# OVERVIEW OF 

# EXPLORATION AND 

# P RODUCTION



# WASTE 

# VOLUMES AND 

# WASTE 

# M ANAGEMENT 

# P RACTICES IN THE 

# U NITED 

# 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 

# C ONTENTS

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 

# L IST 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 

# E XECUTIVE 

# S UMMARY

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 EOR 3

### ) 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

2Class II injection wells are those associated with the oil and gas industry, using a numbering scheme described in the Safe Drinking Water Act.

3For 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. I NTRODUCTION

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.

4The 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 MMboe c 

### 6,661.2 MMboe c 

### -6% Producing Oil Wells a 

### 642,408 oil wells 569,508 oil wells -11% Stripper Oil Wells b 

### 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.
cMillion 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 Hand 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 ’ s1985 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.

5A 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.

6Although 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. S URVEY 

# R ESULTS 

# : P RODUCTION 

# P ITS 

# , TANKS 

# , LAND 

# T RE ATMENT



# O PERATIONS 

# , AND 

# P RODUCED 

# 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 2shows 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 Region a 

### Number

of Pits Operated Number

of Active Pits Number of

Inactive Pits % Active

Pits with Liners Estimated

Number of Active Pits b 

### 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 5summarizes the estimated oil tank

7Reported 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 6summarizes 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 pluscondensate 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.

8Alternate 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 2.2because 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 Region a 

### Estimated

Number of Produced Water Tanks b 

### Estimated

Number of Condensate Tanks b 

### Estimated

Number of Liquid Product Tanks b 

### Estimated

Number of Emergency Tanks b 

### Estimated

Total NonPressurized Tanks b 

### 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. bExtrapolated 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 Operati ons 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 a 

### 3.0 % Inject for Disposal Offsite 2.5 % Beneficial Reuse b 

### 2.0 % Inject at Commercial Disposal Facility < 0.5% Road Spread < 0.01% Other c

### (“ percolation ponds”) 3.0 %

aOver 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. bBeneficial 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.
cAlmost 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 2indicates, 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%

aNearly 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 Region a 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 26,190 b

aBased on 1996 Oil & Gas Journal survey. bDue 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. S URVEY 

# R ESULTS 

# : ASSOCI ATED 

# WASTES 

# , G AS 

# D EHYDRA TION

# /SWEETENING 

# WASTES 

# , D RILLING 

# WASTES 

# , AND 

# WASTE 

# M ANAGEMENT 

# P RACTICES

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 1 985 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

9A 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 2shows 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 minusthe 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.

10In 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 6show 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

aOf 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 6summarizes 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 2contains 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.

12In 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. Volum e 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 4shows 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 5the 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 bAverage for state from API 1985 Production Waste Survey
c(Column 2) x (Column 3) dOil and Gas Journal, Energy Statistics Sourcebook, 12thedition, 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 %

aEstimated 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 API1985 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 Wastes Disposed by Method Drilling Waste 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. S UMMARY OF 

# R ESULTS

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 

# R EFERENCES

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 P RODUCTION 

## FACILITIES AND 

## O IL AND 

## G AS 

## P RODUCTION



### 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.
cMemorandum 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 dAPI 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

15M.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 P RODUCTION 

## FACILITIES AND 

## O IL AND 

## G AS 

## P RODUCTION



### 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 P RODUCTION 

## FACILITIES AND 

## O IL AND 

## G AS 

## P RODUCTION



### 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

P RODUCTION 

## P ITS 

## , TANK 

## B ATTERIES 

## , 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

P RODUCTION 

## P ITS 

## , TANK 

## B ATTERIES 

## , 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 d 55,690

aWhere data was available from a state agency, either estimates or reported data, these have been provided. bSource: Gruy memorandum, 1998.
cThis 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. dAssumes 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

P RODUCTION 

## P ITS 

## , TANK 

## B ATTERIES 

## , 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

P RODUCTION 

## P ITS 

## , TANK 

## B ATTERIES 

## , 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

P RODUCTION 

## P ITS 

## , TANK 

## B ATTERIES 

## , 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

aEquals estimated number of oil production facilities bBased on reported data for state
cBased on reported survey data for Appalachian States; average 6 oil wells per tank dBased on national estimate of 4 tanks per production facility or oil tank battery.

## APPENDIX 

## B

P RODUCTION 

## P ITS 

## , TANK 

## B ATTERIES 

## , 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

aFrom Appendix G bBased on 6 gas wells per tank battery (from reported data)
cBased on reported data for state dWhen 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. eBased 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

P RODUCTION 

## P ITS 

## , TANK 

## B ATTERIES 

## , 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

aBased on 1996 Oil and Gas Journal survey.

## APPENDIX 

## C

P RODUCED 

## 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

P RODUCED 

## 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% 141,894 a 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

aExtrapolated on number of completed wells bExtrapolated on number of active oil and gas wells
cExtrapolated on oil and gas production dExtrapolated 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% 15,800 a 17.5% 100,392b Total (Bbls./Yr.) 100% 608,713 100.0% 574,599

aLand treatment disposal site within field bLand 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% 1,600 a 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% 2,709 b 0.5% 16 c Total (Bbls./Yr.) 100.0% 114,467 100.0% 3,296
aVolume is reported by a single respondent. If this volume is excluded from total, 62.5% of dehydration wastes are disposed at commercial disposal facility. bRespondents noted this as oil containment berms and working pits.
cRespondent 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 Incinerated 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

D RILLING 

## 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

D RILLING 

## 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

D RILLING 

## 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.

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### 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

aFrom Table 3.9, “ Estimated Total Volume of Drilling Wastes” bFrom 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)

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### 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% a 8 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% b 2 VA 56% 4% 2 WV 22% 13% 4
a liquids and solids remediated onsite bcommercial disposal facility

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### 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% a 1 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% b 8 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
agrind and inject in Class II well bpit

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### 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.

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### 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.

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### 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) 0 200 a 0 0 147.7 b 28 c % Other Disposal Method NA 99.5% 99.8% 9%

aRespondent noted this method as “commingle with crude oil ” bRespondents noted this method as “ re-injected for enhanced recovery ” and “evaporation ponds”
cRespondents noted this method as “evaporation pit (lined) ” and “treated/evaporated” dRespondent noted this method as “steam vent to atmosphere”

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### 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 Southeast 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 20 a 0 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%

aRespondent listed method as “commercial disposal contractor” bRespondent listed method as “mix with crude oil being sold”

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

Alaska California Eastern U.S. Mid-West New Mexico Rockies Southeast 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 24.77 a 0 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%

aRespondent listed method as “commercial disposal contractor” bRespondents listed method as “waste to energy plant” and “ burial with permit. ”

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

Alaska California Eastern U.S. Mid-West New Mexico Rockies Southeast 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 0 200 a 0 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%

aRespondent listed method as “commercial disposal contractor”

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

Alaska California Eastern U.S. Mid-West New Mexico Rockies Southeast 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

aRespondent listed method as “onsite burial with permit of mole sieve, charcoal ”

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### 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

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### 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 Hand 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.

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### 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,

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### 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).

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### 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

16For 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

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### 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 

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### 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.

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### 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

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### 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

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### 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

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### 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 

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### 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

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### 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
S URVEY 

## F ORM 

## - API SURVEY OF 

## O NSHORE AND 

## C OASTAL 

## EXPLORATION AND 

## P RODUCTION 

## O PERATIONS FOR 

## 1995

### 1 

# Please respond by

____________



# API S URVEY OF 

# O NSHORE AND 

# C OASTAL 

# EXPLORATION AND 

# P RODUCTION 

# O PERATIONS

FOR 

# 1995

S URVEY 

# FORM



# Name of Field County/Parish

__________ State

A LL 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 t his 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 anattempt 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 

## O NSHORE AND 

## COASTAL 

## EXPLORATION AND 

## P RODUCTION 

## O PERATIONS 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 dailyproduction 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 AP I 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 notproduction 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 notinclude 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 tanksPage 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 pr essure 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 Throughput 1 

### 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/hourPage 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 CO 2or 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 notinclude any compressors that are part of pipeline/transmission operations. Do notinclude 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 notlocated 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 CooperBessemer Clark 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 Rich 1 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 Source 5 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 Rich 1 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 Source 5 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 Source 1

1 Natural gas, diesel, gasoline, propane, or other (please specify).



### h) Estimated average BTU content of natural gas used for fuel BTU/scfPage 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 notincluded in question 13 above. Do notinclude 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 Rich 1 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 Source 5

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 HorsepowerPage 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 notinclude glycol reboilers, which were covered in question 12 above. Do notinclude 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 notlocated 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 SO2scrubber1
Low NOx burner2 Selective catalytic reduction (SCR) 3 Selective non-catalytic reduction (SNCR) 4 Flue gas recirculation 5 Other (please specify)

Total 100% 100% 1 SO 2scrubbers are generally “wet scrubbers” that bring the SO 2 -laden flue gases into contact with a liquid that selectively reacts with the SO 2
. 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 o F to reduce NOx to H 2 0 and N 2

. 4 SNCR involves the injection of ammonia at a temperature of around 1,750 o F, which reacts with NO to form H 2 0 and N 2 .

. 5 R ecycling 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 SO 2 

### NOx 

### CO VOCs PM-10 Heater control efficiency (%) Boiler control efficiency (%)

16. Gas Sweetening Units
Gas sweetening units remove hydrogen sulfide (H 2 S) and/or carbon dioxide (CO 2) from natural gas by a variety of processes, including amine, Sulfinol, caustics, and iron sponge. Do notinclude 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 volume 1 (Bbls/day) Injected for enhanced recovery Injected for disposal onsite Injected for disposal offsite 2 Injected for disposal at commercial facility
Treated 3 and discharged4
Beneficial use 5 Roadspreading

6 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, notcommercial 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 fluids 1 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 field 1 Roadspreading within the field Roadspreading outside the field 1

Commercial NOW 2disposal 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 drilled 1 

### Zone 1 2 

### Zone 2 2 

### Zone 32 

### Zone 42 

### Number drilled for oil or gas 3,4 

### Number of these that are dual completions 4 

### Number drilled for injection or disposal
Number drilled for source water Average well depth in zone 5

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 base 1 

### 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-site 4
Removed from pit and landspread off-site 1
Removed from pit and disposed at a commercial NOW 2facility Removed from pit and disposed at industrial or municipal landfill Removed from pit and reused/recycled 3 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
S URVEY 

## F ORM 

## - API SURVEY OF 

## N ATURAL 

## G AS 

## P ROCESSING 

## P LANTS FOR 

## 1995

### 1 

# Please respond by

_____________



# API S URVEY OF 

# N ATURAL 

# G AS 

# P ROCESSING



# P LANTS FOR 

# 1995

S URVEY 

# FORM



# Plant/Location

A LL 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 anattempt to avoid a mandatory data collection request from EPA that could be far more timeconsuming than this survey.
Your response is crucialto 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 

## N ATURAL 

## G AS 

## P ROCESSING 

## P LANTS 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 neare st 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) (SO 2 

### , 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 y ou 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 (H 2 S) and/or carbon dioxide (CO 2) 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 NoPage 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 notinclude 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 CooperBessemer Clark 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 Rich 1 burn

engines % rich burn

w/ catalytic controls2 Lean3

burn engines Clean 4 

### b urn

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 Source 5 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 Rich 1 burn

engines % rich burn

w/ catalytic controls2 Lean3

burn engines Clean 4

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 Source 5 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/scfPage 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 notinclude engines on mobile sources (trucks, etc.)



### a) Number of stationa ry 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 Rich 1 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 Source 5

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 CooperBessemer Clark Ingersoll Rand Ajax Other

% of compressor drivers Total horsepowerPage 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 Source 1

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 SO2scrubber1
Low NOx burner2 Selective catalytic reduction (SCR) 3 Selective non-catalytic reduction (SNCR) 4 Flue gas recirculation 5 Other (please specify)*

Total 100% 100% 1 SO 2scrubbers are generally “wet scrubbers” that bring the SO 2 -laden flue gases into contact with a liquid that selectively reacts with the SO 2
. 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 ο F to reduce NOx to H 2 0 and N 2

. 4 SNCR involves the injection of ammonia at a temperature of around 1,750 o F, which reacts with NO to form H 2 0 and N 2 . 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 SO 2 

### 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 informat ion 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 offsite 1
Injected for disposal at commercial facility

Treated 2and discharged3

Beneficial use 4
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 stream 1 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 NOW 1 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.