OVERVIEW OF EXPLORATION AND PRODUCTION

WASTE VOLUMES AND WASTE MANAGEMENT PRACTICES

IN THE UNITED STATES

Based on

API Survey of Onshore and Coastal Exploration and

Production Operations for 1995

and

API Survey of Natural Gas Processing Plants for 1995

Prepared for:

The American Petroleum Institute

Prepared by:

ICF Consulting

May 2000
i

TABLE OF CONTENTS

Table of Contents ..................................................................................................................................... i

List of Tables .......................................................................................................................................... iii

Executive Summary.................................................................................................................................1

1. Introduction.........................................................................................................................................4

1.1. Overview of Survey Methodology ...............................................................................................5

1.2.Estimated Production Facilities, 1995 Production, Active Wells, and Other Supplemental Data....5

2. Survey Results: Production Pits, Tanks, Land Treatment Operations, and Produced Water.................7

2.1.Production Pits............................................................................................................................7

2.1.1. E&P Operations - Pits.....................................................................................................7

2.1.2. Gas Plants - Pits..............................................................................................................7

2.2.Tank Batteries and Total Tanks...................................................................................................8

2.2.1. Tanks and Tank Batteries – E&P Operations ...................................................................8

2.2.2. Non-pressurized Tanks – Gas Plants...............................................................................9

2.3.Landspreading/Land Treatment Operations............................................................................... 10

2.4.Produced Water........................................................................................................................ 10

2.4.1. Estimated Volume of Produced Water – E&P Operations.............................................. 10

2.4.2. Produced Water Disposal – E&P Operations................................................................. 11

2.4.3. Produced Water – Gas Processing Plants..................................................................... 12

3. Survey Results: Associated Wastes, Gas Dehydration/Sweetening Wastes, Drilling Wastes, and

Waste Management Practices ......................................................................................................... 14

3.1.Associated Wastes and Waste Management............................................................................. 14

3.1.1. Types of Associated Wastes......................................................................................... 14

3.1.2. Estimated Volume of Associated Wastes – 1995 E&P Operations Survey...................... 15

3.1.3. Associated Waste Disposal........................................................................................... 16

3.2. Gas Processing Plant Wastes and Waste Management ........................................................... 19

3.2.1. Types of Gas Processing Plant Wastes......................................................................... 19

3.2.2. Gas Processing Plant Waste Disposal Methods and Estimated Volumes of Waste........ 19

3.3.Drilling and Drilling Waste Management .................................................................................... 21

3.3.1. Drilling Techniques ....................................................................................................... 21

3.3.2. Percentage of Drilling Wastes by Base Drilling Fluid ..................................................... 21

3.3.3. Volume of Drilling Wastes............................................................................................. 22

3.3.4. Types of Drilling Wastes and Drilling Waste Disposal...................................................... 23

4. Summary of Results.......................................................................................................................... 27

References ........................................................................................................................................... 29
ii

Appendix A 1995 Production Facilities and Oil and Gas Production....................................................... 30

A.1. Estimated Oil and Gas Production Facilities............................................................................. 30

Appendix B Production Pits, Tank Batteries, Tanks............................................................................... 32

Appendix C Produced Water................................................................................................................. 40

Appendix D Associated Wastes ............................................................................................................ 42

Appendix E Drilling Wastes................................................................................................................... 48

Appendix F Gas Processing Plants: Produced Water and Associated Wastes..................................... 56

Appendix G Survey Methodology ......................................................................................................... 62

G.1. Survey Forms ......................................................................................................................... 62

G.2. Design of Survey Sample........................................................................................................ 62

G.2.1. 1995 E&P Operations Survey excluding Appalachia....................................................... 62

G.2.2. 1995 E&P Operations Survey – Appalachian States....................................................... 63

G.2.3. 1995 Natural Gas Processing Plant Survey.................................................................... 64

G.3. Survey Data Analysis.............................................................................................................. 65

G.3.1. Survey Data Extrapolation ............................................................................................. 65

Appendix H Survey Form - API Survey of Onshore and Coastal Exploration and Production Operations

for 1995........................................................................................................................................... 74

Appendix I Survey Form - API Survey of Natural Gas Processing Plants for 1995 ................................ 91
iii

LIST OF TABLES

Table ES.1. 1995 Estimated Volume of Oil and Gas E&P Wastes Disposed by Method (million barrels)..1

Table 1.1. Comparison of U.S. Exploration and Production Activity, 1985 and 1995 ................................5

Table 2.1. Gas Processing Plants – Pits...................................................................................................8

Table 2.2. National Estimate of Total Tank Batteries and Tanks Associated with E&P Operations ..........9

Table 2.3. Estimate of Total Non-Pressurized Tanks Associated with Gas Plants...................................10

Table 2.4. 1995 Produced Water Disposal Method – Reported Data ......................................................11

Table 2.5. Comparison of 1985 and 1995 Produced Water Disposal Methods .......................................12

Table 2.6. Gas Plants, Produced Water Volume – Reported Data and Estimated Volumes ....................13

Table 2.7. Gas Plants; Produced Water Disposal Method – Reported Data............................................13

Table 3.1. Summary of Total Estimated Associated Wastes from 1985 Production Waste Survey

 (barrels)........................................................................................................................................15

Table 3.2. 1995 E&P Operations Survey – Total Estimated Volume of Associated Wastes....................15

Table 3.3. Estimated Associated Waste Disposal Practices for the Total U.S.; Total Associated Waste

Stream – 1995 E&P Operations Survey .........................................................................................17

Table 3.4. Estimated Volume of Associated Wastes by Disposal Techniques From 1985 Production

Waste Survey ................................................................................................................................17

Table 3.5. Estimated Volumes of Associated Wastes by Disposal Method; Completion Fluids and

Workover Fluids, 1995 E&P Operations Survey.............................................................................18

Table 3.6. Estimated Volumes of Associated Wastes by Disposal Method; Tank Bottoms/Oily Sludge

 and Dehydration Wastes, 1995 E&P Operations Survey................................................................18

Table 3.7. Gas Processing Plant Wastes – Estimated Volumes (extrapolated on gas throughput) .........20

Table 3.8. Gas Processing Plants; Estimated Volume of Wastes by Disposal Method ...........................20

Table 3.9. Estimated Total Volume of Drilling Wastes............................................................................23

Table 3.10. Summary of Estimated Drilling Wastes by Type of Waste From 1995 E&P Operations Survey

(barrels).........................................................................................................................................24

Table 3.11. Summary of Estimated Drilling Wastes by Type of Waste From 1985 Production Waste

Survey (barrels) .............................................................................................................................24

Table 3.12. Estimated Drilling Waste Disposal Practices - 1995 E&P Operations Survey......................25

Table 3.13. Comparison of 1985 and 1995 Estimated Drilling Waste Disposal Practices .......................26

Table 5.1. 1995 Estimated Volume of E&P Wastes Disposed by Method (million barrels).......................28

Table A.1. 1995 Producing Wells and Estimated Production Facilities by State .....................................30

Table A.2. Total 1995 Oil, Gas, and Natural Gas Liquids Production by State........................................32

Table B.1. Production Pits – Reported Data .........................................................................................33

Table B.2. Estimated Number of Production Pits ..................................................................................34

Table B.3. Oil Tank Batteries and Oil Tanks – Reported Data ...............................................................35

Table B.4. Condensate Tank Batteries and Condensate Tanks – Reported Data...................................36

Table B.5. Estimated Oil Tank Batteries and Total Tanks Associated With Oil Production Facilities .....37
iv

Table B.6. Estimated Condensate Tank Batteries and Total Tanks Associated with Gas Production

Facilities ........................................................................................................................................38

Table B.7. Gas Plants, Non-Pressurized Tanks – Reported Data ...........................................................39

Table C.1. Estimated Volume of Produced Water by State (1,000 barrels/year).....................................40

Table C.2. Produced Water Volumes Disposed by Method – Reported Data (Barrels/day and

Percentages) .................................................................................................................................41

Table D.1. Associated Waste Volume by State – Reported Data (Barrels per year) ..............................42

Table D.2. Estimated Volume of Associated Wastes by State (Barrels/Year).........................................43

Table D.3. Volume of Completion Fluids and Workover/Stimulation Fluids by Disposal Method

 – Reported Data ...........................................................................................................................44

Table D.4. Volume of Tank Bottoms/Oily Sludge and Dehydration/Sweetening Wastes by Disposal

Method – Reported Data................................................................................................................45

Table D.5. Total Associated Waste; Percentage Waste Disposed by Method – Reported Data..............46

Table D.6. Total Associated Waste; Volume of Waste Disposed by Method – Reported Data

(Barrels per Year) ..........................................................................................................................47

Table E.1. Percentage of New Wells Drilled by Technique - Reported Data...........................................48

Table E.2. Percentage of Drilling Wastes by Base Drilling Fluid – Reported Data ...................................49

Table E.3. Estimated Percentage of Drilling Wastes by Base Drilling Fluid ............................................50

Table E.4. Appalachian States, Volumes of Drilling Wastes – Reported Data .......................................51

Table E.5. Alternative Estimation of Total Drilling Waste for Appalachian States and Other States with

Significant Air Drilling .....................................................................................................................51

Table E.6. Liquid Drilling Waste Disposal- Reported Data (as % of Total Drilling Wastes)......................52

Table E.7. Solid Drilling Waste Disposal- Reported Data (As % of Total Drilling Wastes)........................53

Table E.8. Estimated Volume of Liquid Drilling Wastes Disposed by Method; Estimated for States with

Reported Data (Barrels) ................................................................................................................54

Table E.9. Estimated Volume of Solid Drilling Wastes Disposed by Method; Estimated for States with

Reported Data (Barrels).................................................................................................................55

Table F.1. Gas Plants: Produced Water Disposal by Method and Region – Reported Data (Barrels/day

and Percentages)...........................................................................................................................56

Table F.2. Gas Plants: Disposal of Glycol Wastes by Method and Region – Reported Data..................57

Table F.3. Gas Plants: Disposal of Used Filters/Filter Media by Method and Region – Reported Data ..58

Table F.4. Gas Plants: Disposal of Scrubber Liquids/Sludge by Method and Region – Reported Data..59

Table F.5. Gas Plants: Disposal of Other Dehydration/Sweetening Wastes by Method and Region –

Reported Data ...............................................................................................................................60

Table F.6. Gas Processing Plant Wastes – Reported Data.....................................................................61

Table F.7. Gas Processing Plants; Reported Volume of Wastes Disposed by Method ...........................61

Table G.1. Operations Survey Sample Design - Basin/State Categories................................................63

Table G.2. Operations Survey Sample Design - No. of Large and Small Companies in Sample by

Basin/State Category .....................................................................................................................63

Table G.3. Appalachian State Respondents ..........................................................................................64

Table G.4. Gas Plants Survey - Regions and Sample Size.....................................................................65
v

Table G.5. E&P Operations Survey Sample Design Total 1994 Production (Mboe) in Basin/State

Combinations.................................................................................................................................68

Table G.6. E&P Operations Survey Design – Number of Survey Respondents by State, Company Size,

and by Basin/State Combination ....................................................................................................69

Table G.7. Gas Plants Survey Sample Design – Range in Gas Plant Capacity and Throughput

(mmcfd) for Survey Sample Strata .................................................................................................71

Table G.8. Survey Response by State ..................................................................................................73
1

EXECUTIVE SUMMARY

During 1996, the American Petroleum Institute (API) conducted a survey of onshore oil and gas

exploration and production (E&P) operations and natural gas processing plant operations for the year 1995.

The survey sought data on current waste volumes and waste management practices, produced water

management, and drilling practices. The 1995 survey was designed to update a similar survey of

producers’ waste management practices that was published by API in 1987, and was based on data for

1985. This report provides an evaluation of the results of the 1995 survey pertaining to E&P waste volumes

and waste management practices. The survey covers the three primary categories of wastes produced by

the oil and gas exploration and production industry:

• Produced water – the saline water brought to the surface with oil and gas;

• Drilling waste – the rock cuttings and fluids that are produced from drilling a new wellbore into

the subsurface; and

• Associated wastes – a broad category of a variety of small volume waste streams that

encompasses all other types of wastes “associated” with oil and natural gas production.

The total volume of wastes generated annually by the oil and gas industry has decreased

substantially over the past decade. In 1995, the onshore oil and gas E&P industry generated an estimated

17,900 million barrels of produced water, 149 million barrels of drilling wastes, and 20.5 million barrels of

associated wastes. In addition, natural gas processing contributed an estimated 9.5 million barrels of

produced water and 0.10 million barrels of dehydration wastes. A decade earlier, in 1985, the E&P industry

generated 21,000 million barrels of produced water, 361 million barrels of drilling wastes, and 12 million

barrels of associated wastes.1 The decreased volume of wastes generated by E&P operations in 1995 is

consistent with the general decline in E&P industry activity between 1985 and 1995 (lower oil production,

fewer producing wells, fewer new wells drilled) which affects the two largest waste streams – produced

water and drilling wastes.

Table ES-1 summarizes the total estimated volumes of E&P wastes disposed in 1995 by waste

disposal method. Because E&P wastes are predominately liquid wastes, over 90 percent of E&P wastes are

injected. Another 2 percent of E&P wastes are reused or reclaimed. A brief discussion of the 1995 results

for each category of E&P waste follows in Table ES-1.

Table ES.1. 1995 Estimated Volume of Oil and Gas E&P Wastes Disposed by Method

(million barrels)

Disposal Method

Produced

Water1

Drilling

Wastes

Associated

Wastes2

Total Waste

Volume

% Disposed

by Method

Injection (includes EOR3) 16,386.5 19.3 7.9 16,413.7 90.7 %

Evaporation 0 69.9 2.3 72.2 0.4 %

Burial Onsite 0 31.2 0 31.2 0.2 %

Commercial E&P Waste

Facility 90.3 3.0 3.1 96.4 0.5 %

Reuse, Recycle, Reclaim 358.1 10.4 3.9 372.4 2.1 %

Discharge 537.0 1.5 0 538.5 3.0 %

Land Spread 0 10.4 1.0 11.4

Road Spread 1.8 0b 0.5 2.3 >0.1 %

All Other 537.0 3.0 1.9 541.9 3.0 %

Total 17,910.7 148.7 20.6 18,080.0 100.0 %

1

 Includes produced water removed at gas plants.

2

 Includes wastes from gas processing plants.

3

 Enhanced oil recovery

 

1

 The 1985 survey excluded completion fluids from the associated wastes volume, while the 1995 survey includes these

wastes in the total volume of associated wastes.
2

Produced Water. In 1995, E&P operations produced an estimated 17,900 million barrels of water,

of which 92 percent was injected. Seventy-one percent of the total volume of produced water was injected

for enhanced oil recovery (EOR) in 1995. Another 21 percent of produced water was disposed in Class II

injection wells.2 In 1985, 62 percent of produced water was injected for EOR and 30 percent was disposed

in Class II injection wells. An estimated 6 percent of produced water was discharged under NPDES permits

in 1985. By 1995, only 3 percent of produced water was discharged, with almost all of the discharged

volume from coalbed methane operations. In 1995, 2 percent of the total volume of produced water was put

to beneficial use and 3 percent was disposed by various “other” disposal methods such as percolation pits,

onsite evaporation, and public water treatment works.

Drilling Wastes. The total volume of drilling wastes estimated in 1995 was based on the calculation

of waste volume per foot varied by well depth that was developed during the 1985 survey, and subsequently

confirmed by later analyses. Consequently, the volume of drilling wastes estimated for 1995 is consistent

with the 1985 estimate, adjusted for the substantial decline in drilling activity. Nonetheless, other

improvements in drilling practice between 1985 and 1995 are indicated by the 1995 E&P operations survey.

 By 1995, 69 percent of reserve pits were lined, up from 35 percent lined in 1985. Moreover, an estimated

25 percent of new wells were drilled with a closed mud system and did not require reserve pits. An

estimated 92 percent of onshore drilling wastes in the most recent survey were derived from freshwater

based mud systems, compared to 64 percent of drilling wastes in 1985. In 1995, 68 percent of drilling

wastes were disposed onsite through evaporation and burial, compared to 41 percent in 1985. Disposal by

surface discharge and landspreading decreased from an estimated 17 percent of drilling wastes in 1985 to 8

percent in 1995. 

Associated Wastes. Associated wastes represent only about 0.11 percent of E&P wastes estimated

nationwide. Although, the estimated volume of associated wastes increased from 1985 to 1995, this may be

attributed to general characteristics of the survey (inclusion of certain waste streams and exclusion of other

waste streams), as well as industry trends toward better tracking and reporting of E&P wastes. A key factor

in the difference is the exclusion of completion fluid volumes from the 1985 survey to avoid potential double

counting of those wastes with produced water (with which they are typically co-mingled). The 1995 survey

explicitly addressed completion fluid volumes so that they could be included. In addition, a marked increase

in the volume of workover/stimulation wastes (from operators’ attempts to keep older wells operating

profitably) likely contributed to the increase in associated wastes. In 1995, an estimated 89 percent of

associated wastes were aqueous fluid. The remaining 11 percent of associated wastes consist of oily solids

and glycol-based wastes from dehydration. In 1995, the estimated volume of tank bottoms and oily sludge

declined by 21 percent, from 2.5 million barrels in 1985 to less than 2 million barrels in 1995. Over 68

percent of associated wastes were disposed by a combination of injection into Class II wells, evaporation,

re-use and reclamation. Disposal by surface discharge and land/road spreading dropped from 24 percent in

1985 to less than 8 percent in 1995.

Natural Gas Processing Plants Natural gas processing plants contribute only a small fraction of

E&P wastes, and were not covered by the 1985 waste survey. Gas plants managed an estimated 10 million

barrels of produced water in 1995, 93 percent of which were disposed by injection into Class II wells. In

1995, gas plants produced 0.1 million barrels of associated wastes, an average of 167 barrels of waste per

plant. Seventy-nine percent of gas processing plant wastes consist of scrubber liquids and sludge, 3 percent

consist of glycol compounds and used filter media, and the remaining 18 percent consist of miscellaneous

other waste streams. Seventy-six percent of gas processing plant wastes were disposed by injection and

13 percent were disposed at commercial E&P waste facilities and industrial or municipal disposal facilities.

The results of API’s 1995 E&P operations survey demonstrate increased use of improved drilling

practices and improved waste management practices.3 The survey results suggest a trend towards overall

reduction of oily tank bottoms and sludges, glycol dehydration wastes, and drilling wastes from operations

 

2

 Class II injection wells are those associated with the oil and gas industry, using a numbering scheme described in the Safe

Drinking Water Act.

3

 For more information about how advanced exploration and production technologies are producing waste reductions and

other environmental benefits, see “Environmental Benefits of Advanced Oil and Gas Exploration and Production Technology,”

issued by the U.S. Department of Energy, Office of Fossil Energy, 1999.
3

using oil based mud. Over 90 percent of E&P wastes continue to be disposed by injection, and

underground injection continues to offer the best method to safely and efficiently dispose of liquid E&P

wastes.
4

1. INTRODUCTION

Exploring for and producing oil and natural gas results in the production of substantial volumes of

wastes, the largest portion of which is naturally occurring material removed from the subsurface. Because

exploration and production in the United States takes place at nearly 900,000 separate sites across the

country, no mechanism exists for tabulating the total volume of wastes produced and managed by the

industry. Nevertheless, it is important to the industry to understand its waste volumes and how they are

managed. In the past, the American Petroleum Institute (API) has used statistical surveys of industry

operations to estimate waste volumes and characterize management practices. The oil and gas industry’s

wastes are characterized in three primary categories:

• Produced water – the saline water brought to the surface with oil and gas;

• Drilling waste – the rock cuttings and fluids that are produced from drilling a new wellbore into the

subsurface; and

• Associated wastes – a broad category of a variety of small volume waste streams that encompasses

all other types of wastes “associated” with oil and natural gas production.

In the fall of 1995, API conducted a survey of onshore oil and gas exploration and production (E&P)

operations and natural gas processing plant operations. The survey collected data on current waste

volumes and waste management practices, field equipment and facilities, produced water management,

and drilling practices.4 The purpose of the survey was to update current understanding of waste

management practices in the oil and gas exploration and production industry. The last comprehensive

survey of industry waste management practices was API’s 1985 Production Waste Survey. During the

decade between 1985 and 1995, substantial changes occurred in the U.S. oil and gas industry as illustrated

in Table 1.1. In 1995, API determined that an update of the 1985 waste management survey was needed to

understand how waste management had changed in response to the other changes in the industry. The

management and disposal of oil and gas exploration and production wastes continues to be an important

concern to states, industry, and the public. The survey results presented here demonstrate how the industry

has responded to internal and external concerns about waste management, as well as highlighting some of

the challenges that can be undertaken to further enhance protection of human health and the environment. 

Section 2 of this report discusses survey results pertaining to production pits, tanks, land treatment

operations, and produced water. Section 3 discusses survey results pertaining to associated wastes, drilling

practices, drilling wastes and waste management. Section 4 provides a summary of the survey results.

Appendix G provides a discussion of the survey methodology including design of the survey forms, design

of the survey sample, and methodology for extrapolation of reported data. A brief summary of the survey

methodology is provided below. Throughout the report, the 1995 survey results are compared to API’s 1985

Production Waste Survey wherever possible.

 

4

 The survey form was modified just prior to mailing to include some questions related to equipment such as engines, turbines,

and boilers. These data were collected to provide input to a data collection effort by the U.S. Environmental Protection

Agency for some specific air emission control related rulemakings. The data collected were provided to EPA on an

aggregated basis. The focus of this report, like the primary focus of the survey, is on wastes, and thus the other data

collected are not reported here.
5

Table 1.1. Comparison of U.S. Exploration and Production Activity, 1985 and 1995

1985 1995

Percent

Change

Total U.S. Crude Oil Production 3,274.6 million barrels 2,394.3 million barrels -27%

Total U.S. Natural Gas Production 17.2 trillion cubic feet 19.5 trillion cubic feet +13%

Total U.S. Natural Gas Liquids Prod. 753 million barrels 791 million barrels +5%

Total U.S. Production 7,093.6 MMboec

6,661.2 MMboec-6%

Producing Oil Wellsa

642,408 oil wells 569,508 oil wells -11%

Stripper Oil Wellsb

452,543 stripper oil wells 434,422 stripper oil wells -4%

Producing Gas & Condensate Wells 243,344 gas wells 298,541 gas wells +23%

New Wells Completed 71,108 wells 21,695 wells -69%

Total Footage Drilled 316,778,000 feet 117,886,366 feet -63%

a Federal offshore wells are not included.

b

Stripper wells are a subset of total producing oil wells, and includes those wells that produce 10 barrels of oil per day

or less.

c

 Million barrels of oil equivalent – converts natural gas to oil equivalent based on heating values.

Source: API, Basic Petroleum Data Book, January 1999, Volume XIX, Number 1: Tables III-2, III-10, III-12, III-14, III15; Table IV-4; Table XIII-3, XIII-9.

1.1. Overview of Survey Methodology

Two forms were developed for API’s 1995 survey: API Survey of Onshore and Coastal Exploration

and Production Operations for 1995 and API Survey of Natural Gas Processing Plants for 1995. The

onshore operations survey form is included as Appendix H and the gas processing plant survey form is

included as Appendix I. A detailed discussion of survey methodology is included as Appendix G.

The operations survey form was designed to focus on all the facilities operated by an E&P company

within a single field. An E&P company selected for the survey was asked to complete one survey form per

selected field. Participating companies were selected for the survey sample from databases maintained by

Petroleum Information (PI) Corporation. For a given geological basin/state/company size combination, a

company’s probability of being included in the sample was proportional to its 1994 production in the

basin/state combination. The PI database that served as a sampling frame for the 1995 Onshore and

Coastal E&P Operations survey did not contain production information for the Appalachian states. For these

states, API contacted the Oil and Gas Associations of each state and asked for a list of member companies.

API sent survey forms to a selection of the member companies and asked the companies to complete the

forms for any two of their fields in the designated state.

All of the responses received for a state were aggregated. The total responses received for each

state were used to generate a single extrapolation factor for the state, such as number of tanks per oil

production facility or volume of completion fluids generated per well completion. Reported data from the

operations survey were extrapolated on production, estimated number of production facilities, or number of

wells, as appropriate to the survey question under consideration. Similarly, reported data from the gas

plants survey were extrapolated on gas throughput or number of gas plants as appropriate.

1.2. Estimated Production Facilities, 1995 Production, Active Wells, and Other

Supplemental Data

Appendix A contains two tables which summarize the supplemental data used in this report to

estimate total state values for various elements of the operations survey – waste volumes, produced water

volumes, waste management practices, drilling practices, and production facilities. Appendix A, Table 1 lists

the 1995 producing wells and estimated number of production facilities for each state. Appendix A, Table 2
6

provides 1995 oil, gas, and natural gas liquids production by state.5 The bases for extrapolation for all the

survey elements discussed in this report are the following:

• Production Pits – extrapolated on the estimated number of 1995 production facilities;

supplemented by state estimates and reported data

• Oil Tank Batteries – estimated to be equivalent to the number of oil production facilities

• Condensate Tank Batteries – extrapolated on the number of active gas wells.6 Extrapolation

factor determined from survey data.

• Total Tanks – extrapolated on the estimated number of tank batteries

• Produced Water Volume – extrapolated on 1995 oil and gas production; supplemented by

state estimates, reported data and estimates from Petroleum Information

• Associated Wastes: Completion Fluids – extrapolated on 1995 completed wells

• Associated Wastes: Workover/Stimulation Fluids – extrapolated on 1995 active wells

• Associated Wastes: Tank Bottoms/Oil Sludge – extrapolated on 1995 production

• Associated Wastes: Dehydration/Sweetening Wastes – extrapolated on 1995 gas production

• Drilling Wastes – extrapolated on 1995 footage drilled using drilling waste extrapolation

factors identified in API’s 1985 Production Waste Survey

For the gas processing plant survey, the following survey elements were extrapolated to regional and

nationwide values:

• Production Pits – extrapolated on number of gas plants in a region provided by the Oil and

Gas Journal (OGJ), Gas Processing Survey.

• Non-pressurized tanks – extrapolated on number of gas plants in a region

• Produced water – extrapolated on total gas throughput for a region provided by the OGJ, Gas

Processing Survey

• Dehydration wastes – extrapolated on gas throughput.

 

5

 A consulting engineer with over 30 years of experience in the industry estimated the number of production facilities in each

state. He based his estimates on data from PI, as well as prior analyses, engineering relationships, and professional

experience.

6

 Although the total number of oil tank batteries is estimated as the number of oil production facilities, this estimation cannot be

used for condensate tank batteries because condensate is not always associated with gas production. If all condensate tank

batteries are estimated as the number of gas production facilities, the result is an unreasonably large number of condensate

tank batteries and associated tanks. As an alternative, the number of condensate tank batteries is estimated using a national

extrapolation factor of six gas wells per tank battery determined from the reported data.
7

2. SURVEY RESULTS: PRODUCTION PITS, TANKS, LAND TREATMENT

OPERATIONS, AND PRODUCED WATER

2.1. Production Pits

2.1.1. E&P Operations - Pits

Production pits include all types of pits operated except those associated with drilling operations. 

Examples of production pits include evaporation, blowdown, produced water, percolation, workover, and

emergency pits. These types of pits are used when needed to enhance the safety or efficiency of field

operations. Active pits are defined as pits currently in service as part of field operations, whether or not they

contain fluids. Inactive pits are pits that are no longer part of the field operating system but have not been

closed. Reported data on production pits are presented in Appendix B, Table 1. Survey respondents

reported a total of 2,444 production pits of which 97 percent are active and 59 percent are lined. Several

states have encouraged operators to close production pits and phase out the use of many types of pits in

E&P operations. Louisiana has ordered the closure of pits in many areas of the state since 1986. Texas

and Oklahoma report a very small number of pits relative to the size of the E&P industry in these states and

none of the respondents from Appalachian states report production pits.

Appendix B, Table 2 shows estimated total production pits extrapolated based on the number of

production facilities. (The estimated number of oil and gas production facilities for each state is shown in

Appendix A, Table 1.) For selected states, the numbers of pits estimated in Table B.2 are based on data

collected by state regulatory agencies. These state data were used to represent certain states because they

are believed to be more accurate than the estimates extrapolated from the survey responses. Generally,

one production pit is assumed per oil production facility. If survey respondents for a given state reported

production pits associated with gas production, then one production pit was assumed for each gas

production facility as well. No production pits were extrapolated for states that did not report pits for the E&P

operations survey. Due to relatively low survey response rates on this question, the extrapolated number of

pits for individual states is highly uncertain. The estimated total numbers of pits from Table B.2 are best

interpreted as an estimate of the potential order of magnitude of production pits in an individual state.

Nationwide, an estimated 55,000 pits are associated with production operations. Based on the survey data

reported in Table B.1, 97 percent of the 55,000 estimated pits are assumed to be active pits and 60 percent

are assumed to be lined pits.

2.1.2. Gas Plants - Pits

Gas plant pits include all types of pits operated at the plant except small collection sumps. The pits

included are identical to many types of production pits for E&P operations, namely: evaporation, blowdown,

produced water, and emergency pits. Table 2.1 summarizes the reported numbers of gas plant production

pits as well as the extrapolated number of gas plant pits. Survey respondents reported a total of 78 pits of

which 97 percent are active and 62 percent are lined. The estimated number of pits was extrapolated on the

number of gas plants in a region. No pits were estimated for regions that did not report pits for the survey. 

Approximately 875 gas plant pits are estimated to be associated with gas processing plants. The total of gas

plant pits plus production pits from E&P operations are estimated to be about 56,000 pits nationwide.
8

Table 2.1. Gas Processing Plants – Pits

Reported Data from Survey

Region

# Plants

in

Regiona

Number

of Pits

Operated

Number

of Active

Pits

Number of

Inactive

Pits

% Active

Pits with

Liners

Estimated

Number of

Active Pitsb

Alaska 3 11 11 0 45% 11

California 25 0 0 0 0 0

Eastern U.S. 47 0 0 0 0 0

Mid-West 92 0 0 0 0 0

New Mexico 27 8 8 0 63% 43

Rockies 104 14 14 0 64% 208

Southeast 68 4 4 0 0% 18

Texas 233 41 39 2 72% 606

Total 599 78 76 2 62% 875

a

Based on 1996 OGJ Survey.

b

Extrapolated based on number of plants.

2.2. Tank Batteries and Total Tanks

2.2.1. Tanks and Tank Batteries – E&P Operations

Survey respondents were asked to report either tank batteries on individual leases, or the number

of central or primary separation facilities in unitized fields where storage tanks are present. Produced water

injection facilities and produced water disposal facilities are not included in the count of tank batteries/central

facilities. Survey respondents were also asked to report the numbers and types of tanks at the tank

batteries. The E&P operations survey forms sent to operators in the Appalachian states asked only for the

number of tanks in operation and did not ask for an estimate of tank batteries or central facilities.

Appendix B, Table 3 summarizes the reported data for oil tank batteries, oil tanks and other tanks

associated with oil production. Appendix B, Table 4 summarizes the reported data for condensate tank

batteries, condensate tanks, and other tanks associated with gas production. Table B.3 indicates that the

typical oil tank battery contains two oil tanks, one produced water tank, and an emergency tank and/or

“waste” tank. For condensate tank batteries, the data reported in Table B.4 suggest that the typical

condensate tank battery contains one condensate tank, one or two produced water tanks, and may include

an emergency or “waste” tank.7 Combining the reported data from Tables B.3 and B.4, suggests that the

typical tank battery services five to six wells and is comprised of four tanks: two oil or condensate tanks, one

produced water tank, and one emergency tank or waste oil/water tank.

Because no survey data were collected on tank batteries for Appalachian operations, it cannot be

determined whether the reported components of a typical tank battery represent Appalachian operations.

The combined data from Tables B.3 and B.4 for Appalachian operations suggests that the ratio of product

tanks to produced water tanks for Appalachian operations is 1:2 (i.e., one oil or condensate tank to two

produced water tanks). Also, only about one-third of oil or condensate tanks in Appalachian operations

appear to be associated with either a waste tank or emergency tank.

Estimated total numbers of tank batteries and tanks associated with E&P operations for individual

states were extrapolated from the reported data. Appendix B, Table 5 summarizes the estimated oil tank

 

7

 Reported data for condensate tank batteries includes some responses for Arkansas and Kansas that report very large

numbers of produced water tanks per tank battery. Although these responses are outliers compared to the other reported

data, they are not necessarily invalid responses. If the outlying responses are removed from the reported data, the typical

condensate tank battery appears to include only two to three tanks: one condensate tank, one produced water tank, and

possibly a waste or emergency tank.
9

batteries associated with oil production and Appendix B, Table 6 summarizes the estimated condensate

tank batteries associated with gas production. The number of oil tank batteries was estimated as the

number of oil production facilities (as illustrated in Appendix A). The number of condensate tank batteries

was estimated by applying the ratio of six gas wells per tank battery to the number of active gas wells. The

number of tank batteries estimated for each state was then multiplied by the average number of tanks per

tank battery determined for that state from the survey responses received for the state (shown in Tables B.3

and B.4). If a state had no survey data, a national average of four tanks per oil tank battery or two tanks per

condensate tank battery was assumed.8

Table 2.2. summarizes the national estimate of tank batteries and tanks associated with E&P

operations. A typical ratio of oil or condensate tanks, produced water and “other” tanks can be determined

from the survey data in Appendix Tables B.3 and B.4. If these ratios are applied to the estimated total

number of tanks in Table 2.2, the total number of oil tanks is estimated to be approximately 627,500 and the

total number of condensate tanks is estimated to be 204,300. Therefore, the estimated total number of tanks

associated with E&P operations (oil tanks plus condensate tanks) is approximately 831,800 tanks. About 75

percent of these tanks are estimated to be associated with oil production operations. The remaining 25

percent are estimated to be associated with gas production operations.

Table 2.2. National Estimate of Total Tank Batteries and Tanks

 Associated with E&P Operations

Estimated Oil

Tank

Batteries

Associated

Tanks (Oil

Production)

Estimated

Condensate

Tank

Batteries

Associated

Tanks (Gas/

Condensate

Production)

Total Tanks (oil

plus

gas/condensate

production)

All States Excluding

Appalachian Region 144,100 517,800 27,800 109,600 627,400

Appalachian Region Only 27,400 109,700 20,500 94,700 204,400

Estimated National Total

(includes Appalachian

Region)

171,500 627,500 48,300 204,300 831,800

2.2.2. Non-pressurized Tanks – Gas Plants

The number of tanks reported includes all non-pressurized tanks used at the plant for storage of

produced water, condensate, and liquid products and all tanks used for emergency conditions. Table 2.3

shows the estimated number of tanks associated with gas plants. The reported data for gas plant tanks is

summarized in Appendix B, Table 7. Nationwide, gas plants are estimated to have about five associated

non-pressurized tanks. The typical gas plant has approximately two liquid product tanks per plant, one

condensate tank, and one or two produced water tanks. About 40 percent of plants are estimated to have

an emergency tank. Table 2.3 also indicates the regional variation from the national estimate. For example,

the New Mexico region is estimated to have about six to seven tanks per gas plant. A typical gas plant in

New Mexico is estimated to have three liquid product tanks, two condensate tanks, and one emergency

tank. About 60 percent of New Mexico plants are estimated to have a produced water tank as well.

 

8

 Alternate estimates of total tanks for the Appalachian states were obtained by applying a survey-derived ratio of six oil wells

per tank to a state’s total active oil wells and 1.3 gas wells per tank to a state’s total active gas wells. The alternate estimates

for the Appalachian states are included in Appendix Tables B.5 and B.6. The alternate estimate of tanks associated with oil

production appears to be quite low and is not included in Table 2.2. The alternate estimate of tanks associated with

condensate production is reasonably close to the estimate obtained from applying the method used for non-Appalachian

states. The alternate estimate of tanks associated with condensate production is included in Table 2.2 because this estimate

incorporates survey reported data for the Appalachian region.
10

Table 2.3. Estimate of Total Non-Pressurized Tanks Associated with Gas Plants

Region

# Plants

in

Regiona

Estimated

Number of

Produced

Water

Tanksb

Estimated

Number of

Condensate

Tanksb

Estimated

Number of

Liquid

Product

Tanksb

Estimated

Number of

Emergency

Tanksb

Estimated

Total NonPressurized

Tanksb

Alaska 3 0 0 18 1 19

California 25 no data no data no data no data 0

Eastern U.S. 47 20 94 275 27 416

Mid-West 92 153 123 92 0 368

New Mexico 27 16 54 81 22 173

Rockies 104 134 149 401 89 773

Southeast 68 59 59 59 5 181

Texas 233 466 186 342 124 1,118

Total 599 848 665 1268 267 3,048

a

 Based on 1996 OGJ survey.

b

 Extrapolated based on number of plants.

2.3. Landspreading/Land Treatment Operations

Landspreading/land treatment operations dispose of solid wastes through application to the land or

incorporation into the soil. This process uses the physical, chemical, and biological capabilities of the soil to

decompose constituents of the wastes. Nutrients and water may be added to enhance biodegradation and

the treatment area may be tilled periodically to improve aeration. In this context, “landspreading” or “land

treatment” excludes the practice of landspreading or burying drill cuttings and other drilling wastes. An

example of the type of land treatment operation included here might be land treatment or bioremediation of

hydrocarbon contaminated soil on leased land surrounding a production facility. Land treatment operations

typically require a state permit but some states prohibit land treatment. Question 18 of the E&P operations

survey simply asked operators if on-site landspreading or land treatment operations are carried out in the

field for which they were reporting. Thirty respondents (19 percent) report on-site land treatment operations

and 127 respondents (81 percent) report no land treatment operations:

On-site Land Treatment - Yes On-site Land Treatment – No

Total Responses: 30 (19%) 127 (81%)

2.4. Produced Water

2.4.1. Estimated Volume of Produced Water – E&P Operations

The estimated total volume of produced water by state is shown in Appendix C, Table 1. An

estimated national total of 17.9 billion barrels of water was produced in 1995. As indicated in Table C.1, the

estimated total produced water for most states was obtained from state data, state estimates, or industry

sources (Petroleum Information estimates). Where indicated, a produced water volume was extrapolated

based on 1995 oil production using extrapolation factors estimated from survey responses for question six

on the E&P operations survey form.

The API 1985 Production Waste Survey reports two estimates for produced water. The first

estimate, 16.3 billion barrels, was obtained from state records, operator inventories and EPA estimates. The

second estimate, 20.9 billion barrels, was based on statistical analysis of data received from a supplemental
11

survey form sent to individual companies. The 1985 estimates suggest that, on average, 5.0 barrels to 6.4

barrels of water were produced per barrel of oil. The 1995 estimate indicates that, a decade later, the

produced water cut increased to approximately 7.5 barrels of water per barrel of oil. The 1995 estimate of

produced water, 17.9 billion barrels, represents a 14 percent decline from the 1985 estimate of 20.9 billion

barrels. This corresponds to the 27 percent decline in U.S. oil production over the same period. The

apparent decline in produced water volume was not as great as the decline in oil production for two reasons.

First, declining oil production between 1985 and 1995 was offset, in part, by a 13 percent increase in gas

production. Although, gas wells generally produce less water than oil wells, water production associated

with gas production can be substantial in some regions. Second, as oil production declined, associated

water production increased on a per barrel basis, reflecting a growing population of aging oil wells

2.4.2. Produced Water Disposal – E&P Operations

The reported volumes of produced water and reported disposal methods are tabulated in Appendix

C, Table 2. Survey respondents reported the production of approximately 4.8 million barrels of water per day

or 1,750 million barrels annually. The survey respondents represent about 10 percent of the estimated

national total volume of produced water. Table 2.4 below summarizes the frequency of produced water

disposal methods estimated from the aggregate survey response. Nationwide, 71 percent of produced water

is injected into producing reservoirs to enhance recovery of oil and natural gas. Another 21 percent of

produced water is injected for disposal. Subsurface formation water and waste fluids produced by the oil

and gas industry are injected into Class II wells as required under the Safe Drinking Water Act. Thus,

approximately 92 percent of produced water is managed through Class II well injection into subsurface

reservoirs, generally considered the safest and most effective method for handling these type fluids.

Although only 3 percent of produced water is discharged; almost all of the discharged volume is obtained

from coalbed methane operations in Alabama and is discharged under NPDES permits. Less than half of

one percent of produced water is disposed at commercial disposal facilities. 

Table 2.4. 1995 Produced Water Disposal Method – Reported Data

Produced Water Disposal Method

Percentage of

Produced Water

Disposed by

Method

Inject for Enhanced Oil Recovery (EOR) 71.0 %

Inject for Disposal Onsite 18.0 %

Treat and Discharge a3.0 %

Inject for Disposal Offsite 2.5 %

Beneficial Reuse b2.0 %

Inject at Commercial Disposal Facility < 0.5%

Road Spread < 0.01%

Other c (“percolation ponds”) 3.0 % a

 Over 99 percent of surface discharged water originates from coalbed

methane operations in Alabama. The remaining discharged water is

comprised of small volumes reported from gas production operations in

Appalachian states.

b

 Beneficial reuse takes place under NPDES permits and allows

produced water to be used for irrigation, livestock watering, and similar

uses in the Western U.S.

c

 Almost the entire volume in the “Other” category is reported by

operators in California and appears to represent a produced water

management method unique to California.

The percentage of produced water disposed by the methods summarized in Table 2.4 was applied

to the 17,900 million barrels total volume estimated in Appendix C.1. An estimated 16,500 million barrels

were injected into Class II wells in 1995, of which 12,700 million barrels were used for enhanced oil recovery
12

and 3,800 million barrels were disposed. Approximately 500 million barrels were discharged via NPDES

permit, an estimated 400 million barrels were re-used for beneficial purposes, and 500 million barrels were

disposed by other methods.

As Appendix C, Table 2 indicates, there is significant regional variation from the nationwide

aggregate produced water disposal methods presented in Table 2.4 above. For example, surface discharge

of produced water is permitted for large coalbed methane operations in Alabama. Consequently, the

percentage of water disposed by NPDES discharge in Alabama is quite large relative to other states, and

represents a special case resulting from the coalbed methane operations in that state. The Appalachian

States (KY, OH, PA, NY, VA, WV) and the Rocky Mountain States (CO, WY, UT, MT) provide further

examples of regional variation in produced water disposal methods. In the Appalachian states, 85 percent of

produced water is injected, 15 percent is reported as being surface discharged, and 6 percent of produced

water is disposed at commercial facilities. Only 30 percent of injected produced water is used for enhanced

oil recovery operations in the Appalachian states. In contrast, 85 percent of produced water is injected for

EOR in the Rocky Mountain States, 7 percent is injected onsite for disposal, but less than 1 percent of

produced water is disposed at offsite commercial facilities. In the Rocky Mountain States approximately 7

percent of produced water is reused for beneficial purposes (e.g., livestock watering, irrigation).

Table 2.5 compares the produced water disposal methods reported in API’s 1985 Production Waste

Survey with the disposal methods reported in API’s 1995 E&P operations survey. While the total

percentage of produced water injected remained constant between 1985 and 1995; the percentage injected

for enhanced recovery increased significantly by 1995. Disposal by injection was not distinguished as

onsite, offsite, or commercial disposal in the 1985 survey. The percentage of produced water disposed by

NPDES surface discharge decreased by half between 1985 and 1995. This was mainly due to a prohibition

of coastal discharges in Louisiana and Texas, which was phased in during the early 1990s. In 1995,

disposal by NPDES surface discharge is limited to a few unique, regional operations.

Table 2.5. Comparison of 1985 and 1995 Produced Water Disposal Methods

Produced Water Disposal Method

% Produced

Water Disposed

by Method

1985

% Produced

Water Disposed

by Method

1995

Inject for Enhanced Oil Recovery (EOR) 62 % 71 %

Injected for Disposal 30 % 21 %

NPDES Discharge 6 % 3 %a

Reuse 0 % 2 %

Other (percolation, evaporation, public

treatment works) 2 % 3 %

Total 100% 100%

a

 Nearly all surface discharge is from coalbed methane operations in Alabama.

2.4.3. Produced Water – Gas Processing Plants

Gas plant survey respondents reported the removal of over 6,000 barrels of produced water per

day. This is water that was not separated from the gas in the field but must be removed prior to processing.

When extrapolated on gas throughput, the total volume of produced water from gas processing plants is

estimated to be at least 9.5 million barrels per year. Table 2.6 summarizes the reported data and

extrapolated volume of produced water for each gas plant region. The Alaskan region reported no volume of

produced water. If an estimated volume of produced water is assumed for Alaska, then the total estimated

volume of produced water from gas plants may be as much as 10.9 million barrels per year.
13

Table 2.6. Gas Plants, Produced Water Volume – Reported Data and Estimated Volumes

Region

# Plants

in

Regiona

Gas Plant

Throughput

for Region a

(MMcfd)

Reported

Gas

Throughput

for Region

(MMcfd)

Reported

Volume

Produced

Water

(barrels/day)

Vol.

Produced

Water per

Vol. Gas

Throughput

(bbl/MMcf)

Estimated

Volume

Produced Water

(barrels/day)

Alaska 3 8,600 7,900 0 b b

California 25 700 300 201 0.67 460

Eastern U.S. 47 2,000 990 247 0.25 500

Mid-West 92 5,900 110 71 0.66 3,900

New Mexico 27 2,100 1,100 148 0.13 300

Rockies 104 4,400 2,700 328 0.12 530

Southeast 68 12,900 6,200 520 0.08 1,100

Texas 233 11,500 2,700 4,532 1.69 19,400

Total

(excl. Alaska) 596 39,500 14,100 6,047 0.62 26,190b

a

 Based on 1996 Oil & Gas Journal survey.

b

 Due to processes used in Alaska, all produced water may be removed before it reaches the gas plant. If we

 assume a volume of 0.43 bbl/MMcf for Alaska, total estimated produced water volume is 29,890 bbl/d.

Appendix F, Table 1 shows the reported volumes of produced water disposed from gas plants by

method for each gas plant region. The national results are summarized in Table 2.7 which shows that 93

percent of produced water from gas plants is reported to be disposed by injection into Class II wells.

Approximately 38 percent of the injected volume is disposed onsite. About 46 percent of the injected volume

is disposed offsite into Class II wells with 9 percent going to commercial well disposal facilities. The

remaining produced water not injected is disposed by other miscellaneous methods.

Table 2.7. Gas Plants; Produced Water Disposal Method – Reported Data

Produced Water Disposal Method

Percentage of

Produced Water

Disposed by Method

Volume of Produced

Water Disposed by

Method (barrels/day)

Inject for Disposal Offsite 46 % 2,781

Inject for Disposal Onsite 38 % 2,306

Inject at Commercial Disposal Facility 9 % 534

Reuse 1 % 50

Treat and Discharge 0 % 0

Road Spread 0 % 0

Other 6 % 376

Total 100 % 6,047

“Other” methods include: co-mingle w/ oil product, treat & evaporate, evaporation pits, inject for

EOR in adjacent oil fields, steam vent to atmosphere
14

3. SURVEY RESULTS: ASSOCIATED WASTES, GAS DEHYDRATION/SWEETENING

WASTES, DRILLING WASTES, AND WASTE MANAGEMENT PRACTICES

3.1. Associated Wastes and Waste Management

3.1.1. Types of Associated Wastes

Associated wastes include a wide range of small volume waste streams that are associated with

exploration and production of oil and natural gas. These wastes are often grouped under the term

“associated wastes” as the third category of wastes (along with produced water and drilling wastes) that are

exempt from regulation as hazardous wastes under the Resource Conservation and Recovery Act.9 The

1995 E&P operations survey considered four categories of wastes that together comprise the majority of

associated wastes:

• Completion Fluids – All fluids from initial well completion activities, including any initial acid

stimulation or hydraulic fracturing.

• Workover/Stimulation Fluids – All fluids from subsequent workover and stimulation

operations.

• Tank Bottoms/Oily Sludges – Tank sediment and water, produced sand and other tank

bottoms.

• Dehydration/Sweetening Wastes – Includes glycol-based compounds, glycol filters, molecular

sieves, amines, amine filter, precipitated amine sludge, iron sponge, scrubber liquids and

sludge, backwash, filter media and other wastes associated with the dehydration and

sweetening of natural gas.

Appendix D, Table 1 lists the 1995 reported volumes of associated wastes by state. Completion fluids and

workover fluids comprise 91 percent of the reported volume of associated wastes. Tank bottoms and sludge

comprise almost 9 percent of the reported volumes, and dehydration/sweetening wastes comprise only 0.25

percent.

The associated waste streams considered in the 1995 E&P operations survey differ somewhat from

the API 1985 Production Waste Survey. The types and volumes of associated wastes considered in the

1985 Production Waste Survey are summarized in Table 3.1. The 1985 Production Waste Survey estimated

the total volume of associated wastes generated in 1985 to be 11.76 million barrels; the 1995 survey

estimates the total volume of associated wastes generated annually to be about 20.5 million barrels. The

most significant difference is the 1995 survey defined completion fluids and workover/stimulation fluids as

two separate categories of associated wastes, whereas the 1985 survey combined the two waste streams

into a single category. In the 1985 survey, workover fluids were described as: “... workover, swabbing,

unloading, and completion fluids recovered from a well bore that are not recombined with the production

stream. They include spent acid or stimulation fluids and swab tank fluids sent directly to disposal. They

exclude fluids sent down flow lines, hauled to field batteries or NPDES permitted pits because these fluids

are captured in other waste categories or under produced water disposal statistics.” Unlike the 1985 survey,

the 1995 survey captures the volume of completion and workover fluids injected into Class II wells as

associated waste. Consequently, the large percentage of completion and workover fluids that were reported

disposed by injection in 1995 were not captured as associated waste in the 1985 survey, but were instead

included in the estimated volume of produced water. For this reason, the percentage of associated wastes

comprised of aqueous liquids in 1995 is almost twice the percentage of aqueous liquid associated waste in

1985. The 1985 survey also includes oil-contaminated soil as associated waste, as well as a number of

other small waste streams such as solvents, cooling tower blowdown water, and used oils that were not

 

9

 A fourth category of wastes, ‘industrial wastes’ includes wastes generated at E&P sites that are not uniquely associated with

oil and gas E&P operations and thus are not exempt from regulation as hazardous under RCRA. These include wastes such

as paint and used solvents. Industrial wastes were not addressed by the survey.
15

included in the 1995 survey. Approximately 25 percent of the total associated wastes estimated in 1985

were contributed by waste streams not considered in the 1995 E&P operations survey. 

Table 3.1. Summary of Total Estimated Associated Wastes from

1985 Production Waste Survey (barrels)

Associated Waste % Waste

Est. Waste

Volume

(bbls./yr.)

Workover Fluids 48 % 5,656,000

Produced Sand 11 % 1,276,000

Oily Debris (contaminated soil, rags, etc.) 11 % 1,261,000

Tank Bottoms 10% 1,232,000

Dehydration/Sweetening Unit Wastes 4 % 460,000

Untreatable Emulsions 3 % 355,000

Used Solvents/Degreasers 2 % 252,000

Cooling Water 2 % 219,000

Used Oils 2 % 212,000

Spent Iron Sponge < 1 % 54,000

Other Liquid Wastes 5 % 591,000

Other Solid Wastes 2 % 192,000

Total 11,760,000

3.1.2. Estimated Volume of Associated Wastes – 1995 E&P Operations Survey

Appendix D, Table 2 shows the estimated volumes of associated wastes by state. Completion fluids

were extrapolated based on the number of completed wells, workover/stimulation fluids were extrapolated

on the number of active wells, tank bottoms were extrapolated on total production, and

dehydration/sweetening wastes were extrapolated on gas production. Table 3.2 summarizes the national

total volume of associated wastes estimated from the 1995 E&P operations survey.

Table 3.2. 1995 E&P Operations Survey – Total Estimated Volume of Associated Wastes

Associated Waste % Waste

Est. Waste

Volume

(bbls./yr.)

Completion Fluids 43 % 8,778,000

Workover/Stimulation Fluids 46 % 9,527,000

Tank Bottoms/Oily Sludge 10 % 1,987,000

Dehydration/Sweetening Unit Wastes 1 % 193,000

Total 20,485,000

Total (excluding completion fluids as in

the 1985 Survey) (11,707,000)

In 1985, the injected volume of workover and completion fluids was largely counted with the 1985

volume of produced water. Consequently, the total 1995 volume of associated wastes minus the 1995

volume of completion fluids provides an estimate of the total 1995 volume of associated wastes, 11.7 million

barrels, that is directly comparable to the total 1985 volume of 11.76 million barrels (illustrated in Tables 3.1

and 3.2). The 1995 volume of associated wastes may be underestimated because oily debris and other

miscellaneous waste streams were not included in the 1995 data. For example, in 1985 oily debris

contributed approximately 11 percent of associated wastes, or about 1.3 million barrels, but this waste

stream is not included in 1995. Another 1.0 million barrels, or about 9 percent of the 1985 total associated
16

wastes, were contributed by miscellaneous solid and non-aqueous waste streams that were not included in

1995.

There are several other noteworthy differences between the 1995 estimated volumes of associated

wastes and the 1985 estimated volumes. Aqueous fluids comprise 89 percent of associated wastes in 1995.

The remaining 11 percent of associated wastes are solids, sludges, and glycol compound wastes. In 1985,

solids, sludges, and non-aqueous liquids were estimated to comprise 45 percent of associated wastes, and

workover fluids, cooling tower blowdown water, and miscellaneous other liquid wastes comprised the

remaining 55 percent of associated wastes. In 1995, the estimated total volume of workover fluid was 68

percent greater than the total volume of workover fluid estimated in 1985. This increase probably reflects a

substantial increase in the number of well workovers, recompletions, and well stimulations between 1985

and 1995. In 1995, the estimated volume of tank bottoms/oily sludge (includes produced sand) was about

21 percent less than the 1985 estimated volume of 2.51 million barrels (produced sand plus tank bottoms).

Because tank bottoms were extrapolated on production, the decreased volume of tank bottoms/oily sludge

between 1985 and 1995 reflects the 27 percent decline in crude oil production during the period. The

estimated total volume of dehydration/sweetening wastes in 1995 is less than half the volume of

dehydration/sweetening wastes estimated in 1985. The 1995 estimated volume of dehydration wastes is

surprisingly low considering that total U.S. gas production increased by 13 percent between 1985 and 1995

and the number of active gas wells increased by 23 percent. The apparent decline in the estimated volume

of dehydration wastes may be the result of a combination of factors: 1) Recycled glycol waste fluids were

not reported in the survey; 2) By 1995, the percentage of production that is “new” gas increased relative to

total gas production, and new production tends to be dry gas that does not require dehydration; 3) The

survey response was insufficient to characterize gas dehydration wastes for the total United States.10

In comparing the estimated volumes of associated wastes between 1985 and 1995, another factor

to consider is better record keeping. At the time of the 1985 survey, the term “associated wastes” was new

and many companies simply did not keep track of these waste streams (which tend to be only a few barrels

per well annually). By 1995, increased environmental awareness and the availability of better information

management systems enhanced the accuracy of the data reported on the survey forms. Thus, a portion of

the apparent “increase” in associated wastes may simply be due to better tracking and reporting of these

waste streams within companies.

3.1.3. Associated Waste Disposal

Table 3.3. reports the estimated associated waste disposal practices for the aggregate associated

waste stream for the total United States. The disposal practices reported in Table 3.3 reflect the large

volume of aqueous liquid associated wastes that were identified in the 1995 survey. In 1995, the most

common disposal practice was injection, 7.78 million barrels, followed by recycling, reclamation or beneficial

reuse, 3.89 million barrels. Approximately, 3 million barrels were disposed at commercial E&P waste

facilities and 2.25 million barrels were evaporated.

 

10 In the 1995 survey, only 17 respondents reported dehydration waste in a total of 11 states. It is possible that the sample

reporting gas dehydration wastes were not representative of gas dehydration operations in the U.S. as a whole.
17

Table 3.3. Estimated Associated Waste Disposal Practices for the Total U.S.;

Total Associated Waste Stream – 1995 E&P Operations Survey

Associated Waste Disposal Method % Waste

Total Estimated

Waste Volume

(bbls./year)

Disposal by Injection 38 % 7,784,000

Recycle, Reuse, Oil Reclamation 19 % 3,892,000

Commercial E&P Waste Facility 15 % 3,073,000

Evaporate from Pits 11 % 2,253,000

Land Spread 5 % 1,024,000

Road Spread 2.5 % 512,000

Incinerate 0.4% 82,000

Municipal or Industrial Landfill <0.1 % 20,500

Other: (land treatment, burial onsite, disposal

pits, other commercial disposal) 9% 1,844,000

Total (Bbls./Yr.) 100% 20,484,500

Table 3.4 shows the total volume of associated wastes by disposal practice estimated in the 1985

Production Waste Survey. In 1985, the largest volume of associated wastes, 6.1 million barrels, was

disposed in offsite commercial facilities. In 1995, only half this volume, 3.1 million barrels was estimated to

be disposed at commercial E&P facilities. It is possible that the additional 3 million barrels disposed at offsite

commercial facilities in 1985 includes some of the associated waste streams and volumes not identified in

the 1995 survey, such as oil contaminated soil, spent solvents, emulsions, and miscellaneous oily debris.

Between 1985 and 1995, the estimated volume of associated wastes disposed by land spreading or road

spreading declined by over 40 percent from 2.7 million barrels to 1.5 million barrels. In 1995, 10 million

barrels were estimated disposed by injection and evaporation compared to 1.18 million barrels in 1985. This

reflects the inclusion of completion fluids as an associated waste in 1995, as well as the significant increase

in workover/stimulation fluids between 1985 and 1995.

Table 3.4. Estimated Volume of Associated Wastes by Disposal Techniques

 From 1985 Production Waste Survey

Associated Waste Disposal

Method % Waste

Total Estimated

Waste Volume

(bbls./year)

Offsite Commercial Facility 52 % 6,114,000

Road Spread 14 % 1,646,000

Land Spread 9 % 1,058,000

Injection 7 % 823,000

Recycle 7 % 823,000

Onsite Burial 5 % 588,000

Evaporation/Onsite Pit 3 % 353,000

Surface Discharge 1 % 116,000

Other: (incinerate, burned as fuel) 2% 235,000

Total (Bbls./Yr.) 100.0% 11,756,000

Table 3.5 and Table 3.6 show the estimated volume of wastes disposed by waste disposal practice

for each of the associated waste streams considered in the 1995 E&P operations survey. Appendix D,

Table 3 and Table 4 contain the reported data on which Table 3.5 and Table 3.6 are based. Associated

waste disposal practices vary significantly depending upon the type of waste stream. Appendix D, Table 5

and Table 6 show the reported volumes of associated wastes disposed by state. These tables indicate

variations in associated waste disposal practices between states and regions.
18

Table 3.5. Estimated Volumes of Associated Wastes by Disposal Method;

Completion Fluids and Workover Fluids,

1995 E&P Operations Survey

Associated Waste

 Disposal Methods

%

Completion

Fluids

Est. Volume

Completion

Fluids

(bbls/yr.)

%

Workover

Fluids

Est. Volume

Workover

Fluids

(bbls./yr.)

Disposal by Injection 21 % 1,843,000 59 % 5,621,000

Recycle, Beneficial Reuse, Oil

Reclamation 33 % 2,897,000 <0.1 % 10,000

Commercial E&P Waste Facility 29 % 2,546,000 4 % 381,000

Evaporate from Pits 8 % 702,000 16 % 1,524,000

Land Spread 6 % 527,000 2 % 191,000

Road Spread 0 0.4% 38,000

Incinerate 0 1 % 95,000

Municipal or Industrial Landfill 0 0

Other: (land treatment) 3 % 263,000 17.5 % 1,667,000

Total 100% 8,778,000 100% 9,527,000

Table 3.6. Estimated Volumes of Associated Wastes by Disposal Method; Tank Bottoms/Oily Sludge

and Dehydration Wastes, 1995 E&P Operations Survey

Associated Waste

Disposal Methods

% Tank

Bottoms

Est. Volume

Tank Bottoms/

Sludge

(bbls./yr.)

%

Dehydration

Wastes

Est. Volume

Dehydration

Wastes

(bbls./yr.)

Disposal by Injection 24 % 477,000 4 % 7,700

Recycle, Beneficial Reuse, Oil

Reclamation 37 % 735,000 7 % 13,500

Commercial E&P Waste Facility 2 % 40,000 32 % 61,700

Evaporate from Pits 0.2 % 4,000 0

Land Spread 16.5 % 328,000 8 % 15,400

Road Spread 18 % 358,000 48.5 % a 93,500

Incinerate <0.1 % 2,000 0.1 % 200

Municipal or Industrial Landfill <0.1 % 2,000 0

Other: (onsite burial, other

commercial disposal, disposal pits) 2 % 40,000 0.5 % 1,000

Total 100% 1,986,000 100% 193,000

a

 Of the 17 survey respondents reporting gas dehydration waste, a single respondent accounted for

almost half the total reported volume of dehydration waste. This same respondent reported all

dehydration waste was roadspread in 1995. If this response is excluded from the reported data, then

the total extrapolated volume of dehydration/sweetening waste is 99,000 barrels with an estimated 62.5

percent disposed at commercial E&P waste disposal facilities.

Comparison of the associated waste disposal practices and waste volumes reported in 1985 and

1995 suggest that significant changes occurred over the decade:

• The estimated total volume of associated wastes did not decrease between 1985 and 1995

despite the decline in oil production during that period. Between 1985 and 1995 the volume of

aqueous liquid wastes increased relative to the volume of solid and oily wastes, with a

corresponding increase in the volume of associated wastes disposed by Class II injection and

evaporation.
19

• The volume of workover/stimulation fluids increased between 1985 and 1995, possibly

reflecting an increase in workovers, recompletions, and well stimulations during that time.

• The volume of tank bottoms/oily sludge declined between 1985 and 1995. The decreased

volume of oily wastes may, in part, be the result of the decline in oil production during that

time, as well as improved waste minimization and waste treatment efforts.

• There appears to be an almost 50 percent decrease in the use of offsite commercial E&P

facilities for associated waste disposal between 1985 and 1995. The estimated volume of

associated wastes disposed at commercial facilities was 3 million barrels in 1995, down from

6 million barrels in 1985. This result suggests that a greater percentage of associated wastes

were managed onsite in 1995 than in 1985.

• The estimated volume of associated waste disposed by surface disposal methods such as

surface discharge, land spreading, and road spreading declined between 1985 and 1995.

3.2. Gas Processing Plant Wastes and Waste Management

3.2.1. Types of Gas Processing Plant Wastes

Like other types of wastes uniquely associated with oil and natural gas production, gas processing

plant wastes are exempt from regulation as hazardous under the Resource Conservation and Recovery Act

(RCRA). Exempt gas plant wastes include glycol and glycol-based compounds, glycol filters, molecular

sieves, amines, amine filters, precipitated amine sludge, iron sponge, scrubber liquids and sludge,

backwash, filter media, and miscellaneous other wastes associated with dehydration or sweetening of

natural gas. The 1995 survey of gas processing plant wastes considered four categories of wastes that

represent the primary exempt waste streams from gas processing operations. The waste streams

considered include:

• Spent glycol/glycol compounds

• Used filters and filter media

• Scrubber liquids and sludge

• All other dehydration and sweetening wastes.

Detailed survey data reported for each gas plant dehydration waste stream are presented by region in

Appendix F, Tables 2, Table 3, Table 4, and Table 5. Appendix F, Table 6 summarizes the reported

volumes of gas processing plant wastes for the total United States.

3.2.2. Gas Processing Plant Waste Disposal Methods and Estimated Volumes of Waste

The total estimated volume of gas processing plant wastes for the United States is shown in Table

3.7. No wastes were extrapolated for the Alaska region because no wastes were reported for that region.

The total estimated volume of wastes from gas processing plants is less than 1 percent of the estimated

national total volume of associated wastes. Scrubber liquids and sludge comprise an estimated 79 percent

of the waste stream from gas plants. Glycol compounds and used filters/filter media each contribute 1

percent to 2 percent of the gas plant dehydration waste stream. The remaining 18 percent of the wastes

include other unspecified dehydration wastes.
20

Table 3.7. Gas Processing Plant Wastes – Estimated Volumes

(extrapolated on gas throughput)

Region

Gas

Throughput

for Region

(MMcfd)

Est. Volume

Spent

Glycol/

Glycol

Compounds

(bbls./yr.)

Est.

Volume

Used

Filters/

Filter Media

(bbls/yr.)

Est.

Volume

Scrubber

Liquids &

Sludge

(bbls./yr.)

Est. Volume

All Other

Dehydration/

Sweetening

Wastes

(bbls./yr.)

Est. Total

Reported

Volume of

Gas Plant

Wastes

(bbls./yr.)

Alaska 8,637 0 0 0 0 0

California 679 50 60 460 0 570

Eastern U.S. 2,005 220 1 120 0 340

Mid-West 5,894 0 10 0 830 840

New Mexico 2,122 0 50 40 2,140 2,230

Rockies 4,384 710 420 70 1,950 3,150

Southeast 12,864 210 150 66,370 9,280 76,010

Texas 11,502 10 820 13,470 4,090 18,390

Total 48,087 1,200 1,510 80,530 18,290 101,530

Table 3.8. lists the estimated volume of gas processing plant wastes by disposal method. The

reported volumes of gas plant wastes by disposal method are summarized in Appendix F, Table 7. Table

3.8 suggests that scrubber liquids comprise the largest component of gas processing plant wastes.

Consequently, most gas plant wastes, 78.5 percent, are disposed by injection or evaporation. Thirteen

percent of gas plant wastes are disposed offsite at commercial E&P waste facilities or landfills. Data were

not collected on gas processing plant wastes in the 1985 production survey, so no comparison can be made

with 1985 waste volumes and disposal practices.

Table 3.8. Gas Processing Plants; Estimated Volume of Wastes by Disposal Method

Waste Disposal Method

Percentage of Gas

Processing Plant

Wastes Disposed

by Method

Estimated Volume of

Wastes Disposed by

Method

(barrels/year)

Disposal by Injection 76 % 77,200

Commercial E&P Waste

Disposal Facility 9 % 9,100

Land Spread Onsite 6 % 6,100

Industrial or Municipal Landfill 4 % 4,100

Evaporate from Pits 2.5 % 2,500

Recycle or Reuse 1 % 1,000

Incinerate 0.25% 300

Road Spread Onsite 0.01 % 10

Other 1 % 1,000

Total 100% 101,310

“Other” methods include: “co-mingle w/ oil product, waste disposal contractor, onsite

burial w/ permit, incineration in “waste-to energy” plant”
21

3.3. Drilling and Drilling Waste Management

3.3.1. Drilling Techniques

Traditionally, wells are drilled using one of two techniques. Most wells are drilled using a rotary rig

with drilling mud to cool the bit and lubricate the hole. Wells drilled with a rotary rig generally have a reserve

pit to store and dispose the used drilling fluids and cuttings. An older drilling technique, common in

Appalachia, uses a truck-mounted cable tool drilling rig. But new technologies have made in-roads. In

sensitive areas, reserve pits are increasingly replaced with storage tanks in what is termed as a “closed

system.” Certain types of wells are drilled using pneumatic tools and air, gas, or foam in place of drilling

mud. The survey requested information on drilling techniques to better understand the percentage of wells

drilled with techniques other than a rotary rig and open mud systems. Appendix E, Table 1 summarizes the

reported data on drilling techniques used for new wells in 1995.

Survey respondents reported a total of 1,244 new wells drilled. Operators from the Appalachian

states reported 124 new wells, or approximately 10 percent of the total. With a few regional exceptions, the

1995 E&P operations survey indicates that the majority of new wells in the onshore U.S. were drilled using a

reserve pit to store and dispose used drilling muds and cuttings. The primary regional exceptions are Alaska

(100 percent wells reported drilled with closed system), New Mexico (73 percent of new wells drilled with air

or gas), and Appalachia (96 percent drilled with air, gas, or pneumatics).

Table E.1 shows that for the total United States, 66 percent of new wells were reported drilled with a

mud system discharging to reserve pits, 23 percent of new wells were drilled with a closed system (no

reserve pits), 11 percent were drilled with air or gas (no drilling mud), and less than 0.1 percent were

reported drilled with a cable tool.11 Sixty-nine percent of mud reserve pits was reported to be lined. For the

Appalachian states reporting, 96 percent of new wells were drilled with air and the remaining 4 percent were

drilled using a reserve pit. No respondents from Appalachian states reported wells drilled with a cable tool. If

the Appalachian component is removed from the reported data in Table E.1, for the remaining states, 74

percent of new wells were drilled using a reserve pit, 25 percent with a closed system, and only 1 percent

was drilled with air or gas.

A significant improvement in drilling practices between 1985 and 1995 is indicated by the difference

in drilling techniques reported in the 1995 E&P operations survey and the drilling techniques inferred from

the 1985 survey.12 Between 1985 and 1995, the percentage of lined reserve pits increased from 35 percent

to 69 percent. By 1995, one quarter of new wells were drilled with a closed system and did not require

reserve pits.

3.3.2. Percentage of Drilling Wastes by Base Drilling Fluid

Appendix E, Table 2 contains reported percentages of drilling wastes by base drilling fluid. Table

E.2 indicates that most of the new wells, with a few local exceptions, are drilled with freshwater base mud.

Alaska is the only state that reports a significant percentage of new drilling with synthetic based drilling mud

(30 percent). Most drilling with oil based mud is reported only in Louisiana and Oklahoma. Drilling with

saltwater-based mud is reported in only six states known to have salt bearing formations.

In Appendix E, Table 3, the percentage of drilling wastes by base drilling fluid (from Table E.2) were

applied to reported drilling waste volumes to estimate a national percentage of drilling wastes by base

drilling fluid. Table E.3 shows that in 1995, 92.5 percent of drilling wastes were derived from freshwater

based drilling fluid, 5.5 percent of drilling wastes were derived from saltwater based drilling fluids, oil based

drilling fluid produced less than 1.5 percent of wastes, and the remaining 0.5 percent were derived from

 

11 Only one well was reported drilled with a cable tool.

12 In the API 1985 Production Waste Survey, 91 percent of wells were reported drilled with a mud system. The remaining 9

percent of new wells reported as “other” in 1985 is inferred to represent air- or gas-drilled wells. Of the 91 percent of new wells

drilled with mud systems in 1985, 2 percent were drilled with a polymer mud system, which are inferred to be closed systems.

Nationwide, an estimated 35 percent of reserve pits was estimated to be lined.
22

synthetic based drilling fluid. The 1985 Production Waste Survey reported that 64 percent of drilling wastes

were derived from freshwater based mud systems; 23 percent of drilling wastes were derived from saltwater

based muds; oil based muds produced 7 percent of drilling wastes; and polymer or “other” muds produced

the remaining 6 percent of drilling wastes. The decline in drilling waste from oil-based drilling reflects the

availability of better water-based and synthetic-based drilling formulas, along with industry practice to

substitute more environmentally friendly materials where feasible. 

3.3.3. Volume of Drilling Wastes

Table 3.9 provides an estimate of the volume of drilling wastes generated within each state during

1995. Drilling waste volumes for the 1995 survey were estimated by multiplying the total 1995 footage drilled

by the average waste extrapolation factor determined for the state (by depth category) in the API 1985

Production Waste Survey.

13 The estimated national total volume of drilling wastes for 1995 is 148.7 million

barrels or approximately 1.21 barrels of waste per foot drilled. This estimated 1995 volume is less than half

the 361 million barrels of drilling wastes estimated in 1985. Because the approach used to estimate the

1995 volume of drilling wastes does not account for improvements in the efficiency of drilling systems

between 1985 and 1995, the actual volumes of drilling wastes may be over stated.

Appalachian States The 1995 E&P operations survey form sent to operators in the Appalachian

states asked respondents to report volumes of drilling waste. This information had not been collected for the

Appalachian states in the 1985 Production Waste Survey. Appendix E, Table 4 shows the reported drilling

waste volumes and reported footage drilled for the Appalachian region. Only eight respondents in the region

reported drilling in 1995 and almost 97 percent of the reported footage was drilled with air rather than a mud

system. The remaining 3 percent of reported footage was drilled with a mud system.

The reported data collected for the Appalachian region (0.07 barrels waste/foot) may represent

typical waste volumes generated by air drilling, and may not be representative of typical drilling waste

volumes generated for the Appalachian region as whole. In Appendix E, Table 5 the estimated waste

extrapolation factor for air drilling, 0.07 barrels/foot, (from Table E.4) is applied to the Appalachian states, as

well as other states, which report significant air drilling in the 1995 survey (New Mexico, Oklahoma, and

Utah). Table E.5 provides alternative estimates of drilling wastes for these states (NM, OK, UT, KY, NY, OH,

PA, TN, VA, WV) that are considerably lower than the drilling waste volumes estimated in Table 3.9. If the

alternative drilling waste volumes estimated for the selected states in Table E.5 are substituted for the

drilling waste volume estimated in Table 3.9, the estimated national total volume of drilling waste for 1995

becomes 132.8 million barrels, or approximately 1.08 barrels of waste per foot drilled.

 

13 API 1985 Production Waste Survey, Table 90, Total Drilling Waste Volumes Discharged to the Reserve Pit.
23

Table 3.9. Estimated Total Volume of Drilling Wastes

STATE

Est. Total

Footage Drilled

in 1995 – Survey

Reported Data a

(feet)

Est. Volume

Total Drilling

Waste per Foot

Drilled b (bbls/ft)

Est. Vol. Drilling

Waste for 1995

Drilling - Survey

Reported Data c

(barrels)

1995 Total

Footage

Drilled d

(Completed

Wells)

Est. Total

Volume Drilling

Wastes for

State e

(barrels)

AK 132,000 0.84 110,880 1,911,300 1,605,492

AL 0 3.26 0 1,087,500 3,545,250

AR 0 2.05 0 1,289,500 2,643,475

AZ 1.92 0 5,400 10,368

CA 830,325 0.61 506,498 2,994,100 1,826,401

CO 72,000 0.87 62,640 4,117,600 3,582,312

FL 3.71 0 15,500 57,505

IL 55,800 0.51 28,458 749,100 382,041

IN 0.62 0 172,200 106,764

KS 1,024,428 0.9 921,985 5,344,700 4,810,230

KY 83,500 1.43 119,405 1,465,100 2,095,093

LA 175,390 1.95 342,011 11,526,800 22,477,260

MI 11,900 1.1 13,090 1,573,900 1,731,290

MO 1.13 0 0

MS 0 2.94 1,370,100 4,028,094

MT 58,616 1.52 89,096 898,500 1,365,720

ND 0 1.05 841,500 883,575

NE 0 0.55 159,800 87,890

NM 60,911 1.29 78,575 5,752,500 7,420,725

NV 1.57 104,600 164,222

NY 18,200 1.28 23,296 108,000 138,240

OH 44,650 0.56 25,004 3,073,700 1,721,272

OK 133,600 1.11 148,296 11,857,800 13,162,158

OR 0.36 0 0

PA 98,600 1.03 101,558 2,357,100 2,427,813

SD 1.03 9,300 9,579

TN 2.39 93,000 222,270

TX 2,488,209 1.13 2,811,676 57,847,100 65,367,223

UT 100,250 1.68 168,420 929,400 1,561,392

VA 93,793 0.41 38,455 139,900 57,359

WV 254,160 0.54 137,246 1,585,000 855,900

WY 24,000 1.27 30,480 3,443,900 4,373,753

Total 5,760,332 1.2 5,757,070 122,823,900 148,720,666

a Extrapolated from survey form question 22a: reported # new wells drilled in each depth zone x average drilling

depth reported for each depth zone

b

 Average for state from API 1985 Production Waste Survey

c

 (Column 2) x (Column 3)

d

 Oil and Gas Journal, Energy Statistics Sourcebook, 12th edition, Table “Footage Drilled by State”

e

 (Column 3) x (Column 5)

3.3.4. Types of Drilling Wastes and Drilling Waste Disposal

Appendix E, Table 6 summarizes the disposal methods reported for liquid drilling wastes. The

percentage of liquid wastes disposed by each method is expressed as a percentage of total drilling wastes.

In California for example, survey respondents report that 19 percent of total drilling wastes are liquid wastes

disposed by evaporation. Appendix E, Table 7 summarizes the disposal methods reported for solid drilling

wastes. The percentage of solid wastes disposed by each method is expressed as a percentage of total

drilling wastes. In Texas for example, survey respondents report that 13 percent of total drilling wastes are

solid wastes disposed by burial onsite.
24

Table 3.10 illustrates that, for the total United States, almost 74 percent of drilling wastes were

characterized as liquid wastes and 26 percent were characterized as solid drilling wastes. The estimated

waste volumes disposed by various disposal methods are summarized in Appendix E, Table 8 for liquid

drilling wastes and in Appendix E, Table 9 for solid drilling wastes. 

Table 3.10. Summary of Estimated Drilling Wastes by Type of Waste

From 1995 E&P Operations Survey (barrels)

Estimated Total Liquid Wastes 109,443,000 73.6 %a

Estimated Total Solid Wastes 39,257,000 26.4 %

Estimated Total Drilling Waste Volume 148,700,000 100 % a

 Estimated relative percentages of solid and liquid drilling waste are derived from

Appendix E, Tables 8 and 9, “Estimated Volumes of Liquid and Solid Drilling Waste for

States with Reported Data.”

The relative volumes of solid and liquid drilling wastes reported in Table 3.10. were derived in the

following manner. The estimated volume of drilling wastes for each state (shown in Table 3.9.) was

multiplied by the reported percentage of wastes disposed by each method (shown in Appendix E, Table 6

and Appendix E, Table 7). This was done only for states that reported drilling wastes in the 1995 survey.

This exercise produced an estimate of the volume of drilling wastes disposed by each method for each state

with reported data. These estimated volumes were aggregated to obtain an estimate of the relative volume

of solid and liquid drilling wastes for the total United States, and an estimate of the aggregate drilling waste

disposal practices for the total United States.

In the 1985 waste survey, liquid drilling wastes were estimated to comprise almost 90 percent of

drilling wastes. Ten percent of drilling wastes were estimated to be solids, primarily drill cuttings. Table 3.11

summarizes the types of drilling wastes identified in the API 1985 Production Waste Survey. Comparison of

Tables 3.10 and Table 3.11 indicate a significant increase in the relative volumes of solid drilling wastes to

liquid wastes from 1985 to 1995.

Table 3.11. Summary of Estimated Drilling Wastes by Type of Waste

From 1985 Production Waste Survey (barrels)

Mud and

Completion Fluid 226,801,000 62.75%

All Other Water 87,724,000 24.3 %

Formation Testing

Fluids 916,000 0.25 %

Other Fluids 8,222,000 2.3 %

Total Liquid

Wastes 323,663,000 89.6 %

Drill Cuttings 35,674,000 9.9%

Circulated Cement 1,876,000 0.5 %

Other Solids 196,000

Total Solid

Wastes 37,746,000 10.4 %

Total Volume 361,409,000
25

Two factors may contribute to the apparent increase in solid drilling wastes relative to liquid drilling

wastes in the 1995 survey:

1. There appears to be more air drilling represented in the 1995 E&P operations survey relative to

the 1985 survey due, in part, to an increase in air-drilled coalbed methane wells by 1995 and in

part, to greater representation of Appalachian operations in the 1995 survey. If Appalachian

states are omitted from total drilling waste estimate, the percentage of solid drilling wastes are

estimated to be 25 percent. 

2. In the 1985 survey, drilling mud was characterized as a liquid waste, and a significant portion of

drilling mud was reported hauled offsite for disposal as a liquid waste. In the 1995 survey, most

drilling wastes were reported disposed onsite through evaporation of the liquid portion and

burial of the solid portion. The 1995 E&P operations survey may have more effectively captured

the solid component of drilling mud as a solid drilling waste. The mud solids remaining after

onsite evaporation of freshwater based liquid drilling waste would generally be incorporated

with drill cuttings and disposed through onsite burial. This would increase the volume of solid

drilling wastes relative to liquid drilling wastes in the 1995 E&P operations survey.

Table 3.12 shows the aggregate nationwide drilling waste disposal practices estimated from the

1995 E&P waste survey. Nationwide, over two-thirds of drilling wastes (68 percent) were disposed onsite

through evaporation and burial. Injection and reuse of liquid wastes account for another 20 percent of

drilling wastes. Approximately 8 percent of drilling wastes were disposed on the land surface through land

spreading and surface discharge. Disposal at commercial E&P waste facilities appears to be a minor

disposal practice used for less than 3 percent of onshore drilling wastes.

Table 3.12. Estimated Drilling Waste Disposal Practices - 1995 E&P Operations Survey

Evaporate On or Offsite 47 % Liquid Drilling Waste

Burial Onsite 21 % Solid Drilling Waste

Injection (includes injection down annulus) 13 % Liquid Waste

Reuse for Drilling 7 % Liquid Waste

Land Spread Onsite 6 % Solid and Liquid Waste

Land Spread Offsite 1 % Solid and Liquid Waste

Commercial Disposal Facility 2 % Solid Waste

Treat and Discharge 1 % Liquid Waste

Recycle, Road Spread, Municipal Landfill <0.5 % Solid and Liquid Waste

Other < 1.5 %

Includes: grind and inject – solid

waste; commercial disposal – liquid

waste; onsite remediation – solids &

liquid waste; disposal pits – solid

waste.

Total 100%

The greatest change in drilling waste disposal practices between 1985 and 1995 appears to be a

marked increase in onsite disposal and a decrease in surface discharge of liquid drilling wastes. In the 1985

Production Waste Survey, 28 percent of drilling wastes were estimated to be hauled offsite for disposal. By

1995, less than 3 percent of drilling wastes were disposed at offsite commercial facilities. This increase in

onsite disposal, particularly onsite evaporation, may be a function of the increased use of lined reserve pits.

The estimated drilling waste disposal practices from the 1985 Production Waste Survey are summarized in

Table 3.13 for comparison with the 1995 E&P operations survey results.
26

Table 3.13. Comparison of 1985 and 1995 Estimated Drilling Waste Disposal Practices

Drilling Waste % Drilling Wastes Disposed by Method

Disposal Method 1985 1995

Evaporate Onsite 29 % 47 %

Hauled Offsite 28 % 2 %

Injection 13 % 13 %

Buried Onsite 12 % 21 %

Discharge to Surface 10 % 1 %

Land Spread 7 % 7 %

Reuse for Other Drilling 0 % 7 %

Other (includes

solidification, incineration) 1 % 2 %

Total 100% 100%
27

4. SUMMARY OF RESULTS

Following is a summary of the extrapolated results of the survey questions evaluated in this report.

The results presented here are national totals estimated for onshore operations for the total United States. 

The detailed survey results presented in the foregoing sections demonstrate that there is significant regional

variation in E&P operations, the volume of wastes generated, and waste management practices.

• Production Pits – E&P Operations

Nationwide, an estimated 55,000 pits are associated with production operations; 97 percent of

production pits are estimated to be active. An estimated 60 percent of production pits are lined.

• Production Pits – Gas Plants

An estimated 875 production pits are associated with gas plants in the total United States; 97

percent of pits are estimated to be active. An estimated 62 percent of gas plant pits are lined.

• Tank Batteries and Tanks – E&P Operations and Gas Plants

The estimated total number of oil tank batteries is 171,500 batteries. The estimated total number of

condensate tank batteries is 48,300 batteries. The estimated total number of tanks associated with E&P

operations is approximately 832,000 tanks. Over 3,000 additional non-pressurized tanks are estimated to be

associated with gas processing plants.

• Produced Water – E&P Operations

An estimated national total of 17,900 million barrels of water was produced in 1995. This volume

represents approximately 7.5 barrels of produced water per barrel of oil. Most produced water, an estimated

92 percent, was injected into Class II wells for enhanced oil recovery or disposal. Three percent of produced

water, primarily from coal bed methane wells in Alabama, was treated and discharged under NPDES

permits. Two percent of produced water was beneficially reused, and 3 percent was disposed by other

methods.14

• Produced Water – Gas Plants

An estimated 9.5 million barrels of water was produced by gas plants in 1995. Ninety-three percent

of produced water from gas plants was disposed by injection into Class II wells. Only 1 percent was reused,

and 6 percent was disposed by a variety of miscellaneous methods including co-mingling with oil production,

evaporation, EOR injection into adjacent oil fields, and steam venting to the atmosphere.

• Associated Wastes

The total estimated volume of associated wastes produced in 1995 was 20.5 million barrels. This

total is comprised of 8.9 million barrels of completion fluids, 9.5 million barrels of workover/stimulation fluids,

2.0 million barrels of tank bottoms/oily sludge, and 0.2 million barrels of dehydration/sweetening wastes. Of

the aggregate associated wastes, 38 percent were disposed by injection, 19 percent were recycled, reused,

or reclaimed, 15 percent were disposed at offsite commercial E&P waste facilities, 11 percent were

evaporated, and 8 percent were land spread or road spread.

• Gas Processing Plant Wastes

The total estimated volume of gas processing plant wastes produced in 1995 was 0.1 million

barrels. This total is comprised of approximately 80,500 barrels of scrubber liquids and sludge, 1,200 barrels

of spent glycol compounds, 1,500 barrels of used filters and filter media, and 18,300 barrels of

miscellaneous other dehydration wastes. Seventy-six percent of gas processing plant wastes were

disposed by injection, 1 percent were recycled or reused, 9 percent were disposed at commercial E&P

waste facilities, 3 percent were evaporated, 6 percent were land spread, and 4 percent were sent to landfills.

 

14 “Other” produced water disposal methods include percolation ponds, which are used only in California.
28

• Drilling Technique

Drilling practices improved significantly between 1985 and 1995. In 1995, 66 percent of wells

nationwide were drilled with reserve pits compared to 89 percent of wells drilled with reserve pits in 1985. In

1995, 69 percent of reserve pits were lined compared to 35 percent in 1985. Almost 25 percent of wells

were drilled with a closed system in 1995 compared to an inferred 2 percent of wells in 1985.

• Drilling Wastes

The results from the 1995 E&P waste survey indicate an apparent decline in the use of oil and

saltwater based drilling fluids since 1985. In 1995, an estimated 93 percent of drilling wastes were derived

from freshwater based mud systems compared to 64 percent of drilling wastes in 1985. In 1995, 6 percent

of drilling wastes were produced from saltwater-based mud systems compared to 23 percent in 1985.

Finally, only 2 percent of drilling wastes were derived from oil based muds in 1995 compared to 7 percent of

wastes in 1985. Polymer and “other “ drilling fluids produced the remaining 6 percent of drilling wastes in

1985. In 1995, synthetic based drilling fluids produced less than 0.5 percent of drilling wastes from onshore

operations.

In 1995, almost 74 percent of drilling wastes were characterized as liquid wastes and 26 percent

were characterized as solid wastes. The total drilling wastes generated in 1995 are estimated to be 148.7

million barrels or about 1.21 barrels/wastes per foot drilled. An alternative drilling waste estimate

incorporates the survey-derived waste estimation factor for air-drilled wells of 0.07 barrels of waste per foot

drilled. This alternative national estimate of the total volume of drilling wastes is 132.8 million barrels or

about 1.08 barrels of waste per foot drilled. Most drilling wastes in 1995 were disposed onsite. Forty-seven

percent of drilling wastes was evaporated, 21 percent were buried onsite, 13 percent of drilling wastes were

injected and 7 percent were reused for drilling other wells. Seven percent of drilling wastes were land

spread and only 2 percent were disposed at commercial E&P waste facilities.

• Summary of Total Waste Volumes Disposed by Method in the United States

Table 5.1. 1995 Estimated Volume of E&P Wastes Disposed by Method (million barrels)

Disposal Method Produced

Water a

Drilling

Wastes

Associated

Wastes b

Total Waste

Volume

% Total

Wastes

Disposed

by Method

Injection (includes EOR) 16,386.5 19.0 7.9 16,413.7 90.8 %

Evaporation 0 69.9 2.3 72.2 0.4 %

Burial Onsite 0 31.2 0 31.2 0.2 %

Commercial E&P Waste Facility 90.3 3.0 3.1 96.4 0.5 %

Reuse, Recycle, Reclaim 358.1 10.4 3.9 372.4 2.1 %

Discharge 537.0 1.5 0 538.5 3.0 %

Land Spread 0 10.4 1.0 11.4

Road Spread 1.8 - 0.5 2.3 >0.1 %

All Other 537.0 3.0 1.9 541.9 3.0 %

Total 17,910.7 148.7 20.6 18,080.0 100.0%

a

Includes produced water removed at gas plants.

b

Includes associated wastes generated at gas plants.
29

REFERENCES

American Petroleum Institute. Basic Petroleum Data Book, Volume XVIII, Number 1, January 1998.

American Petroleum Institute. 1985 Production Waste Survey, Statistical Analysis and Survey Results,

October 1987.

American Petroleum Institute. 1985 Production Waste Survey, Part II - Associated and Other Wastes,

Statistical Analysis and Survey Results, June 1988.

Energy and Environmental Research Center, Onshore Gas-Well Drilling Wastes: Character, Distribution,

Management, and Research Issues report prepared for Gas Research Institute, March 1994.

Entropy Limited, Aboveground Storage Tank Survey report prepared for American Petroleum Institute,

April 1989.

Gruy and Associates, Inc., memorandum from M.A. Brown to Glenda Smith, American Petroleum Institute

and Bill Freeman, Shell E&P Technology Company, February 3, 1998.

Gruy and Associates, Inc., memorandum from M.A. Brown to Glenda Smith, American Petroleum Institute

and Bill Freeman, Shell E&P Technology Company, March 10, 1998.

Independent Petroleum Association of America. The Oil and Gas Producing Industry in Your State, 1996-

1997.

Oil & Gas Journal, 1995 Survey of Natural Gas Processing.
APPENDIX A

1995 PRODUCTION FACILITIES AND OIL AND GAS PRODUCTION

30

Table A.1. 1995 Producing Wells and Estimated Production Facilities by State

STATE

1995

Producing

Oil Wells a

1995

Producing

Gas Wells b

1995 Total

Producing

Wells

1995 Oil

Production

Facilities c

1995 Gas

Production

Facilities c

1995

Well

Completions d

AK 2,086 100 2,186 417 44 165

AL 913 3,526 4,439 302 1,728 176

AR 7,834 3,988 11,822 2,611 2,659 215

AZ 22 7 29 6 0 7

CA 39,365 997 40,362 8,610 421 1,293

CO 9,022 7,017 16,039 3,007 6,049 868

FL 85 0 85 21 0 1

IL 31,128 372 31,500 10,376 248 365

IN 7,135 1,347 8,482 2,162 806 106

KS 44,235 22,020 66,255 14,745 9,919 1,495

KY 23,538 13,311 36,849 7,846 8,874 763

LA 24,430 14,169 38,599 8,143 9,446 1,307

MI 4,079 5,258 9,337 1,360 3,081 873

MO 518 15 533 64 0 0

MS 1,516 535 2,051 444 304 155

MT 3,100 2,918 6,018 1,033 2,000 217

ND 3,171 99 3,270 1,057 63 150

NE 1,489 87 1,576 496 52 47

NM 17,976 23,510 41,486 5,753 18,069 1,005

NV 72 0 72 18 0 26

NY 3,670 6,134 9,804 918 3,008 33

OH 29,622 34,380 64,002 7,406 11,500 786

OK 91,289 29,733 121,022 22,822 14,669 1,797

OR 0 17 17 0 3 0

PA 18,157 31,792 49,949 5,295 18,094 570

SD 150 56 206 45 29 7

TN 701 0 701 186 258 52

TX 174,527 54,635 229,162 56,498 33,999 7,957

UT 1,851 1,127 2,978 617 571 230

VA 23 1,671 1,694 0 805 53

WV 17,436 35,148 52,584 5,784 23,978 385

WY 10,368 4,196 14,564 3,456 2,433 530

Total 569,508 298,165 867,673 171,498 173,110 21,634

a

API Basic Petroleum Data Book, Vol.18, No. 1, Table III-19.

b

API Basic Petroleum Data Book, Vol. 18, No. 1, Table III-17. 

c

 Memorandum from M.A. Brown, Gruy and Associates, Inc. to Glenda Smith, API dated March 10, 1998.

Status report for work performed under contract to American Petroleum Institute

d

 API Basic Petroleum Data Book, Vol. 18, No.1, Table III –15.

A.1. Estimated Oil and Gas Production Facilities

Table A.1 contains an estimated number of oil and gas production facilities by state. This estimate

of 1995 oil and gas production facilities was developed by Gruy and Associates for API to provide

supplemental data for extrapolation of API’s 1995 waste survey data. The estimate of 1995 production

facilities/tank batteries is compiled from several sources including standard industry data, a custom 1990

report prepared for API and Gruy Associates by the Petroleum Information Corporation (PI), other

proprietary company data, plus specific industry knowledge of contributing individuals.15

 

15 M.A. Brown, Gruy and Associates, March 10 1998 memorandum to Glenda Smith, American Petroleum Institute and Bill

Freeman, Shell E & P Technology Center.
APPENDIX A

1995 PRODUCTION FACILITIES AND OIL AND GAS PRODUCTION

31

The 1990 PI report lists all active producing wells and “reporting entities” for each state categorized

by producing rate and depth of production. A reporting entity usually corresponds to a lease or production

unit and is the point of product measurement and custody transfer. Stock tanks, separators, and other

treating equipment are usually located at the same site. Each lease must have separate metering and

treating facilities because the ownership of each lease is usually different. For states that require production

reported by lease, unit, or other custody transfer point, the number of production facilities/tank batteries can

be estimated fairly accurately.

Some states require oil production to be reported by well. For these states, the number of oil

production facilities/tank batteries is estimated with considerably less certainty. In areas where production is

shallow and the leases are relatively small, there are fewer producing wells per facility. In western states,

the leases tend to be larger and may have more wells per producing facility/tank battery. Deep wells are

generally widely spaced (up to one mile apart) and often have a production facility/tank battery for each well.

Shallow wells are more closely spaced and have more wells per producing facility/tank battery.

Gas wells are usually more widely spaced than oil wells. Overall, there are fewer gas wells per gas

facility than there are oil wells per oil facility. Most states require gas production to be reported by well or by

“gas unit”. When gas fields are first drilled there is usually only one gas well per unit and each unit has its

own facility. However, as gas fields mature and are infill drilled, several gas wells may be tied into the gas

unit facility. If a field has both oil wells and gas wells, the facilities may be located at the same site. This case

is considered to represent two facilities.

This document contains two different estimates for the number of gas production facilities, which

were derived differently. This appendix includes a large estimated number of facilities, based on PI data, as

described above. In Table 3-2 and Appendix B, figures are provided for condensate tank batteries, which

are essentially analogous to gas production facilities. The estimated number of condensate tank batteries

was derived from survey data. Comparing the two numbers and the number of gas wells per facility that

each represents, it seems likely that the actual number of gas production facilities/tank batteries is

somewhere between these two estimates.
APPENDIX A

1995 PRODUCTION FACILITIES AND OIL AND GAS PRODUCTION

32

Table A.2. Total 1995 Oil, Gas, and Natural Gas Liquids Production by State

STATE

Total 1995

 Oil Production a

(Mbbl)

Total 1995

Gas Production b

(MMcf)

Total 1995 Natural

Gas Liquids

Production c

(estimated)

(Mbbl)

AK 541,654 469,550 8,395

AL 18,731 519,661 33,945

AR 8,910 187,242 460

AZ 71 558 - 

CA 350,686 279,555 8,030

CO 27,976 523,084 14,600

FL 5,693 6,463 1,260

IL 16,190 335 145

IN 2,778 249 - 

KS 43,767 721,436 35,309

KY 3,492 74,754 1,582

LA 426,322 5,108,366 93,425

MI 11,383 238,203 4,597

MO 120 16 - 

MS 19,911 95,533 304

MT 16,529 50,264 322

ND 29,335 49,468 2,804

NE 3,794 2,240 9

NM 64,508 1,625,837 59,651

NV 1,342 13 - 

NY 304 18,400 - 

OH 8,258 126,336 84

OK 87,491 1,811,734 63,501

OR 0 1,923 - 

PA 1,939 111,000 104

SD 1,344 1,252 - 

TN 382 1,820 - 

TX 600,527 6,330,048 264,512

UT 19,988 241,290 2,329

VA 12 49,818

WV 1,948 186,231 7,891

WY 78,884 673,775 10,368

Total 2,394,269 19,506,454 613,627

a

API Basic Petroleum Data Book, Vol. 18, No. 1, Table IV-5.

b

API Basic Petroleum Data Book, Vol. 18, No. 1, Table XIII-9.

c IPAA, The Oil and Gas Industry in Your State, 1996-1997.
APPENDIX B

PRODUCTION PITS, TANK BATTERIES, TANKS

33

Table B.1. Production Pits – Reported Data

Percentage of Total Pits

State

Total

Production

Pits

Reported

Total

Workover

Pits

Total

Active

Pits

Total

Inactive

Pits

Total

Lined

Pits Workover Active Inactive Lined

AK 7 0 7 0 7 100% 100%

AL 48 0 48 0 48 100% 100%

AR 0 0 0 0 0

CA 234 27 209 25 87 12% 89% 11% 37%

CO 884 6 881 3 846 1% 100% 96%

FL 5 0 5 0 5 100% 100%

IL 1 0 1 0 1 100% 100%

KS 7 0 7 0 0 100% 0%

LA 22 0 17 5 0 77% 23% 0%

MI 0 0 0 0 0

MS 2 0 2 0 2 100% 100%

MT 39 1 38 1 5 3% 97% 3% 13%

ND 8 0 8 0 0 100% 0%

NE 4 0 2 2 0 50% 50% 0%

NM 5 0 0 5 0 100% 0%

OK 0 0 0 0 0

TX 310 282 307 3 300 91% 99% 1% 97%

UT 498 38 468 30 143 8% 94% 6% 29%

WY 370 253 369 1 1 68% 100% 0%

Total 2,444 607 2,369 75 1,445 25% 97% 3% 59%
APPENDIX B

PRODUCTION PITS, TANK BATTERIES, TANKS

34

Table B.2. Estimated Number of Production Pits

State Dataa (Where Available)

State

Estimated

Total Number

of Pits

Workover

Pits

Active

Pits

Inactive

Pits

Total

Number of

Lined Pits Comments

AK 400 Assumes 1 pit per oil production

facility

AL 2,000 Assumes 1 pit per oil and gas

production facility

AR no pits reported

CA 8, 600 Assumes 1 pit per oil production

facility

CO 9, 271 "unknown" 9, 271 "unknown" 588 1998 data from state

FL 20 Assumes 1 pit per oil production

facility

IL 10,400 Assumes 1 pit per oil production

facility

KS 14,700 Assumes 1 pit per oil production

facility

LA 8,099 5,339

"reserve"

1,795

 "open

prod."

965

 "orphan

prod."

402 1997/ 98 State data b

MI no pits reported

MS 48 48 48 1997/ 98 State data b

MT 3,000 Assumes 1 pit per oil and gas

production facility

ND 1,100 Assume 1 pit per oil production

facility

NE 500 Assume 1 pit per oil production

facility

NM 5,800 Assume 1 pit per oil production

facility

OH 0 1998 data from state

OK 93 1998 data from state

TX 4,830c"unknown" 4,830 "unknown" 2,490 1998 data from state

UT 1,200 Assume 1 pit per oil and gas

production facility

WY 3,500 800 3,500 1997/ 98 State estimate b

Total d55,690

a

 Where data was available from a state agency, either estimates or reported data, these have been provided.

b

 Source: Gruy memorandum, 1998.

c

 This likely understates the total number of production pits in the state. In Texas, certain types of pits require

permits, while some types of production pits do not require permits. This includes permitted pits only.

d

 Assumes zero pits in the Appalachian states. No survey respondents from Appalachian states reported pits. 

Recent state data from Ohio (6/99) indicates that Ohio has no active production pits.
APPENDIX B

PRODUCTION PITS, TANK BATTERIES, TANKS

35

Table B.3. Oil Tank Batteries and Oil Tanks – Reported Data

State

Active Oil

Wells

Reported

Oil Tank

Batteries

Oil

Tanks

Oil Tanks

per Tank

Battery

 Waste

Oil/

Water

Tanks

Produced

Water

Tanks

Produced

Water Tanks

per Tank

Battery

Emergency

Tanks

Total

Tanks per

Oil Tank

Battery

AK 355 11 9 1 6 7 1 11 3

AL 140 24 135 6 3 49 2 0 8

AR 5 5 10 2 0 7 1 0 3

CA 6,570 152 308 2 73 101 1 70 4

CO 437 67 101 2 3 44 1 4 2

FL 50 1 2 2 0 2 2 0 4

IL 291 14 29 2 2 26 2 3 4

KS 497 174 343 2 5 112 1 9 3

LA 330 79 190 2 8 74 1 28 4

MI 6 1 2 2 0 1 1 0 3

MS 125 41 183 4 2 66 2 0 6

MT 425 41 129 3 3 22 1 11 4

ND 8 8 20 3 0 8 1 0 4

NE 3 3 7 2 0 1 0 0 3

NM 16 10 19 2 0 3 0 0 2

OK 72 52 113 2 15 16 0 9 3

TX 5,599 1,647 3,475 2 508 1,209 1 926 4

UT 486 264 416 2 6 346 1 18 3

WY 1,064 114 351 3 7 136 1 0 4

Total

(excluding

Appalachian

States)

16,479 2,708 5,842 2 641 2,230 1 1,089 4

Appalachian

States:

Active Oil

Wells

Reported Oil Tanks

Oil

Wells

per Oil

Tank

Produced

Water

Tanks

Oil Wells

per

Produced

Water

Tank

 Waste

Oil/

Water

Tanks

Emergency

Tanks

Total Tanks

Reported

Total Oil

Wells per

Tank

KY 340 15 23 3 113 0 0 18 19

NY 125 11 11 4 31 0 0 15 8

OH 8 17 0.5 9 1 0 0 26 0.3

PA 8 0 0 0 0 0

VA 1 2 0.5 0 0 0 0 2 1

WV 230 41 6 13 18 0 0 54 4

Total -

Appalachian

States

712 86 8 29 24 0 0 115 6
APPENDIX B

PRODUCTION PITS, TANK BATTERIES, TANKS

36

Table B.4. Condensate Tank Batteries and Condensate Tanks – Reported Data

State

Active Gas

Wells

Reported

Condensate

Tank

Batteries

Condensate

Tanks

Condensate

Tanks per

Battery

 Waste

Oil/ Water

Tanks

Produced

Water

Tanks

Produced

Water

Tanks per

Battery

Emergency

Tanks

Total Tanks

per

Condensate

Tank Battery

AK 15 1 0 0 2 1 1 3 6

AL 976 2 2 1 26 15 8 0 22

AR 152 3 9 3 0 33 11 0 14

CA 47 1 0 0 1 1 1 0 2

CO 1,516 816 974 1 8 212 0 1 1

FL 0 0 0 0 0 0 0 0 0

IL 0 0 0 0 0 0 0 0 0

KS 4,960 40 60 2 2 2,269 57 1 58

LA 89 51 118 2 6 15 0 2 3

MI 45 1 1 1 3 3 0 4

MS 15 2 2 1 0 0 1

MT 23 0 0 0 0 0 0 0 0

ND 0 0 0 0 0

NE 0 0 0 0 0

NM 878 251 278 1 1 611 2 583 6

OK 226 58 70 1 6 148 3 0 4

TX 413 61 84 1 4 78 1 0 3

UT 361 322 322 1 0 0 0 2 1

WY 32 20 29 1 3 24 1 13 3

Total

(excluding

Appalachian

States)

9,748 1,629 1,949 1 59 3,410 2 605 4

Appalachian

States:

Active Gas

Wells

Reported

Condensate

Tanks

Gas Wells

per

Condensate

Tank

Produced

Water

Tanks

Gas Wells

per

Produced

Water

Tank

 Waste 

Water

Tanks

Emergenc

y Tanks

Total Tanks

Reported

Total Active

Gas Wells per

Tank

KY 4,127 1,038 4 1,776 2 15 0 2,829 1

NY 108 0 0 113 1 1 0 114 1

OH 333 351 1 116 3 0 0 467 1

PA 1,124 19 59 981 1 51 4 1,055 1

VA 908 39 23 443 2 11 0 493 2

WV 1,062 32 33 353 3 395 0 780 1

Total -

Appalachian

States

7,662 1,479 5 3,782 2 473 4 5,738 1
APPENDIX B

PRODUCTION PITS, TANK BATTERIES, TANKS

37

Table B.5. Estimated Oil Tank Batteries and Total Tanks

Associated With Oil Production Facilities

State

1995 Active Oil

Wells

Estimated Oil Tank

Batteries a

Estimated Total

Tanks per Tank

Battery b

Estimated Total Tanks

(Associated w/ Oil

Production Facilities)

AK 2,086 417 3 1,251

AL 913 302 8 2,416

AR 7,834 2,611 3 7,833

AZ 22 6 4 24

CA 39,365 8,610 4 34,440

CO 9,022 3,007 2 6,014

FL 85 21 4 84

IL 31,128 10,376 4 41,504

IN 7,136 2,162 4 8,648

KS 44,235 14,745 3 44,235

LA 24,430 8,143 4 32,572

MI 4,079 1,360 3 4,080

MO 518 64 4 256

MS 1,516 444 6 2,664

MT 3,100 1,033 4 4,132

ND 3,171 1,057 4 4,228

NE 1,489 496 3 1,488

NM 17,976 5,753 2 11,506

NV 72 18 4 72

OK 91,289 22,822 3 68,466

OR 0 0 4 0

SD 150 45 4 180

TX 174,527 56,498 4 225,992

UT 1,851 617 3 1,851

WY 10,368 3,456 4 13,824

Estimated Total

(excluding

Appalachian

States)

476,362 144,063 517,760

Appalachian

States:

1995 Active Oil

Wells

Estimated Oil Tank

Batteries a

Estimated Total

Tanks

(based on wells) c

Estimated Total Tanks

(based on facilities) d

KY 23,538 7,846 3,923 31,384

NY 3,670 918 459 3,672

OH 29,622 7,406 4,937 29,624

PA 18,157 5,295 3,026 21,180

TN 701 186 117 744

VA 0 0 0 0

WV 17,436 5,784 4,359 23,136

Estimated

Appalachian Total 93,124 27,435 16,821 109,740

Estimated National

Total 569,486 171,498 627,500

a

 Equals estimated number of oil production facilities

b

 Based on reported data for state

c

 Based on reported survey data for Appalachian States; average 6 oil wells per tank

d

 Based on national estimate of 4 tanks per production facility or oil tank battery.
APPENDIX B

PRODUCTION PITS, TANK BATTERIES, TANKS

38

Table B.6. Estimated Condensate Tank Batteries and Total Tanks

 Associated with Gas Production Facilities

State 1995 Gas Wells

Estimated

Number of Gas

Production

Facilities a

Estimated

Condensate

Tank Batteries b

Estimated Total

Tanks per Tank

Battery c

Estimated Total

Tanks at Gas

Production

Facilities

AK 109 44 18 6 109

AL 3,455 1,728 576 22 12,668

AR 3,988 2,659 665 2

d

1,329

AZ 0 0 0 2 0

CA 962 421 160 2 321

CO 7,259 6,049 1,210 1 1,210

FL 0 0 0 2 0

IL 372 248 62 2 124

IN 1,330 806 222 2 443

KS 14,878 9,919 2,480 3

d

7,439

LA 14,169 9,446 2,362 3 7,085

MI 4,621 3,081 770 4 3,081

MO 0 0 0 2 0

MS 518 304 86 1 86

MT 3,000 2,000 500 2 1,000

ND 94 63 16 2 31

NE 78 52 13 2 26

NM 28,231 18,069 4,705 6 28,231

NV 0 0 0 2 0

OK 29,337 14,669 4,890 4 19,558

OR 18 3 3 2 6

SD 49 29 8 2 16

TX 49,639 33,999 8,273 3 24,820

UT 1,142 571 190 1 190

WY 3,649 2,433 608 3 1,825

Estimated Total

(excluding

Appalachian

States)

166,898 106,593 27,816 109,598

Appalachian

States: 1995 Gas Wells

Estimated

Number of Gas

Production

Facilities a

Estimated

Condensate

Tank Batteries b

Estimated Total

Tanks

(based on

wells) e

Estimated Total

Tanks

(based on

facilities) f

KY 13,311 8,874 2,219 10,239 8,874

NY 6,016 3,008 1,003 4,628 4,011

OH 34,501 11,500 5,750 26,539 23,001

PA 31,025 18,094 5,171 23,865 20,683

TN 485 258 81 373 323

VA 1,610 805 268 1,238 1,073

WV 36,144 23,978 6,024 27,803 24,096

Estimated

Appalachian

Total

123,092 66,517 20,515 94,686 82,061

Estimated

National Total 289,990 173,110 48,332 204,284 191,659

a

 From Appendix G b Based on 6 gas wells per tank battery (from reported data)

c

 Based on reported data for state d When outliers in Kansas and Arkansas are removed (responses reporting

unusually large number of produced water tanks), national estimate of tanks per condensate tank battery is 2 to 3

tanks per battery. e Based on survey reported data; average 1.3 gas wells per tank

f Based on estimated number of tank batteries and national estimate of 4 tanks per gas production facility/tank

battery.
APPENDIX B

PRODUCTION PITS, TANK BATTERIES, TANKS

39

Table B.7. Gas Plants, Non-Pressurized Tanks – Reported Data

Region

# Plants in

Region a

Reported

No.

Produced

Water

Tanks

Reported No.

Condensate

Tanks

Reported

No. Liquid

Product

Tanks

Reported No.

Emergency

Tanks

Alaska 3 0 0 18 1

California 25 0 0 0 0

Eastern U.S. 47 3 14 41 4

Mid-West 92 5 4 3 0

New Mexico 27 3 10 15 4

Rockies 104 9 10 27 6

Southeast 68 13 13 13 1

Texas 233 30 12 22 8

Total 599 63 63 139 24

a

 Based on 1996 Oil and Gas Journal survey.
APPENDIX C

PRODUCED WATER

40

Table C.1. Estimated Volume of Produced Water by State

(1,000 barrels/year)

State

Estimated Volume of

Produced Water a NOTES

AK 1,090,000 Estimated from survey response & 1995

production

AL 320,000 Estimated from survey response & 1995

production for state

AR 110,000 Estimated from survey response & 1995

production

AZ 100 Estimated from survey response & 1995

production for state

CA 1,684,200 PI estimate

CO 210,600 PI estimate

FL 76,500 PI estimate

IL 285,000 state estimate

IN 48,900 Based on bbl PW/bbl oil ratio for IL

KS 683,700 State estimate

KY 3,000 Estimated from survey response

LA 1,346,400 State estimate adjusted for onshore/coastal

production only

MI 52,900 PI estimate

MO 100 Estimated from survey response

MS 234,700 PI estimate

MT 103,300 State estimate

ND 79,800 State estimate

NE 61,200 PI

NM 706,000 Estimated from survey response

NV 6,700 State

NY 300 Estimated from survey response

OH 7,900 State estimate

OK 1,642,500 State estimate

OR 40 State estimate

PA 2,100 State estimate

SD 4,000 State estimate

TN 400 Estimated from survey response

TX 7,630,000 State estimate

UT 124,600 PI estimate

VA 300 Estimated from survey response

WV 6,000 Estimated from survey response

WY 1,401,000 PI estimate

Total 17,922,240

a State data were used where available. PI estimate is from the Petroleum Information Corp.

produced water database. If state or PI estimates for 1995 were not available, the produced

water volume for a state was estimated from 1995 production for the state using extrapolation

factors developed from the 1995 survey responses.
APPENDIX C

PRODUCED WATER

41

Table C.2. Produced Water Volumes Disposed by Method – Reported Data

(Barrels/day and Percentages)

State

 Reported

Volume

Produced

Water

(b/d)

Inject for

EOR

(b/d)

% PW

Inject

for EOR

Injected for

Disposal

Onsite (b/d)

% PW

Inject

Onsite

Injected

Offsite

(b/d)

 % PW

Inject

Offsite

Injected @

Commercial

Facility (b/d)

% PW

Inject @

Comm.

Facility

Treat and

Discharge

(b/d)

% PW

Treat and

Discharge

Reuse

(b/d)

% PW

Reuse

AK 797,037 787,500 99% 9,500 1% 37 <0.01%

AL 151,897 206 0.1% 8,087 5% 1,710 1% 141,894a 93%

AR 302 276 91% 1 0.3%

CA 713,904 365,844 51% 179,573 25% 5,050 0.7%

CO 322,505 269,525 84% 52,828 16% 11 <0.01% 141 0.04%

FL 190,550 190,550 100%

IL 79,650 79,650 100%

KS 75,533 3,646 5% 64,302 85% 7,356 10% 225 0.3%

KY 518 34 7% 465 90% 19 4%

LA 131,645 131,645 100%

MI 1,838 1,708 93% 130 7%

MS 74,045 74,045 100%

MT 137,616 119,735 87% 2,302 2% 555 0.4% 22 0.02% 15,000 11%

ND 29 29 100%

NE 524 44 8%

NM 7,086 5,405 76% 507 7% 1,175 17%

NY 213 210 99%

OH 107 96 90% 11 10%

OK 6,575 4,706 72% 997 15% 10 0.2% 862 13%

PA 198 61 31% 86 43%

TX 1,226,786 831,820 68% 276,872 23% 97,652 8% 17,478 1% 2,964 0.2%

UT 113,214 65,000 57% 36,368 32% 7,533 7% 4,313 4%

VA 568 550 97% 18 3%

WV 736 661 90% 6 1% 10 1% 59 8%

WY 775,879 689,206 89% 6,600 1% 21 <.01% 80,000 10%

Survey

Total 4,808,955 3,408,083 71% 851,108 18% 121,133 2.5% 24,386 0.5% 142,227 3% 97,964 2%

a In Alabama, surface discharge of produced water is allowed under NPDES permits for coalbed methane operations. 
APPENDIX D

ASSOCIATED WASTES

42

Table D.1. Associated Waste Volume by State – Reported Data

(Barrels per year)

State

Reported

Volume

Completion

Fluids

Reported

Volume

Stimulation

Fluids

Reported

Volume Tank

Bottoms/ Oily

Sludge

Reported

Volume

Dehydration/

Sweetening

Wastes

Total Reported

Volume

Associated

Waste

AK 0 110 15,051 16 15,177

AL 0 5,600 1,955 0 7,555

AR 0 0 0 0 0

CA 262,300 155,020 39,600 1,042 457,962

CO 156,071 177,157 6,800 0 340,028

FL 0 595 1,051 0 1,646

IL 3,650 8,600 460 0 12,710

KS 66,670 26,620 1,430 1,600 96,320

KY 2,250 850 70 0 3,170

LA 3,242 55,700 258 18 59,218

MI 0 200 0 80 280

MS 0 0 4,600 0 4,600

MT 37,000 9,635 2,300 0 48,935

ND 0 0 100 0 100

NE 0 0 0 0 0

NM 11,800 17,000 0 238 29,038

NY 500 250 10 2 762

OH 1,200 2,000 0 0 3,200

OK 3,900 20,000 825 270 24,995

PA 14,000 3,200 0 0 17,200

TX 19,580 19,375 29,699 20 68,674

UT 0 32,895 888 0 33,783

VA 5,050 530 0 10 5,590

WV 20,800 13,262 2,670 0 36,732

WY 700 26,000 6,700 0 33,400

Survey Total 608,713 574,599 114,467 3,296 1,301,075
APPENDIX D

ASSOCIATED WASTES

43

Table D.2. Estimated Volume of Associated Wastes by State

(Barrels/Year)

State

 Completion

Fluids a

Workover/

Stimulation

Fluids b

 Tank Bottoms/

Oily Sludges c

 Dehydration/ Gas

Sweetening

Wastes d

Total Estimated

Associated

Wastes

AK 72,800 18,500 217,800 5,130 314,230

AL 77,600 22,300 25,200 5,670 130,770

AR 94,800 201,000 9,900 2,040 307,740

AZ 2,300 700 100 10 3,110

CA 431,300 945,600 220,300 29,290 1,626,490

CO 382,800 305,000 35,900 5,710 729,410

FL 400 1,000 400 10 1,810

IL 57,900 931,000 15,800 320 1,005,020

IN 16,900 144,200 14,300 2,070 177,470

KS 939,200 366,600 207,300 7,880 1,520,980

KY 65,000 24,600 19,400 1,840 110,840

LA 571,400 656,200 217,300 9,080 1,453,980

MI 385,000 143,600 12,600 8,560 549,760

MO 0 9,100 3,600 30 12,730

MS 68,400 34,900 10,800 1,040 115,140

MT 95,700 135,800 9,500 550 241,550

ND 66,200 75,200 12,600 540 154,540

NE 20,700 26,800 1,500 80 49,080

NM 494,600 788,900 80,900 2,150 1,366,550

NV 8,700 1,700 400 20 10,820

NY 1,200 10,500 2,000 490 14,190

OH 295,900 375,400 12,800 3,200 687,300

OK 1,427,300 968,200 121,000 19,780 2,536,280

OR 0 300 0 10 310

PA 443,300 308,600 10,000 4,990 766,890

SD 3,100 3,500 1,000 90 7,690

TN 17,600 2,800 200 40 20,640

TX 2,152,900 1,882,200 619,900 69,110 4,724,110

UT 101,400 115,700 10,400 2,630 230,130

VA 9,400 1,500 200 540 11,640

WV 195,300 539,800 10,500 2,630 748,230

WY 279,200 485,500 83,100 7,360 855,160

Total 8,778,300 9,526,700 1,986,700 192,890 20,484,590

a

 Extrapolated on number of completed wells

b

 Extrapolated on number of active oil and gas wells

c

 Extrapolated on oil and gas production

d

 Extrapolated on gas production.
APPENDIX D

ASSOCIATED WASTES

44

Table D.3. Volume of Completion Fluids and Workover/Stimulation Fluids

by Disposal Method – Reported Data

Associated Waste

Disposal Method

%

Completion

Fluids

VolumeCompletion

Fluids

(Bbls./Year)

% Workover/

Stimulation

Fluids

Volume –

Workover/

Stimulation

Fluids

(Bbls./Year)

Disposal by injection 21.3% 129,605 59.1% 339,714

Landspread within field 6.0% 36,275 1.9% 11,130

Landspread outside field 0% 0 0% 0

Roadspread w/in field 0% 0 < 0.1% 100

Roadspread outside field 0.4% 2,500 0.3% 1,500

Commercial E&P waste facility 28.8% 175,142 3.9% 22,380

Industrial or municipal landfill 0% 0 0% 0

Crude oil reclamation 0.1% 500 0% 45

Recycling/beneficial reuse 32.9% 200,450 < 0.1% 3

Incinerate 0% 0 1.0% 5,503

Evaporate from pits or tanks 8.0% 48,441 16.3% 93,833

Other: 2.6% 15,800a17.5% 100,392b

Total (Bbls./Yr.) 100% 608,713 100.0% 574,599

a

 Land treatment disposal site within field

b

 Land treatment and onsite burial
APPENDIX D

ASSOCIATED WASTES

45

Table D.4. Volume of Tank Bottoms/Oily Sludge and Dehydration/Sweetening Wastes

by Disposal Method – Reported Data

Associated Waste Disposal

Method

% Tank

Bottoms/

Oily Sludge

VolumeTank

Bottoms/

Oily Sludge

(Bbls./Year)

%

Dehydration/

Sweetening

Wastes

Volume –

Dehydration/

Sweetening

Wastes

(Bbls./Year)

Disposal by injection 23.9% 27,311 4.2% 140

Landspread within field 9.0% 10,256 8.2% 270

Landspread outside field 7.5% 8,621 0% 0

Roadspread within field 17.4% 19,885 0% 0

Roadspread outside field 0.3% 400 48.5% 1,600a

Commercial E&P waste facility 2.0% 2,327 31.7% 1,045

Industrial or municipal landfill < 0.1% 3 0% 0

Crude oil reclamation 18.3% 20,973 0% 0

Recycling/beneficial reuse 19.0% 21,738 6.8% 223

Incinerate <0.1% 44 0.1% 2

Evaporate from pits or tanks 0.2% 200 0% 0

Other: 2.4% 2,709b0.5% 16c

Total (Bbls./Yr.) 100.0% 114,467 100.0% 3,296

a

 Volume is reported by a single respondent. If this volume is excluded from total, 62.5% of

dehydration wastes are disposed at commercial disposal facility.

b

 Respondents noted this as oil containment berms and working pits.

c

 Respondent noted this as commercial disposal.
APPENDIX D

ASSOCIATED WASTES

46

Table D.5. Total Associated Waste; Percentage Waste Disposed by Method – Reported Data

State

%

Disposal

by

Injection

 % Land

Spread

within

Field

% Land

Spread

outside

of Field

 % Road

Spread

within

Field

 % Road

Spread

outside

of Field

 %

Comm.

E&P

Waste

Disposal

% to 

Landfill

 %

Crude

Oil

Reclaim.

%

Recycle/

Beneficial

Use Incinera

AK 98.8% 1.1%

AL 76.7% 13% 0.1% 10.0%

AR No waste volumes reported

CA 1.5% 3% 1.0% 2% 0.2% 0.7% 48.3%

CO 52.0% 2% 46.0% 0.2%

FL

IL 99.2% 1%

KS 77.8% 6% 1.6% 1.5%

KY 15.8% 82% 1.3% 1%

LA 12.0% 32.3%

MI 100.0%

MS 97.8% 2.0%

MT 87.8% 0.2% 0.6%

ND 100.0%

NE

NM 55.1% 8.0%

NY 13.1% 3% 13% 0.4% 6.6% 59.6%

OH 100.0%

OK 89.6% 1% 1% 1% 6.1% 0.8%

PA 18.6% 81.4%

TX 63.7% 3.0% 12% 5.7% 14.2% 0.1%

UT 96.9% 2.5%

VA 100% 0.2%

WV 16.1% 84%

WY 78.8% 6.0% 10% 0.6% 4.5%

Survey

Total 38.2% 4% 0.7% 2% 0.5% 15.4% < 0.10% 1.7% 17.1%
APPENDIX D

ASSOCIATED WASTES

47

Table D.6. Total Associated Waste; Volume of Waste Disposed by Method – Reported Data

(Barrels per Year)

State

Disposed

by Injection

Land

Spread

within

Field

Land

Spread

outside

of Field

Road

Spread

within

Field

Road

Spread

outside of

Field

Comm. E&P

Waste

Disposal Landfill

 Crude

Oil

Reclaim.

Recycle/

Beneficial

Use Incinerated

AK 15,000 161

AL 5,796 1,000 4 755

AR No waste volumes reported

CA 7,060 12,400 4,500 7,300 800 3,000 221,000 2

CO 176,908 6,000 156,320 770 30

FL 42

IL 12,610 100

KS 74,899 5,600 1,500 1,430

KY 500 2,600 42 28

LA 7,100 19,105 13 5,500

MI 280

MS 10 4,500 90

MT 42,985 100 300

ND 100

NE

NM 16,000 2,330 8 0

NY 100 25 100 0 3 50 454 5

OH 3,200

OK 22,400 270 300 300 1,525 200

PA 3,200 14,000

TX 43,730 246 2,079 8,057 0 3,910 0 9,764 63

UT 32,750 833

VA 5,580 10

WV 5,932 30,800

WY 26,320 2,000 3,200 200 1,500

Survey

Total 496,770 57,931 8,621 19,985 6,000 200,894 3 21,518 222,413 5,549
APPENDIX E

DRILLING WASTES

48

Table E.1. Percentage of New Wells Drilled by Technique - Reported Data

State

No. Of 

 New 

 Wells

 % With 

 Mud 

 Reserve 

 Pits

% With 

 Closed

System

% With Air,

Gas, or

Pneumatic

Drilling

% With

Cable

Tool

% Of Mud

Reserve

Pits -

Lined

Number of

Responses

AK 11 100% 1

CA 349 79% 21% 0% 8

CO 9 78% 22% 0% 2

IL 25 96% 4% 0% 2

KS 306 39% 61% 17% 6

LA 21 100% 71% 4

MI 7 100% 100% 1

MT 7 100% 86% 2

NM 11 27% 73% 100% 3

OK 14 64% 36% 22% 2

TX 349 99% 1% 87% 8

UT 9 22% 56% 22% 100% 3

WY 2 100% 100% 1

Survey Total 1,120 74% 25% 1% < 0.1% 69% 43

Appalachian

States:

KY 22 5% 95% 0% 3

NY 14 100% Not reptd. 1

OH 3 38% 62% 33% 3

PA 26 100% Not reptd. 2

VA 16 100% Not reptd. 2

WV 38 3% 97% 100% 4

Appalachian

Total 124 4% 0% 96% 0% 15

Nationwide

Total 1,244 66% 23% 11% < 0.1% 69% 58
APPENDIX E

DRILLING WASTES

49

Table E.2. Percentage of Drilling Wastes by Base Drilling Fluid – Reported Data

Percentage of Wastes by Base Fluid

State Freshwater Saltwater Oil Synthetic

No. Of

Responses

AK 70% 30% 1

CA 98% 1.5% 0.5% 8

CO 100% 2

IL 100% 2

KS 99% 1% 6

LA 93% 7% 4

MI 100% 1

MT 14% 86% 2

NM 82% 16% 2% 3

OK 63% 37% 2

TX 93% 7% 8

UT 100% 3

WY 100% 1

Appalachian

States:

KY Air drill only

NY Air drill only

OH 67% 33% 3

PA Air drill only

VA Air drill only

WV 83% 17% 1
APPENDIX E

DRILLING WASTES

50

Table E.3. Estimated Percentage of Drilling Wastes by Base Drilling Fluid

Percentage of Wastes by Base Fluid

State

Estimated

Volume Drilling

Wastes

Reported by

Respondents a

(barrels) Freshwater Saltwater Oil Synthetic

No. of

Responses

AK 111,000 70% 30% 1

CA 506,000 98% 1.5% 0.5% 8

CO 63,000 100% 2

IL 28,000 100% 2

KS 922,000 99% 1% 6

LA 342,000 93% 7% 4

MI 13,000 100% 1

MT 89,000 14% 86% 2

NM 21,000 82% 16% 2% 3

OK 95,000 63% 37% 2

TX 2,812,000 93% 7% 8

UT 131,000 100% 3

WY 30,000 100% 1

Estimated

Survey

Total

5,163,000 92.5% 5.5% 1.3% < 0.6% 43

a Estimated volume of drilling waste for rotary drilling w/ open mud system. Air/pneumatic drilling

is excluded. Estimate is based on reported footage drilled multiplied by appropriate factors for

drilling waste volume per foot by depth category. This is not, and should not be interpreted as, a

total volume of drilling waste (see Table 3.9). This is based on the respondents only and was

used solely to calculate national average distribution of drilling wastes by base fluid.
APPENDIX E

DRILLING WASTES

51

Table E.4. Appalachian States, Volumes of Drilling Wastes – Reported Data

State

Footage

Drilled –

Rotary w/ mud

Footage

Drilled –

Air

Drilling

Volume of

Drilling

Wastes to

Mud

Reserve

Pits

Volume of

Drilling

Wastes –

Air/Pneum.

Drilling

Drilling

Wastes to

Reserve Pit:

Approx.

Volume per

Foot Drilled

(bbl

waste/ft)

Air Drilling

Wastes:

Approx.

Volume per

Foot Drilled

(bbl

waste/ft.)

Total

Number of

Responses

KY 0 80,000 0 2,000 N/A 0.025 1

OH 11,890 32,760 1,900 2,800 0.16 0.085 3

PA 0 55,800 0 2,900 N/A 0.052 1

WV 1,740 232,920 800 20,300 0.46 0.087 3

TOTAL 13,630 401,480 2,700 28,000 0.20 0.070 8

Table E.5. Alternative Estimation of Total Drilling Waste for Appalachian States and Other States

with Significant Air Drilling

State

1995 Total

Footage

Drilled for

State a (ft)

Estimated

1995

Footage

Drilled w/

Mud b (ft)

Estimated

1995

Footage

Drilled w/

Air b (ft)

Estimated

1995 Volume

of Drilling

Wastes -

Rotary Drill w/

Mud c (bbls)

Estimated

1995 Volume

of Drilling

Wastes – Air

Drill d (bbls)

Total

Alternative

Estimated

Volume of

Drilling Wastes

for State (bbls)

NM 5,752,500 1,553,175 4,199,325 2,003,596 293,953 2,297,549

OK 11,857,800 7,588,992 4,268,808 8,423,781 298,817 8,722,598

UT 929,400 724,932 204,468 1,217,886 14,313 1,232,199

Appalachian

States:

KY 1,465,100 73,255 1,391,845 104,755 97,429 202,184

NY 108,000 4,320 103,680 5,530 7,258 12,788

OH 3,073,700 1,168,006 1,905,694 654,083 161,984 816,067

PA 2,357,100 94,284 2,262,816 97,113 158,397 255,510

TN 93,000 3,720 89,280 8,891 6,250 15,141

VA 139,900 0 139,900 0 9,793 9,793

WV 1,585,000 47,550 1,537,450 25,677 133,758 159,435

Appalachian

Total: 8,821,800 1,391,135 7,430,665 896,049 574,869 1,470,918

a

 From Table 3.9, “Estimated Total Volume of Drilling Wastes”

b

 From Table E.1, “Percentage of New Wells Drilled by Technique.” (Total for all the Appalachian States is applied

to PA, NY, TN)

c

 (Column 3) x (waste extrapolation factor, bbl waste per foot drilled, from API 1985 Production Waste Survey)

d (Column 4) x (estimated extrapolation factor for air drilling, 0.07 bbl waste per foot drilled, from Table E.4)
APPENDIX E

DRILLING WASTES

52

Table E.6. Liquid Drilling Waste Disposal- Reported Data (as % of Total Drilling Wastes)

Percentage of Total Drilling Waste Disposed by Method

State Injection

Down

Annulus

Treat &

Discharge

Road

Spread

Evaporate

On or

Offsite

Land

Spread

Onsite

Land

Spread

Offsite

 Reuse

for

Drilling Other Response

AK 50% 1

AR 70% 1

CA 19% 44% <0.1% 1.2% 14%a8

CO 36% 52% 2

IL 83% 2

KS 1% 19% 37% 6

LA 7% 45% 1% 10% 0.5% 4

MI 80% 1

MT 51% 10% 2

NM 4% 78% 3% 3

OK 1% 49% 2

TX 1% 0.1% 82% 0.9% 2% 8

UT 39% 5% 3

WY 50% 1

Appalachian States:

KY 64% 6% 3

NY No liquid wastes reported; air drilling only 1

OH 74% 3

PA 7% 32%b2

VA 56% 4% 2

WV 22% 13% 4

a liquids and solids remediated onsite

b

 commercial disposal facility
APPENDIX E

DRILLING WASTES

53

Table E.7. Solid Drilling Waste Disposal- Reported Data (As % of Total Drilling Wastes)

Percentage of Total Drilling Waste Disposed by Method

State

Buried

Onsite

Land

Spread

Onsite

Land

Spread

Offsite

Commercial

Disposal

Facility

Industrial or

Municipal

Landfill

 Reuse

or

Recycle Other Response

AK 50%a1

AR 30% 1

CA 21% 0.3% 0.1% 0.2% 0.1% 8

CO 3% 9% 2

IL 1% 16% 2

KS 42% 6

LA 20% 4% 13% 4

MI 20% 1

MT 39% 2

NM 13% 3% 3

OK 50% 2

TX 13% 0.3% 0.1% 0.6% 0.1%b8

UT 56% 3

WY 50% 1

Appalachian States:

KY 28% 2% 3

NY 100% 1

OH 26% 3

PA 2% 59% 2

VA 40% 2

WV 66% 4

a

 grind and inject in Class II well

b

 pit
APPENDIX E

DRILLING WASTES

54

Table E.8. Estimated Volume of Liquid Drilling Wastes Disposed by Method;

Estimated for States with Reported Data (Barrels)

State

Est. Total

Volume

Drilling

Wastes for

State Injection

Injected

Down

Annulus

Treat &

Discharge

Road

Spread

Evaporate

On or

Offsite

Land

Spread

Onsite

Land

Spread

Offsite

Reuse for

Drilling Other

AK 1,605,000 803,000

AR 2,643,000 1,850,000

CA 1,826,000 347,000 804,000 1,000 22,000 256,000

CO 3,582,000 1,290,000 1,863,000

IL 382,000 317,000

KS 4,810,000 48,000 914,000 1,780,000

LA 22,477,000 1,573,000 10,115,000 225,000 2,245,000 112,000

MI 1,731,000 1,385,000

MT 1,366,000 697,000 137,000

NM 7,421,000 297,000 5,788,000 223,000

OK 13,162,000 132,000 6,449,000

TX 65,367,000 654,000 65,000 53,601,000 588,000 1,307,000

UT 1,561,000 609,000 78,000

WY 4,374,000 2,187,000

Total Volume

(excludes

Appalachian

States):

132,307,000 7,529,000 10,115,000 0 65,000 65,666,000 4,657,000 589,000 9,885,000 256,000

Appalachian States:

KY 2,095,000 1,341,000 126,000

NY 138,000

OH 1,721,000 1,274,000

PA 2,428,000 170,000 777,000

VA 57,000 32,000 2,000

WV 856,000 188,000 111,000

Total Volume

(Appalachian

States Only):

7,295,000 1,444,000 0 1,529,000 0 0 269,000 2,000 0 777,000

National Est.

Total 

Volume a:

139,602,000 8,973,000 10,115,000 1,529,000 65,000 65,666,000 4,926,000 591,000 9,885,000 1,033,000

National

Total, % by

Disposal

Method

Liquid Wastes

= 73.6% 6% 7% 1% 0.05% 47% 3.5% 0.4% 7% 0.7%

a Table only includes states with reported data. Therefore, the estimated total volume of drilling waste is less than the 148.7

million barrels discussed in the text. The estimated total volume reported in the text, 148.7 million barrels, includes drilling waste

volumes estimated for states for which no responses to drilling related questions were received on the 1995 survey.
APPENDIX E

DRILLING WASTES

55

Table E.9. Estimated Volume of Solid Drilling Wastes Disposed by Method;

Estimated for States with Reported Data (Barrels)

State

Estimated

Total

Volume

Drilling

Wastes for

State a

Buried

Onsite

Land

Spread

Onsite

Land

Spread

Offsite

Commercial

Disposal

Facility

Industrial or

Municipal

Landfill

Reuse or

Recycle Other

AK 1,605,000 803,000

AR 2,643,000 793,000

CA 1,826,000 383,000 5,000 2,000 4,000 2,000

CO 3,582,000 107,000 322,000

IL 382,000 4,000 61,000

KS 4,810,000 2,020,000

LA 22,477,000 4,495,000 899,000 2,922,000

MI 1,731,000 346,000

MT 1,366,000 533,000

NM 7,421,000 965,000 223,000

OK 13,162,000 6,581,000

TX 65,367,000 8,533,000 197,000 65,000 394,000 65,000

UT 1,561,000 874,000

WY 4,374,000 2,187,000

Total

Volume

(excludes

Appalachian

States):

132,307,000 28,060,000 1,492,000 389,000 2,926,000 2,000 394,000 868,000

Appalachian States

KY 2,095,000 587,000 42,000

NY 138,000 138,000

OH 1,721,000 448,000

PA 2,428,000 49,000 1,432,000

VA 57,000 23,000

WV 856,000 565,000

Total

Volume

(Appalachian

States Only):

7,295,000 1,672,000 1,612,000

National Est.

Total

Volume a:

139,602,000 29,732,000 3,104,000 389,000 2,926,000 2,000 394,000 868,000

National

Total, % by

Disposal

Method

Solid

Wastes =

26.4 %

21% 2.2% 0.3% 2% 0.001% 0.3% 0.6%

a

Table only includes states with reported data. Therefore, the estimated total volume of drilling waste is less than the 148.7

million barrels discussed in the text. The estimated total volume reported in the text, 148.7 million barrels, includes drilling

waste volumes estimated for states for which no responses to drilling related questions were received on the 1995 survey.
APPENDIX F

GAS PROCESSING PLANTS; PRODUCED WATER AND ASSOCIATED WASTES

56

Table F.1. Gas Plants: Produced Water Disposal by Method and Region – Reported Data

(Barrels/day and Percentages)

Alaska California

Eastern

U.S. Mid-West New Mexico Rockies

Number of Plants Responding 3 3 7 3 5 7

Reported Volume of Produced Water (Bbl/day) 0 201 246.9 70.9 147.95 328

 Injected Onsite for Disposal (Bbl/day) 0 0 246 0 0 0

% Injected Onsite NA 99.6%

Injected Offsite for Disposal (Bbl/day) 0 1 0.9 0 0 230

% Injected Offsite NA 0.5% 0.4% 0% 70%

 Injected at Commercial Disposal Facility (Bbl/day) 0 0 0 70.9 0.25 20

% Injected at Commercial Disposal Facility NA 100% 0.2% 6%

Treat/Discharge (Bbl/day) 0 0 0 0 0 0

% Treat/Discharge NA

 Reuse (Bbl/day) 0 0 0 0 0 50

% Reuse NA 15%

 Road spread (Bbl/day) 0 0 0 0 0 0

% Road spread NA

Other Disposal Method (Bbl/day) 0 200a0 0 147.7b28c

% Other Disposal Method NA 99.5% 99.8% 9%

a

 Respondent noted this method as “commingle with crude oil”

b

 Respondents noted this method as “re-injected for enhanced recovery” and “evaporation ponds”

c

 Respondents noted this method as “evaporation pit (lined)” and “treated/evaporated”

d

 Respondent noted this method as “steam vent to atmosphere”
APPENDIX F

GAS PROCESSING PLANTS; PRODUCED WATER AND ASSOCIATED WASTES

57

Table F.2. Gas Plants: Disposal of Glycol Wastes by Method and Region – Reported Data

Alaska California

Eastern

U.S. Mid-West

New

Mexico Rockies South

Spent Glycol/ Glycol Compounds (Bbls/yr) 0 20 108 0 0 437

Volume Disposed by Method (Barrels/yr):

 Dispose by Injection 0 0 28 0 0 61.64

 Land spread Onsite 0 0 0 0 0 0

 Road spread Onsite 0 0 0 0 0 0

 E&P Waste Facility 0 0 5 0 0 0

 Industry or Municipal Landfill 0 0 0 0 0 0

 Recycle or Reuse 0 0 39 0 0 375

 Incinerate 0 0 36 0 0

 Evaporate from pits 0 0 0 0 0 0.36

 Other method 0 20a0 0 0 0

Percentage Disposed by Method:

% Injection 26% 0% 14%

% Land Spread Onsite

% by Road Spread Onsite

% Commercial Disposal Facility 5%

% Landfill

% Recycle/ Reuse 36% 86%

% Incinerate 33%

% Evaporate from Pits 0.08%

% Other 100%

a

 Respondent listed method as “commercial disposal contractor”

b

 Respondent listed method as “mix with crude oil being sold”
APPENDIX F

GAS PROCESSING PLANTS; PRODUCED WATER AND ASSOCIATED WASTES

58

Table F.3. Gas Plants: Disposal of Used Filters/Filter Media by Method and Region – Reported D

Alaska California

Eastern

U.S. Mid-West

New

Mexico Rockies South

Spent Used Filters/Filter Media (Bbls/yr) 0.04 24.96 0.35 0.25 25.66 259.65

Volume Disposed by Method (Barrels/yr):

 Dispose by Injection 0 0 0 0 0 0

 Land spread Onsite 0 0 0 0 0 0

 Road spread Onsite 0 0 0 0 0 0

 E&P Waste Facility 0 0.19 0 0.10 0.14 7.62

 Industry or Municipal Landfill 0 0.00 0.35 0.15 25.53 252.03

 Recycle or Reuse

 Incinerate 0.04

 Evaporate from pits 0 0 0 0 0 0

 Other method 0 24.77a0 0 0 0

Percentage Disposed by Method:

% Injection

% Land Spread Onsite

% by Road Spread Onsite

% Commercial Disposal Facility 1% 38% 1% 3%

% Landfill 100% 61% 99% 97%

% Recycle/ Reuse 0% 0%

% Incinerate 100%

% Evaporate from Pits

% Other 99%

a

 Respondent listed method as “commercial disposal contractor”

b

 Respondents listed method as “waste to energy plant” and “burial with permit.”
APPENDIX F

GAS PROCESSING PLANTS; PRODUCED WATER AND ASSOCIATED WASTES

59

Table F.4. Gas Plants: Disposal of Scrubber Liquids/Sludge by Method and Region – Reported D

Alaska California

Eastern

U.S. Mid-West

New

Mexico Rockies South

Scrubber Liquids and Sludge (Bbls/yr) 0 200 57 0 20 40

Volume Disposed by Method (Barrels/yr):

 Dispose by Injection 0 0 7 0 0 0

 Landspread Onsite 0 0 0 0 0 0

 Roadspread Onsite 0 0 0 0 0 0

 E&P Waste Facility 0 0 50 0 20 40

 Industry or Municipal Landfill 0 0 0 0 0 0

 Recycle or Reuse 0 0 0 0 0 0

 Incinerate 0 0 0 0 0 0

 Evaporate from pits 0 0 0 0 0 0

 Other method 0 200a0 0 0 0

Percentage Disposed by Method:

% Injection 12%

% Land Spread Onsite

% by Road Spread Onsite

% Commercial Disposal Facility 88% 100% 100%

% Landfill

% Recycle/ Reuse

% Incinerate

% Evaporate from Pits

% Other 100%

a

 Respondent listed method as “commercial disposal contractor”
APPENDIX F

GAS PROCESSING PLANTS; PRODUCED WATER AND ASSOCIATED WASTES

60

Table F.5. Gas Plants: Disposal of Other Dehydration/Sweetening Wastes by Method and Region – Rep

Alaska California

Eastern

U.S. Mid-West

New

Mexico Rockies South

Other Dehydration/Sweetening Wastes (Bbls/yr) 0 0 0 195 1,117 1,203

Volume Disposed by Method (Barrels/yr):

 Dispose by Injection 0 0 0 0 0 0

 Land spread Onsite 0 0 0 0 207 0

 Road spread Onsite 0 0 0 0 0 0

 E&P Waste Facility 0 0 0 0 25 58

 Industry or Municipal Landfill 0 0 0 195 841 50

 Recycle or Reuse 0 0 0 0 0 0

 Incinerate 0 0 0 0 44 0

 Evaporate from pits 0 0 0 0 0 1095

 Other method 0 0 0 0 0 0

Percentage Disposed by Method:

% Injection

% Land Spread Onsite 19%

% by Road Spread Onsite

% Commercial Disposal Facility 2% 5%

% Landfill 100% 75% 4%

% Recycle/ Reuse

% Incinerate 4%

% Evaporate from Pits 91%

% Other

a

 Respondent listed method as “onsite burial with permit of mole sieve, charcoal”
APPENDIX F

GAS PROCESSING PLANTS; PRODUCED WATER AND ASSOCIATED WASTES

61

Table F.6. Gas Processing Plant Wastes – Reported Data

Region

Reported

Gas

Throughput

(MMcfd)

Spent Glycol/

Glycol

Compounds

(bbls./yr.)

Used Filters/

Filter Media

(bbls./yr.)

Scrubber

Liquids &

Sludge

(bbls./yr.)

All Other

Dehydration/

Sweetening

Wastes

(bbls./yr.)

Total Reported

Volume of Gas

Plant Wastes

(bbls./yr.)

Alaska 7,938 0 0.04 0 0 0.04

California 298.38 20 24.96 200 0 244.96

Eastern U.S. 992.4 108 0.35 57 0 165.35

Mid-West 108 0 0.25 0 195 195.25

New Mexico 1,109 0 25.66 20 1,117 1,162.66

Rockies 2,699 437 259.65 40 1,203 1,939.65

Southeast 6,159 102 69.82 31,775 4,442 36,388.82

Texas 2,689.8 3 192.35 3,150 957 4,302.35

Total 21,994 670 573.08 35,242 7,914 44,399.08

Table F.7. Gas Processing Plants; Reported Volume of

Wastes Disposed by Method

Waste Disposal Method

Percentage of Gas

Plant Wastes

Disposed by Method

Reported Volume of

Wastes Disposed by

Method (barrels/day)

Disposal by Injection 76 % 33,717

Commercial E&P Waste

Disposal Facility 9 % 4,102

Land Spread Onsite 6% 2,854

Industrial or Municipal Landfill 4 % 1,606

Evaporate from Pits 2.5 % 1,095

Recycle or Reuse 1 % 587

Incinerate 0.3 % 113

Road Spread Onsite 0.01 % 5

Other 1 % 320

Total 100 % 44,399

“Other” methods include: co-mingle w/ oil product, waste disposal contractor,

onsite burial w/ permit, incineration in “waste-to energy” plant
APPENDIX G

SURVEY METHODOLOGY

62

G.1. Survey Forms

Two forms were developed for API’s 1995 survey: API Survey of Onshore and Coastal Exploration and

Production Operations for 1995 and API Survey of Natural Gas Processing Plants for 1995. The onshore

operations survey form is included in Appendix H and the gas processing plant survey form is included in

Appendix I. The survey form was originally intended to collect data only on waste volumes and waste

management practices. However, following a beta test of the survey forms but prior to distribution of the survey,

a need arose to collect data on equipment that produces air emissions at E&P sites. This resulted in the

addition of several pages of questions to the survey form. Although this data collection effort was needed, it

increased the length and complexity of the survey form and may have reduced the rate of response to the

survey. Although the survey forms were beta tested, in analyzing the results it was apparent that the wording of

some questions was unclear to the respondents. API and its contractor made follow-up phone calls to survey

respondents to clarify responses as needed.

A separate version of the onshore E&P operations survey was developed for operators in the

Appalachian states. The Appalachian version of the 1995 survey form did not collect data on tank

batteries/central facilities (question 10). The Appalachian version of the 1995 survey form also asked

respondents to specify volumes of drilling waste generated because this data was not collected for the

Appalachian states in API’s 1985 survey. The 1995 survey form developed for states outside the Appalachian

region did not ask operators to report drilling waste volumes. This data was collected in the 1985 survey and

the relationship between footage drilled (by depth category) and drilling waste volume was not believed to have

changed substantially between 1985 and 1995.

G.2. Design of Survey Sample

The survey was conducted using a representative statistical sample of industry operations. Two survey

samples were designed for the 1995 Onshore and Coastal E&P Operations Survey. The first sample was

designed to characterize E&P industry facilities and wastes for the entire U.S. excluding the Appalachian

states. The second sample was designed to characterize the Appalachian states, Kentucky, New York, Ohio,

Pennsylvania, Tennessee, Virginia, and West Virginia. It was necessary to separate out Appalachia because

the population frame used to draw the samples did not contain data for those states. The following section

describes the survey sample design for both the E&P operations survey and the gas processing plant survey.

G.2.1. 1995 E&P Operations Survey excluding Appalachia

The survey questionnaire was designed to focus on all the facilities operated by an E&P company

within a single field. A selected E&P company was only asked to complete one survey form per selected field.

The participating companies were selected as follows.

The United States can be divided into 50 geological basins. Because geological basins cross state

boundaries, a single state can contain parts of several basins. This results in 71 unique onshore basin/state

combinations. If the Appalachian states are excluded, the number of basin/state combinations with oil or natural

gas production is 59. The E&P companies operating in each of the 59 basin/state combination were classified

as either large or small companies. If a publicly traded company’s 1994 combined oil and gas production

exceeded 20 million barrels of oil equivalent (BOE), the company was designated as ‘large’. This method

yielded a group of thirty-one large companies, with the remaining companies considered ‘small’. Stratification

by company size ensured that a cross-section of the types and sizes of oil and gas operators were included in

the sample. The fifty-nine basin/state combinations were grouped into, high, medium, or low producing areas,

based on the 1994 production of oil and gas. The production range of these three categories is shown in Table

G.1 below. The total 1994 production in the basin/state combinations is summarized in Table G.5.
APPENDIX G

SURVEY METHODOLOGY

63

Table G.1. Operations Survey Sample Design - Basin/State Categories

Basin/State

Categories

1994 Production

(barrels of oil equivalent)

Number of

Basin/State

Combinations in

Category

High Producing >100 Million BOE 12

Medium Producing 10 Million – 100 Million BOE 28

Low Producing <10 Million BOE 19

Participating companies were selected for the survey sample from databases maintained by Petroleum

Information (PI) Corporation using the selection method termed “probability proportional to size with

replacement”. For a given basin/state/company size combination, a company’s probability of being included in

the sample was proportional to its 1994 production in that basin/state combination. For example, if company A

had twice as much production as company B, company A was twice as likely to be selected as company B. For

each selected company in a basin/state location, one of the company’s fields was selected with probability

proportional to the production from that field. The selected company was then asked to respond with

information for all its leases in that field. Previous beta test experience indicated that small operating companies

were less likely to respond to the survey questionnaire. To account for possible non-response by small

companies, the sample size for these companies was increased by a factor of two. Under this sampling

methodology, a company could receive survey forms for a field in more than one basin/state, but only one field

in each basin/state. The final composition of the sample in each basin/state category is shown in Table G.2

below. 

Table G.2. Operations Survey Sample Design - No. Of Large and Small Companies in Sample by

Basin/State Category

Basin/State

Categories

Large Companies

in Sample

Small Companies

in Sample

Number of

Basin/States

Total Sample

Size

High Producing 3 6 12 96

Medium Producing 2 4 28 156

Low Producing 1 2 19 44

Total = 296

Three large and six small companies were selected from each basin/state category in a high producing

area. Two large and four small companies were selected from each basin/state category in a medium

producing area. One large and two small companies were selected from each category in a low producing

area. The final sample size contained 296 survey forms. A total of 131 operators responded to the survey,

approximately 44 percent of the fields sampled. Sixty-eight percent of large companies responded and 33

percent of small/independent operators responded. Table G.6 tabulates the respondent coverage by state and

by basin/state combination.

G.2.2. 1995 E&P Operations Survey – Appalachian States

The PI database that served as a sampling frame for the 1995 Onshore and Coastal E&P Operations

survey did not contain production information for the Appalachian states, Kentucky, New York, Ohio,
APPENDIX G

SURVEY METHODOLOGY

64

Pennsylvania, Tennessee, Virginia, and West Virginia. For these states, API contacted the Oil and Gas

Associations of each state and asked for a list of member companies. API sent survey forms to a selection of

the member companies and asked the companies to complete the forms for any two of their fields in the

designated state. Companies in Appalachia were chosen for their likelihood of response, rather than based on

a statistical sampling. Participating companies were asked to select one large field and one medium/small field

in the assigned state. Thirty-three responses were received from seven states. Table G.3 below lists the

number of respondents for each state.

Table G.3. Appalachian State Respondents

State Respondents

Kentucky 8

New York 3

Ohio 4

Pennsylvania 5

Tennessee 0

Virginia 4

West Virginia 9

Appalachia Total 33

G.2.3. 1995 Natural Gas Processing Plant Survey

For sampling purposes, the United States was divided into eight regions shown in Table G.4. The

sampling frame used for the gas plants waste management survey was obtained from the July 1, 1996, Oil and

Gas Journal Gas Processing Survey. The original Oil and Gas Journal 1996 survey list contains 623 gas plants

operating in the United States in 1995. Twenty-four plants listed had missing capacity information and were

removed from the population frame for the wastes survey. This left a total of 599 gas plants in the population.

A stratified random sample design was used, with an individual gas plant facility being the primary

sampling unit. One hundred two gas plants were to be included in the nationwide survey. The country was first

divided into 8 regions. Each region was divided into three strata, small, medium, and large, by gas plant

capacity and all “large” gas plants were included in the sample. Some regions had zero facilities in some of the

strata. For example, Alaska had only three facilities in the region and all three were in the “large” stratum. After

including all the “large” plants and all the Alaska plants, eighty-three “non-large” plants (facilities not classified in

the large stratum) remained to be randomly selected.

Proportional allocation was used to determine the sample sizes (total sample size for the small and

medium strata) for each region. Proportional allocation was also used to distribute the non-certainty sample

between the strata within each region. Table G.7 lists the population, sample, and respondent number of gas

plants by region and stratum (gas plant capacity and gas throughput).
APPENDIX G

SURVEY METHODOLOGY

65

Table G.4. Gas Plants Survey - Regions and Sample Size

Region State Population

Size

Sample

Size

Respondents

Alaska Alaska 3 3 3

California California 25 4 3

Eastern U.S.

Alabama, Florida, Kentucky,

Michigan, Ohio, Pennsylvania,

West Virginia

47 10 7

Mid-West Arkansas, Kansas, Oklahoma 92 14 3

New Mexico New Mexico 27 6 5

Rockies Colorado, Montana, North Dakota,

Utah, Wyoming 104 11 7

Southeast Louisiana, Mississippi 68 27 15

Texas Texas 233 27 15

Total 599 102 85

G.3. Survey Data Analysis

The 1995 E&P operations survey and gas plants survey collected data on a range of facilities and their

operational practices. This report evaluates only the survey questions pertaining to waste volumes and waste

management practices:

• numbers of production pits and non-pressurized tanks,

• produced water volumes and produced water management,

• drilling practices, drilling waste volumes and waste management,

• associated production waste volumes and waste management, and

• gas processing plant dehydration waste volumes and waste management.

Although survey samples were designed on a basin/state basis for the E&P operations survey, the

survey responses are aggregated, reported and extrapolated by state. The objective of the analysis presented

here is to provide reported data and data extrapolations that can be meaningfully compared with other oil and

gas data that are typically reported by state. Table G.8 shows the number of responses by state for the E&P

operations survey. The response rate for the onshore operations survey was 44 percent (131 responses were

received from a sample size of 296). Thirty-three additional responses were received from seven Appalachians

states. For the 32 states included in the survey sample design, the number of responses ultimately received for

each state range from zero to 22, with an average of five responses per state. The gas processing plant data is

reported and extrapolated by the regions defined in the survey sample design. The responses received for the

gas plant regions are shown in Table G.4 and range from three to fifteen responses per region.

G.3.1. Survey Data Extrapolation

For most questions, a ratio estimation method is used to extrapolate the reported data for a given state

to an estimated total for that state. Different extrapolation methods were applied to the data received for the

E&P operations survey in an attempt to find a method that produced state by state estimates that were

reasonable when compared to known data.16 However, because most states are represented by a small

 

16 For example, large states with a greater number of respondents, such as California and Texas, had enough responses for some

questions that regression analysis could be used. The survey responses were examined on a respondent-by-respondent basis for

individual survey questions to determine whether any trend or relevant clustering occurred. For example, did responses tend to

cluster by oil production vs. gas production, large operator vs. small operator? Individual responses were also examined to
APPENDIX G

SURVEY METHODOLOGY

66

number of responses, straightforward ratio estimation produced the most consistent and reasonable estimated

values. Reported data from the operations survey are extrapolated on production, estimated number of

production facilities, or number of wells, as appropriate to the survey question under consideration. Similarly,

reported data from the gas plants survey are extrapolated either on gas throughput or on number of gas plants,

as appropriate.

All of the responses received for a state were aggregated. Depending upon the survey question under

consideration, the individual survey responses were designated as predominately representing gas production

or predominately representing oil production. The total responses received for the state were used to generate

a single extrapolation factor for the state such as number of tank batteries per oil production facility or volume of

completion fluids generated per well completion. The extrapolation factor was then applied to state data such

as number of well completions or volume of gas production, in order to generate a total estimated survey

response for the state. Depending upon the nature of the survey question, “zero” responses received from

survey responses were either incorporated into the state extrapolation factor or omitted. For example, for some

questions related to facilities, “zero” responses are treated as questionable data and are omitted. Consider the

example below:

State “A”

Response 1 10 wells 2 tank batteries

Response 2 100 wells 0 tank batteries

Response 3 37 wells 10 tank batteries

It is unlikely that a field with 100 wells has no tank batteries, so “Response 2” is considered

questionable data and is omitted from the state extrapolation factor:

Extrapolation Factor for State “A” =

10 wells + 37 wells =

2 tank batteries + 10 batteries

 4 wells

tank battery

For most questions related to volumes of produced water or waste, the “zero” responses are appropriately

treated as valid data and are incorporated into the state extrapolation factor. The example shown below

illustrates the case in which a volume of workover waste is generated intermittently depending upon field

operations. In this example, “zero” responses represent valid data that should be incorporated into the state

extrapolation factor.

State “A”

Response 1 10 oil wells 20 barrels waste

Response 2 100 oil wells 280 barrels waste

 Response 3 37 oil wells 0 barrels waste

Extrapolation Factor for State “A” =

20 bbls. + 280 bbls. + 0 bbls. =

10 wells + 100 wells + 37 wells

2.04 bbls. waste

oil well

For some of the survey questions evaluated in this report, a statewide value for wastes or facilities is

estimated for states that have no reported data. Either these states were not sampled (Oregon, Missouri), or

the states were sampled but no response was received (Nevada, South Dakota). Also, in a few instances for

both the operations survey and the gas plants survey, the survey response received appears to be an “outlier”,

or in some way is a non-representative respondent. In these cases, either a value is estimated for the state

using a “national” extrapolation factor based upon the total survey response or an extrapolation factor or survey

response from a similar neighboring state is applied. For example, an extrapolation factor based upon gas

(..continued)

determine the most reasonable way to treat “zero” responses and outliers. Depending upon the type of question, a zero response

was treated as valid response, or was considered an “unlikely” response and omitted.
APPENDIX G

SURVEY METHODOLOGY

67

production in West Virginia might be applied to gas production in Virginia, or an extrapolation factor for an

associated waste volume reported for Montana might also be applied to North Dakota. It was apparent that the

wording of some survey questions was unclear to respondents. This contributed to a poor response rate on

some questions, and to results that were difficult to interpret. Follow-up calls were made to respondents by API

and its contractors to clarify responses where needed. Also, for some questions such as produced water

volumes, the results extrapolated from the survey responses are supplemented by estimates from other

sources.
APPENDIX G

SURVEY METHODOLOGY

68

Table G.5. E&P Operations Survey Sample Design

Total 1994 Production (Mboe) in Basin/State Combinations

State

Basin/

State

Total 1994

Production

(Mboe) State

Basin/

State

Total 1994

Production

(Mboe) State

Basin/

State

Total 1994

Production

 (Mboe)

Alabama AL1 21,211 Louisiana LA1 78,029 Oklahoma OK1 57,699

Alabama AL2 68,813 Louisiana LA2 303,705 Oklahoma OK2 93,813

AL - Total 90,024 LA - Total 381,734 Oklahoma OK3 238,136

Alaska AK1 1,018,672 Michigan MI1 46,097 OK - Total 389,648

Alaska AK2 67,408 Mississippi MS1 1,598 SD SD1 2,474

AK-Total 1,086,080 Mississippi MS2 25,675 SD SD2 191

Arizona AZ1 191 Mississippi MS3 12,874 SD - Total 2,665

Arkansas AR1 24,725 MS - Total 40,147 Texas TX1 318,382

Arkansas AR2 12,122 Montana MT1 18,795 Texas TX2 2,603

AR - Total 36,847 Montana MT2 700 Texas TX3 97,963

California CA1 46,110 Montana MT3 4,242 Texas TX4 218,914

California CA2 258,198 Montana MT4 1,334 Texas TX5 212,916

California CA3 13,330 MT - Total 25,071 Texas TX6 607,207

CA - Total 317,638 Nebraska NE1 Texas TX7 69,390

Colorado CO1 37,064 Nebraska NE2 2,594 TX - Total 1,527,375

Colorado CO2 2,291 Nebraska NE3 42 Utah UT1 12,486

Colorado CO3 36,425 Nebraska NE4 2,043 Utah UT2 66,145

Colorado CO4 23,694 NE- Total 13 Utah UT3 0

Colorado CO5 7,630 Nevada NV1 4,692 UT - Total 78,631

CO - Total 107,104 New Mexico NM1 1,699 Wyoming WY1 13,340

Florida FL2 5,964 New Mexico NM2 151,280 Wyoming WY2 2,416

Illinois IL1 15,704 New Mexico NM3 130,894 Wyoming WY3 40,067

Indiana IN1 2,590 NM –Total 0 Wyoming WY4 161,192

Kansas KS1 17,513 ND - total ND1 282,174 Wyoming WY5 45,178

Kansas KS2 124,547 37,357 WY - Total 262,193

Kansas KS3 19,919

KS - Total 161,979
APPENDIX G

SURVEY METHODOLOGY

69

Table G.6. E&P Operations Survey Design – Number of Survey Respondents

by State, Company Size, and by Basin/State Combination

Large Companies Small Companies Total Companies

State

Basin/

State

Basin/

State

Category

Sample

Size Responses

Sample

Size Responses

Sample

Size Responses

Alabama AL1 M 2 1 4 2 6 3

Alabama AL2 M 1 1 3 2 4 3

AL - Total 3 2 7 4 10 6

Alaska AK1 H 2 1 1 0 3 1

Alaska AK2 M 2 2 1 0 3 2

AK-Total 4 3 2 0 6 3

Arizona AZ1 L 0 -- 2 0 2 0

Arkansas AR1 M 2 1 4 2 6 3

Arkansas AR2 M 2 1 4 1 6 2

AR - Total 4 2 8 3 12 5

California CA1 M 2 0 4 3 6 3

California CA2 H 2 3 4 3 6 6

California CA3 M 2 0 4 2 6 2

CA - Total 6 3 12 8 18 11

Colorado CO1 M 2 1 4 1 6 2

Colorado CO2 L 1 1 2 0 3 1

Colorado CO3 M 2 2 4 1 6 3

Colorado CO4 M 1 1 4 0 5 1

Colorado CO5 L 1 1 2 1 3 2

CO - Total 7 6 16 3 23 9

Florida FL1 L 0 -- 2 0 2 0

Florida FL2 L 1 1 1 0 2 1

Illinois IL1 M 2 1 4 1 6 2

Indiana IN1 M 1 0 2 0 3 0

Kansas KS1 M 1 1 4 2 5 3

Kansas KS2 H 3 3 6 4 9 7

Kansas KS3 M 2 1 5 3 7 4

KS - Total 6 5 15 9 21 14

Louisiana LA1 M 2 2 4 2 6 4

Louisiana LA2 H 3 3 6 2 9 5

LA - Total 5 5 10 4 15 9

Michigan MI1 M 2 2 3 1 5 3

Mississippi MS1 L 0 -- 2 0 2 0

Mississippi MS2 M 1 1 4 0 5 1

Mississippi MS3 M 2 1 3 0 5 1

MS - Total 3 2 9 0 12 2

Montana MT1 M 2 1 4 3 6 4

Montana MT2 L 1 0 2 2 3 2

Montana MT3 L 1 0 2 1 3 1

Montana MT4 L 1 1 2 2 3 3

MT - Total 5 2 10 8 15 10

Nebraska NE1 L 1 0 2 1 3 1

Nebraska NE2 L 0 -- 2 0 2 0

Nebraska NE3 L 1 1 1 0 2 1

Nebraska NE4 L 0 -- 1 0 1 0

NE- Total 2 1 6 1 8 2
APPENDIX G

SURVEY METHODOLOGY

70

Large Companies Small Companies Total Companies

State

Basin/

State

Basin/

State

Category

Sample

Size Responses

Sample

Size Responses

Sample

Size Responses

Nevada NV1 L 1 0 1 0 2 0

New Mexico NM1 H 3 3 4 0 7 3

New Mexico NM2 H 3 2 6 2 9 4

New Mexico NM3 -- 0 -- 0 -- 0 --

NM – Total 6 5 10 2 16 7

North Dakota ND1 M 2 0 4 1 6 1

Oklahoma OK1 M 2 2 4 0 6 2

Oklahoma OK2 M 2 2 4 3 6 5

Oklahoma OK3 H 3 1 6 0 9 1

OK - Total 7 5 14 3 21 8

South

Dakota

SD1 L 1 0 2 0 3 0

South

Dakota

SD2 L 0 -- 2 0 2 0

SD - Total 1 0 4 0 5 0

Texas TX1 H 3 3 6 2 9 5

Texas TX2 L 0 -- 1 1 1 1

Texas TX3 M 2 0 4 2 6 2

Texas TX4 H 3 1 6 2 9 3

Texas TX5 H 3 2 6 3 9 5

Texas TX6 H 3 3 6 1 9 4

Texas TX7 M 2 1 4 1 6 2

TX - Total 16 10 33 12 49 22

Utah UT1 M 1 1 3 0 4 1

Utah UT2 M 2 1 3 2 5 3

Utah UT3 -- -- -- -- -- -- --

UT - Total 3 2 6 2 9 4

Wyoming WY1 M 2 2 4 1 6 3

Wyoming WY2 L 1 1 1 0 2 1

Wyoming WY3 M 2 2 4 2 6 4

Wyoming WY4 H 2 2 6 1 8 3

Wyoming WY5 M 2 1 4 0 6 1

WY - Total 9 8 19 4 28 12

U. S. Total 96 65 200 66 296 131

Appalachian Responses: KY = 8, NY = 3, OH = 4, PA = 5, TN = 0, VA = 4, WV = 9
APPENDIX G

SURVEY METHODOLOGY

71

Table G.7. Gas Plants Survey Sample Design – Range in Gas Plant Capacity

and Throughput (mmcfd) for Survey Sample Strata

Strata

Region Small Medium Large Total

Alaska

Stratum Size, MMcfd per plant N/A N/A < 8200

Population Size 0 0 3

Sample Size 0 0 3

No. of Responses 0 0 3

Gas Capacity, MMcfd 0 0 8,975

Gas Throughput, MMcfd 0 0 8,637

California

Stratum Size, MMcfd per plant < 160 > 160 N/A

Population Size 23 2 0 25

Sample Size 2 2 0 4

No. of Responses 1 2 0 3

Gas Capacity, MMcfd 718 320 0 1,038

Gas Throughput, MMcfd 379 300 0 679

Eastern U. S.

Stratum Size, MMcfd per plant < 500 > 500 N/A

Population Size 46 1 0 47

Sample Size 9 1 0 10

No. of Responses 6 1 0 7

Gas Capacity, MMcfd 5,132 1,000 0 6,132

Gas Throughput, MMcfd 1,934 71 0 2,005

Mid West

Stratum Size, MMcfd per plant < 180 > 180 and < 480 > 480

Population Size 82 7 3 92

Sample Size 7 4 3 14

No. of Responses 2 1 0 3

Gas Capacity, MMcfd 3,773 2,012 2,600 8,385

Gas Throughput, MMcfd 2,579 1,285 2,030 5,894

New Mexico

Stratum Size, MMcfd per plant < 80 > 80 and < 220 > 220

Population Size 19 6 2 27

Sample Size 2 2 2 6

No. of Responses 2 1 2 5

Gas Capacity, MMcfd 784 894 1,094 2,772

Gas Throughput, MMcfd 585 679 858 2,122

Rockies

Stratum Size, MMcfd per plant < 120 > 120 and < 350 > 350

Population Size 91 10 3 104

Sample Size 4 4 3 11

No. of Responses 0 4 3 7
APPENDIX G

SURVEY METHODOLOGY

72

Strata

Region Small Medium Large Total

Gas Capacity, MMcfd 2,125 2,255 1,965 6,345

Gas Throughput, MMcfd 1,253 1,649 1,482 4,384

Southeast

Stratum Size, MMcfd per plant < 300 > 300 and < 950 > 950

Population Size 51 13 4 68

Sample Size 10 13 4 27

No. of Responses 4 9 2 15

Gas Capacity, MMcfd 3,757 9,345 5,650 18,752

Gas Throughput, MMcfd 2,855 5,224 4,785 12,864

Texas

Stratum Size, MMcfd per plant < 140 > 140 and < 375 > 375

Population Size 208 21 4 233

Sample Size 15 8 4 27

No. of Responses 9 3 3 15

Gas Capacity, MMcfd per 8,354 4,580 3,300 16,234

Gas Throughput, MMcfd 5,873 3,415 2,214 11,502

Population Size (All) 520 60 19 599

Total Sample Size 49 34 19 102

Total Respondents 24 21 13 58
APPENDIX G

SURVEY METHODOLOGY

73

Table G.8. Survey Response by State

State

Total

Responses

No. of Oil and Gas

Fields Represented

by Respondents

Responses

representing

predominately OIL

production

Responses

representing

predominately GAS

production

AK 3 3 2 1

AL 6 6 2 4

AR 5 5 1 4

AZ 0

CA 11 10 9 2

CO 9 7 4 5

FL 1 1 1 0

IL 2 2 2 0

IN 0

KS 14 11 7 7

LA 9 9 2 7

MI 3 3 1 2

MS 2 2 2 0

MO 0

MT 10 10 9 1

ND 1 1 1 0

NE 2 2 2 0

NM 7 6 1 6

NV 0

OK 8 8 2 6

OR 0

SD 0

TX 22 21 13 9

UT 4 4 2 2

WY 12 12 8 4

Sub-Total 131 123 71 60

Appalachian

States:

KY 8 6 4 4

NY 3 3 1 2

OH 4 4 2 2

PA 5 5 0 5

TN 0

VA 4 2 1 3

WV 9 9 2 7

Appalachian

Total:

33 29 10 23

TOTAL 164 152 81 83
74

APPENDIX H

SURVEY FORM - API SURVEY OF ONSHORE AND COASTAL EXPLORATION AND PRODUCTION

OPERATIONS FOR 1995
1

Please respond by ____________

API SURVEY OF ONSHORE AND COASTAL

EXPLORATION AND PRODUCTION OPERATIONS

FOR 1995

SURVEY FORM

Name of Field 

County/Parish __________ State 

ALL SURVEY RESPONSES WILL BE HELD CONFIDENTIAL.

Only aggregated results from the survey will be made publicly

available. For API internal use, company names and field names will

be replaced by codes to maintain confidentiality.
1

We hope that you will look at completing the survey not as an additional cost

or inconvenience, but as an investment in the well-being of our industry.

Carl Giardini, Chairman

API General Committee on Exploration and Production

Estimated Time Required

Before sending out this survey, we asked several companies to complete the survey as a

test both of its clarity and the length of time involved in its completion. The small companies

participating reported spending between 30 minutes and 2 hours on completion of the survey. 

Larger companies reported spending up to 8 hours (spread over a week) to complete the survey

form, due primarily to the need to coordinate with many different individuals throughout the

company to gather the information. We hope that you will find this burden sufficiently light to

complete this vitally important survey.

Please remember that the survey focuses on operations in a single field, not for your

company as a whole. Several of the questions focus only on large pieces of equipment (e.g.,

heater treaters or boilers with > 10 million Btu/hour capacity) because they are possible targets of

future regulatory activity. Many field operations will not have these large pieces of equipment —

thus, those questions can be quickly answered; reducing the effort involved in responding to the

survey.

Benefits to Completing the Survey

The primary benefit to you will be knowing that API and other industry organizations have

an accurate characterization of industry operations that they can provide to regulators, legislators,

and the general public to educate them about our industry. This will help to allow future

requirements to be based on current conditions, and may result in compliance cost savings on

future regulations that better reflect the real risks associated with industry activities.

In addition, the questions related to equipment that may produce air emissions are an

attempt to avoid a mandatory data collection request from EPA that could be far more timeconsuming than this survey. 

Your response is crucial to our survey design (which has attempted to minimize the

burden on companies). Given these benefits, and the importance of this effort, we hope that you

will help and complete the survey form. It really is an investment in the well-being of our industry.
Page 1

API SURVEY OF ONSHORE AND COASTAL EXPLORATION AND PRODUCTION OPERATIONS

FOR 1995

Name of Field 

County/Parish State 

Please complete this survey to cover all of your operated leases/units in the field noted above. If the field crosses

county or parish boundaries, please provide data for the entire field, not just the portion in the county listed above. 

Please provide data for calendar year 1995. Do not include information about the leases within the field that you do

not operate. Do not include data on gas plants located in the field. If you did not operate leases in this field during

1995, please complete questions 1-2 below, check here and return this form to the address on the back

page.

Instructions are enclosed that provide additional explanation about the completion of each question.

1. Operator/Company Name 

2. Contact Person Phone # 

3. Number of months of 1995 you operated in this field: 

FIELD/LEASE INFORMATION

4. Number of individual leases or units you operate in field 

5. Number of active wells you operate in field by type (end of 1995):

Oil

Wells

Gas

Wells

Disposal

(Injection)

Wells

Enhanced

Recovery

(Injection) Wells

Source

Water

Wells

Number of active wells at

year end 1995

6. Your gross daily production volumes from this field for 1994 and 1995:

Natural Gas

Oil

Bbls/day

From Oil

Wells*

1,000 scf/day

From Gas

Wells*

1,000 scf/day

Condensate

Bbls/day

Produced

Water

Bbls/day

1994 production volume

1995 production volume

Please report gross daily production volumes from all operated wells in the field. Please use the units

noted in each column. 

* If you do not have a breakdown on gas from oil wells vs. gas from gas wells available, please put total

gas production in gas wells column and label as both oil and gas wells.
Page 2

7. Estimated distance from field to nearest town or city with population of 2,500 or more

 miles

8. a) Average API gravity of produced fluids:

Oil degrees; Condensate degrees

b) Is gas production from this field sweet or sour? (Mark one) Sweet Sour 

FIELD EQUIPMENT/FACILITIES

9. Production Pits

Production pits include all types of pits operated, except those associated with drilling operations. Small collection sumps are

not production pits, and should not be included in the total provided. Examples of production pits include evaporation,

blowdown, produced water, percolation, workover, washout, skim, and emergency pits. If you use tanks rather than pits for

emergency upsets, please report these tanks in question 10 below. Active pits are defined as those currently part of the

operation, whether or not they currently contain fluids. Inactive pits are pits that are no longer part of the system but have not

yet been closed.

a) Total number of production pits you operate in this field 

If zero, please place a zero in the blank above and proceed to question 10.

b) Number of these production pits that are workover pits 

c) Number of production pits that are: Active Inactive 

d) Number of active production pits you operate in field that are lined 

10. Tank Batteries/Central Facilities

Central facilities are primary separation facilities in unitized fields where storage tanks are present. Do not include facilities for

injection or disposal of produced water (covered in question 11 below) in your count of facilities (question 10a), but do include

produced water storage tanks at these facilities in the count of tanks in question 10b. For this survey, please consider gun

barrel tanks to be produced water tanks. Do not include pressurized vessels. Include only tanks currently in service (part of

field operations, regardless of whether they currently contain fluids). Tanks used for emergency or upset conditions (e.g.,

blowdown tanks or tanks installed to replace a pit) should be reported as emergency tanks, even if they are not located at tank

batteries or central facilities.

a) Number of tank batteries/central facilities you operate in this field: 

Oil batteries/facilities Condensate batteries/facilities 

b) Number of tanks you operate in this field (both at tank batteries and elsewhere in the field) by type:

Oil Condensate Waste

Oil/Water

Produced Water Emergency

Total number

of tanks
Page 3

c) Percentage of oil and condensate tanks that route vapors directly to a flare %

d) Percentage of oil and condensate tanks with a floating roof %

e) Percentage of oil and condensate tanks with a vapor recovery unit installed %

f) Of oil and condensate tanks with a vapor recovery unit, percentage by vapor destination:

Percentage

Incineration (flare)

Sales (as product)

Return to process

Other (specify)

Total 100%

g) Average operating pressure of high pressure separator psig

h) Average operating pressure of low pressure separator psig

i) Is gas from the low pressure separator vented? Yes No 

 

11. Produced Water Injection/Disposal Facilities

Produced water injection/disposal facilities include one or more wells injecting water for disposal or enhanced recovery, along

with the associated treatment equipment. Storage tanks located at these facilities should be reported in question 10 above.

a) Number of facilities operated and water volumes injected in this field:

If zero, place a zero in the table below and proceed to question 12.

Enhanced

Recovery/Injection

Produced Water

Disposal

Number of facilities operated in field

Volume of water injected (barrels/day)

b) Source of produced water disposed (disposal facilities only):

Percentage

From company operations in this field

From company operations in other fields

From other companies in this field

From other companies in other fields

TOTAL 100%
Page 4

12. Gas Dehydration Units

a) Total number of gas dehydration units you operate in field by dehydration method (do not include

dehydration units located at a gas plant):

If zero, place a zero in the table below and proceed to question 13.

Triethylene

glycol (TEG)

Ethylene

glycol (EG)

Diethylene

glycol

(DEG)

Dry bed

desiccant or

molecular sieve

Other

Number of dehydration units

Note: Remaining parts of this question address TEG units only. If zero, proceed to question 13.

b) Number of triethylene glycol (TEG) dehydration units you operate in field by size:

Number of TEG Units Design Capacity and Actual Throughput Ranges

≤ 1

 million scf/d

1.01–3

 million scf/d

3.01–10

 million scf/d

> 10

 million scf/d

Number of units with Design

Capacity in range

Number of units with Actual

Throughput1 in range

1 Annual average operating throughput for year 1995.

c) Percentage of TEG dehydration units with both flash tanks (fuel economizers) and condensers

 %

d) Percentage of TEG dehydration units with a flash tank, but no condenser %

e) Percentage of TEG dehydration units with a condenser, but no flash tank %

f) Percentage of TEG units with a condenser which:

Incinerates the offgas in a unit burner %

Flares the offgas %

g) Percentage of TEG units that route emissions to a flare without prior condensation %

h) Number of glycol reboiler fireboxes with maximum rated heat input capacity ≥ 10 million btu/hour

 
Page 5

13. Field Gas Compressor Drivers

Field gas compressors are driven by engines or turbines, and are used to compress gas to prepare it for pipeline

transportation, to inject CO2 or natural gas to enhance oil and gas recovery, or to boost gas pressure to use in gas lift

operations. Include only those compressor drivers of 150 Hp or larger (continuous design-rated Hp) operated by you. 

Include electric motors that are used to drive compressors. Do not include any compressors that are part of

pipeline/transmission operations. Do not include compressors located at gas plants.

Size and physical location of field compressor drivers may affect whether they are covered by certain air regulations in the

future. Two locations are of interest:

• Productionsite – a contiguous graded pad, gravel pad, foundation, platform, or other location upon which any

combination of compressor(s), separator(s), pumps(s), storage tank(s), heater treater(s), and/or boiler(s) are physically

affixed and comprise a field facility to process the produced fluids for sale and/or injection/discharge.

• Compressor site – a contiguous graded pad, gravel pad, foundation, platform, or other location upon which one or more

compressors are physically affixed that is not located within a productionsite.

a) Total number of field gas compressor drivers (engines and turbines) larger than 150 continuous

design-rated Hp 

If zero, place a zero in the blank above and proceed to question 14.

b) Percentage and total horsepower of compressor drivers (engines and turbines) 150 Hp or larger by

engine manufacturer:

Engine Manufacturer Waukesha CooperBessemerClark Ingersoll

Rand

Ajax Other

% of compressor drivers

Total Horsepower

c) Number, type, size and fuel source for compressor drivers (engines) at productionsites:

Number of engines/motors

Horsepower

(continuous

design-rating)

Engine

Type

Electric

powered

motors

Rich1 burn

engines

% rich burn

w/ catalytic

controls2

Lean3 burn

engines

Clean4 burn

engines

150-300 Hp 2-Stroke

4-Stroke

301-500 Hp 2-Stroke

4-Stroke

501-750 Hp 2-Stroke

4-Stroke

751-1,000 Hp 2-Stroke

4-Stroke

>1,000 Hp 2-Stroke

4-Stroke

Fuel Source5

electric

1

Rich burn engines produce less than 4% oxygen in their exhaust. The manufacturer's original recommended

operating air-fuel ratio divided by the stoichiometric air/fuel ratio is less than or equal to 1:1. Most 4-stroke

engines installed prior to 1982 are rich burn engines.

2

Include the percentage of your rich burn engines that have had catalytic controls installed.

3

A lean burn engine produces greater than 4% oxygen in its exhaust. All 2-stroke engines are lean burn, along

with some 4-stroke engines.

4

Clean burn engines are engines (typically 4-stroke) that have had the cylinder heads, combustion chamber, or

other parts modified so that the engine is a low NOx emitter without catalytic controls .

5

Natural gas, diesel, gasoline, propane, or other (please specify).
Page 6

d) Number of compressor sites in the field with one compressor sites

e) Number of compressor sites with more than one compressor sites

f) Number, type, and fuel source for compressor drivers (engines) at compressor sites:

Number of engines/motors

Horsepower

(continuous

design-rating)

Engine

Type

Electric

powered

motors

Rich1 burn

engines

% rich burn

w/ catalytic

controls2

Lean3 burn

engines

Clean4 burn

engines

150-300 Hp 2-Stroke

4-Stroke

301-500 Hp 2-Stroke

4-Stroke

501-750 Hp 2-Stroke

4-Stroke

751-1,000 Hp 2-Stroke

4-Stroke

>1,000 Hp 2-Stroke

4-Stroke

Fuel Source5

electric

1

Rich burn engines produce less than 4% oxygen in their exhaust. The manufacturer's original recommended

operating air-fuel ratio divided by the stoichiometric air/fuel ratio is less than or equal to 1:1. Most 4-stroke

engines installed prior to 1982 are rich burn engines.

2

Include the percentage of your rich burn engines that have had catalytic controls installed.

3

A lean burn engine produces greater than 4% oxygen in its exhaust. All 2-stroke engines are lean burn, along

with some 4-stroke engines.

4

Clean burn engines are engines (typically 4-stroke) that have had the cylinder heads, combustion chamber, or

other parts modified so that the engine is a low NOx emitter without catalytic controls .

5

Natural gas, diesel, gasoline, propane, or other (please specify).

g) Number, size, location, and fuel source of turbines to drive compressors:

Location

Turbine Size Plant Site Compressor Site

≤ 1,000 Hp

1,001-5,000 Hp

5,001-15,000 Hp

15,001-25,000 Hp

> 25,000 Hp

Fuel Source1

1

Natural gas, diesel, gasoline, propane, or other (please specify).

h) Estimated average BTU content of natural gas used for fuel BTU/scf 
Page 7

14. Field Internal Combustion Engines

Please include all types of stationary field internal combustion engines, including drivers for pumping units, pumps, generators,

and other equipment not included in question 13 above. Do not include engines on mobile sources (trucks, etc.)

a) Number of stationary internal combustion engines of 150 horsepower or more (exclud ing compressor

drivers) you operate in this field by size:

If zero, place zeros in the table below and proceed to question 15.

Number of engines

Horsepower

rating

Engine

Type Rich1

 burn

engines

% rich burn w/

catalytic

controls2

Lean3 burn

engines

Clean4 burn

engines

150-300 Hp 2-Stroke

4-Stroke

301-500 Hp 2-Stroke

4-Stroke

501-750 Hp 2-Stroke

4-Stroke

751-1,000 Hp 2-Stroke

4-Stroke

>1,000 Hp 2-Stroke

4-Stroke

Fuel Source5

1

Rich burn engines produce less than 4% oxygen in their exhaust. The manufacturer's original recommended

operating air-fuel ratio divided by the stoichiometric air/fuel ratio is less than or equal to 1:1. Most 4-stroke engines

installed prior to 1982 are rich burn engines.

2

Include the percentage of your rich burn engines that have had catalytic controls installed.

3

A lean burn engine produces greater than 4% oxygen in its exhaust. All 2-stroke engines are lean burn, along with

some 4-stroke engines.

4

Clean burn engines are engines (typically 4-stroke) that have had the cylinder heads, combustion chamber, or

other parts modified so that the engine is a low NOx emitter without catalytic controls .

5

Natural gas, diesel, gasoline, propane, or other (please specify).

b) Percentage and total horsepower of stationary internal combustion engines of 150 horsepower or more

(excluding compressor drivers) by manufacturer:

Engine

Manufacturer

Waukesha General

Electric

Detroit

Diesel

Caterpillar Ajax Other

% of engines

Total Horsepower
Page 8

15. Field Heater Treaters and Boilers/Steam Generators

This question covers only units with a maximum rated heat input capacity of 10 million Btu/hour or more. Do not include

glycol reboilers, which were covered in question 12 above. Do not include heaters or boilers located at gas plants.

Size and physical location of heater treaters and boilers/steam generators may affect whether they are covered by certain

air regulations in the future. Two locations are of interest:

• Productionsite – a contiguous graded pad, gravel pad, foundation, platform, or other location upon which any

combination of separator(s), pumps(s), storage tank(s), compressor(s), heater treater(s), and/or boiler(s) are physically

affixed and comprises a field facility to process the produced fluids for sale and/or injection/discharge.

• Heater/Steam Generator/Boiler site – a contiguous graded pad, gravel pad, foundation, platform, or other location upon

which heater treater(s) and/or boiler/steam generator(s) are physically affixed that is not located within a productionsite.

a) Total number of heater treaters and boilers/steam generators with maximum heat input capacity of 10

million Btu/hour or more operated in the field:

If zero, place a zero in the table and proc eed to question 16.

Capacity ≥ 10 million Btu/hour

Heater Treaters Boilers/Steam

Generators

Number of units

b) List the number of heater treaters and boiler/steam generators with capacity of ≥ 10 million Btu/hour, by

size and location, using a separate line of the table for each size unit:

Productionsites Heater/Boiler Sites

Unit Capacity Heater Treaters Boilers/Steam Gen. Heater Treaters Boilers/Steam Gen.

c) Fuel used for heater treaters and boilers/steam generators:

Natural gas Diesel Propane Other (please specify) Total

Percentage of BTUs

generated using

100%
Page 9

d) Percentage of heater treaters and boilers/steam generators with emission controls by type:

Control Heaters using control (%) Boilers using control (%)

No controls installed

SO2 scrubber1

Low NOx burner2

Selective catalytic reduction (SCR) 3

Selective non-catalytic reduction (SNCR) 4

Flue gas recirculation5

Other (please specify)

Total 100% 100%

1

SO2 scrubbers are generally “wet scrubbers” that bring the SO2-laden flue gases into contact with a liquid that

selectively reacts with the SO2.

2

Low NOx burners generally incorporate the principles of delayed fuel-air mixing, oxygen-deficient zones for initial

combustion, lower flame turbulence, and lower flame temperatures.

3

SCR involves the use of ammonia and catalysts at a temperature of around 700 oF to reduce NOx to H20 and N2.

4

SNCR involves the injection of ammonia at a temperature of around 1,750 oF, which reacts with NO to form H20 and N2

.

.

5

Recycling a portion of the flue gases back into the combustion zone can reduce both the flame temperature and the

oxygen concentration, thus lowering NOx emissions.

e) Based on currently installed control equipment, estimated control efficiency for variou s pollutants

from heater treaters and boilers/steam generators:

Pollutant SO2 NOx CO VOCs PM-10

Heater control efficiency (%)

Boiler control efficiency (%)

16. Gas Sweetening Units

Gas sweetening units remove hydrogen sulfide (H2S) and/or carbon dioxide (CO2) from natural gas by a variety of processes,

including amine, Sulfinol, caustics, and iron sponge. Do not include gas sweetening units located at gas plants in the field.

a) Total number of gas sweetening units you operate in this fiel d 

17. Pneumatic Devices

a) Percentage of pneumatic devices for control valve operation by type:

Instrument Air Instrument

Gas*

Other Total

Percentage by type 100%

* Use of natural gas to control the valve.
Page 10

18. Landspreading/Land Treatment Operations

Landspreading/land treatment operations dispose of solid wastes through application to the land or incorporation into the soil. 

This process uses the physical, chemical, and biological capabilities of the soil to absorb and decompose waste constituents. 

Nutrients and/or water may be added to enhance biodegradation. The waste/soil mixture may be tilled for aeration. These

operations typically require a state permit. Include both single and multiple applicationsites, but do not include drilling sites

where wastes are spread when the reserve pit is closed. Do not include roadspreading operations.

a) Do you perform on-site landspreading/land treatment for waste disposal in this field?

Yes No 

PRODUCED WATER MANAGEMENT

19. Produced Water Management

a) Disposition of produced water:

1995 Produced water volume1

(Bbls/day)

Injected for enhanced recovery

Injected for disposal onsite

Injected for disposal offsite2

Injected for disposal at commercial facility

Treated3 and discharged4

Beneficial use5

Roadspreading6

Other (please specify):

1

Total produced water volume should equal total provided in question 6 for 1995.

2

Offsite disposal wells operated by your company or as part o f a co-op, partnership, or communal disposal

operation, not commercial facilities.

3

Treated (if needed) to meet applicable discharge requirements.

4

Discharge may be to the land surface, or to a stream, lake, or other body of water as allowed by state or federal

regulations.

5

Irrigation, livestock watering and other special uses allowable west of 98th meridian.

6

Spreading on roads for dust suppression or de-icing.

OTHER ASSOCIATED WASTES

Other associated wastes are wastes other than produced water and drilling wastes that are exempt from regulation as hazardous

wastes under the Resource Conservation and Recovery Act. Of these, four waste streams are typically the largest by volume:

• Completion fluids. All fluids from initial completion activities including any acidizing or fracturing performed.

• Workover and stimulation fluids. All fluids from subsequent workover and stimulation activities.

• Tank bottoms/oily sludges. This includes basic sediment and water, produced sand, and other tank bottoms.

• Dehydration/sweetening wastes. This includes glycol-based compounds, glycol filters, molecular sieves, amines, amine filters,

precipitated amine sludge, iron sponge, scrubber liquids and sludge, backwash, filter media and other wastes associated with

the dehydration or sweetening of natural gas.
Page 11

20. Other Associated Waste Volume

a) Volume of selected associated waste streams managed from operations in this field during 1995:

Waste stream Units Estimated volume

Completion fluids1 Barrels/Year

Workover and stimulation fluids Barrels/Year

Tank bottoms/oily sludges2 Barrels/Year

Dehydration/sweetening wastes Barrels/Year

1

If your company does not differentiate completion activities from other workover and stimulation

activities, please estimate based on the number of wells completed during 1995.

2

If you did not clean out any tanks, and therefore manage any tank bottom wastes, during 1995, enter

zero as the volume, even though tank bottoms did accumulate (which will be cleaned out and

managed in a subsequent year).

21. Other Associated Waste Disposal

a) Disposal of other associated waste streams by method:

Please fill in the percentage of each waste stream disposed by each method listed at left. The percentages in each

column should add to 100%.

Tank bottoms/oily

sludges

Completion

fluids

Workover/

stimulation

fluids

Dehydration/

sweetening

wastes

Disposal by injection

Landspreading within the field

Landspreading outside the field1

Roadspreading within the field

Roadspreading outside the field1

Commercial NOW2 disposal

Industrial or municipal landfill

Crude oil reclamation

Recycling/beneficial reuse

Incinerated

Evaporated from pits or tanks

Other (specify):

TOTAL 100% 100% 100% 100%

1

Activities conducted directly by your company at another location, not through use of a commercial disposal location or

contractor.

2

Non-hazardous oilfield waste commercial disposal contractor.
Page 12

DRILLING ACTIVITIES

If you did not perform any drilling in this field during 1995, check here and return the completed survey to the address on

the back page.

22. New Wells Drilled

a) Number and depth of new wells you drilled in field in 1995:

Wells drilled1Zone 12Zone 22Zone 32Zone 42

Number drilled for oil or gas 3,4

Number of these that are dual completions4

Number drilled for injection or disposal

Number drilled for source water

Average well depth in zone5

1

Include all wells finished drilling in 1995, regardless of when they were spudded or completed .

2

Since multiple pay zones may exist within the field, please use as many columns as needed to describe your

drilling in this field. If a single pay zone, use only the first column. Source water wells and disposal wells would

typically be from/to a separate zone from oil and gas production .

3

Include all wells drilled for the purpose of finding oil or gas, including dry holes.

4

Use 0.5 wells in each applicable zone to represent dual completions.

5

For horizontal wells, consider measured hole depth.

b) Percentage of new wells drilled by technique:

Mud Rotary Drilling Air, Gas, or

Reserve Pits Closed System

(Tanks)

Cable Tool

Drilling

Pneumatic

Drilling

Total

Percentage of new

wells using

100%

c) Percentage of your reserve pits that were lined (clay or synthetic) %

d) Percentage of drilling waste by base drilling fluid:

Fresh-water

base1

Salt-water

base

Oil-base Syntheticbase

Total

Percentage of waste 100%

1 Mud made with fresh water would be classified as fresh water base even if the fluid later became

“contaminated” with chlorides or other solids.
Page 13

23. Drilling Waste Disposal

a) Disposal of drilling wastes by technique:

Drilling Waste Disposal Method Percentage of Total

Drilling Waste

LIQUID PORTION OF DRILLING WASTE

Liquids extracted and disposed via injection (Class II well)

Liquids extracted and disposed down well annulus between surface pipe and production

casing

Liquids extracted, treated, and discharged

Liquids extracted and used for roadspreading

Liquids evaporated from solids on-site or off-site

Liquids removed from pit and landspread on-site

Liquids removed from pit and landspread off-site 1

Liquids reused/recycled for drilling other wells

Other (specify):

SOLID PORTION OF DRILLING WASTE

Backfilled/buried in reserve pit or trench following evaporation or extraction of liquids 4

Removed from pit and landspread on-site4

Removed from pit and landspread off-site 1

Removed from pit and disposed at a commercial NOW2 facility

Removed from pit and disposed at industrial or municipal landfill

Removed from pit and reused/recycled3

Other (specify):

TOTAL 100%

1

Activities conducted by your company at another location, not use of a commercial disposal sit e.

2

Nonhazardous oilfield waste commercial disposal contractor.

3

Used for landfill cover, road bed construction, dike stabilization, or plugging and abandoning wells, etc.

4

Includes practice of removing a section of pit wall, allowing pit contents to fl ow into a trench or onto the

ground, then treating material like other burial or landspreading operations.
Thank you for your assistance with this important survey.

The information provided will help educate policy-makers about current

practices within the oil and gas industry.

Please return the completed survey form to:

Amita Gopinath

Statistical Services Division

American Petroleum Institute

1220 L Street N.W.

Washington, DC 20005

For questions about completing the survey, please call (703) 934-3675 and leave a

detailed message. Someone knowledgeable in the subject area of your question will

return your call as soon as possible.
91

APPENDIX I

SURVEY FORM - API SURVEY OF NATURAL GAS PROCESSING PLANTS FOR 1995
1

Please respond by _____________

API SURVEY OF NATURAL GAS PROCESSING

PLANTS FOR 1995

SURVEY FORM

Plant/Location 

 

ALL SURVEY RESPONSES WILL BE HELD CONFIDENTIAL.

Only aggregated results from the survey will be made publicly

available. For API internal use, company names and plant names will

be replaced by codes to maintain confidentiality.
1

We hope that you will look at completing the survey not as an additional cost

or inconvenience, but as an investment in the well-being of our industry.

Carl Giardini, Chairman

API General Committee on Exploration and Production

Estimated Time Required

Based on input from companies asked to review the survey form, we estimate that

completion of the survey will require 2-4 hours for smaller plants. For larger plants, or larger

companies, where coordination among more individuals may be required, the total time

investment may be larger. We hope that you will find this burden sufficiently light to complete this

vitally important survey.

Benefits to Completing the Survey

The primary benefit to you will be knowing that API and other industry organizations have

an accurate characterization of industry operations that they can provide to regulators, legislators,

and the general public to educate them about our industry. This will help to allow future

requirements to be based on current conditions, and may result in compliance cost savings on

future regulations that better reflect the real risks associated with industry activities.

In addition, the questions related to equipment that may produce air emissions are an

attempt to avoid a mandatory data collection request from EPA that could be far more timeconsuming than this survey. 

Your response is crucial to our survey design (which has attempted to minimize the

burden on companies). Given these benefits, and the importance of this effort, we hope that you

will help and complete the survey form. It really is an investment in the well-being of our industry.
Page 1

API SURVEY OF NATURAL GAS PROCESSING PLANTS

FOR 1995

Plant/Location 

Please complete this survey to cover operations at the natural gas processing plant listed above. Please provide data

for calendar year 1995. 

Instructions are enclosed that provide additional explanation about the completion of each question.

1. Operator/Company Name 

2. Contact Person Phone # 

3. Number of months of 1995 you operated this plant: 

PLANT INFORMATION

4. Plant size, throughput data:

Units 1995 Data

Processing Capacity Million scf/day

Gas Throughput Million scf/day

Total Liquids Recovered Thousand gallons/day

Total Sulfur Recovered Metric tons/year

5. Estimated distance from plant to nearest town or city with population of 2,500 or more

 miles

6. a) Is the plant currently subject to PSD (prevention of significant deterioration) requirements? 

Yes _________ No __________

b) If so, which criteria pollutant(s) (SO2, NOx, CO, VOCs, etc.) has caused plant to be subject to PSD

requirements?

 

7. Percentage of gas processed at this plant by source (onshore fields/offshore fields):

Onshore % Offshore %
Page 2

PLANT EQUIPMENT/FACILITIES

8. Pits

Include all types of pits operated at the plant, except small collection sumps. Examples of pits include evaporation,

blowdown, produced water, percolation, washout, skim, and emergency pits. If you use tanks rather than pits for

emergency upsets, please report these tanks in question 9 below. Active pits are defined as those currently part of

the operation, whether or not they currently contain fluids. Inactive pits are pits that are no longer part of the system

but have not yet been closed.

a) Total number of pits you operate at this plant 

If zero, please place a zero in the blank above and proceed to question 9.

b) Number of pits that are: Active Inactive 

c) Number of active pits you operate at the plant that are lined 

9. Tanks

Please include all tanks used for storage of produced water, condensate, or liquid products, and tanks used for

emergency conditions. Do not include pressurized vessels. Include only tanks currently in service (part of plant

operations, regardless of whether they currently contain fluids). Tanks used for emergency or upset conditions (e.g.,

blowdown tanks or tanks installed to replace a pit) should be reported as emergency tanks.

a) Number of tanks you operate at this plant by type:

Produced Water Condensate Liquid Products Emergency

Total number

of tanks

b) Percentage of condensate and product tanks that route vapors directly to a flare %

c) Percentage of condensate and product tanks with floating roofs %

d) Percentage of condensate and product tanks with a vapor recovery unit installed %

e) Of crude and product tanks with a vapor recovery unit, percentage by vapor destination:

Percentage

Incineration (flare)

Sales (as product)

Return to process

Other (specify)

Total 100%
Page 3

10. Produced Water Disposal Wells

a) Number of disposal wells operated by this plant 

If zero, place a zero in the table below and proceed to question 11.

b) Volume of water injected to these wells (barrels/day) 

11. Gas Sweetening Units

Gas sweetening units remove hydrogen sulfide (H2S) and/or carbon dioxide (CO2) from natural gas by a variety of

processes, including amine, Sulfinol, caustics, and iron sponge.

a) Total number of gas sweetening units you operate in this plant 

b) Total volume of gas sweetened (daily average) Million scf/day

12. Gas Dehydration Units

a) Total number of gas dehydration units you operate at plant by dehydration method:

If zero, place a zero in the table below and proceed to question 13.

Triethylene

glycol (TEG)

Ethylene

glycol (EG)

Diethylene

glycol

(DEG)

Dry bed

desiccant or

molecular sieve

Other

Number of dehydration units

Gas volume dehydrated by

method (million scf/d)

Note: Remaining parts of this question address TEG and EG units only. If zero, proceed to question 13. 

If zero TEG units, proceed to subpart h for questions on EG units.

Triethylene glycol (TEG) units

b) Number of triethylene glycol (TEG) dehydration units you operate at plant by size:

Design Capacity and Actual Throughput Ranges

Number of TEG Units ≤ 3

 million scf/d

3.01–10

 million scf/d

10.01–50

 million scf/d

> 50

 million scf/d

Number of units with Design

Capacity in range

Number of units with Actual

Throughput1 in range

1

Annual average operating throughput for year 1995.
Page 4

c) Percentage of TEG dehydration units with both flash tanks (fuel economizers) and condensers

 %

d) Percentage of TEG dehydration units with a flash tank, but no condenser %

e) Percentage of TEG dehydration units with a condenser, but no flash tank %

f) Percentage of TEG units with a condenser which:

Incinerates the offgas in a unit burner %

Flares the offgas %

g) Percentage of TEG units that route emissions to a flare without prior condensation %

Ethylene glycol (EG) units

h) Number of ethylene glycol (EG) dehydration units you operate at plant by size:

Design Capacity and Actual Throughput Ranges

Number of EG Units ≤ 10

 million scf/d

10.01–100

 million scf/d

100.01–500

 million scf/d

> 500

 million scf/d

Number of units with Design

Capacity in range

Number of units with Actual

Throughput1 in range

1

Annual average operating throughput for year 1995.

i) Percentage of EG dehydration units with condensers %

j) For EG units with condensers, percentage by vapor destination:

Percentage

Incineration (flare)

Return to process

Use as fuel

Vented to atmosphere

Other (please specify)

Total 100%
Page 5

Both triethylene glycol (TEG) and ethylene glycol (EG) units

k) Heat or fuel source for glycol reboiler, both TEG and EG units (percentage by source):

Waste

heat

Steam Hot Oil Natural gas Propane Other (specify) Total

TEG units

% by fuel 100%

EG units

% by fuel 100%

l) Size of firebox for glycol reboilers (TEG and EG units - number):

Firebox capacity Number of TEG units Number of EG units

< 10 Million Btu/hour

10-25 Million Btu/hour

>25 Million Btu/hour

m) Are emission controls installed on the glycol reboiler firebox? Yes No 
Page 6

13. Gas Compressor Drivers

Gas compressors driven by engines or turbines compress the gas for processing or to prepare it for pipeline

transportation. Include only those engines 150 Hp or larger (continuous design-rated) operated by you. Include

any electric-powered motors that are used to drive compressors. Do not include any compressors that are part of

pipeline/transmission operations or field operations.

Size and physical location of field compressor drivers may affect whether they are covered by certain air

regulations in the future. Two locations are of interest:

• Plant site – one or more compressors physically located within the plant.

• Compressor site – one or more compressors located on a single pad or platform, operated and maintained by

the plant, but located away from the plant site.

a) Total number of gas compressor drivers (engines and turbines) larger than 150 continuous designrated Hp operated by the plant (both plant and compressor sites). If zero, place a zero in the blank

and proceed to question 14.

 compressor drivers

b) Percentage and total horsepower of compressor drivers (engines and turbines) 150 Hp or larger by

engine manufacturer:

Engine Manufacturer Waukesha CooperBessemerClark Ingersoll

Rand

Ajax Other

% of compressor drivers

Total horsepower

c) Number, type, and fuel source for compressor drivers (engines) at plant sites:

Number of engines/motors

Horsepower

(continuous

design-rating)

Engine

Type

Electric

powered

motors

Rich1 burn

engines

% rich burn

w/ catalytic

controls2

Lean3 burn

engines

Clean4 burn

engines

150-300 Hp 2-Stroke

4-Stroke

301-500 Hp 2-Stroke

4-Stroke

501-750 Hp 2-Stroke

4-Stroke

751-1,000 Hp 2-Stroke

4-Stroke

>1,000 Hp 2-Stroke

4-Stroke

Fuel Source5

electric

1

Rich burn engines produce less than 4% oxygen in their exhaust. The manufacturer's original recommended

operating air-fuel ratio divided by the stoichiometric air/fuel ratio is less than or equal to 1.1. Most 4-stroke engines

installed prior to 1982 are rich burn engines.

2

Include the percentage of your rich burn engines that have had catalytic controls installed.

3

A lean burn engine produces greater than 4% oxygen in its exhaust. All 2-stroke engines are lean burn, along with

some 4-stroke engines.

4

Clean burn engines are engines (typically 4-stroke) that have had the cylinder heads, combustion chamber, or

other parts modified so that the engine is a low NOx emitter without catalytic controls.

5

Natural gas, diesel, gasoline, propane, or other (please specify).
Page 7

d) Number of compressor sites with one compressor sites

e) Number of compressor sites with more than one compressor sites

f) Number, type, and fuel source for compressor drivers (engines) at compressor sites:

Number of engines/motors

Horsepower

(continuous

design-rating)

Engine

Type

Electric

powered

motors

Rich1 burn

engines

% rich burn

w/ catalytic

controls2

Lean3 burn

engines

Clean4

burn

engines

150-300 Hp 2-Stroke

4-Stroke

301-500 Hp 2-Stroke

4-Stroke

501-750 Hp 2-Stroke

4-Stroke

751-1,000 Hp 2-Stroke

4-Stroke

>1,000 Hp 2-Stroke

4-Stroke

Fuel Source5

electric

For footnotes, see table above.

g) Number, size, location, and fuel source of turbines to drive compressors:

Location

Turbine Size Plant Site Compressor Site

< 1,000 Hp

1,000-5,000 Hp

5,001-15,000 Hp

15,001-25,000 Hp

> 25,000 Hp

Fuel Source 1

1

 Natural gas, diesel, gasoline, propane, or other (please specify).

h) Estimated average BTU content of natural gas used for fuel BTU/scf 
Page 8

14. Internal Combustion Engines and Turbines

Please include all types of stationary internal combustion engines and turbines, including drivers for pumps,

generators, and other equipment not included in question 13 above. Do not include engines on mobile sources

(trucks, etc.)

a) Number of stationary internal combustion engines of 150 horsepower or larger (excluding

compressor drivers) you operate in this plant by size:

Number of engines

Horsepower

(continuous

design-rating)

Engine

Type Rich1

 burn

engines

% rich burn

w/ catalytic

controls2

Lean3 burn

engines

Clean4 burn

engines

150-300 Hp 2-Stroke

4-Stroke

301-500 Hp 2-Stroke

4-Stroke

501-750 Hp 2-Stroke

4-Stroke

751-1,000 Hp 2-Stroke

4-Stroke

>1,000 Hp 2-Stroke

4-Stroke

Fuel Source5

1

Rich burn engines produce less than 4% oxygen in their exhaust. The manufacturer's original

recommended operating air-fuel ratio divided by the stoichiometric air/fuel ratio is less than or equal to 1.1.

Most 4-stroke engines installed prior to 1982 are rich burn engines.

2

Include the percentage of your rich burn engines that have had catalytic controls installed.

3

A lean burn engine produces greater than 4% oxygen in its exhaust. All 2-stroke engines are lean burn,

along with some 4-stroke engines.

4

Clean burn engines are engines (typically 4-stroke) that have had the cylinder heads, combustion

chamber, or other parts modified so that the engine is a low NOx emitter without catalytic controls.

5

Natural gas, diesel, gasoline, propane, or other (please specify).

b) Percentage and total horsepower of engines and turbines (excluding compressor drivers) 150 Hp or

larger by engine manufacturer:

Engine Manufacturer Waukesha CooperBessemerClark Ingersoll

Rand

Ajax Other

% of compressor drivers

Total horsepower
Page 9

c) Number, size, and fuel source of turbines (excluding compressor drivers):

Turbine Size Number of Turbines

< 1,000 Hp

1,000-5,000 Hp

5,001-15,000 Hp

15,001-25,000 Hp

> 25,000 Hp

Fuel Source1

1

 Natural gas, diesel, gasoline, propane, or other (please specify).

15. Heaters and Boilers

a) Total number of heaters with maximum rated heat input capacity of 10 million Btu/hour or more

operated at the plant:

If zero, place a zero in the table and proceed to question 15b.

Heater capacity Number of Heaters

10-25 million Btu/hour

26-50 million Btu/hour

51-75 million Btu/hour

76-100 million Btu/hour

> 100 million Btu/hour

b) Total number of boilers (other than glycol reboilers) with maximum rated heat input capacit y of 10

million Btu/hour or more operated at the plant:

If zero, place a zero in the table and proceed to question 16.

Boiler capacity Number of Boilers

10-50 million Btu/hour

51-100 million Btu/hour

101-150 million Btu/hour

> 150 million Btu/hour

c) Fuel used for heaters and boilers:

Natural gas Diesel Propane Other (please specify) Total

Percentage of BTUs

generated using

100%
Page 10

d) Percentage of heaters and boilers with controls:

Control Heaters using control (%) Boilers using control (%)

No controls installed

SO2 scrubber1

Low NOx burner2

Selective catalytic reduction (SCR) 3

Selective non-catalytic reduction (SNCR) 4

Flue gas recirculation5

Other (please specify)*

Total 100% 100%

1

SO2 scrubbers are generally “wet scrubbers” that bring the SO2-laden flue gases into contact with a liquid that

selectively reacts with the SO2.

2

Low NOx burners generally incorporate the principles of delayed fuel-air mixing, oxygen-deficient zones for initial

combustion, lower flame turbulence, and lower flame temperatures.

3

SCR involves the use of ammonia and catalysts at a temperature of around 700 οF to reduce NOx to H20 and N2.

4

SNCR involves the injection of ammonia at a temperature of around 1,750 oF, which reacts with NO to form H20 and N2

.

5

Recycling a portion of the flue gases back into the combustion zone can reduce both the flame temperature and the

oxygen concentration, thus lowering NOx emissions.

e) Based on currently installed control equipment, estimated control efficiency for various pollutants

from heaters and boilers:

Pollutant SO2 NOx CO VOCs PM-10

Heater control efficiency (%)

Boiler control efficiency (%)

16. Pneumatic Devices

a) Percentage of pneumatic devices for control valve operation by type:

Instrument Air Instrument Gas* Other Total

Percentage by type 100%

* Use of natural gas to control the valve.

17. Emissions Inventory

If one is readily available, please enclose a copy of the emissions inventory for this plant. 

This information will be treated as confidential. Availability of emission inventories may provide additional

data/insights to assist in response to future rulemakings, since they provide more data than it is feasible

to request as part of this survey.
Page 11

WASTE VOLUMES AND MANAGEMENT

18. Produced Water

a) Volume of produced water removed from processed gas streams: Barrels/day

b) Disposition of produced water removed:

1995 produced water volume

(Bbls/day)

Injected for disposal onsite

Injected for disposal offsite1

Injected for disposal at commercial facility

Treated2 and discharged3

Beneficial use4

Roadspreading5

Other (please specify):

1 Offsite disposal wells operated by your company or as part of a co-op, partnership, or

communal disposal operation, not commercial facilities.

2

Treated (if needed) to meet applicable discharge requirements.

3

Discharge may be to the land surface, or to a stream, lake, or other body of water as allowed by

state or federal regulations.

4

Irrigation, livestock watering and other special uses allowable west of 98th meridian.

5

Spreading on roads for dust suppression or de-icing.
Page 12

19. Dehydration/Sweetening Wastes

Dehydration and sweetening wastes are typically exempt from regulation as hazardous wastes under the Resource

Conservation and Recovery Act. Exempted wastes include: glycol-based compounds, glycol filters, molecular

sieves, amines, amine filters, precipitated amine sludge, iron sponge, scrubber liquids and sludge, backwash, filter

media, and other wastes associated with the dehydration or sweetening of natural gas.

a) Volume of selected dehydration/sweetening waste streams managed during 1995:

Waste stream1 Units Estimated volume

Spent glycol/glycol compounds Barrels/Year

Used filters/filter media Pounds/Year

Scrubber liquids and sludge Barrels/Year

All other dehydration/sweetening wastes Barrels/Year

1

 Please provide a breakdown where possible. If separate estimates for each waste stream are not

feasible, please provide estimated total waste volume in the category for “all other dehydration/

sweetening wastes,” and write “included below” in the column for volume of the other waste streams.

20. Dehydration/Sweetening Waste Disposal

a) Disposal of dehydration/sweetening waste streams by method:

Please fill in the percentage of each waste stream disposed by each method listed at left. The percentages in

each column should add to 100%.

Spent glycol/

glycol

compounds

Used

filters/filter

media

Scrubber

liquids and

sludge

All other

dehydration/

sweetening wastes

Disposal by injection

Landspreading onsite

Roadspreading onsite

Commercial NOW1 disposal

Industrial or municipal landfill

Recycling/beneficial reuse

Incinerated

Evaporated from pits or tanks

Other (specify):

TOTAL 100% 100% 100% 100%

1

Non-hazardous oilfield waste commercial disposal contractor.
Thank you for your assistance with this important survey.

The information provided will help educate policy-makers about current

practices within the oil and gas industry.

Please return the completed survey form to:

Amita Gopinath

Statistical Services Division

American Petroleum Institute

1220 L Street N.W.

Washington, DC 20005

Please include a copy of your emi ssions inventory for this plant, if available.

For questions about completing the survey, please call (703) 934-3675 and leave

a detailed message. Someone knowledgeable in the subject area of your question

will return your call as soon as possible.