surface of a
solid.
Wetting Agent: A substance or composition which, when
added to a liquid, increases the spreading of the liquid
on a surface or the penetration of the liquid into a
material.
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APPENDIX
METHODOLOGY AND RATIONALE
B.1 Estimation of Water Usage (Table 2-4)
The following data on Table B-l were the assumptions
used as a basis for the calculations. Derived data ire
presented at the bottom of the table.
B.2 Chapter Two — Fate of Sulfur Compounds and Nitrogen
Compounds Created During In-Situ Combustion
The theoretical basis for assuming that all of the
sulfur compounds will appear dissolved in the reservoir
water and produce water is as follows:
Most sulfur will be present as elemental (Sx), pyritic
(FeS) or high molecular weight organics in the residual or
coking fractions of the crude oil. Small amounts of sulfur
(e.g., thiophene, C~HcS) will distill ahead of the firefront,
but will probably condense and be produced in the liquid
stream (Boiling Point 84.1°C.). In the combustion process,
elemental and pyritic sulfur will burn to form sulfur
dioxide and organics will pyrolyze. Since not all the
oxygen is consumed in the formation, oxygen is available
ahead of the burning region for further oxidation of sulfur
and sulfur dioxide. Water solubility of sulfur dioxide is
low at high temperatures and low pH. However, oxidation of
sulfur dioxide in aerated water is rapid in the presence
of ferric ions (Fe+3).
Air oxidation of sulfur dioxide is very complex. The
reaction is thermodynamically favored, but is very slow in
the absence of a catalyst. Within the oil reservoir,
several catalysts may be present. Coke will be like
activated carbon and siliceous sandstones may offer active
sites. Ferric ion or vanadium may act as catalysts in
aerated water. In addition, the distance between injection
and producing wells of 400 feet or more provides sufficient
mixing length to produce sulfuric acid. This conclusion is
supported by the low pH values for produced waters in
firefloods which may be attributed to the production of
sulfuric acid in the formation.
B-l
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TABLE B-l
ASSUMED OIL AND MICELLAR FLOOD CHARACTERISTICS
FOR ESTIMATION OF WATER OSAGE
TYPE HZCROEMULSION
OIL EXTERNAL
HATER EXTERNAL
WATER QUALXTV
HIGH
LOW
81GH
LOW
Oil Saturation
(initial)
301
30«
30%
30%
Recovery %
50*
40%
50%
40%
Water in Micellar
Solution®
50%
50%
90%
90%
Preflush (PV)
o.o5-o;i
0.01-0.2
0.03-0.5
0.5-1.0
Micellar Solution
(PV)
o:03-0.08
0.03-0.08
0.10-0.25
0.10-0.25
Mobility Buffer
(PV)
0.4-0.6
0.4-0.6
0.4-0.6
0.4-0.6
Drive Hater (PV)
0.5-0.6
0.5-0.6
0.5-0.6
0.5-0.6
Calculations:




Oil Recovery (BBL)
per (PV)
0.15
0.12
0.15
0.12
Hater Usage
(per BBL oil
covered)




Preflush:
Slug:
Buffer:
Drive:
0.33-0.67
0.1 - 0.27
2.7 - 4.0
3.3 - 4.0
0.8 - 1.7
0.12 - 0.3
3.3 - 5.0
4.2 - 5.0
2.0 - 3.3
0.6 - 1.5
2.6 - 4.0
3.3 - 4.0
3.3 - 6.7
0.75- 2.0
3.3 - 5.0
4.2 - 5.0
Total
6.5 - 9
8.5 - 12
3.5 - 13
11.5 - 19
aOthar stages of- flood are assumed to be approximately all water.
B-2
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Similarly, oxides of nitrogen, which are probably
produced in much smaller quantities at typical in-situ
combustion temperatures of 700-1,200°F, may be converted
to nitric acid in the formation. These are some situations
in fireflooding which, require further study. The composition
of the emissions may change as the firefront approaches the
producing well due to a decreased mixing length and other
factors. Operation of a fireflood ht non-optimum conditions
may also alter the produced gas stream. In particular,
since air injection is expensive, operation of a "lean"
fireflood could produce more sulfur dioxide. Conversely,
operation of a "rich" flood might result in larger output
of nitrogen compounds.
B.3 Identification of Technically Feasible Projects
Project sites for the various tertiary oil recovery
processes were identified by Energy Resources and Core
Laboratories through an appraisal of the suitability of
reservoir and oil characteristics in more than 800 discrete
reservoirs in 381 major oil fields in the on-shore contiguous
United States. In some instances, especially in Texas,
Oklahoma and Kansas, insufficient data were available to
assess definitively the technical feasibility of tertiary
oil recovery in the reservoir. However, the review of
discrete reservoirs often revealed possibility for several
methods of tertiary oil recovery within the same field. For
each field, data were considered on water composition (if
available), average porosity, average permeability, depth,
lithology, drive mechanism, temperature gradient, oil
viscosity, permeability variation, presence of fractures,
and past production history. Few rigid limitations were
placed on the assessment. Surfactants and polymers were
assumed stable up to 200°F and raicellar-polymer flooding was
considered effective on oils with a viscosity less than 10
centipoise. Steam processes were considered feasible at
depths up to 3,000 feet; in-situ combustion, 5,200 feet.
Carbon dioxide injection was considered infeasible in oil
reservoirs shallower than 6,500 feet. Generally, sandstone
reservoirs were the type considered as feasible with the
exception of oolitic limestone formations. Other factors
were weighed on a case-by-case basis.
Throughout the assessment, the economics of individual
fields were set aside. Factors are recognized such as
B-3
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development/drilling pattern in existence, size of reservoir,
oil saturation, reservoir thickness, availability of raw
materials that will influence the size and economic feasibility
of any tertiary recovery project undertaken in the field.
The location and timing of actual tertiary oil recovery
projects will depend upon the interaction of political,
technical, economic and environmental factors.
Revision, updating or estimating of the production
potential from tertiary oil recovery through consideration
of the possible interactions of these factors was beyond the
scope of this study as defined. In order to estimate regional
potentials for tertiary oil recovery, available estimates of
the national production potential were allocated among the
technically feasible projects. The technical assessment
occasionally revealed that more than one recovery technique
might be feasible in a given reservoir within a field. In
such cases, both types of projects were counted. For each
recovery process, the number of projects within the region
was tabulated. The massive nature of the shallow reservoirs
in California'which are amenable to thermal methods required
favorable weighting of these projects by a factor of 10 in
order to reach reasonable agreement with Bureau of Mines
estimates of potential oil recovery there. The national
estimates were then allocated proportionally to the regions
based on the number of reasible projects identified. Given
the other sources of variation in the amount of oil eventually
produced by tertiary methods the approach is useful. One
problem which does occur is an understatement of the potential
for the Rocky Mountain region. This problem arises because
of the lack of suitable "giant" oil fields in the region,
insufficient reservoir data and a large number of small or
"near giant" fields in the area which might be feasible for
tertiary recovery but were not evaluated.
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