EPA 440/1-76/055-a 

Group II 

Development Document for Interim 

Final Effuent Limitations Guidelines 

and 

Proposed New Source Performance 

Standards for the 

OIL & GAS EXTRACTION 

Point Source Category 

UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

SEPTEMBER 1976 
DEVELOPMENT DOCUMENT 

for 

INTERIM FINAL 

EFFLUENT LIMITATIONS GUIDELINES 

and 

PROPOSED NEW SOURCE PERFORMANCE STANDARDS 

for the 

OIL AND GAS EXTRACTION 

POINT SOURCE CATEGORY 

Russell E. Train 

Administrator 

Andrew W. Breidenbach 

Assistant Administrator for 

Water and Hazardous Materials 

Eckardt C. Beck 

Deputy Assistant Administrator for 

Water Planning and Standards 

Robert B. Schaffer 

Director, Effluent Guidelines Division 

Martin Halper Project Officer 

September, 1976 

Effluent Guidelines Division 

Office of Water and Hazardous Materials 

U.S. Environmental Protection Agency Washington, D. C. 20460 
ABSTRACT 

This development document presents the findings of an extensive 

study of the Oil and Gas Extraction Industry for the purposes of 

developing effluent limitations guidelines, for existing point 

sources and standards of performance for new sources, to 

implement Sections 301, 304, 306 and 307 of the Federal Water 

Pollution Control Act, as amended (33 u.s.c. 1551, 1314, and 

1316, 86 Stat. 816 et. seq.) (the "Act"). Guidelines and 

standards were developed for the Oil and Gas Extraction Industry, 

which was div~ded into 6 subcategories. 

Effluent limitations guidelines contained herein set forth the 

degree of effluent reduction attainable througb the application 

of the best practicable control technology currently available 

(BPCTCA) and the degree of effluent reduction attainable through 

the application of the best available technology economically 

achievable (BATEA) which must be achieved by existing point 

sources ~Y July 1, 1977 and July 1, 1983, respectively. The new 

source performance standards (NSPS) contained herein set forth 

the degree of effluent reduction which are achievable through the 

application of the best available demonstrated control 

technology, processes, operating methods, or other alternatives. 

Suppor~ng data and rationale for the development of proposed 

effluent 1imitat~ons guidelines and standards of performance are 

contained in this develo~ment document. 

i 
Section 

I 

II 

III 

IV 

v 

VI 

TABLE OF CONTENTS 

ABSTRACT 

CONCLUSIONS 

RECOMMENDATIONS 

IN'I'RODUCT ION 

Purpose and Authority 

General Description of Industry 

Industry Distribution 

Industry Growth 

Bibliography 

INDUSTRY SUBCATEGORIZATION 

Rationale of Subcategorization 

Development of Subcategories 

Description of subcategories 

Bibliography 

WASTE CHARACTERISTICS 

waste Constituents 

Bibliography 

SELECTION OF POLLUTANT PARAMETERS 

Parameters for Effluent Limitations 

Other Pollutants 

Oxygen Demand Parameters 

Phenolic COmpounds 

Bibliography 

iii 

1 

3 

7 

7 

8 

23 

26 

29 

31 

31 

32 

36 

40 

41 

41 

53 

55 

55 

56 

59 

60 

63 
Section 

VII CONTROL AND TREATMENT TECHNOLOGY 

Page No. 

65 

Vl~I 

IX 

X 

In-plant Control/Treatment Techniques 65 

Analytical Techniques and Field 68 

Verification Studies 

zero Lischarge Technologies 85 

End-of-Pipe Technology for Wastes Other 94 

than Produced water 

Bibliography 100 

COST, J:;NERGY, AND NONWA 'I·ER 

QUALITY ASFEC'IS 

COf!t Analysis 

Offshore Produced Water Disposal 

Onshore Produced water Disposal 

Offshore Sanitary Waste 

Energy Requirements for Operating 

Flotation Systems 

Nonwater-Quality Aspects 

Bibliography 

EFFLUEN'I !.IMITATIONS FOR BES'I· 

PRACTICABLE CONTROL TECHNOLOGY 

Produced Water Technology 

Procedure for Development of 

BPCT Effluent Limitations 

Bibliography 

EFFLUENT LIMITATIONS FOR BEST AVAILABLE 

TECHNOLOGY ECONOMICALLY ACHIEVABLE 

103 

103 

103 

106 

116 

116 

117 

123 

125 

125 

126 

138 

139 

Near Offshore and Coastal Subcategories - 139 

Produced Water 

Far Offshore subcategory - Produced water 139 

and Deck Drainage 

iv 
Section 

XI 

XII 

XIII 

NEW SOURCE PERFORMANCE S~ANDARDS 

ACKNOWLEDGEMENTS 

GLOSSARY AND ABBREVIA~·IONS 

v 

Page No. 

143 

145 

147 
Table No. 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

L~ST OF TABLES 

Title Pag:e 

Eff~uent Limitation - BPCTCA 

Effluent Limitation - BATEA and 

New Source 

u.s. Supply and Demand of Petroleum 

and Natural Gas 

u.s. Offshore Oil Production 

Po~lutants in Produced Water, 

Louisiana Coastal 

Pol~utants contained in Produced Water, 

coastal California 

Range of constituents in Produced 

Formation Water--Offshore Texas 

Range of constituents in Produced 

Formation Water--Onshore Ca~ifornia 

Range of COnstituents in Produced 

Formation Water--wyoming 

Range of COnstituents in Produced 

Formation Water--Pennsylvania 

Range of constituents in Produced 

Formation Water--Onshore Louisiana 

Range of Constituents in Produced 

Formation water--Onshore Texas 

Volume of Cuttings and Muds in 

Typical 10,000 Foot Dril~ing 

Operation 

Typical Raw combined Sanitary and 

Domestic Wastes from Offshore Facilities 

Effluent Qualit~ Requirements for 

ocean Waters of California 

Effect of Acidif~cation on Oil 

and Grease Data 

Oil and Grease Data, Texas Coastal 

vii 

No. 

4 

5 

28 

28 

42 

44 

45 

46 

47 

47 

48 

48 

51 

52 

62 

69 

71 
Table No. 

18 

19 

20 

21 

22 

23 

24 

25 

26 

27 

28 

29 

30 

31 

32 

Title 

Oil and Grease Data, California 

coastal 

Performance of Individual Units, 

Louisiana Coastal 

Texas coastal Verification Data 

Verification of Oil and Grease Data, 

California Coastal 

Performance of Various Treatment 

Systems, Louisiana coastal 

Performance of various Treatment 

Systems, Wyoming and Pennsylvania 

Design Requirements for 

Offshore Sanitary wastes 

Average Effluents of Sanitary Treatment 

Systems, Louisiana coastal 

Operating Cost Offshore 

Formation Water Treatment Equipment 

Costs, Offshore Installations, 200 

Barrels Per Day Flow Rate 

Formation water Treatment Equipment Costs, 

Oftshore Installation, 1,000 Barrels 

Per Day Flow Rate 

Formation Water Treatment Equipment costs, 

Offshore Installation, 5,000 Barrels Per 

Day Flow Rate 

Formation Water Treatment Equipment Costs, 

Offshore Installation, 10,000 Barrels 

Per Day Flow Rate 

Formation Water Treatment Equipment costs, 

Offshore Installation, 40,000 Barrels 

Per Bay Flow Rate 

Capital Costs for Onshore Disposal by 

Reinjection of Produced Formation water 

From Field surveys in Se.lected States 

viii 

73 

74 

75 

84 

84 

99 

99 

106 

107 

108 

109 

110 

111 

113 
Table No. Title Page No. 

33 Annual Operating cost for onshore Disposal 114 

by Reinjection of Produced Formation Water 

From Field surveys in Selected States 

34 cost Estimates for Treatment in Ponds and 115 

Disposal by Discharge for Stripper Well 

Facilities 

35 cost Estimates for ~reatment by Gas 116 

Flotation and Pond and Discharge for 

Beneficial Dischargers 

36 cost Estimates for Treatment by Gas 116 

Flotation and Discharge for coastal 

Platforms 

31 Estimated Treatment Plant Costs for 119 

Sanitary Wastes for Offshore Locations 

Package Extended Aeration Process 

38 Estimated Horsepower Requirements for the 120 

Operation of Flotation Treatment Systems 

39 Estimated Incremental Energy Requirements, 121 

Flotation systems 

40 Energy Requirements for Flotation Systems 122 

as Compared to Net Energy Production 

Associated with the Produced water Flows 

41 Conversion Table 154 

ix 
Fi9:ure No. 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

13 

LIST OF FIGURES 

Title 

Rotary Drilling Rig 

Shale Shaker and Blowout 

Preventer 

Central Treatment Facility in 

Estuarine Area 

Horizontal Gas Separator 

Vertical Heater-Treater 

Rotor-Disperser and Lissolved Gas 

Flotation Processes for Treatment 

of Produced Water 

Onshore Production Facility with 

Discharge to surface waters 

Typical Cross Section Unlined 

Earthern Oil-Water Fit 

Typical completion of an Injection 

Well and a Producing Well 

99th Percentile of Monthly Average Oil 

and Grease concentration vs. Frequency 

of Sampling Each Month 

Cumulative Plot Effluent Concentrations 

of all Selected Flotation Units in the 

Louisiana Gulf Coast Area 

Cumulative Plot of Effluent Concentrations 

of all Wyoming Data 

cumulative Plot of Effluent concentrations 

of '!'en Selected Flotation Units in the 

Louisiana Gulf coast Area 

xi 

Page No. 

10 

11 

15 

16 

18 

77 

86 

87 

90 

131 

132 

134 

141 
SECTION I 

CONCLUSIONS 

Th~s study covered the waste treatment technology for the Oil and 

Gas Extraction Point Source Category. The Oil and Gas Extraction 

Point Source category covers the pollutants ar~s~ng from the 

production of crude petroleum and natural gas, drilling oil and 

gas wells, and oil and gas field exploration services. 

The wastes associated with this category result from the 

discharge of produced water, drilling muds, drill cuttings, well 

treatment, and produced sands for all subcategories and 

additionally, deck drainage, sanitary and domestic wastes for the 

offshore and coastal subcategories. 

Since the raw waste loads and treatability of the wastes are 

independent of size, location and climate and the volume of 

production water varies with the age and nature of the ~roducing 

formation, the limitations are set in terms of concentration and 

the subcategorization is based on a balance of the costs with the 

potential environmental benefits and energy use (loss) • The 

subcategories developed for the oil and gas extraction industry 

for the purpose of establishing effluent limitations are as 

follows: 

subcategory 

1. Near-Offshore 

2. Far-Offshore 

3. Onshore 

4. Coastal 

s. Beneficial Use 

6. Stripper 

Operations Included 

All facilities within offshore State 

waters. 

All facilities in Federal waters. 

All facilities landward of the territorial 

seas (except as defined by 4, 5, and 6 

below) • 

All facilites in the coastal bays and 

estuaries of Louisiana and Texas. 

These facilites with low TDS content 

produced waters who's discharge serves 

some beneficial use. 

All facilities with less than 10 barrels 

of crude oil per calendar day of 

production. 

1 
SECTION II 

R~COMMEN£A~IONS 

The significant or potentially significant waste water 

constituents are oil and grease, fecal coliform, oxygen demanding 

parameters, heavy metals, total dissolved solids, and toxic 

materials. These waste water constituents were selected to be 

the subject of the effluent limitations. 

Effluent limitations commensurate with the best practicable 

control technology currently available are promulgated interim 

final for each sutcategory. These limitations, listed in Table 1 

are explicit numerical values (whenever possible) or some other 

criteria. 

BPCTCA end-of-pipe technology is based on the application of the 

existing waste water treatment ~rocesses currently used in the 

Oil and Gas Extraction Industry. ~hese consist of equalization, chem~cal addition, and gas flotation (or ~ts equivalent) for the 

treatment of produced water and deck drainage. The variability 

of performance of this type of waste water treatment system has 

been recognized in the development of the BPCTCA effluent 

limitations. 

Effluent limitations commensurate with the best available 

technology economically achievatle are proposed for each 

subcategory. These effluent limitations are listed ~n Table 2. 

The primary end-of-pipe treatment for the near offshore 

subcategory is the subsurface disposal of production water and 

for the far offshore subcategory it is similar to that for 

BFCTCA. 

New source performance standards commensurate with the best 

available demonstrated technology are the same as the BATEA 

limitations. These effluent limitations are listed in Table 2. 

3 
~ 

Subcategory 

A. Near Offshore 

B. Far Offshore 

D. Coastal 

C. Onshore 

E. Beneficial Use 

Notes: 

TABLE 1 

Oil and Gas Extraction Industry 

Effluent Limitations - BPCTCA 

Water Source 

produced water 

deck drainage 

drilling muds 

dri 11 cuttings 

well treatment 

sanitary MlO 

M9IMc 

domesticc 

produced sand 

produced water 

dri 11 i ng muds 

drill cuttings 

well treatment 

produced sand 

Oil & Grease - mg/1 

Maximum for 

any one day 

72 

72 

a 

a 

a 

N/A 

N/A 

N/A 

a 

e 

Average of daily 

values for thirty 

consecutive days 

sha 11 not exceed 

48d 

48d 

a 

a 

a 

N/A 

N/A 

N/A 

a 

N/A 

no discharge 

no discharge 

no discharge 

no discharge 

a - No discharge of free oil to the surface waters. 

b - Minimum of l mg/1 and maintained as close to this concentration as possible. 

c - There shall be no floating solids as a result of the discharge of these materials. 

d - Not applicable to the coastal subcategory. 

Residual Chlorine - mg/1 

N/A 

N/A 

N/A 

N/A 

N/A 

greater than 1b 

N/A 

N/A 

N/A 

N/A 

e- For the onshore subcategory- no discharge; for the beneficial use subcategory- 45 mg/1. 
U'l 

TABLE 2 

Oil and Gas Extraction Industry Effluent Limitations - BATEA and New Source 

Pollutant Parameter- Effluent Limitations 

Subcategory Water Source Oil & Grease - mg/1 

Maximum for Average of daily 

anx one dax values for thirty consecutive days shall not exceed 

A. Near Offshore produced water No discharge D. Coastal deck drainage 72 48 

B. Far Offshore produced water 52 30 

deck drainage 52 30 

A. Near Offshore drilling muds a a 

B. Far Offshore drill cuttings a a 

C. Onshore well treatment a a 

D. Coastal sanitary M10 N/A N/A 

E. Beneficial Use M9IM N/A N/A 

domestic N/A N/A 

produced sand a a 

Notes: 

a - These BAT and New Source limitations are identical to those applicable for each 

subcategory as for BPT listed in Table 1. 

Residual Chlorine - mg/1 

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

greater than 1 

N/A 

N/A 

N/A 
SEC'IION III 

INTRODUC'IION 

Purpose and Authority 

Section 301 (b) of the Federal Water Pollution Control Act 

Amendments of 1972 requires the achievement by not later than 

July 1, 1977, of effluent limitat~ons for point sources, other 

than publicly owned treatment works. The limitations are to be 

based on application of the best practicable control technology 

currently available as defined by the Administrator pursuant to 

Section 304(b) of the Act. Section 301 (b) also requires the 

achievement by not later than July 1, 1983, of more stringent 

effluent limitations for point sources, other than publicly owned 

treatment works. The 1983 limitations are to be based on 

application of the best available technology economically 

achievable which will result in reasonable further progress 

toward the national goal of eliminating the discharge of all 

pollutants, as determined in accordance with regulations issued 

by the Administrator ~ursuant to Section 304(b) of the Act. 

Section 306 of the Act requires the Administrator, within one 

year after a category of sources is included in a list published 

pursuant to section 306(b) (1) {A) of the Act, to propose 

regulations establishing Federal standards of performances for 

new sources within such categories. 'I·he Administrator published, 

in the Federal Register of January 16, 1973 (38 F.R. 1624), a 

list of 27 source categories. Publication of an amended list 

will constitute announcement of the Administrator's intention of 

establishing, under section 306, standards of performance 

applicable to new sources within the Oil and Gas Extraction 

Industry. The list will be amended when proposed regulations for 

the 0~1 and Gas Extraction Industry are published in the Federal 

Reqister.The standards are to reflect the greatest degree of 

effluent reduction which the Administrator determines to be 

achievable through the application of the best available 

demonstrated control technology, ~rocesses, operating methods, or 

other alternatives; where practicable, a standard may permit no 

discharge of pollutants. 

Section 304(b) of the Act requires the Administrator to publish 

within one year of enactment of the Act, regulations providing 

guidelines for effluent limitations. 'Ihe guidelines are to set 

forth: 

The degree of effluent reduction attainable through application 

of the best practicable control technology currently available. 

The degree of effluent reduct~on attainable through 

of the best control measures and practices 

7 

application 

economically 
achievable including treatment techniques, process and procedure 

innovations, operating methods, and other alternatives. 

The findings contained herein set 

guidelines pursuant to section 304(b) 

segments of the petroleum industry. 

General Description of Industry 

forth effluent limitations 

of the Act for certain 

The segments of the industry to be covered by this study are the 

following Standard Industrial Classifications (SIC): 

1311 crude Petroleum and Natural 

Gas 

1381 Drilling 0~1 and Gas Wells 

1382 Oil and Gas Field Exploration 

services 

1389 Oil and Gas Field Services, 

not classified elsewhere 

Within the above SIC's, this study covers those activit~es 

carried out both onshore and in the estuarine, coastal, and outer 

Continental Shelf areas. 

The characteristics of wastes differ considerably for the 

different processes and operations. In order to describe the 

waste derived from each of the industry subcategories established 

in section IV, it is essential to evaluate the sources and 

contaminants in the three broad activities in the oil and gas industry--explor~ng, drilling, and producing--as well as the 

satellite industries that su~~ort those activities. 

Exploration 

The exploration process usually consists of mapping and aerial 

photography of the surface of the earth, followed by special 

surveys such as seismic, gravimetric, and magnetic, to determine 

the subsurface structure. The special surveys may be conducted 

by vehicle, vessel, aircraft, or on foot, depending on the 

location and the amount of detail needed. 

These surveys can suggest underground conditions favorable to 

accumulation of oil or gas deposits, but they must be followed by 

the drill since only drilling can prove the actual existence of 

oil. 

Aside from sanitary wastes generated by the personnel involved, 

only the drilling phase of exploration generates significant 

amounts of water pollutants. Exploratory drilling, whether 

8 
shallow or deep, generally uses the same rotary drilling methods 

as development drilling. The discussion of wastes generated by 

exploratory drilling are discussed under "Drilling System". 

Drilling System 

The majority of wells drilled by the petroleum industry are 

drilled to obtain access to reservoirs of oil or gas. A 

significant number, however, are drilled to gain knowledge of 

geologic formation. This latter class of wells may be shallow 

and drilled in the initial exploratory phase of operations, or 

may be deep exploration seeking to discover o~l or gas bearing 

reservoirs. 

Most wells are drilled today by rotary drilling 

Basically the methods consist of: 

methods. 

1. Machinery to turn the bit, to add sections on the drill 

pipe as the hole deepens, and to remove the drill pipe 

and the bit from the hole. 

2. A system for circulating a fluid down through the drill 

pipe and tack up to the surface. 

This fluid removes the particles cut by the bit, cools and 

lubricates the bit as ~t cuts, and, as the well deepens, controls 

any pressures that the bit may encounter in its passage through 

various formations. The fluid also stabilizes the walls of the 

well bore. 

The drilling fluid system consists of tanks to formulate, store, 

and treat the fluids; pumps to force them through the drill pipe 

and back to the surface; and machinery to remove cuttings, fines, 

and gas from fluids returning to the surface (see Figure 1). A 

system of valves controls the flow of drilling fluids from the 

well when pressures are so great that they cannot be controlled 

by weight of the fluid column. A situation where drilling fluids 

are ejected from the well by subsurface pressures and the well 

flows uncontrolled is called a blowout, and the controlling valve 

system is called the blowout preventer (see Figure 2). 

For offshore o~erations, drilling rigs may be mobile or 

stationary. Mobile rigs are used for both exploratory and 

development drilling, while stationary r~gs are used for 

development drilling in a proven field. Some mobile rigs are 

mounted on barges and rest on the bottom for drilling in shallow 

waters. Others, also mounted on barges are jacked up above the 

water on legs for drilling in deeper water (up to 300 feet). A 

third class of mobile rigs are on floating units for even deeper 

operations. A floating rig may be a vessel, with a typical 

ship's hull, or it may be semisubmersible--essentially a floating 

platform with special submerged hulls and supporting a rig well 

9 
Fig. 1 

A KELLY 

B STANDPIPE and ROTARY HOSE 

C SHALESHAKER 

D OUTLET FOR DRILLING FLUID 

E SUCTION TANK 

F PUMP 

---) FLOW OF DRILLING FLUID 

E 

F 

-- ROTARY DRILLING RIG 

10 
~~~-D . ~. \ 

: I 

I I 

I I 

I I 

DRILL BIT-t 

' . ' ' ' ' G ..._-... :_...-4=~ ....,.-........,..,..,, 

H 

A KELLY 

C SHALESHAKER 

D OUTLET FOR DRILLING FLUID 

G HYDRAULICALLY OPERATED BLOWOUT PREVENTER 

H OUTLETS, PROVIDED WITH VALVES 

AND CHOKES FOR DRILLING FLUID 

DRILLING FLUID 

Fig. 2 -- SHALESHAKER AND BLOWOUT PREVENTER 

11 
above the water. Stationary rigs are mounted on pile-supported 

platforms. 

Onshore drilling rigs used today are almost completely mobile. 

The derrick or mast and all drilling machinery are removed when 

the well is completed and used again in a new location. 

Rigs used in marsh areas are usually barge mounted, and canals 

are dredged to the drill sites so that the rigs can be floated 

in. 

The major source of pollution in the drilling system is the 

drilling fluid or "mud" and the cuttings from the bit. In early 

wells arilled by the rotary method, water was the drilling fluid, 

The water mixed with the naturally occurring soils and clays and 

made up the mud. The d1fferent characteristics and superior 

performance of some of these natural muds were evident to 

drillers, which led to deliberately formulated muds. The 

composition of modern drilling muds is quite complex and can vary 

widely, not only from one geographical area to another, but also ~n different portions of the same well. 

The drilling of a well from top to bottom is not a continuous 

process. A well is dr~lled in sections, and as each section is 

completed it is lined with a section of pipe or casing (see 

Figure 2). The different sections may require different types of 

mud. The mud from the previous section must either be disposed 

of or converted for the next section. some mud is left in the 

completed well. 

Basic mud components include: bentonite or attapulgite clays to 

increase viscosity and create a gel; barium sulfate (barite), a 

weighting agent; and lime and caustic soda to increase the pH and 

control viscosity. (Additional cond~tioning constituents may 

consist of polymers, starches, lignitic material, and various 

other chemicals). Most muds have a water base, but some have an 

oil base. Oil based muds are used in special situations and 

present a much higher potential for pollution. They are 

generally used where bottom hole temperatures are very high or 

where water based muds would hydrate water-sensitive clays or 

shales. They may also be used to free stuck drill pipes, to 

drill in permafrost areas, and to kill producing wells. 

As the drilling mud is circulated down the drill pipe, around the 

bit, and bacK up in annulus between the bore hole and the drill 

pipe, it br~ngs with it the material cut and loosened by the bit, 

plus fluids which may enter the hole from the formation (water, 

oil, or gas) • When the mud arrives at the surface, cuttings, 

silt, and sand are removed by shaleshakers, desilters, and 

desanders. Oil or gas from the formation is also removed, and 

the cleansed mud is cycled through the drilling system again. 

With offshore wells, the cuttings, silt and sand are discharged 

12 
overboard if they do not contain oil. Some drilling mud clings 

to the sand and cuttings, and when this material reaches the 

water the heavier particles (cuttings and sand) sink to the 

bottom while the mud and fines are swept down current away from 

the platform. 

Onshore, discharges from the shaleshakers and cyclone separators 

(desanders or desilters) usually go to an earthen (slush) pit 

adjacent to the rig. To dispose of this material the pit is 

backfilled at the end of the drilling operations. 

The removal of fines and cuttings is one of a number of steps in 

a continuing process of mud treatment and conditioning. This 

processing may be done to keep the mud characteristics constant 

or to change them as required by the drilling conditions. Many 

constituents of the drilling mud can be salvaged when the 

drilling is completed, and salvage plants may exist either at the 

rig or at another location, normally at the industrial facility 

that supplies mud or mud components. 

Where dri~ling is more or 

well offshore platform, 

frequent occurrence since 

one well to another. 

less continuous, such as on a multiplethe disposal of mud should not be a 

it can te cond~tioned and recycled from 

The drilling of deeper, hotter holes may increase use of oil 

based mud. Hollliever, new mud additives may permit use of water 

based muds where only oil muds would have served before. Oil 

muds always present disposal problems. 

Production System 

crude oil, natural gas, and gas liquids are normally produced 

from geological reservoirs through a deep bore well into the 

surface of the earth. The fluid ~roduced from oil reservoirs 

normally consists of oil, natural gas, and salt water or brine 

containing both dissolved and suspended solids. Gas wells may 

produce dry gas but usually also ~roduce varying quantities of 

light hydrocarbon liquids (known as gas liquids or condensate) 

and salt water. As in the case of oil field brines, the water 

contains dissolved and sus~ended solids and hydrocarbon 

contaminants. The suspended solids are normally sands, clays, or 

other fines from the reservoir. The oil can vary widely in its 

physical and chemical properties. The most important properties 

are ~ts density and viscosity. Density is usually measured by 

the "API Gravity" method which assigns a number to the oil based 

on its specific gravity. The oil can range from very light 

gasoline like mater~als (called qatural gasolines) to heavy, 

viscous asphalt like materials. 

The fluids are normally moved through tubing contained within the 

larger cased bore hole. For oil wells, the energy required to 

13 
lift the fluids up the well can be supplied by the natural 

pressures in the formation, or it can be provided or assisted by 

various man-made operations at the surface. The most common 

methods of supplying man-made energy to extract the oil are: to 

inject fluids (normally water or gas) into the reservoir to 

maintain pressure, which would otherwise drop during withdrawal; 

to force gas into the well stream in order to lighten the column 

of fluid in the bore and assist in lifting as the gas ex~ands up 

the well; and to employ various types of pumps in the well 

itself. As the fluids rise in the well to the surface, they flow 

through various valves and flow control devices which make up the 

well head. One of these is an orifice (choke) which maintains 

required back Fressure on the well and controls, by throttling 

the fluids, the rate at which the well can flow. In some cases, 

the choke is placed in the bottom of the well rather than at the 

well head. 

Once at the surface, the various constituents in the fluids 

produced by oil and gas wells are separated: gas from the 

liqu~ds, oil from water, and solids from liquids (see Figure 3). 

The marketable constituents, normally the gas and oil, are then 

removed from the production area, and the wastes, normally the 

brine and solids, are dis~osed of after further treatment. At 

this stage, the gas may still contain significant amounts of 

hydrocarbon liquids and may be further processed to separate the 

two. 

The gas, o~l, and water may be separated in a single vessel or, 

more commonly, in several stages. some gas is dissolved in the 

o~l and comes out of solution as the pressure on the fluids 

drops. Fluids from high-pressure reservoirs may have to be 

passed through a number of separating stages at successive~y 

lower pressures before the oil is free of gas. The oil and brine 

do not separate as readily as the gas does. usually, a ~uantity 

of oil and water is present as an emulsion. This emulsion can 

occur naturally in the reservoir or can be caused by various 

processes which tend to mix the oil and water vigorously together 

and cause droplets to form. Passage of the fluids into and up 

the well tends to mix them. Passage through well head chokes, 

through various pipes, headers, and control valves into 

separation chambers, and through any centrifugal pumps in the 

system, tends to increase emulsification. Moderate heat, 

chemical action, and/or electrical charges tend to cause the 

emulsified liquids to separate or coalesce, as does the passage 

of time in a quiet environment. Other types of chemicals and 

fine suspended solids tend to retard coalescence. The 

characteristics of the crude oil also affect the ease or 

difficulty of achieving process separation.(1) 

Fluids produced by oil and gas wells are usually introduced into 

a ser~es of vessels for a two-stage separation process. Figure 4 

shows a gas separator for separating gas from the well stream. 

14 
... 

l11 

CENTRAL TREATMENT FACILITY IN ESTUARINE AREA 

HIGH PRESSURE GAS 

INTERMEDIATE PRESSURE GAS 

~ _:wELL STREAM 

~ 

~-

--- ~- .:--..._. 

~ ~ 

--- "'---=------~~ 

- :. ----- - --- -==-=- _-~ --....._-:-..-«:::-=; 

-=:..-:. ...... =--=-~~~~ ~ -- --;;-, f, .... , - ..=...... ~-- ---=-= -~--= -""-- -::.-::....::. __ 

~" ~ ._ ~ .... --<ol!&.--:~ _:.~ __ 

~;'7 .:....: 

:......=-::--~~~ -~"=--=.-.4..- ~~~- . . ~~ ~ 

WATFR TReATMENT POLLUTION CONTROL 

--~:~~-~:==--=~~-:.=c::~ ~ ~~ -ar - •-=_.~ -- -- -- - - - - ·- -- -- :... De. -_- - ... -_ - .. .:. -

___:::-___::!_-TO CRUDE OIL SALES M- :_ :...: ~ -- - -- ~---- ''•••••••••••••••••••••••.._~~ ---------- ~------..-·-

Fig. 3 -- CENTRAL TREATMENT FACILITY IN ESTUARINE AREA 
_. 

0' 

A 

A-OIL AND GAS INLET 

B-IMPACT ANGLE 

C -DE -FOAM lNG 

ELEMENT 

0- WAVE BREAKER AND 

E-MIST EXTRACTOR G-DRAIN 

SELECTOR PLATE F-G·As OUTLET H-OIL OUTLET 

(DUMP VALVEI 

Fig. 4 -- HORIZONTAL GAS SEPARATOR 
Liquids (oil or oil and water) along w~th particulate matter 

leave the separator through the dump valve and go on to the next 

stage: oil-water separation. Because gas comes out of solution 

as pressure drops, gas-oil separators are often arranged in 

series. High-pressure, intermediate, and low-pressure separators 

are the most common arrangement, with the h~gh-pressure liquids 

passing through each stage in series and gas being taken off at 

each stage. Fluids from lower-~ressure wells would go directly 

to the most appropriate separator. The liquids are then piped to 

vessels for separating the oil from the produced water. Water 

which is not emulsified and separates easily may be removed in a 

simple separation vessel called a free water knockout. 

The remain~ng oil-water mixture will continue to another vessel 

for more elaborate treatment (see Figure 5). In this vessel 

(which may be called a heater-treater, electric dehydrator, gun 

barrel, or wash tank, depending on configuration and the 

separation method employed), there is a relatively pure layer of 

oil on the top, relatively pure trine on the tottom, and a layer 

of emulsified oil and brine in the middle. There is usually a 

sensing unit to detect the oil-water interface in the vessel and 

regulate the discharge of the fluids. Emulsion breaking 

chemicals are often added before the liquid enters this vessel, 

the vessel itself is often heated to facilitate breaking the 

emulsion, and some units employ an electrical grid to charge the 

liquid and to help break the emulsion. A combination of 

treatment methods is often employed in a single vessel. In 

three-phase separation, gas, oil, and water are all separated in 

one unit. The gas-oil and oil-water interfaces are detected and 

used to control rates of influent and discharge. 

Oil from the oil-water separators is usually sufficiently free of 

water and sediment (less than 2 percent) so as to be marketable. 

The produced water or produced water/solids mixtures discharged 

at this point contain too much oil to be d~sposed of into a water 

body. The object of processing through this point is to produce 

marketable products (clean oil and dry gas). In contrast, the 

next stages of treatment are necessary to remove sufficient oil 

from the produced water so that it may be discharged. These 

treatment operat~ons do not significantly increase the quality or 

quantity of the saleable product. They do decrease the impact of 

these wastes on the environment. 

Typical produced water from the last stage of process would 

contain several hundred to perhaps a thousand or more parts per 

million of oil. There are two methods of disposal: treatment 

and discharge to surface (salt) waters or injection into a 

suitable subsurface formation in the earth. Surface discharge is 

normally used offshore or near shore where bodies of salt or 

brackish water are available for disposal. Injection ~s widely 

used onshore where bodies of salt water are not available for 

17 
EMULSION 

INL.E:T 0 nO 0 

Oo~ 

- 0 

0 ..... 0 ) o• 0 

0 oO 0 

""- l . -i 

-.. HEAT 

EXCHANGER 

EXSELSIOR 

FILTER 

(OTHER TYPES OF UNITS 

MIGHT CONTAIN THE GRID 

OF AN ELECTRIC DEHYDRATOR 

IN PLACE OF THE FILTER SECTION) 

\ 

OIL OUT 

EMULSION IN/ DRAIN __ __J..------

Fig. 5 VERTICAL HEATER-TREATER 

18 

z 

0 

~ Cl: 

~ 

"" en 

en 

4 

C) 

C) 

z 

::::; 

... 

... 

"" en 

~ 

5 

WATER 

LEG 
surface disposal. (produced water to be disposed of by injection 

may still require some treatment). 

Some of the same operations used to facilitate separation ~n the 

last stage of processing (chemical addition and retention tanks) 

may be used in waste water treatment, and other methods such as 

filtering, and separation by gas flotation are also used. In 

addition, combinations of these operations can be used to 

advantage to treat the waste water. The vast majority of present 

offshore and near shore (marsh) facilities in the Gulf of Mexico 

and most facilities in cook Inlet, Alaska, treat and dispose of 

their produced water to surface salt or brackish water bodies. 

The sophistication of the treatment employed by dischargers of 

produced water is dependent upon the regulation governing such 

discharges. For instance in the A~palachian states most produced 

water is discharged to local streams after only treatment in 

ponds; while ~n California dischargers utilize a high degree of 

treatment. The state of Wyoming allows discharge for beneficial 

use ~f the produced water meets oil and grease and total 

dissolved solids (TDS) requirements. 

several options are available in injection systems. Often water 

will be injected into a producing oil resorvoir to maintain 

reservoir pressure, and stabilize reservoir conditions. In a 

similar operation called water flooding, water is ~njected into 

the reservoir in such a way as to move oil to the producing wells 

and increase ultimate recovery. This process is one of several 

known as secondary recovery since ~t produces oil beyond that 

available by primary production methods. A successful water 

flooding project will increase the amount of oil being produced 

at a field. It will also increase produced water volume and thus 

affect the amount of water that must be treated. Pressure ma~ntenance of water injection may also increase the amount of 

water produced and treated. Injection is also feasible solely as 

a disposal method. It (injection) is extensively used in onshore product~on areas except in the Appalchian states of Pennsylvania, 

west Virginia, New York and Kentucky, where useable shallow hor~zons do not exist. In California, produced water from 

offshore facilities is transported to shore for dis~osal by 

reinjection. 

The treatment associated with produced water disposal by 

injection is dependent upon the permeability of the receiving 

formation. In most all cases corrosion-inhibiting chemicals are 

necessary, but the treatment can range from simply skim tanks to 

gas flotat~on followed by mixed-media filtration. 

Evolution of Facilities 

Early offshore develo~ment tended to place 

structures, bringing the fluids ashore 

19 

wells 

for 

on individual 

separation and 
treatment (see Figure 3). As the industry moved farther 

offshore, the wells still tended to be located on individual 

platforms with the output to a central platform for separation, 

treatment, and discharge to a pipeline or barge transportation 

system. 

With increasing water depth, multiple-well ~latforms were 

developed with 20 or more wells drilled directionally from a 

single platform. Thus an entire field or a large portion of a 

field could be developed from one structure. Offshore Louisiana 

multiple-well flatforms include all processing and treatment, in 

offshore California and in cook Inlet facilities, gas separation 

takes place on the platforms, with the liquids usually sent 

ashore for separat~on and treatment. 

All forms of primary and secondary recovery as well as separation 

and treatment are performed on platforms, which may include 

cam~ressor stations for gas lift wells and sophisticated water 

treatment facilities for water flood projects. Platforms far 

removed from shore are practically independent production units. 

Platform design reflects the o~erating environment. cook Inlet 

~latforms are enclosed for frotection from the elements and have 

a structural support system designed to withstand ice floes and 

earthquakes. Gulf Coast platforms are usually open, reflecting a 

mild climate. Support systems are designed to withstand 

hurricane-generated waves. 

A typical onshore production facility would consist of wells and 

flowlines, gas-liquid and oil-water production separators, a 

waste water treatment unit (the level of treatment being 

dependent on the quality of the waste water and the demands of 

the injection system and receiving reservoir) , surge tank, and 

injection well. Injection might either be for pressure 

maintenance and secondary recovery or solely for disposal. In 

the latter case, the well would probably be shallow and operate 

at lower pressure. The system might include a pit to hold waste 

water should the injection system shut down. 

A more recent production technique and one which may become a 

significant source of waste in the future is called "tertiary 

recovery." The process usually involves injecting some substance 

into the oil reservoir to release or carryout additional oil not 

recovered by primary recovery (flowing wells by natural reservoir 

pressure, pumping, or gas lift) or by secondary recovery. 

Tertiary recovery is usually classified by the substance injected 

into the reservo~r and includes: 

1. Thermal recovery 

2. Miscible hydrocarbon 

20 
3. Carbon dioxide 

4. Alcohols, soluble oil, micellar solutions 

5. Chemical floods, surfactants 

6. Gas, gas/water, inert gas 

7. Gas repressuring, depletion 

8. Polymers 

9. Foams, emuls~ons, precipitates 

The material is injected into the reservoir and moves through the 

reservoir to the producing wells. During this passage, it 

removes and carries with it oil remaining in pores in the 

reservoir rocks or sands. Oil, the injected fluid, and water may 

all be moved up the well and through the normal production and 

treatment system. 

Nine economically successful applications of tertiary recovery 

have been documented (two of them in Canadian fields): one 

miscible hydrocarbon application; three gas applications; two 

polymer applications, and three combinations of miscible 

hydrocarbon with gas drive. 

At this time very little is known about the wastes that will be 

produced by these production processes. They will obviously 

depend on the ty~e of tertiary recovery used. 

Field Service 

A number of satellite ~ndustries specialize in providing certain 

services to the production side of the o~l industry. Some of 

these service industries produce a particular class of waste that 

can be identified with the service they provide. Of the wasteproducing serv~ce industries, drilling (which is usually done by 

a contractor) is the largest. Drill~ng fluids and their disposal 

have already been discussed. Other services include completions, 

workovers, well acidizing, and well fracturing. 

When a company decides that an oil or gas well is a commercial 

producer, certain equipment will be installed in the well and on 

the well head to bring the well into production. The equipment 

from this process--called 11 completion11 --normally consists of 

various valves and sealing devices installed on one or more 

strings of tubing in the well. If the well will not produce 

sufficient fluid by natural flow, various types of pumps or gas 

lift systems may be installed in the well. Since heavy weights 

and high lifts are normally involved, a rig is usually used. The 

21 
rig may be the same one that drilled the well, or it may be a 

special (normally smaller) workover rig installed over the well 

after the drilling rig has been moved. 

After a well has been in service for a while it may need remedial 

work to keep it producing at an acceptable· rate. For example, 

equipment in the well may malfunction, different equipment may be 

required, or the tubing may ~ecome plugged up by deposits of 

paraffin. If it is necessary to remove and reinstall the tubing 

in the well, a workover r~g will ~e used. It may be possible to 

accomplish the necessary work with tools mounted on a wire and 

lowered into the well through the tubing. This is called a wire 

line operation. In another systeu, tools may be forced into the 

well by pumping them down w~th fluid. Where possible, the use of 

a rig is avoided, since it is expensive. 

In many wells, the potential for production is limited by 

impermeability in the producing geological formation. This 

cond~tion may ex~st when the well is first drilled, it may worsen 

with the passage of time, or both situations may occur. Several 

methods may be used, singly or in combination, to increase the 

well flow by altering the physical nature of the reservoir rock 

or sand in the immediate vicinity of the well. 

The two most common methods to increase well flow are acidizing 

and fracturing. Acidizing consists of introducing acid under 

pressure through the well and into the producing formation. The 

acid reacts with the reservoir material, producing flow channels 

which allow a larger volume of fluids to enter the well. In 

addition to the acid, corrosion inhibitors are usually added to 

protect the metal in the well system. Wetting agents, solvents, 

and other chemicals may also be used in the treatment. 

In fracturing, hydraulic pressure forces a fluid into the 

reservoir, producing fractures, cracks, and channels. Fracturing flu~ds may contain acids so that chemical disintegration, as well 

as fracturing takes place. The fluids also contain sand or some 

similar material that keeps the fracture propped open once the 

pressure is released. 

When a new well is being completed or when it is necessary to 

pull tubing to worK over a well, the well is normally "killed"--

that is, a column of drilling mud, oil, water, or other liquid of 

sufficient weight is introduced into the well to control the down 

hole pressures. 

When the work is completed, the liquid used to kill the well must 

be removed so that the well will flow again. If mud is used, the 

initial flow of oil from the well will be contaminated with the 

mud and must be disposed of. Offshore, it may be disposed of 

into the sea if it is not oil contaminated, or it may be 

salvaged. onshore, the mud may te disposed of in pits or may ne 

22 
salvaged. Contaminated oil is usually disposed by burning at the 

site. 

In acidizing and fracturing, the spent fluids used are wastes. 

They are moved through the production, process, and treatment 

systems after the well begins to flow again. Therefore, initial 

production from the well will contain some of these fluids. 

Offshore, contaminated oil and other liquids are barged ashore 

for treatment and disposal; contaminated solids are buried. 

The fines and chemicals contained in oil from wells put on stream 

after acidizing or fracturing have seriously upset the waste 

water treatment units of production facilities. When the sources 

of these upsets have been identified, corrective measures can 

prevent or mitigate the effects. (2) 

Industry Distribution 

1974, domestic production was 8.8 million barrels-per-day (bpd) 

of oil and 1.7 million bpd of gas liquids, for a total production 

of 10.5 bpd; down slightly from the four previous years. (3) 

Total imports were 6.1 million bpd for 1974. 

There are approximately half a m~llion producing oil wells and 

126,000 gas and condensate wells in the United States. Of the 

30,000 new we~ls drilled each year, about 55 percent produce oil 

or gas. 

Oil is presently produced in 32 of the 50 states and from the 

Outer continental Shelf (OCS) off of Louisiana, Texas, and 

California. Exploratory drilling is underway on the ocs off of 

Mississippi, Alabama, and Florida. In 1972, the five largest 

oil-producing States were: Texas, Louisana, California, Oklahoma, 

and Wyoming. With development of the North Slope oil fields and 

construction of the Alaska pipeline, Alaska will become one of 

the most important oil producing States. 

Offshore oil production is presently concentrated in three areas 

in the Un~ted States: the Gulf of Mexico, the coast of 

California, and cook Inlet in Alaska. Offshore oil production in 

1973 was approximately 62 million ~arrels from cook Inlet, 116 ~llion from California, and 215 million from Louisiana and 

Texas, 

Gulf of Mexico - Texas and Louisiana 

Approximately 2,000 wells now produce oil and gas in State waters 

in the Gulf of Mexico and 6,000 on the ocs. over 90 percent are 

in Louisiana, with the remainder in Texas. Recent lease sales 

have been held on the ocs off Texas and off the Mississi~pi, 

Alabama, and Florida coasts. Discoveries have been made in those 

areas, and development will take place as ~uickly as platforms 

23 
can be installed, development dril~ing completed, and pipelines 

laid. 

Leases have been granted 

deep areas will probably be ~latforms, but their size 

increasing depth. 

in water as deep as 600 feet. These 

served by conventiona~ types of 

and cost increase rapidly with 

In addition to offshore activities, onshore production in Texas 

for 1974 accounted for 1,226 million barrels of oil and 7,942,352 

million cubic feet of gas, the largest contribution of any state. 

Oil production has been on a decline in Texas since the peak year 

of 1972. Oil and gas production in Texas is widespread, 

involving 212 out of 254 counties and approximately 165,000 gas, 

condensate, and crude oil wells. The amount of produced water 

generated is dependent on the method of oil production and the 

field location. Higher water cut ratios are experienced near the 

Gulf. Regulation by the State Railroad Commission prohibits 

discharge of produced water to fresh water bodies, and therefore 

reinjection for recovery and disposal technology has been 

developed to a high degree. 

Onshore activity in Louisiana is also significant, accounting for 

307 million barrels of crude in 1974 originating from 61 out of 

the 64 parishes (counties) in the State. There are approximately 

11,500 wells producing crude oil onshore and less than one 

percent of these wells are in the stripper category (less than 

ten barrels per day production). Of the 1,068 million barrels of 

produced water generated in 1974 the majority was re~njected for 

either recovery or disposal purposes; the remainder was 

discharged to unlined puts, saltwater estuaries or fresh water 

streams. The discharge of production water to fresh water 

streams is limited to the southern and central parts of the State 

where dril~ing of re~njection wells is extremely costly. 

Discharge to saltwater estuaries is practiced along the Gulf 

coast. Treatment prior to discharge consists of skim tanks and 

settling/separator ponds. Where reinjection is practiced the 

facilities are unsophisticated, consisting of a pximary separator 

and sedimentation. The disposal formations are at 2000-5000 foot 

depth and are very permeable, resulting in low well head pressure 

and power costs. Approximately 601 of the oil production under 

state onshore leases is generated at facilities which discharge 

their produced water. 

California 

There has been a general moratorium on drilling and development 

in the offshore areas of California since the Santa Barbara 

blowout of 1969. (4) 

Present offshore production in State waters comes from the area 

around Long Beach and Wilmington and also from the santa Barbara 

24 
area farther north. ocs production is confined to the Santa 

Barbara area. Except for one facility, all production from both 

state and Federal leases is piped ashore for treatment. A large 

and increasing amount of the produced brine is disposed of by 

subsurface injection. 

Exxon Corporation has applied for permits to develop an area 

leased prior to 1969 in the northern Santa Barbara Channel (the 

"Santa Ynez Unit"). several fields have been discovered on these 

leases in water depths from 700 to over 1,000 feet. Proposed 

development of the shallower portion of one of these areas calls 

for erection of a multiple-well drilling and production platform 

in 850 feet of water. If gas and oil are found in commercial 

quantities, the gas would be separated on the platform, with the 

water and oil sent ashore for separation and treatment. Produced 

water would be disposed of by subsurface injection ashore. 

Additional lease sales have been made on the OCS off Santa 

Barbara in southern California. 

Total oil production in California for 1974 was approximately 390 

million barrels (83 million barrels offshore) , a decline from the 

previous year. In addition to offshore facilities, the major 

areas of production in California are in the southern San Jacquin 

Valley, centered around the city of Bakersfield, and in the Long 

Beach-Wilmington area. In California, steam, hot water, and 

water flooding methods of secondary recovery are used. The total 

produced water is approximately 2,044 mill~on barrels per year, 

the majority of which is either reinjected for recovery or 

disposal or evaporated in ponds. Only eight producers in the 

State have discharge to navigable waters. 

cook Inlet, Alaska 

Offshore production in Cook Inlet comes from 14 multi~le-well 

platforms on four oil fields and one gas field. Development took 

place in the 1960's and has been relatively static for the past 5 

years. The demarcation line between Federal and State waters in 

lower cook Inlet is under litigation. The settlement of this 

dispute will probably lead to leasing and development of 

additional areas in the Inlet. 

Present practice is to separate gas on the platforms, sending the 

produced water and oil ashore for separation and treatment. some 

platforms are producing increasing amounts of produced water, and 

this, plus the occasional plugging of oil/water pipelines with 

ice in the winter, will encourage a change to platform se~ration, treatment, and disposal of produced waters. 

cook Inlet platforms are presently employing gas lift and treat 

Inlet sea water for water flooding. 

25 
Ap~alachia - Pennsylvania 

Oil was discovered over 100 years ago in Pennsylvania, the 

earliest discovery in the United States. Today the State of 

Pennsylvania•s oil production industry, like the other 

Appalachian states, is characterized by marginal production of 

0.3 barrles per day per well average for the 31,000 producing 

wells in the State, operating on approximately 2,300 leases. 

Although the amount of oil production is low (only 0.1~ of the 

u.s. total), Pennsylvania crudes supply 20~ of all u.s. lube oil 

production. Small independent operators dominate the industry, 

accounting for 65-701 of the production. The oil fields are 

located primarily in the northwest section of the State, McKean 

county alone accounting for 50i of the State•s ~reduction. The 

oil-bearing strata is shallow (1000-2000 feet) and relatively 

impermeable (1-20 millidarcies). 

All produced water generated is discharged to the surface 

following ripple aeration and separation/sedimentation in earthen 

ponds. Where water flooding is practiced, ground water is used 

after treatment as the source. There are plans on some of the 

larger leases to utilize production water for flooding, despite 

earlier failure of this method from plugging of the formation 

strata. current discharge pract~ces are in part justified by the 

absence of formations acceptable for reinjection due to 

permeability, surface outcroppings, lack of void space and 

substandard well abandonment procedures in the past. 

Industry Growth 

From 1960 to 1970, the Nation•s demand for energy increased at an 

average rate of 4.3 percent. Table 3 gives the projected nat~onal demands for oil and gas through 1985 and Table 4 the 

u.s. offshore oil production from 1970 through 1973. 

u.s. offshore production declined by about 78,500 barrels/day 

from 1972 to 1973. Offshore ~reduction amounts to approximately 

10 percent of u.s. demand and about 15 percent of u.s. 

production. 

While offshore production declined slightly from 1972 to 1973, 

the potential for increasing offshore production is much greater 

than for increasing onshore production. The Department of the 

Interior has pro~osed a schedule of three or four lease sales per 

year through 1978, mainly on remaining acreage in the Gulf of 

Mexico and offshore California. Additional areas in which ocs 

lease sales will very probably te held by 1978 include the 

Atlantic Coast (George 1 s Bank, Baltimore Canyon, and Georgia 

Embayment) and the Gulf of Mexico. 

26 
Not only will new areas be opened to exploration and ultimate 

development, but production will move farther offshore and into 

deeper waters in areas of present development. 

Movement into more distant and isolated environments will mean 

even more self-sufficiency of platform operationsr with all 

production, processing, treatment, and disposal being performed 

on the platforms. Movement into deeper waters will necessitate 

multiple-well structures, with a maximum number of wells drilled 

from a minimum number of platforms. 

Offshore leasing, explorationr and deve~opment will rapidly 

expand over the next 10 yearsr and offshore production will make 

up an increasing proportion of our domestically produced supplies 

of gas and oil. 

27 
TABLE 3 

u.s. su~ply and Demand of Petroleum 

and Natural Gas (5) 

Petroleum (million barrels/day) 

Projected Demand 

% of Total u.s. Energy Demand 

Projected Domestic Supply 

% petroleum demand fulfilled 

by domestic supply 

Natural Gas (trillion cubic feet/year) 

Projected Demand 

i of Total u.s. Energy Demand 

Projected Domestic Supply 

~ gas demand fulfilled 

by domestic supply 

~AbLE 4 

15. 1 

44.1 

11.3 

74.9 

22.0 

33.0 

21.1 

96.0 

20.8 

43.9 

11.7 

56.3 

26.2 

28.1 

23.0 

87.8 

25.0 

43.5 

11. 7 

46.7 

27.5 

24.3 

23.8 

86.6 

u.s. Offshore Cil Production - (million barrels/day) (6) 

1970 

1. 58 

1971 

1. 69 

28 

1972 

1.67 

1973 

1. 59 
SECTION III 

Bibliography 

1. University of Texas-Austin, Petroleum Extension Service, and 

Texas Education Agency, Trade and Industrial Serivce. 1962. 

"Treating Oil Field Emulsions.'' 2nd. ed. rev. 

2. Gidley, J.L. and Hanson, H.R. 1974. "Central-Terminal Upset 

from Well Treatment Is Prevented." Oil and Gas Journal, Vol. 

72: No. 6: pp. 53-56. 

3. Independent Petroleum Association of America. "United States 

Petroleum statistics 2974 (Revised)." wash.Lngton, D.C. 

4. u.s. Department of the Interior, Geological survey. 1973. 

5. 

Draft Environment Impact Statement. Vol. 1: Proposed Plan 

of Development Santa Ynez Unit, Santa Barbara Channel, Off 

California." washington, DC 

Dupree, W.G., and West, J.A. 

Through the Year 2000." 

Washington, D.c. 

1972. "United States Energy 

u.s. Department of Interior. 

6. McCaslin, John c. 1974. "Offshore Oil Production soars. 11 

Oil and Gas Journal, Vol. 72: No. 18: pp. 136-142. 

29 
SECTION IV 

INDUSTRY SUBCATEGORIZATION 

Rationale For sutcategorization 

The Standard Industrial Classification's subcategorize industry 

into various groups for the purpose of analyzing production, 

employment, and economic factors which are not necessarily 

related to the type of wastes generated b¥ the industry. In 

development of the effluent limitations and standards, production 

methodology, waste characteristics, and other factors were 

analyzed to determine if separate limitations need to be 

designated for different segments of the industry. The following 

factors were examined for delineating different levels of 

pollution control technology and possibly subcategorizing the 

industry: 

1. Type of facility or operation 

2. Facility's size, age, and waste volumes 

3. Process technology 

4. Climate 

5. waste water characteristics 

6. Location of facil~ty 

Field surveys, waste treatment technology, and effluent data 

indicate that the most important factors are the type of 

facility, the facility's size, age, waste water volume, waste 

water characteristics, and location. The factor of climate is 

significant with respect to operational practices but has less 

influence on waste treatment technology. Process technology was 

found to have very little ~nfluence on the selection of pollution 

control technology. 

An evaluation of industry•s production units (barrels of oil per 

day or thousands of cubic xeet of gas per day) and waste volumes 

indicated no relationship between them. Produced water 

production may vary from less than 1 to 90 percent of the 

production fluids. High volumes of produced waters are assoc~ated with older production fields and recovery methods used 

to extract crude oil from partially depleted formations. 

Similarly, the amount of waste generated during drilling operat~ons is dependent upon the depth of the well, subsurface 

characteristics, recovery of drill muds, and recycl~ng. 

Therefore, industry subcategorization could not include an 

analysis of segmenting the industry on waste load per unit of 

production. 

31 
Development of Subcategories 

Based upon the type of facility, the industry may be subdivided 

into three major categories with similar type operations or 

activities: 1) crude petroleum and natural gas production; 2) 

oil and gas well field exploration and drilling; and 3) oil and 

gas well completions and workover. Further subdivision can be 

made within each to reflect location - offshore and onshore - and 

any wastes requiring specific effluent limitations and standards. 

Since sanitary wastes for onshore operations normally don't 

result in a discharge and since deck drainage is not applicable 

to onshore operations, these subcategories are only applicable to 

offshore facilities. Therefore, considering location and wastes, 

the major groups are subcategorized as follows: 

I crude Petroleum and Natural Gas Production 

A. Produced Water 

B. Deck Drainage 

c. Sanitary and Domestic waste 

II Oil and Gas Well Field Exploration and Drilling 

A. Drilling Muds 

B. Drill Cuttings 

c. sanitary and Domestic waste 

III Oil and Gas Well completions and Workover 

A. Chemical Treatment of Wells 

B. Production Sands 

Facility's Size, Age and waste Volumes 

Offshore facilities in Category I differ little in the type of 

process or produced water treatment technology for large, medium, 

or small facilities. One of the most significant factors 

affecting the size of the facility is the availability of space 

for central treatment systems to handle waste from several 

platforms or fields. Treatment systems on offshore platforms are 

usually limited to meet the needs of the immediate production 

facility and are designed for 5,000 to 40,000 barrels/day. In 

contrast,. onshore treatment systems for offshore production 

wastes may be designed to handle 100,000 barrels/day or more. 

For small facilities, wastes may require intermediate storage and 

a transport system to deliver the produced water to another 

facility for treatment and disposal. comparable treatment 

technology has been developed for both large and small systems. 

32 
For onshore facilities, the type of ~roduced water treatment 

technology does tend to differ according to the size of the 

facility but there are notable exceptions. Since for the primary 

unit treatment process (the separation of oil and water), ponds 

of sufficient size are feasible for smaller facilities while 

mechanical systems (such as flotation) are required where larger 

amounts of produced water are handled. Smaller facilities are 

least likely to have the type cf operating staff required for 

sophisticated water treatment systems and are more likely to 

receive operating variances from local regulatory authorities. 

The types of treatment for sanitary wastes for large and small 

offshore facilities are different, as are facilities which are 

intermittently manned. For small and intermittently manned 

facilities, the waste may be incinerated or chemically treated, 

result~ng in no discharge. Because of operational problems and 

safety considerations, other types of treatment systems that will 

result in a discharge are being considered. Thus sanitary wastes 

must be sutcategorized based on facility size. 

The state of the art and treatment technology for Category I has 

been improving over the past several years; the majority of the 

facilities regardless of age have installed waste treatment 

facilities. However, the age of the production f~eld can impact 

the quantity of waste water generated. Many new fields have no 

need to treat for a number of years until the formation begins to 

produce water. The period before ~nitiating treatment is 

variable, depending on the characteristics of the particular f~eld, and can also be affected by method of recovery. If wastes 

are to be treated off shore, the initial design should provide 

for the necessary space and energy requirements that will be 

needed for the treatment systems to be installed over the 

expected life of the platform. 

Process Technology 

Process technology was reviewed to determine if the existing 

equipment and separation systems influenced the characteristics 

of the produced waste. Most oil/water process separation units 

consist of heater-treaters, electric dehydration units or gravity 

separation (free water knockout or gun barrel). The type of 

process equi~ment and its configuration are based in part on the 

characteristics of the ~roduced fluids. For example, if the 

fluids contain entrained oil in a 11 tight 11 emulsion, heat may be 

necessary to assist in separating water from the oil. Raw 

produced water data showed no significant difference in oil 

content between the various ~rocess units. When high influent 

concentrations to the produced water treatment facilities were 

observed they were found to be caused by malfunctions in the 

process equipment. It was concluded that there is no basis for 

subcategorization because of differences in process systems. 

33 
Climate 

C~imate was considered because condit~ons in the production 

regions differ w~dely. All regions treat by gravity separation 

or chemical/physical methods. ~hese systems are less sensitive 

to climatic changes than biological treatment. Sanitary waste 

treatment can be affected by extreme temperatures, but in areas 

with cold climates, facilities are enclosed, minimizing 

temperature variations. The volume or hydraulic loading due to 

rainfall may be significant with respect to the offshore Gulf 

Coast, but the waste contaminants (residual oils from drips, 

leaks, etc.) from deck drainage are independent of rainfall. 

Proper operation and maintenance can reduce waste oil 

concentrations to minimal levels, thus reducing the effect of 

rainfall. Therefore, no subcategorization is required to account 

for climate. 

Waste Water Characteristics 

Treatability and other characteristics of produced water are one 

of the most significant factors considered for subcategorization. 

Produced water may be high in dissolved solids (TDS) , oxygen 

demanding wastes, heavy metals, and taxies, in addition to the o~l and grease contamination. The current treatment technolog~es 

for produced water are either subsurface disposal or oil removal 

prior to discharge. The technology developed for each area of 

the country has been primarily influenced by local regulatory 

requirements (water quality and individual state or local laws), 

but other factors associated with produced water treatability and 

cost effectiveness may also have had an effect. (1,2,3) 

Factors which may affect produced water treatability are: 

1. Physical and chemical ~roperties of the crude oil, 

including solubility. 

2. Concentration of suspended and settleable solids. 

3. Fluctuation of flow rate and production method. 

4. Droplet sizes of the entrained oil emulsification. 

5. Other characteristics of the produced water. 

The impact of these variables can be minimized by existing 

process and treatment technology, which include desanders, surge 

tanks, and chemical treatment. 

34 
Location of Facility 

The locat~on of the facility affects the applicable treatment, 

the cost of that treatment, and the makeup of the wastes 

produced. The factors that affect the treatment method based on 

location are as follows: 

1. Availability of space and site conditions, such as, dry 

land, marsh area, or open water. 

2. Proximity to shore. 

3. ~ype and depth of subsurface formations suitable for 

injection of ~roduced water. 

4. surface water availability ( possible agricultural use 

of produced water) • 

5. Evaporation rate at location. 

6. Local water quality and statues. 

7. Type of receiving water ~ody. 

Location is a significant £actor specifically with respect to 

areas where saline produced water discharges are not permitted. 

The usual procedure in inland areas is to reinject the ~roduced 

water to the producing formation, where the formation conf~guration ~ermits (to assist in oil recovery), or to other 

subsurface formations for disposal only. Evaporation ponds are 

usea in some inland areas, with the assumption that all produced 

waters are evaporated and no discharge occurs. In an arid 

western oil field an evaporation pond, if properly maintained, 

may provide for acceptable disposal of the produced waters; 

however, in humid areas in the East and South, evaporation ponds 

may not be acceptable. 

In ~nland f~elds where produced waters are sufficiently low in 

total solids, discharges have been used for stock watering and 

other beneficial uses where the treated produced water is of 

sufficient quality to meet the regulations for other 

constituents, such as oil and grease. 

In the Appalachian area, typified by the northwest portion of 

Pennsylvania, discharge of produced water is the rule, not the 

exception. Treatment consisting of ripple aeration and semimentation/se~aration in ponds achieves a high degree of free 

oil removal apparently due to the separability of the crude. 

The technology for disposal of drilling muds, cuttings, solids, 

and other materials differs depending upon the location. In the 

open water offshore areas, the materials, if properly treated, 

are normally discharged into the saline waters. Onshore 

technology has been developed to ensure no discharge to surface 

35 
waters, and waste materials are disposed of in approved land 

disposal sites. 

Description of su~cateqories 

Based upon the above rationale and discussion the oil and gas 

extraction industry has been su~categorized as follows: 

Subcategory 

Subcategory 

A - near offshore (facilities located in 

offshore state waters) 

1. 

2. 

3. 

4. 

5. 

6. 

produced water 

deck drainage 

drilling muds 

drill cuttings 

well treatment 

sanitary wastes 

a. MlO continuously manned with 10 or more 

people 

b. M9IM - facilities with 9 or less people 

or intermittantly manned. 

1. domestic wastes 

8. produced sand 

B - far offshore (facilities located in 

federal waters) 

1. produced water 

2. deck drainage 

3. drilling muds 

4. drill cuttings 

5. well treatment 

6. sanitary wastes 

a. Mlu continuously manned with 10 or more 

people 

36 
b. M9IM - facilities with 9 or less peo~le 

or intermittantly manned. 

7. domestic wastes 

8. produced sand 

Subcategory c - onshore 

1. produced water 

2. drilling muds 

3. drill cuttings 

4. well treatment 

5. produced sand 

subcategory D - coastal 

1. produced water 

2. deck drainage 

3. drilling muds 

4. drill cuttings 

5. well treatment 

6. sanitary wastes 

a. MlO continuously manned with 10 or more 

people 

b. M9IM - facilities with 9 or less people 

or intermittantly manned. 

7. domestic wastes 

8. produced sand 

Subcategory E - beneficial use 

1. produced water 

2. drilling muds 

3. drill cuttings 

4. well treatment 

37 
s. produced sand 

Subcategory F - stripper 

1. produced water 

2. drilling muds 

3. drill cuttings 

4. well treatment 

s. produced sand 

Produced Water 

Produced water includes all waters and particulate matter 

associated with oil and gas producing formations. Sometimes the 

terms "formation water" or 11 brine water" are used to describe 

produced water. Most oil and gas producing geological formations 

contain an oil-water or gas-water contact. In some formations, 

water is produced with the oil and gas in the early stages of 

production. In others, water is not produced until the producing 

formation has been significantly depleted and in some cases water 

is never produced. (4) The amount of produced water generated is 

also dependent on the method of oil recovery. If water injection 

is used some of the ~njected water is recovered by the production 

causing higher percentage water cuts. 

Deck Drainage 

Deck drainage includes all waste resulting from platform 

washings, deck washings, and run-off from curbs, gutters, and 

drains including drip pans and work areas. 

San~tary waste 

Sanitary waste includes human body waste discharged from toilets 

and urinals. 

Domestic waste 

Domestic wastes are materials discharged from sinks, showers, 

laundries, and galleys. 

Drilling Muds 

Drilling muds are those materials used to maintain hydrostatic 

pressure control in the well, lubricate the drilling bit, remove 

drill cuttings from the well, or stabilize the walls of the well 

during drilling or workover. 

38 
Generally, two basic types of muds (water-based and oil muds) are 

used in drilling. Various additives may be used depending upon 

the specific needs of the drilling program. water-based muds are 

usually mixtures of fresh water or sea water with muds and clays 

from surface formations, plus gelling compounds, weighting 

agents, and various other components. Oil muds are referred to 

as o~l based muds, invert emulsion muds, and oil emulsion muds. 0~1 muds are used for special drilling requirements such as 

t~ghtly consolidated subsurface formations and water sensitive 

clays and shales. (5) (6) (7) 

Drill Cuttings 

Drill cuttings are particles 

subsurface geologic format~ons. 

the surface of the well with the 

from the drilling mud. 

Treatment of Wells 

generated by drilling into 

~rill cuttings are circulated to 

drilling mud and separated there 

Treatment of wells includes acidizing and hydraulic fracturing to 

improve oil recovery. Hydraulic fracturing involves the parting 

of a desired section of the formation by the application of 

hydraulic pressure. Selected particles added to the fracturing 

fluid are transported into the fracture, and act as propping 

agents to hold the fracture o~en after the pressure is released. 

Chemical treatments of wells consists of pumping acid or 

chemicals down the well to remove formation damage and increase 

drainage in the permeable rock formations.(8) 

Produced Sand 

Produced sand or solids for this subcategory consist of part~cles 

used in hydraulic fracturing and accumulated formation sands, 

which are generated during production. These sands must be 

removed when they tuild up and block flow of fluids. 

39 
SECTION J:V 

Bibliography 

1. Bassett, M.G. 1971. 11Wemco Depurator TM System." Paper 

presented at the SPE of AJ:ME Rocky Mountain Regional Meeting, 

Billings, Montana, June 2-4, 1971. Preprint No. SPE-3349. 

2. Boyd, J.L., 

"Treatment 

standards." 

Shell, G.L., and Dahlstrom, D.A. 1972. 

of Oily waste 

AJ:ChE Symposium. 

waters to Meet Regulatory 

Serial NO. 124, ~P· 393-401. 

3. Ellis, M.M., and Fischer, P.W. 1973. "Clarifying Oil Field 

and Refinery ~aste waters by Gas Flotation. 11 Paper ~resented 

at the SPE of AJ:ME Evangeline section Regional Meeting, 

Lafayette, Louisiana, November 9-10, 1970. Preprint No. SPE3198. 

4. u.s. Department of the 

control Administration. 

Water Quality Criteria. 

Interior, 

1968. 

Federal Water Pollution 

Report of the committee on 

5. u.s. Department of the Interior, Bureau of Land Management. 

1973. Draft Environmental Impact Statement, "Proposed 1973 

outer Continental Shelf Oil and Gas General Lease Sale 

Offshore Mississippi, Alabau.a, and Florida." washington, 

D.C. 

6. Hayward, B.S., Williams, R.H., and Methven, N.E. 1971. 

"Prevention of Offshore Pollution from Drilling Fluids." 

Paper presented at the 46th Annual SPE of AIME Fall Meeting 

at New Orleans, Louisiana, october 3-o, 1971. Preprint No. 

SPE-3579. 

1. Cranfield, J. 1973. "Cuttings Clean-Up Meets Offshore 

Pollution Specifications, 11 Petrol. Petrochem. Int., Vol., 

13: No. 3: pp. 54-56, 59 

8. American Petroleum Institute. Division of Production. 1973. 

"Primer of Oil and Gas Production." 3rd. ed. Dallas, Texas. 

40 
SECTION V 

WASTE CHARACiERISTICS 

wastes generated ty the oil and gas industry are produced by 

drilling exploratory or development wells, by the production or 

extraction phase of the industry, and, in the case of offshore 

fac~lities, sanitary wastes generated b¥ personnel occupying the 

platforms. Drilling wastes are generally in the form of drill 

cuttings and mud, and production wastes are generally produced 

water. (1) Additionally, well workover and completion operations 

can produce wastes, but they are generally sim~lar to those from 

drilling or production operations. 

Approximately half a million producing oil wells onshore generate 

produced water in excess of 20 million barrels-per-day of which 

it is estimated 50~ is reinjected for recovery ~urposes. 

Approximately 17,000 wells have been drilled offshore in u.s. 

waters, and approximately 11,000 are producing oil or gas. The 

offshore Louisiana ocs alone produces approximately 410,000 

barrels of water per day (2); by 1983, coastal Louisiana 

product~on will generate an estimated 1.54 million barrels of 

water per day. (3) 

This section characterizes the types of wastes that are produced 

at offshore and onshore wells and structures. The discussion of 

drilling wastes can be applied to any area of the United States 

since these wastes do not change significantly with locality. 

Other than o~ls, the primary waste constituents 

oxygen demanding pollutants, heavy metals, 

dissolved solids contained in drilling muds or 

(4) 

considered are 

toxicants, and 

produced water. 

Sanitary wastes are also produced during both drilling and 

production operations both onshore and offshore, but they are 

discussed only for offshore situations where sanitary wastes are 

produced from fixed platforms or structures. Drilling or 

exploratory rigs that are vessels are not part of this 

discussion. 

Waste constituents 

Production 

Production wastes include produced waters associated with the 

extracted oil, sand and other solids removed from the produced 

waters, deck drainage from the platform surfaces, sanitary 

wastes, and domestic wastes. 

The produced waters from production platforms generate the 

greatest concern. The wastes can contain oils, toxic metals, and 

41 
a variety of salts, solids and organic chemicals. The 

concentrations of the constituents vary somewhat from one 

geographical area to another, with the most pronounced variance 

in chloride levels. Table 5 shows the waste constituents in 

offshore Louisiana production facilities.in the Gulf of Mexico. 

The data were obtained during the verification survey conducted 

by EPA in 1974. The only influent data obtained in the survey 

were on oil and grease. In planning the verification survey, it 

was decided that offshore produced water treatment facilities 

would have virtually no effect on metals and salinity levels in 

the influent, and that these constituents could be satisfactorily 

characterized by analyzing only the effluent. 

Total organic carbon (TOC) is also tatulated under effluent in 

Table 5, but it is reasonable to assume that actual analysis of 

the influent would be higher. Since TOC is a measurement of all 

organic carbon in the sample and oil is a major source of organic 

carbon, it is logical to assume removal of some organic carbon 

when oil is removed in the treatment process. suspended solids 

are also expressed as effluent data, and this parameter would be 

expected to be reduced by the treatment process. 

TABLE 5 

Pollutants in Produced Water 

Louisiana coastal(a) 

Pollutant Parameter Range mg/1 Average mg/1 

Oil and Grease 7 - 1300 202 

cadmium <0.005 - .675 <0.068 cyan~ de <0.01 - 0.01 <0.01 

Mercury <0.0005 

Total Organic carbon 30 - 1580 413 

Total suspended solids 22 - 390 73 

Total dissolved solids 32,000 - 202,000 110,000 

Chlorides 10,000 - 115,000 61,000 

Flow (bbl./day) 250 - 200,000 15,000 

(a) - results of 1974 EPA survey of 25 discharges 

< - less than 

42 
Industry data for offshore California describes a broader range 

of parameters (see Table 6). Similar data were provided for 

offshore Texas (see Table 7). Except as noted on the tables, all 

data are from effluents. 

Sand and other solids are produced along with the produced water. 

Observations made by EFA personnel during field surveys indicated 

that drums of these sands stored on the platform had a high oil 

content. Sand has been reported to be produced at approximately 

1 barrel sand per 2,000 barrels oil. (5,6) 

43 
TABLE 6 

Pollutants Contained in Produced Water 

Coastal California (a) (7) 

Pollutant 

Parameter Range, mg/1 

Arsenic o. 001 - 0.08 

Cadmium 0.02 - 0.18 

Total Chromium 0.02 - 0.04 

Copper 0.05 - 0.116 

Lead 0.0 - o. 28 

Mercury 0.0005 - 0.002 

Nickel 0.100 - 0.29 

Silver 0.03 

Zinc o.os - 3.2 

Cyanide o.o - 0.004 

Phenolic Compounds 0.35- ~.10 

BOD 

COD 

Chlorides 

TDS 

suspended Solids 

Effluent 

Influent 

Oil and Grease 

370 - 1,920 

400 - 3,000 

17,230 - 21,000 

21,700 - 40,400 

1 - 60 

30 - 75 

56 - 359 

(a)Some data reflect treated waters for re~njection. 

44 
'IA.BLE 7 

Range of constituents in Produced 

Formation water--Offshore Texas(8) 

Pollutant Parameter 

Arsenic 

cadmium 

Total Chromium 

Copper 

Lead 

Mercury 

Nickel 

Silver 

Zinc 

Phenolic compounds 

BOD 

COD 

Chlorides 

TDS 

Suspended Solids 

< - less than 

45 

Range, mq/1 

<0.01 - <0.02 

<o. 02 - o .193 

<0.1 0 - o. 23 

<0.10 - 0.38 

<0.01 - 0.22 

<0.001 - 0.13 

<0.10 - 0.44 

<0.01 - 0.10 

0.10 - 0.27 

53 

126 - 342 

182 - 582 

42,000 - 62,000 

806 - 169,000 

12 - 656 
As part of a recent EPA study (1976) to collect information on 

treatment technologies and costs, surveys were made of onshore 

production facilities in California, Wyoming, Texas, Louisiana 

and Pennsylvania. The data refresented in tables 8-12 is from 

the effluent of the treatment facilities prior to reinjection for 

secondary recovery or disposal. It could be expected that the 

quality of the untreated produced water from the production 

separator would range from 200-1000 mg/1 oil and grease and 100-

400 mg/1 suspended solids. The remainder of the analyzed 

constituents such as TDS, phenols and heavy metals would be 

unaffected by treatment. 

The analytical methods used were from "Standard Methods for Waste 

and wastewater" 13th edition (16) with the exception of the 

procedure for oil and grease. Prior to the utilization of the 

freon extraction method for oil and grease, the samples were 

screened for organic acids and if they were present in quantit~es 

greater than 100 mg/1 the sample was not acidified. Therefore, 

the results for oil and grease as reported in tables 8-12, 

particularly in California where organic acids are known to be a 

part of the crude oil, are not comparable to data in other parts 

of this report and are shown only for information. 

'IABLE 8 

Range of Constituents in Produced 

Formation Water--Onshore California 

Pollutant Parameter 

Oil and Grease 

suspended SOlids 

Total Dissolved Solids 

Phenol 

Arsenic 

Chromium 

Cadmium 

Lead 

Barium 

< = less than 

Range, mg/1 

16-1 91 

3-51 

580-27,300 

0.07-0.15 

<0.01-0.03 

<0.01 

<0.005-0.02 

<0.05 

<0.2-0.4 

46 

Median, mg/1 

75 

31 

6,300 

0.11 

0.11 

<0.01 

<O. 005 

<0.05 

0.3 
TAl3LE 9 

Range of Const~tuents in Produced 

Formation Water--wyo~ng 

Pollutant Parameter 

Oil and Grease 

suspended Solids 

Total Dissolved Solids 

Phenol 

Arsenic 

Chromium 

Cadmium 

Lead 

Barium 

< = less than 

Range, mg/1 

1. 5-205 

<1-64 

345-90,400 

0.07-0.33 

<0.01-0.06 

<0.01 

<0.005-0.023 

<0.05-0.08 

<0.2-9.7 

TABLE 10 

Median, mg/1 

67 

12.8 

13,800 

0.16 

0.01 

<0.01 

<0.005 

<0.05 

0.9 

Range of Constituents in Produced 

Formation Water--Pennsylvania 

Pollutant Parameter 

Oil and Grease 

suspended Solids 

Total Dissolved Solids 

Phenol 

Arsenic 

Chromium 

Cadmium 

Lead 

Barium 

< = less than 

Range, mg/1 

<0.2-114 

1.4-666 

1500-109,400 

0.06-0.35. 

<0.01 

<0.01-0.025 

<0.005-0.013 

<0.05-0.50 

0.1-36 

47 

Median, mg/1 

25 

107 

29,000 

0.19 

<0.01 

<0.01 

<0.005 

<0.05 

8.6 
TAbLE 11 

~ange of constituents in Produced 

Formation Water--Onshore Louisiana 

Pollutant Parameter 

Oil and Grease 

Suspended Solids 

Total Dissolved Solids 

Range, mg/1 

16-441 

20.8-155 

42,600-132,000 

TABLE 12 

Median, mq/1 

165 

82 

73,900 

Range of Constituents in Produced 

Formation Water--onshore Texas 

Pollutant Parameter 

Oil and Grease 

Suspended Solids 

Total Dissolved solids 

Drilling 

Range mg/1 

57-1,200 

30-473 

42,600-132,000 

Median, mg/1 

460 

143 

94,000 

Drill cuttings are composed of the rock, fines, and liquids 

contained in the geologic formations that have been drilled 

through. The exact make-up of the cuttings varies from one dr~lling location to another, and no attempt has been made to 

qualitatively identify cuttings. 

The two basic classes of drilling muds used 

muds and oil muds. In general, much of the 

the well hole is eventually displaced 

requires disposal or recovery. (13) 

today are water based 

mud introduced into 

out of the hole and 

Water based muds are formulated using naturally occurring clays 

such as bentonite and attapulgite and a variety of organic and 

inorganic additives to achieve the desired consistency, 

lubricity, or density. Fresh or salt water is the liquid ~base 

for these muds. The additives are used for such functions as pH 

48 
controlr corrosion 

emulsification. 

inh~bitionr lubricationr weightingr and 

The additives that should be scrutinized for pollution control 

are ferrochrome lignosulfonate and lead compounds. (14) 

Ferrochrome lignosulfonate contains 2.6 percent ironr 5.5 percent 

sulfur, and 3.0 percent chromium. In an example presented by the 

Bureau of Land Management in an Environmental Impact Statement 

for offshore developmentr the drilling operation of a typical 

10r000-foot development well (not exploratory) used 32r900 pounds 

of ferrochrome lignosulfonate mud which contained 987 pounds of chro~um.(2) Table 13 presents the volumes of cuttings and muds 

used in the Bureau's example of a "typical" 10r000-foot drilling 

operation. The amount of lead additives used in mud composition 

varies from well to wellr and no examples are available. 

Drilling constituents for onshore operations will parallel those 

for offshorer except for the water used in the typical mud 

formulation. onshore drilling operations normally use a fresh 

water based mudr except where drilling operations encounter large 

salt domes. Tnen the mud system would be converted either to a 

salt clay mud system with salt added to the water phaser or to an 

oil based mud system. This change in the liquid phase is 

intended to prevent dissolving salt in the dome, enlarging the 

holer and causing solution cavities in the formation. 

In offshore operationsr the direct discharge of cuttings and 

water based muds create turb~dity. Limited information is 

available to accurately define the degree of turbidityr or the 

area or volume of water affected ty such turbid dischargesr but 

experienced observers have described the existence of substantial 

plumes of turbidity when muds and cuttings are discharged. 

Oil-based muds contain carefully formulated mixtures of oxidized 

asphalt, organic acids, alkali, stabilizing agents and high-flash 

diesel oil. (14r15) The oils are the principal ingredients and so 

are the liquid phase. Muds displaced from the well hole also 

contain solids from the hole. ~here are two types of emulsif~ed 

oil muds: 1) oil emuls~on mudsr which are oil-in-water emulsions; 

and 2) inverted emulsion muds, which are water-in-oil emulsions. 

The principal differences between these two muds and oil based 

muds is the addit~on of fresh or salt water into the mud mixture 

to provide some of the volume for the liquid phase. Newer 

formulations can contain from 20 to 70 percent water by volume. 

The water is added by adding emulsifying and stabilizing agents. 

Clay solids and weighting agents can also be added. 

49 
Sanitary and Domestic Waste 

The sanitary wastes from offshore oil and gas facilities are 

composed of human body waste and domestic waste such as kitchen 

and general housekeeping wastes. The volume and concentration of 

these wastes vary widely with time, occupancy, platform 

characteristics, and Oferational situation. Usually the toilets 

are flushed w1th brackish water or sea water. Due to the com~act 

nature of the facilities the wastes have less dilution water than 

common municipal wastes. This results in greater waste 

concentrations. Table 14 indicates ty~ical waste flow for 

offshore facilities and vessels. 

so 
Table 13 

Volume of Cuttings and Muds in Typical 

10,000-Foot Drilling Operation (2) 

Vol of Wt. of 

Hole Vol. of Wt. of Mud com- Mud comInterval, Size, Cuttings, Cuttings, Drilling ponents, ponents 

Feet inches bbl. pounds mud bbl pounds 

0-1,000 24 562 505,000 sea water variable 

U'l 

_.. & natural 

mud 

1, 000-3' 500 16 623 545,000 Gelled sea 700 81,500 

water 

3,500-10,000 12 915 790,000 Lime base 950 424,000 
No. of 

Men 

76 

l1' 66 

IV 

67 

42 

10-40 

Flow 

Table 14 

Typical Raw Combined Sanitary and Domestic 

Wastes from Offshore Facilities 

BOD, mg/1 Suspended 

5 Solids, mg/1 Total 

gal/day Average Range Average Range Coliform 

(X 10) 

5,500 460 270-770 195 14-543 10-180 

1,060 875 ---- 1,025 ----- -----

1,875 460 ---- 620 ----- -----

2,155 225 ----- 220 ----- -----

2,900 920 ----- --- ----- -----

Reference 

(10) 

(12) 

(12) 

(12) 

(11) 
SECTION V 

Bibliogzaphy 

1. Biglane, K.E. 1958. "SOme current waste Treatment Practices 

in Louisiana Industry." Papez presented at the 13th Annual 

Industrial waste Conference, Purdue University, Lafayette, 

Indiana. 

2. u.s. Department of the Interior. Bureau of Land Management. 

Draft Environmental Impact Statement. "Proposed 1973 Outer 

continental Shelf Oil and Gas General Lease Sale Offshore Mississ~~pi, Alabama, Florida • 11 Washington, D. c. 

3. Offshore Operators Committee, Sheen Technical Subcommittee. 

1974. "Determination of Best Practicable Control Technology 

currently Available to Remove Oil from Water Produced with 

Oil and Gas. 11 Prepared by Brown and Root, Inc., Houston, 

Texas. 

4. Moseley, F.N., and COpeland, E.J. 1974. 11Brine Pollution 

system." In: "Coastal Ecological systems of the United 

States." Odum, Copeland, and McMahan (ed.). The Conservation 

Foundation, washington, D.c. 

5. Garcia, J. A. 19 71 • 11 A system for the Removal and Disposal 

of Produced Sand." Paper presented at the 47th Annual SPE of 

AIME Fall Meeting, San Antonio, Texas, October 8-11, 1972. 

Preprint No. SFE-4015. 

6. Frankenberg, W.G., and Allred, J.H. 1969. "Design, 

Installation, and Operation of a Large Offshore Production 

Complex; 11 and Bleakley, W. G., "Shell Production complex 

Efficient, controls, Pollution--. "Oil and Gas Journal, Vol. 

67:No. 36: pp. 65-69. 

7. Western Oil and Gas Association and the Water Quality Board, 

State of California. 

8. Offshore Operators committee. 

9. crawford, J.G. 1964. "Rocky Mountain Oil Field Waters." 

1 o. 

Chemical and Geological Laboratories, casper, Wyoming. 

Sacks, Bernard R. 1969. "Extended Aeriation Sewage 

Treatment on u.s. corps of Engineers Dredges." u.s. 

Department of the Interior, Federal water Pollution control 

Administration. 

53 
11. Amoco Production Company. 197 4. 11 Draft comments Regarding 

Rationale and Guideline Proposals for Treatment of sanitary 

wastes from Offshore Production Platforms. 11 

12. Humble Oil and Refining company. 1970. 11Report on the Human 

waste on Humble Oil and Refining company's Offshore Platforms 

with Living Quarters in the Gulf of Mexico. 11 Prepared by 

Waldermar s. Nelson COmFany, Engineers and Architects, New 

Orleans, Louisiana. 

13. Hayward, B.s., Williams, R.H., and Methven, N.E. 1971. 11Prevention of Offshore Pollution from Drilling Fluids." 

Paper presented at the 46th Annual SPE of AIME Fall Meeting, 

New Orleans, Louisiana, Octo£er 3-6, 1971. Preprint No. SPE 

3579. 

14. Gulf I-ublishing company. "Drilling Fluids File. 11 Special 

compilation from World Oil, January 1974. 

15. The University of Texas, Petroleum Extension Service. 1968. 

"Lessons in Rotary Drilling - Drilling Mud." 

54 
SECTION VI 

SELECTION OF POLLUiANT PARAMETERS 

Oil and grease from produced water, deck drainage, muds, 

cuttings, and produced sands and solids, and residual chlorine 

(as an indicator of fecal coliform) and floating solids from 

sanitary and domestic sources have been selected as the 

pollutants for which effluent limitations will be established. 

The rationale for inclusion of these parameters are discussed 

below. 

Parameters for Effluent Limitations 

Freon Extractables - Oil and Grease 

No solvent is known which will directly dissolve only oil or 

grease, thus the manual 11Metnods for the Chemical Analysis of 

water and wastes 197 411 distributed by the Environmental 

Protection Agency states that their method for oil and grease 

determinations includes the freon extractable matter from waters. 

In the oil and gas extraction industry, oils, greases, organic 

acids, various other hydrocarbons and some inorganic compounds, 

such as sulfur, will be included in the freon extraction 

procedures. The majority of material removed by the procedure 

from a produced water will, in most instances, be of a 

hydrocarbon nature. These hydrocarbons, predominately oil and 

grease type compounds, will make their presence felt in the COD, 

TOC, TOD, and usually the BOD tests where high test values will 

result. The oxygen demand potential of these freon extractables 

is only one of the detrimental effects exerted on water bodies by 

this class of compounds. Oil emulsions may adhere to the gills 

of fish or coat and destroy algae or other plankton. Depostion 

of oil in the bottom sediments can serve to inhibit normal 

benthic growths, thus interrupting the aquatic food chain. 

Soluble and emulsified materials ingested b¥ fish may taint the 

flavor of the fisn flesh. Water soluble components may exert 

toxic action on fish. The water insoluble hydrocarbons and free 

floating emulsified oils in a waste water will affect stream 

ecology by interfering with oxygen transfer, by damaging the 

plumage and coats of water animals and fowls, and by contributing 

taste and toxicity froblems. The effect of oil spills upon boats 

and shorelines and their production of oil slicks and 

iridenscence upon the surface of waters is well known. 

Fecal coliform (Chlorine Residual) 

The concentration of fecal coliform bacteria can serve as an 

indication of the potential pathogencity of water resulting from 

the disposal of human wastes. Fecal coliform levels have been 

55 
established to protect beneficial water use (recreation and 

shellfish propagation) in the coastal areas. 

The most direct method to determine compliance with specified 

l~ts is to measure the fecal coliform levels in the effluent 

for a period representing a normal cycle of operations. This 

approach may be applicable to onshore installations; howeverr for 

offshore operations the logistics become complexr and simplified 

methods are desirable. 

Howeverr the presence of specific levels of suspended solids and 

chlorine residual in an effluent are indicative of corresponding 

levels of fecal coliforms. In general if suspended solids levels 

in the effluent are less than 150 mg/1 and the chlorine residual 

is maintained at 1.0 mg/lr the fecal coliform level should be 

less than 200 per 100 ml. Froperly operating biological 

treatment systems on offshore platforms have effluents containing 

less than 150 mg/1 of suspended solids; thereforer chlorine 

residual is a reasonable control parameter. 

It may be considered desirable, however, that a study of each 

sanitary treatment system be made at least once a year to measure 

influent and effluent biochemical oxygen demandr suspended 

solids, and fecal coliform. The purpose of the survey is to 

determine the treatment efficienciesr to evaluate operating 

procedures, and to adjust the system to obtain maximum treatment 

efficiencies and minimize chlorine usage. 

Floating Solids 

Mar~ne waters should be capable of su~porting indigenous life 

forms and should be free of substances attributable to discharges 

or wastes which will settle float on the waterr and produce 

objectionable odors. Floating solids have been selected as a 

control parameters for domestic wastes and sanitary wastes from 

small or intermittently manned offshore facilities. 

Other Pollutants 

Some produced formation waters are known to conta~n heavy metalsr 

toxic substancesr constituents with substantial oxygen demand, 

and inorganic salts. Insufficient data exist to warrant 

comprehensive control of these parameters and there is no 

discharge technology now in use by the industry to remove these 

pollutants, although some concomitant reduction in oxygen 

demanding constituents may take place as a result of treatment 

not specifically designed for their removal. 

56 
Heavy Metals 

Produced waters have been shown to contain cyanide cadmium, and 

mercury. section 307(a) (1) of the Federal water Pollution 

control Act Amendments of 1972 requires a list of toxic 

pollutants and effluent standards or proh~bitions for these 

substances. The proposed effluent standards for toxic pollutants 

state that there shall be no discharge of cyanide, cadmium, or 

mercury into streams, lakes or estuaries with a low flow less 

than or equal to 0.283 cubic meters per second (M3/sec) (10 cubic 

feet per second) or into lakes with an area less than or equal to 

200 hectares (500 acres). Many estuarine areas fall into this 

category. 

The harmful effects of these toxicants, which include direct 

toxicity to humans and other animals, biological concentration, 

sterility, mutagenicity, teratogenicity, and other lethal and 

sublethal effects, have been well documented in the development 

of the Section 307(a) (1) proposed regulations. 

Produced formation waters have also been shown to contain 

arsenic, chromium, copper, lead, nickel, silver, and zinc as pollu~ants. Accord~ng to McKee and Wolfe (6) , arsenic is toxic 

to aquatic life in concentrations as low as 1 mg/1. The toxicity 

of chromium is very much dependent upon environmental factors and 

has been shown to be as low as 0.016 mg/1 for aquatic organisms. 

Copper is toxic to aquatic organisms in concentrations of less 

than 1 mg/1 and is concentrated by plankton from their habitat by 

factors of 1,000 to 5,000 or more. Lead has been shown to be 

toxic to fish in concentrations as low as 0.1 mg/1, nickel at a 

concentration of 0.8 mg/1, and silver at a concentration of 

0.0005 mg/1. Zinc was shown to ~e toxic to trout eggs and larvae 

at a concentration of 0.01 mg/1. 

TDS 

Dissolved solids in produced waters consist mainly of carbonates, 

chlorides, and sulfates. u.s. Public Health service Drinking 

Waters Standards for total dissolved solids are set at 500 mg/1 

on the basis of taste thresholds. Many communities in the United 

States use water containing from 2,000 to 4,000 mg/1 of dissolved 

solids. Such waters are not palatable and may have a laxative 

effect on certain people. However, the geographic location and 

availability of potable water w~ll dictate acceptable standards. 

The following is a summary of a literature survey indicating the 

levels of dissolved solids which should not interfere with the 

indicated beneficial use: 

57 
Domestic water Supply 

Irrigation 

L~vestock watering 

Freshwater Fish and Aquatic 

Life 

lrOOO mg/1 

700 mg/1. 

2r500 mg/1 

2r000 mg/1 

Estuaries are typically bilaminar systemsr stratified to some 

degreer with each layer dependent upon the other for cycling of 

mineralsr gasesr and energy. The upperr low salinityr euphotic 

zone supports production of organic materials from sunlight and 

C02; it also produces oxygen in excess of respiration so that 

this upper layer is characteristically supersaturated with 02 

during the daylight hours. The bottom higher salinity layer funct~ons as the catabolic side of the cycler (microbial 

breakdown of organic material with subseliuent 02 utilization and 

C02 production). In a healthy estuarine system, these two layers 

are in precarious synchrony, and the alteration of density, 

minerals, gases, or organic material is capable of causing an 

imbalance in the system. 

Apparently due to the stresses resulting from salinity shocks, 

anamalous ion ratios, strong buffer systems, high pH, and low 

oxygen solubility, few organisms are capable of adapting to 

brine-dominated systems. This results in low diversity of 

species, short food chains, and depressed trophic levels. (7) 

Chlorides 

Chloride ion is one of the major anions found in water and 

produces a salty taste at a concentration of about 250 mg/1. 

Concentrations of 1000 mg/1 may te undetectable in waters which 

contain appreciable amounts of calcium and magnesium ions. 

some produced water associated with naturally occurring 

subsurface hydrocarbons may contain extremely high amounts of 

sodium chloride. These 11 so-called11 connate brines developed 

because the particular geologic formation has not allowed the 

entrance of surface water for dilution. In the mid-continent 

region where these brines are found, they average 174,000 mg/1 of 

dissolved solids. 

The toxicity of chloride salts will depend upon the metal with 

which they are combined. Because of the rather high 

concentration of the anion necessary to initiate detrimental 

biological effects, the limit set upon the concentration of the 

metallic ion with which it may be tied, will automatically govern 

its concentration in effluents, in practically all forms except 

potassium, calcium, magnesium, and sodium. 

Since sodium is by far the most common (sodium 75 percent, 

magnesium 15 percent and calcium 10 percen~ the concentration of 

58 
this salt w~ll probably govern the amount of chlorides in waste 

streams. 

It is extremely 

chloride salt 

concentrations 

and poultry. 

difficult to pinpoint the exact amount of sodium 

necessary to result in toxicity in waters. Large 

have been proven toxic to sheep, swine, cattle. 

In swine fed diets of swill containing 1.5 to 2.0~ salt by 

weight, poisoning symptoms can be induced if water intake is 

limited and other factors are met. ~he time interval necessary 

to accomplish this is still about one full day of feeding at this 

level. 

Problems of corrosion, taste, and quality of water necessary for 

~ndustrial or agricultural purfoses occur at sodium chloride 

concentration levels below those at which toxic effects are 

experienced. 

Oxygen Demand Parameters 

Dissolved oxygen (DO) is a water quality constituent that, in 

ap~ropriate concentrations, is essential not only to keep 

organisms living but also to sustain species reproduction, vigor, 

and the development of populations. Organisms undergo stress at 

reduced DO concentzations that make them less competitive and 

able to sustain their species within the aquatic environment. 

For example, reduced DO concentrations have been shown to 

interfere with fish population through delayed hatching of eggs, 

reduced size and vigor of embryos, production of deformities in 

young, interference with food digestion, acceleration of blood 

clotting, decreased tolerance to certain toxicants, reduced food 

efficiency and growth rate, and reduced maximum sustained 

swimming speed. Fish food organisms are likewise affected 

adversely in conditions with suppressed DO. Since all aerobic 

aquatic organisms need a certain amount of oxygen, the 

consequences of total lack of dissolved oxygen due to a high BOD 

can kill all inhabitants of the affected area. 

Two oxygen demand parameters are discussed below: BODS, and TOC. 

Almost without exception, waste 

extraction exert a significant and 

The primary sources are soluble 

inorganic sulfur compounds. 

Biochemical Oxygen Demand (BOD) 

waters from oil and gas 

sometimes major oxygen demand. 

biodegradable hydrocarbons and 

Biochemical oxygen demand is a measure of the oxygen consuming 

capabilities of organic matter. The BOD does not in itself cause 

direct harm to a water system, but it does exert an indirect 

effect by depressing the oxygen content of the water. sewage and 

59 
other organic effluents during their processes of decomposition 

exert a BOD, which can have a catastrophic effect on the 

ecosystem £y depleting the oxygen supply. conditions are reached 

frequently where all of the oxygen ~s. used and the continuing 

decay process causes the production of noxious gases such as 

hydrogen sulfide and methane. Water with a h~gh BOD indicates 

the presence of decomposing organic matter and subsequent h~gh 

bacterial counts that degrade its quality and potential uses. 

If a high BOD is present, the quality of the water is usually 

visually degraded by the presence of decomposing materials and 

algae blooms due to the uptake of degraded materials that form 

the foodstuffs of the algal populations. 

Total Organic carbon (TOC) 

Total organic carbon is a measure of the amount of carbon in the 

organic material in a wastewater sample. The TOC analyzer 

withdraws a small volume of sample and thermally oxidizes it at 

1sooc. The water vapor and carbon dioxides from the combustion 

chamber (where the water vapor is removed) is condensed and sent 

to an infrared analyzer, where the carbon dioxide is monitored. 

This carbon dioxide value corresponds to the total inorganic 

value. Another portion of the same sample is thermally oxidized 

at 9sooc, which converts all the carbonaceous material to carbon 

dioxide; this carbon dioxide value corresponds to the total 

carbon value. TOC is determined by subtracting the inorganic 

carbon (carbonates and water vapor) from the total carbon value. 

The recently developed automated carbon analyzer has provided 

rapid and simple means of determining organic carbon levels in 

waste water samples, enhancing the popularity of TOC as a 

fundamental measure of pollution. The organic carbon 

determination is free of many of the variables which plaque the 

BOD analyses, yielding more relia£le and reproducible data. 

Phenolic Compounds 

Many phenolic compounds are more toxic than pure phenol; their 

toxicity varies with the combinations and general nature of total 

wastes. The effect of combinations of different phenolic 

com~ounds is cumulative. 

Phenols and phenolic compounds are both acutely and chronically 

toxic to fish and other aquatic animals. Also, chlorophenols 

produce an unpleasant taste in fish flesh that destroys their 

recreational and commercial value. 

It is necessary to limit phenolic compounds in raw water used for 

drinking water supflies, as conventional treatment methods used 

by water su~ply facilities do not remove phenols. The ingestion 

60 
of concentrated solutions of phenols will result in severe pain, 

renal irritation, sbock and possibly death. 

Phenols also reduce the utility of water for certain industrial 

uses, notably food and beverage processing, where it creates 

unpleasant tastes and odors in the product. 

As seen from the above discussion on the potential harm from 

produced water discharges, the effects of toxicants, high 

salinity, low dissolved oxygen, and high organic matter can 

combine to ~roduce an ecological enigma. 

The State of California, recognizing the potential impact of 

industrial wastes in the coastal areas, has adopted effluent 

limitations for ocean waters undex its jurisdiction (see Table 

15. They were arrived at by first applying safety factors to 

known toxicity levels and a consideration of control technology. 

This produced proposed standards which were subjected to the 

public hearing process, revised accordingly, and then declared. 

To meet the coastal water quality standards, the oil and gas 

extraction industry has developed a no discharge technology 

(reinjection of production water) • 

61 
TABLE 15 

Effluent Quality Requirements for 

Arsenic 

Cadmium 

Total Chromium 

copper 

Lead 

Mercury 

Nickel 

Silver 

Zinc 

cyanide 

Phenolic compounds 

Total Chlorine 

Residual 

Ammonia(expressed 

as nitrogen) 

Total Identifiable 

chlorinated Hydrocarbons 

Toxicity concentration 

ocean Waters of California 

Unit of 

measurement 

mg/1 

mg/1 

mg/1 

mg/1 

mg/1 

mg/1 

mg/1 

mg/1 

mg/1 

mg/1 

mg/1 

mg/1 

mg/1 

mg/1 

tu 

Concentration not to be 

exceeded more than: 

50~ of time 

0.01 

0.02 

0.005 

0.2 

0.1 

0.001 

0.1 

0.02 

0.3 

0.1 

0.5 

1. 0 

40.0 

0.002 

1. 5 

10% of time 

0.02 

0.03 

0.01 

0.3 

0.2 

0.002 

0.2 

0.04 

0.5 

0.2 

1.0 

2.0 

60.0 

0.004 

2.0 

Radioactivity not to exceed the limits specified in Title 17, 

Chapter 5, Subchapter 4, Group 3, Article 5, section 30285 and 

30287 of the California Administrative Code. 

62 
SECTION VI 

Bioliography 

1. Great Lakes water Quality Agreement, April 1972. 

2. Federal Water Pollution Control Act Amendments of 1972, 

Section 311(b) (3). 40 CFR 1110. 

3. california state water Resources control Board. 1972. 

"Water Quality Control Plan. Ocean Water of California." 

4. Adams, J.K. 1974. "The Relative Effects of Light and Heavy 

Oils." u.s. Environmental Protection Agency, Division of Oil 

and Special Materials control, washington, D.c. Pub. No. 

EPA-520/9-74-021. 

5. Evans, D.R., and Rice, S.D. 1974. "Effects of Oil and 

Marine Ecosystems: A Review for Administrators and Folicy 

Makers.•• u.s. Department of the Interior, Bulletin 72 (3): pp. 

625-638. 

6. McKee, J.E., and Wolf, H.W. 1963. "Water Quality Criteria." 

7. 

California State water Quality Control Board. Pub. No. 3-A. 

Moseley, F.N., and Copeland, B.J. 1974. 

System. •• In: "Coastal Ecology Systems 

States. 11 Odum, Copeland, and ~cMahan, (ed) • 

Foundation, washington, D.c. 

63 

•• Brine Pollution 

of the United 

The conservation 
SECTION VII 

CONTROL AND TREAT~£NT TECHNOLOGY 

Petroleum production, drilling, and exploration wastes vary in 

quantity and quality from facility to facility. A wide range of 

control and treatment technologies has been developed to treat 

these wastes. The results of industry surveys indicate that 

techniques for in-process controls and end-of-pipe treatment are 

generally similar for each of the industry subcategories; 

however, local factors, discharge criteria, availability of 

space, and other factors influence the method of treatment. 

In-plant control/Treatment Techniques 

In-plant control or treatment techniques are those practices 

which result in: 1) reduction or elimination of a waste stream; 

or 2) a change in the character of the constituents and allow the 

end-of-pipe processes to be more efficient and cost effective. 

Reduction or Elimination of waste Streams 

The two ty~es of in-plant techniques that reduce the waste load 

to the treatment system or to the environment are reuse and 

recycle of waste products. Exam~les of reuse are: 1) reinject~on 

of produced water to increase reservoir pressures; and 2) 

utilization of treated production water (softened, if necessary) 

for steam generation. An example of a recycle system is the 

conservation and reuse of drilling muds. 

waste Character Change 

Examples of character change in waste stream would be: 1) the 

substitution of a positive displacement pump for a high speed 

centrifugal pump; and 2) substitution of a downhole choke for a 

well head choke, thereby reducing the amount of emulsion created. 

(1) 

Proper pretreatment and maintenance practices are also effective 

in reducing waste flows and ~mproving treatment efficiencies. 

Return of deck drainage to the process units and elimination of 

waste crankcase oil from the deck drainage or produced water 

treatment systems are examples of good offshore pretreatment and 

maintenance practices. 

Process Technology 

The single most significant change in process technology is 

reinjection to the reservoir formation for secondary recovery and 

pressure maintenance. This is distinguished from injection for 

disposal purposes only, wnich is considered as end-of-pipe 

treatment. Waters used for secondary recovery and pressure 

65 
maintenance should be free of sus~ended solids, bacterial slimes, 

oxygen, sludges, and precipitates. In some cases the quantity of 

produced water is insufficient to provide the needed water for a 

secondary recovery and pressure maintenance system. In this 

case, additional make-up water must be found, and wells or 

surface water (including sea water) may be used as a source of 

make-up water. ~here may be problems of compatability between 

produced water and make-u~ water. A typical reinjection water 

treatment facility consists of a surge tank, flotation cell, 

filters, retention tank, and injection pumps. (2) 

Reinjection of produced water for secondary recovery and pressure 

maintenance is a very common practice onshore. It has been es~mated that 60 percent of all onshore produced water is 

reinjected for secondary recovery. 

Produced water treatment for reinjection is si~lar, both 

offshore and onshore. Existing reinjection systems vary from 

small units which treat less than 100 barrels per day of brine 

waste to large com~lexes which handle over 170,000 barrels per 

day. Produced water reinjection systems for presure maintenance 

and water flooding are less common in the Gulf Coast, and none 

are in use in Cook Inlet, Alaska (Cook Inlet water is treated and 

injected for water flooding, because of compatibility problems 

with the ~roduced water). 

Produced water treatment and reinjection systems are not 

generally limited by space availability but must be specifically 

designed to fit offshore platforms. Two limiting factors which 

affect produced water reinjection are insuffiecint quantities of 

produced water to meet the requirement for reservoir pressure 

maintenance and incompatibility between make-up sea water and 

produced water. 

With the increasing oil demand, new ("tertiary") methods are 

being developed to recover greater amounts of oil from producing 

formations. The addition of steam or other fluids into the 

formation can improve ultimate recovery. A system which reuses 

produced water for steam generation is operating on the West 

coast. The system consists of a typical reinjection treatment 

unit with water softeners added to the system. 

Changes in process technology have also occurred in drilling 

operations. Environmental considerations and high cost of 

drilling muds have led to the development of special equipment 

and procedures to recycle and recondition both water based and o~l based muds. With the system operating properly, mud losses 

are limited to deck splatter and the mud clinging to drill 

cuttings. 

66 
Pretreatment 

The main pretreatment process which is applicable to offshore 

production systems is the return of deck drainage to the 

production process units to remove free oil prior to end-of-pipe 

treatment. This method of pretreatment is not applicable to 

facilities that flush drilling muds into the deck drainage system 

during rig wash down or to facilities that pipe all produced 

crude oil and water to shore for processing and brine treatment. 

Operation and Maintenance 

A key in-plant control is good operation and maintenance 

practices. Not only do they reduce waste flows and improve 

treatment efficiencies, but they also reduce the frequency and 

magnitude of systems upsets. 

Some examples of good offshore o~erations are: 

1. Separation of waste crankcase oils from deck drainage 

collection system. 

2. Reduction of waste water treatment system upset from 

deck washdown by discriminant use of detergents. 

3. Reduction 

techniques 

methods. 

of oil 

such as 

spillage through 

drip pans and 

good 

other 

prevention 

collection 

4. Elimination of oil drainage from transfer pump bearings 

or seals by pumping into the crude oil processing 

system. 

5. Reduction of oil gathered in the pig (pipeline scraper) 

traps ~Y channeling oil back into the gathering line 

system instead of the sump system. 

6. Elimination of extreme loading of the produced water 

treatment system, when the process system malfunctions, 

by redirecting all production to shore for treatment. 

(3) 

Good maintenance practice includes: 1) inspection of dum~ valves 

tor sand cutting as a preventive measure; 2) use of dual sump 

pumps for pumping drainage into surge tanks; 3) use of reliable 

chemical injection pumps for produced water treatment; 4) 

selection of the best combination of oil and water treating 

chemicals; and 5) use of level alarms for initiating shut down 

during major system u~sets. Operation and maintenance of a 

produced water treatment system during start-up presents special 

problems. As an example, an offshore faciLity had two problems 

67 
with the heater-treaters that caused problems with the water 

treatment system: 1) insufficient heat in the treaters; and 2) 

malfunctioning level controls which caused excessive oil loading. 

A change in the type of level controls and reduced production 

which lowered the beating requirements and helped allev~ate the 

problem during start-up of the produced water treatment unit. 

Further improvements were achieved by careful selection of 

chemicals for treating oil and froduced water, and the chemical inject~on and recylcing pumps were replaced. 

The preceding paragraph describes an actual case where deta~led 

failure analysis and corrective action ended an upset in the 

waste treatment system. Evaluation of operat~onal practices, 

process and treatment equipment and correct chemical use is 

imperative for proper operation and in the prevention and 

detection ot failures and upsets. The description of these 

operation and maintenance practices is not intended to advocate 

their universal application. Nevertheless, good operations and 

maintenance on an oil/gas production facility can have a 

substantial impact on the loads discharged to the waste treatment 

system and the efficiency of the system. careful planning, good 

engineering, and a comrnittment on the part of operating and 

management personnel are needed to ensure that the tull benefits 

of good o~eration and maintenance are realized. 

Analytical Techniques and Field verification Studies 

Data on the types of treatment equipment and performance of the 

systems in this report were provided by the industry. An early 

analysis of data indicated a need to both verify the information 

and determine current waste handling practices. EPA conducted a 

3-week sampling verification study for facilities. off the 

Louisiana Coast; and 3-day studies were conducted in Texas and cal~fornia to verify performance data. In addition, three field 

surveys were made to determine the ade~uacy of laboratory 

analytical techniques, sample collection procedures, operation 

and maintenance procedures, and general practices for handling 

deck drainage. Similar field surveys were made of facilities 

located in Cook Inlet. 

Performance verification studies were also conducted to identify 

the most efficient onshore facilities and to determine 

geographical and process differences based on crude oil residual separab~lity and various produced water treatment processes. 

var~ance in Analytical Results for Oil and Grease concentrations 

Effluent oil and grease values in produced 

reported by the oil and gas industry are 

contracting laboratories using various 

Analytical methods presently in use 

gravimetric, utlraviolet- fluorescence, and 

68 

water recorded and 

usually determined by 

analytical methods. 

include infrared, 

colorimetric. The 
method used by a contractor is usually governed by regulatory 

authority, the person in charge of the laboratory, the client, or 

some combination of these. For example, Department of the 

Interior, u. s. Geological survey, Outer continental Shelf 

Operating order i8 (Gulf of Mexico area) dated october 30, 1970, specif~es to F·ederal leasees that oil content values for 

effluents shall be determined and reported in accordance with the 

American Society for Testing and Materials Method Dl340, "Oily 

Matter in Industrial waste water. 11 A regional water quality 

board in California specifies APHA Standard Methods, 13th 

Edition, "Oil and Grease" Test No. 137 (Gravimetric). The u. s. 

Environmental Protection Agency lists the APHA Standard for oil 

and grease determination under the provisions of 40 CFR Part 136 

"Guidelines Esta.l::lishing Test Procedures for the Analysis of 

Pollutants." The manner in which the sample is prepared for analys~s is equally critical. For example, Table 16 shows 

oil/grease concentrations of acidized and unacidized samples from 

facilities in California (both analyzed by the same method). 

TABLE 16 

Effect of Acidification on 

Oil and Grease Data 

Oil and Grease - mg/1 

Date of 

Effluent Sample 

7-26-74 

7-26-74 

Unacidized 

7.6 

36.3 

Acidized 

26.3 

61.8 

The values after pH adjustment were significantly higher than the 

samples that were not acidified. One 

acidification converts many of the water 

salts to water insoluble acias that 

hydrocarbon solvents. 

explanation is that the 

soluble organic acid 

are then extractable by 

The solvent used for the extraction of oil and grease from a 

sample is another critical step that can affect analytical 

results. For example, petroleum ether extracts all crude oil 

constituents from a produced water sample except asphaltenes or 

bitumen. This limitation would affect the reported results of a 

sample containing high asphaltic constituents. Other solvents 

used in oil/grease determinations are trichlorotrifluroethane 

69 
(Freon), hexane, carbon tetrachloride, and methylene chloride, 

with each being somewhat selective in the hydrocarbon 

constituents extracted. 

Reported oil/grease concentrations in waste water effluents from 

offshore facilities were highly variable within and between 

geographical areas. The available information did not show any 

discernible reason for this variability (difference in waste 

treatability or treatment technology). Therefore, EPA undertook f~eld verification studies to determine the reasons for the low 

oil/grease concentration data in the coastal area of Texas and 

California as compared to Louisiana. These field studies 

included sampling for o~l/grease in effluent waste water d~scharges and duplicate samples were provided to the industry 

for independent laboratory analysis. Tables 17 and 18 compare 

the results of two analytical methods (gravimetric and infrared) 

measuring Freon extractible oil/grease and those values 

determined by petroleum ether extraction using the gravimetric 

method. This study was conducted by the EPA Robert s. Kerr 

Research Laboratory (RSKRL) at Ada, Oklahoma. 

70 
Table 17 

Oil and Grease Data - Texas coastal 

Analytical Procedure study 

Oil and Grease - mg/1 

RSKRL 

Sample Freon Freon 

Identification Gravimetric Infrared 

T-li 32 45 

T-lE 126 154 

T-2I 372 314 

T-2E 242 197 

T-3I 643 695 

T-3E 52 62 

T-4I 1905 1736 

T-4E 46 51 

Table 18 

Oil and Grease Data - California coastal 

Analytical Procedure study 

sample 

Identification 

e-li 

C-lE 

c-2I 

C-2E 

c-3I 

c-3E 

RSKRL 

Freon 

Gravimetric 

106 

22.3 

359.6 

42.2 

167.6 

46.1 

1 - unacidified samples 

I - influent 

E - effluent 

Freon 

Infrared 

126 

16 

473 

39 

197 

35 

71 

Pet. Ether 

Gravimetric 

76 

5 

241 

27 

141 

7 

INDUSTRY LABS 

Freon 

Gravimetric 

2 

5 

178 

145 

685 

10 

968 

6 

INDUSTRY LABS 

Pet. Ether 

Gravimetric 

79 

3.1 

508 

3.6 

189.1 

11.2 
The preceding tables indicate that there was good correlation 1n 

analytical results when EPA uses two d1fferent methods on the 

same sample. There is no correlation between the same sample 

analyzed by the same method by EPA and the industry labs in Texas 

and California (EPA's results did correlate well to the contract 

labs during the Louisiana verification study). Therefore the low 

oil and grease concentrations reported by Texas and California 

appear to be more a function of the analytical techniques and the 

laboratory rather than an indication of treatibility of the waste 

water produced and/or treatment equipment efficiency. This 

conclusion was validated by a statistical analysis of the data, w~ch is contained in Supplement B. The analysis indicated a 

high correlation with the results of the two analytical methods 

performed within the EPA laboratory and little or no correlation 

with the analytical results between the EPA and contractor 

laboratories. 

Field Verif~cation Studies 

The EPA field verification study of coastal Louisiana facilities 

included sampling for oil/grease in effluent waste water 

discharges. Dupl~cate samples were provided to the oil/gas 

industry for independent· laboratory analysis. The analytical 

results of this study, contained in Supplement B, verified the 

data collected over the years by coastal Louis~ana facilities. 

In addition, the study found a very high correlation between 

analytical results of contractor laboratories and the EPA 

laboratory. 

The selection of facilities for the Gulf Coast verification study 

was based on a general cross section of the production industry 

and did not favor the more efficient systems. Table 19 indicates 

types of treatment units, the performance observed during the 

survey, and long term performance based on historical data for 

each facility. Tables 20 and 21 indicate the comparative oil and 

grease concentration data for 'Iexas and California offshore 

facilities and onshore treatment of offshore produced water 

treatment units. 

72 
TABLE 19 

Performance of Individual Units 

Louisiana coastal 

Long Term Mean Effluent 

Oil and Grease 

Fac~lity Identificatign mg/1 

Flotation Cells 

GFVOl 

GFV02 

GFS03 

GFS04 

GFS05 

GFT06 

GFG07 

GFS08 

GF.r09 

GFGlO 

Parallel Plate coalescers 

GCCll 

GCC12 

GCM13 

GCC14 

GCG15 

GCS16 

GCC17 

Loose Media coalescers 

GI.G23 

GLT24 

Simple Gravity separators 

GPV18 

GPT19 

GPE20 

GIM21 

G'l'T22 

GPE25 

22 

23 

31 

29 

32 

18 

24 

28 

18 

35 

66 

43 

39 

39 

51 

25 

18 

'System malfunctioning during survey. 

73 

EPA survey Results 

Oil and Grease 

mg/1 

23 

6 

25 

21 

32 

24 

1481 

30 

31 

13 

21 

78 

34 

52 

19 

56 

118 

12 

8 

13 

26 

19 

44 

63 

16 
TABLE 20 

Texas coastal Verification Data 

Facility Freon Extractibles Freon Extractibles 

Identification Gravimetric Method Infrared Method 

Oil and Grease - mg/1 

Influent Effluent Influent Effluent 

T-1 32.0 126.0 45.0 154.0 

28.9 103.0 57.0 134.0 

830.0 116.0 1,230.0 232.0 

49.0 561.0 130.0 827.0 

199.0 141.0 300.0 304.0 

36.0 118.0 64.0 277.0 

T-2 333.0 220.0 305.0 209.0 

372.0 242.0 314.0 197.0 

301.0 194.0 336.0 198.0 

327.0 185.0 351.0 204.0 

352.0 196.0 293.0 188.0 

.2.86.0 220.0 312.0 237.0 

T-3 1,250.0 13.0 1,350.0 55.0 

643.0 52.0 695.0 62.0 

1,626.0 45.0 1,635.0 60.0 

154.0 50.0 206.0 66.0 

667.0 55.0 1,242.0 81.0 

1,169.0 87.0 1, 215.0 84.0 

T-4 1,583.0 37.0 1,520. 0 42.0 

921.0 9.0 1,578.0 9.0 

1,710.0 14.0 1,677.0 14.0 

1,844.0 24.0 1,780.0 27.0 

1,905.0 46.0 1, 736.0 51.0 

1,007.0 1,884.0 

74 
TABLE 21 

Verification of Oil and Grease Data 

California Coastal 

RSKRL, Ada, Oklahoma 

Freon Freon Petroleum Ether 

Extractibles, Extractibles, Extractibles 

Facility Gravimetric Infrared Gravimetric ' 

Identification M:lthod, mg/1 Method, mg/1 Method, mg/1 

Influent Effluent Influent Effluent Influent Effluent 

C-1 112.3 28.9 94.0 18.0 6.0 

97.4 43.1 101.0 18.0 

110.7 26.0 122.0 18.0 90.0 -.J 

01 106.1 22.3 126.0 16.0 76.0 5.0 

C-2 359.6 42.2 437.0 39.0 241.0 27.0 

363.6 44.0 446.0 40.0 193.0 13.0 

215.6 53.5 323.0 54.0 172.0 19.0 

599.8 51.6 851.0 47.0 462.0 51.0 

881.1 55.4 1,214.0 53.0 611.0 14.0 

C-3 165.6 54.0 188.0 39.0 83.0 23.0 

163.2 44.3 148.0 34.0 100.0 22.0 

202.2 51.7 206.0 37.0 71.0 

167.6 46.1 197.0 35.0 141.0 7.0 

C-4 56.7 19.1 58.0 16.0 55.0 1 6.01 

24.2 15.0 59.01 

19.9 15.0 102.01 

1. Carbon tetrachloride extractibles. 
End-of-pipe control technology for offsbore treatment of produced 

water from oil and gas production primarily consists of 

physical/chemical methods. The type of treatment system selected 

for a particular facility is dependent upon availability of 

space, waste characteristics, volumes of waste produced, existing 

discharge limitations, and other local factors. Simple treatment 

systems may consist of only gravity separation pits without the 

addition of chemicals, while more complex systems may include 

surge tanks, clarifiers, coalescers, flotation units, chemical 

treatment, or reinjection. 

Gas Flotation 

In a gas flotation unit gas bubbles are released into the body of 

waste water to be treated. As the bubbles rise through the 

liquid, they attach themselves to any oil droplet in their path, 

and the gas and oil rise to the surface where they may be skimmed 

off as a froth. 

Two types of gas flotation systems are presently used in oil 

production: 1) Dispersed gas flotation these units use 

specially shaped rotating mines or dispersers to form small gas 

bubbles which float to the surface with the contacted oil. The 

gas is drawn down into the water phase through the vortex created 

by the rotors, from a gas blanket maintained above the surface. 

The rising bubbles contact the oil droplets and come to the 

surface as a froth, which is then skimmed off. These units are 

normally arranged as a series of cells, each one operating as 

outlined above. The waste water flows from one cell to the next, 

with a net oil removal in each cell (some oil is recycled back 

into the ~ater phase by the rotor action). 2) Dissolved gas 

flotation these units differ from the dispersed gas flotation 

because the gas bubbles are created by a change in pressure which 

lowers the dissolved gas solubility, releasing tiny bubbles. A 

portion of the waste water stream is recycled back to the bottom 

of the cell after waste water has been gasified. This 

gasification is accomplished by passing the waste water through a 

pump to raise the pressure and then through a contact tank filled 

with gas. The waste water leaves the contact tank with a 

concentration of gas equivalent to the gas solubility at the 

elevated pressure. When the recycled (gasified) water is 

released in the bottom of the cell (at atmospheric pressure) the 

solubility of the gas decreases and the excess gas is released as 

microscopic bubbles. These bubbles then rise to the surface 

contacting the oil and bringing it to the surface where it is 

skimmed off. Dissolved gas flotation units are usually a single 

cell only. 

On production facilities it is usual practice to recycle the 

skimmed oily froth back through the production oil-water 

separating units. A flow diagram of the two typical flotation 

units is shown in Figure 6. 

76 
CRUDE OIL PRODUCTION PROCESSING 

L.P. GAS GAS 

H.P. GAS 

I.P. GAS 

SALES 

TO 

~ OIL TO SALES 

,.t::. ~ ........_ PROCESS 01 L· ,:::::_ :::::::. 

LOW PRESSURE OIL WEL/r ......._ L. WATER SEPARATION .....---- p (HEATER TREATER, 

INTERMEDIATE\ 1. . CHEMICAL, ELEC t--r. 

PRESSURE OIL f<} HIGH P. TRICAL, SURGE TANK. 

WELL T<-t: PRESSURE GUN BARREL, FREE SKIMMER TANK 

<: b- SEPARATOR -~ WATER KNOCK OUT. I.:C:P ~ ETC.) ~ CP H-AT BRINE \. ....... t: to....... -- ..._ ..... 

HIGH PRESSURE 11 -~ OILWELL v ~ OILANDBRlNE 

v ·• 7 ' I SKIMMED OIL RECYCLE FROM 

GAS 

CHEMICAL INJECTION FLOTATION 

-.J "\ 

-.J 

WASTE WATER TO EITHER - ./ 

SKIMMED OIL RECYCLE 

• ROTOR-DISPERSERS 

u- - GAS OR AIR 

DISCHARGE 1----" AND CHEMICALS 

~ ::~ vo-rVERBOAR')_ 

~b 

lf 

~~)/~b FLOTATION 

UNIT 

_ 

~ 

Ct:TACT 

~ TANK ~ -

SKIMMED OIL RECYCLE TO PROCESS SEPARATION ..._ - - ROTOR-DISPERSER GAS FLOTATION PROCESS DISSOLVED GAS FLOTATION PROCESS 

Fig. 6 -- ROTOR-DISPERSER AND DISSOLVED GAS FLOTATION PROCF.SSES 

FOR TREATMENT OF PRODUCED WATER 
The addition of chemicals can increase the effectiveness of e~ther type of gas flotation unit. some chemicals increase the 

forces of attraction between the oil droplets and the gas 

bubbles. Others develop a floc which eases the capture of oil 

droplets, gas bubbles, and fine suspended solids, making 

treatment more effective. 

In addition to the use of chemicals to increase the effectiveness 

of gas flotation systems, surge tanks upstream of the treatment 

unit also increase its effectiveness. The period of quiescence 

provided by the surge tank allows some gravity separation and 

coalescence to take place, and dampens out surges in flow from 

the process units. This ~rovides a more constant hydraulic 

loading to the treatment unit, which, in turn, aids in the oil 

removal process. 

The verification survey conducted on Coastal Louisiana facilities 

includea 10 flotation systems which varied in design capacities 

from 5,000 to 290,000 barrels-per-day and included both 

rotor/disperser and dissolved gas units. The designs of waste 

treatment systems are basically the same for both offshore 

platform installations and onshore treatment complexes; however, paralle~ units are frovided at two of the onshore installations, 

permitting greater flexibility in operations. 

Information obtained during the field survey of onshore treatment 

systems for cook Inlet indicated that one of the four onshore 

systems utilized a dissolved gas flotation system comparable to 

those used in the Gulf Coast. This system provides 

physical/chemical treatment and consists of a surge tank, 

chemical injection, and a dissolved air flotation unit. In 

addition, two of the cook Inlet platforms use flotation cells for 

treatment of deck drain wastes. 

Field surveys on the west Coast found that physical/chemical 

treatment is the primary method of treating produced water for 

either discharge to coastal waters or for reinjection and that 

flotation is the most widely used of the physical/chemical 

methods. on the west coast, all treatment systems except one are 

located onshore and produced fluids are piped to these complexes. 

The majority of the waste water treatment systems have been 

converted to reinjection systems. However, some of those that 

still discharge are somewhat different from the systems in the 

Gulf coast and Cook Inlet. One of the more complex onshore 

systems consists of pretreatment and grit settling, primary 

clarification, chemical addition (coagulating agent), chemical m~~ng, final clarification, aeration, chlorination, and air 

flotation. Th~s system handles 50,000 barrels-per-day. 

surveys of onshore production facilities in California revealed 

induced gas flotation being used for treatment of produced water 

for recovery, disposal by reinjection and discharge. A total of 

78 
seven units were observed, three of which were utilized ahead of 

sand filters and one unit was followed by a pond. The size range 

of the entire group was from 10,500 to 350,000 Bbl/day. Surge 

tanks normally preceded the flotation units with the floc going 

to a sump or being recycled. 

In Wyoming two dispersed air flotation systems were observed, 

both of which discharge and reinjected for recovery the treated 

produced water. The system consisted of a skim tank, flotation 

unit, surge tank and in the case of the discharged stream, an 

earthen pond. The addition of chemicals was used to increase 

separation efficiency. The produced water treatment capacities 

of the two systems surveyed were 70,000 and 340,000 Bbl/day 

respectively. 

Parallel Flate Coalescers 

Parallel plate coalescers are gravity separators which contain a 

pack of parallel, tilted plates arranged so that oil droplets 

passing through the pack need only rise a short distance before 

striking the underside of the plates. Guided by the tilted 

plate, the droplet then rises, coalescing with other droplets 

until it reaches the tip of the pack where channels are provided 

to carry the oil away. In their overall operation, parallel 

plate coalescers are similar to API gravity oil water separators. 

The pack of parallel plates reduces the distance that oil 

droplets must rise in order to be separated; thus the unit is 

much more compact than an API seFarator. suspended particles, 

which tend to sink, move down a short distance when they strike 

the upper surface of the plate; then they move down along the 

plate to the bottom of the unit where they are deposited as a 

sludge and can be periodically drawn off. Particles may become 

attached (scale) to the plate surface of the plate; then they 

move down along the plate surfaces, requiring periodic removal 

and cleaning of the plate pack. 

Where stable emulsions are present, or where the oil droplets 

dispersed in the water are relatively small, they may not 

separate in passing through the unit. 

The verification survey of Coastal Louisiana facilities included 

seven plate coalescer systems which had design capacities from 

4,500 to 9,000 barrels-per-day. A recent survey indicated that 

approximately 10 ~ercent of the units in this area were plate 

coalescers and they treated about 9 percent of the total volume 

of produced water in offshore Louisiana waters. (4) Both the 

long-term performance data and the verification survey indicated 

that performance of these units was considerably poorer than that 

of flotation units. In addition to the physical limitations, 

coalescers• operation and maintenance data indicated that the 

units require frequent cleaning to remove solids. 

79 
No plate coalescers are in use in cook Inlet or California, 

either onshore or offshore. 

Filter Systems (Loose or Fibrous Media Coalescers) 

Another type of produced water treatment system is filters. They 

may be classified into two general classes based on the media 

through which the waste stream passes. 

1. Fibrous media, such as fiberglass, usually in the form 

of a replacable element or cartridge. 

2. Loose media filtez·s, which normally use a bed of 

granular material such as sand, gravel, and/or crushed 

coal. 

Some filters are designed so that some coalescing and oil removal 

take place continuously, but a considerable amount of the 

contaminants (oil and suspended fines) remain on the filter 

media. This eventually overloads the filter media, requiring its 

replacement or backwashing. Fibrcus media filters may be cleaned 

by special washing techniques or the elements may simply be 

disposed of and a new element used. Loose media filters are 

normally backwashed by forcing water through the bed with the 

normal direction of flow zeversed, or by washing in the normal 

direction of flow after gasifying and loosening the media bed. 

Filters which re~uire backwashing ~resent somewhat of a 

on platforms because the valving and controls need 

maintenance and disposal of the dirty backwash water 

difficult. Replacing filter media and contaminated 

elements also create disposal. problems. 

problem 

regular 

may be 

filter 

Measured by the amount of oil removed, filter performance has 

generally been good (provided that the units are backwashed 

sufficiently often): however, problems of excessive maintenance 

and disposal have caused the industry in the Gulf coast to move 

away from this type of unit, and a number of them have been 

replaced with gas flotation systems. 

The Gulf Coast survey information indicated that when filter 

systems are used there is no in~tial pretreatment of the waste 

other than surge tanks. Backwashing, disposal of solids, and 

complex instrumentation were reported as the main problems with 

these units. 

On the West Coast and Cook Inlet, no filter systems are in use as 

the primary tzeatment method. Filters are however, used for 

final treatment in injection systems in Cal~fornia and several 

steps of filtration are used prior to sea water injection in cook 

Inlet. on the west coast, these units are preceded by a surge 

tank, flotation unit, and other treatment units which remove most 

80 
of the oil and suspended particles. These units, when used in 

series with other systems, perform well. 

In Wyoming a site was visited where ap~roximately 6,600 Bbl/day 

was being treated by a mixed sand media pressure filter. Earthen 

ponds both preceded and followed the filter unit with backwash 

feed being pumped from the final pond and discharged to the 

primary pond. 

Gravity Separation 

The simplist form of treatment is gravity separation. The 

produced water is retained for a sufficient time for the oil and 

water to separate. Tanks, pits, and, occasionally, barges are 

used as gravity separation vessels. Large volumes of storage to 

permit sufficient retention times are characteristic of these 

systems. Performance is dependent upon the characteristics of 

the waste water, water volumes, and availability of space. While 

total gravity separation requires large containers and long 

retention times, any treatment system can benefit from quiescent 

retention prior to further treatment. This retention allows some 

gravity separation and dam~ens surges in volume and oil content. 

About 75 percent of the systems on the Gulf Coast are gravity 

separation systems. The majority are located onshore and have 

limited application on offshore platforms because of space 

limitations. Properly designed, maintained, and operated systems 

can provide adequate treatment. A 30,000-barrel-per-day gravity 

system with the addition of chemicals produced an effluent of 

less than 15 mg/1 during the verification survey. 

Two of the onshore treatment systems in cook Inlet use gravity 

separation with various configurations of settling tanks and 

pits. No gravity systems were reported to be in use on the west 

Coast. The four installations visited ~n the Texas verification 

study all use gravity separation tanks offshore and a combination 

of tanks and/or pits onshore. 

The most prevalent treatment method for produced water 

encountered in the onshore f~eld surveys of California, Wyoming, 

Texas, Louis~ana and Pennsylvania onshore production sites were 

tanks and ponds when utilized as the single treatment process. 

As previously mentioned, tanks do not afford the retention times 

of ponds, but whether or not their primary function is separation 

they are effective in skimming readily removed free oil. 

In Cal~fornia four sites were visited which utilized tankage as 

the single method of treatment prior to disposal by reinjection. 

The capacity of these systems to treat produced water ranged from 

6,000-35,000 Bbl/day. 

81 
In Wyoming a total of 37 production facilities were visited which 

utilized either tanks or ponds as the method of treatment. Of 

the 23 sites using tanks for treatment ranging in produced water 

capacity from 920 to 34.000 Bbl/day, 11 were reinjecting for d~sposal and the remainde.r were reinjecting for secondary 

recovery purposes. Of the 14 sites using ponds for treatment, 

nine were discharging, two were reinjecting for recovery. while 

the remaining three both discharged and reinjected for recovery. 

In Pennsylvania, where disposal ~y discharge is 

than the exception, 11 sites were v~sited which 

for separation treatment ranging in capacity from 

of produced water capacity. 

Distillation 

the rule rather 

utilized ponds 

2-8,000 Bbl/day 

In California a site was visited which utilized produced water as 

boiler feedwater. The boiler was fired by field natural gas and 

discharged condensate to the local groundwater table. The steam 

was utilized to heat onsite crude storage tanks and the boiler 

blowdown containing oil and qrease residue was hauled to a Class 

I (California Classification) landfill site. Reported daily fuel 

costs for the 150 Bbl/day facility are $70. 

Chemical Treatment 

The addition of chemicals to the waste water stream is an 

effective means to increase the efficiencies of treatment 

systems. Pilot studies for a large onshore treatment complex in 

the Gulf of Mexico indicated that addition of a coagulating agent 

could increase efficiencies approximately 15 percent and the 

ad~tion of a polyelectrolyte and a coagulating chemical could 

increase efficiencies 20 percent. (5) 

Three basic types of che~cals are used for waste water treatment 

and, many different formulations of these chemicals have been 

developed for specific applications. The basic types of 

chemicals used are: 

1. Surface Active Agents These chemicals modify the 

interfacial tensions between the gas, suspended solids, 

and liquid. They are also referred to as surfactants, 

foaming agents, demulsifiers. and emulsion breakers. 

2. coagulating Chemicals - Coagulating agents assist the 

formation of floc and improve the flotation or settling 

characteristics of the suspended particles. The most 

common coagulating agents are aluminum sulfate and 

ferrous sulfate. 

82 
3. Folyelectrolytes - These chemicals are long chain, high 

molecular weight polymers used to assist in removal of 

colloidal and extremely fine suspended solids. 

The results of two EPA surveys of 33 offshore facilities using 

chemical treatment in the Gulf Coast disclosed the following: 

1. Surface active agents and polyelectrolytes are the most 

commonly used chemicals for waste water treatment. 

2. The chemicals are injected into the waste water upstream 

from the treatment unit and do not require premixing 

units. 

3. Chemicals are used to imfrove the treatment efficiencies 

of flotation units, plate coalescers, and gravity 

systems. 

4. Recovered oil, foam, floc, 

skimmed from the treatment 

process system. 

and suspended ~articles 

units are returned to the 

A similar survey of facilities in cook Inlet, Alaska indicated 

that a facility uses coagulating agents and polyelectrolytes to 

improve treatment efficiency. Recovered oil and floc are 

returned to the ~rocess system. 

Chemical treatment procedures on the west coast are similar to 

those used in the Gulf Coast and cook Inlet. However, there are 

exceptions where refined clays and bentonites are added to the 

waste stream to absorb the oil and both are removed after 

addition of a high molecular weight nonionic polymer to promote 

flocculation. The oil, clay, and other suspended particles 

removed from the waste stream are not returned to the process 

system but are disposed of at approved land disposal sites. A 

14,000-barrel-per-day treatment system using refined clay was 

reported to have generated 60 barrels-per-day of oily floc which 

required disposal in a State approved site. selection of the 

proper chemical or combination of chemicals for a particular 

facility usually requires jar tests, pilot studies, and trial 

runs. Adjustments in chem~cals used in the process separation 

systems may also require modification of chemicals or application 

rate in the waste stream. Other chemicals may also be added to 

reduce corrosion and bacterial growths which may interfere with 

both process and waste treatment systems. 

Effectiveness of Treatment Systems 

Table 22 gives the relative long term performance of existing 

waste water treatment systems. The general superiority of gas 

flotation units and loose media filters over the other systems is 

83 
readily apparent. However, individual units of other types of 

treatment systems have produced com~arable effluents. 

TABLE 22 

Performance of Various Treatment Systems 

Louisiana Coastal 

Mean Effluent, No. of Units 

Oil and Grease in Data 

Type Treatment System mg/1 Base 

Gas Flotation 27 27 

Parallel Flate coalescers 48 31 

Filters 

Loose Media 21 15 

Fibrous Media 38 7 

Gravity Separation (4) 

Pits 35 31 

Tanks 42 48 

Table 23 

treatment 

of weekly 

treatment 

gives the performance of existing produced water 

systems over a 6-month to one and one-half year period 

and monthly sampling. The data has been divided into 

systems according to State of location. 

State 

Wyoming 

Pennsylvania 

TABLE 23 

Performance of various Treatment Systems 

Wyoming and Pennsylvania 

Type of Mean Effluent 

Treatment Oil and Grease 

System mq/1 

Ponds 8.2 

Gas Flotation 10.6 

Sand Filtration 12.5 

Ponds 4.1 

84 

No. of Units 

in Data 

Base 

6 

2 

1 

4 
zero Discharge Technologies 

water produced along with liquid or gaseous hydrocarbons may vary 

in quantity from a trace to as much as 98 percent of the total 

fluid production. Its quality may range from essentially fresh 

to solids-saturated brine. The no discharge control technology 

for the treatment of raw waste water after processing varies with 

the use or ultimate disposition of the water. The water may be: 

1. Discharged to pits, ponds, or reservoirs and evaporated. 

2. Injected into formations other than their place of 

origin. 

Evaporation 

In some ar~d and semiarid producing areas, use of evaporation is 

acceptable, although limited in its practice. The surface pit, 

pond, or reservoir can only be used where evaporation rates 

greatly exceed precipitation and the quantity of emplaced water 

is small. The pit or pond is ordinarily located on flat to very 

gently rolling ground and not within any natural drainage 

channel, so as to avoid danger of flooding. Pit facilities are 

normally lined with impervious u.aterials to prevent seepage and 

subsequent damage to fresh surface and subsurface waters. 

Linings may range from reinforced cement grout to flexible 

plastic liners. Materials used are resistant to corrosive 

chemically-treated water and oily waste water. In areas where 

the natural soil and bedrock are high in bentonite, 

montmorillonite, and similar clay minerals which expand upon 

be~ng wetted, no lining is normally applied and sealing depends 

on the natual swelling properties of the clays. All pits are 

normally enclosed to prohibit or impede access. 

In much of the Rocky Mountain oil and gas producing area, the 

total dissolved solids of the produced waters are relatively low. 

These waters are discharged to pits and put to use for local 

farmers and ranchers by irr~gating land and watering stock. A 

typical produced water system widely in use is shown in Figure 7. 

A cross section of the individual pit is shown in Figure 8. 

A producing oil field in Nevada discharges produced water to a 

closed saline basin. The basin contains no known surface or 

subsurface fresh water and is normally dry. The field contains 

13 wells and produces ap~roximately 33 barrels of brine per well 

per day. 

Subsurface Disposal 

Injection and disposal of oil field produced water underground is 

practiced extensively by the petroleum industry throughout the 

85 
DETAIL MAP 

r--------------------, 

TREATER 

DFWKO 

I 

I 

I 

I 

SAMPLE I 

500 BBL 

WATER 

SETTLING 

TANK 

500 

~ BBL 

OIL STORAGE 

TANKS 

DLACT 

I 

I 

I 

0HEADER I 

L_ ----------------------__j 

Fig. 7 -- ONSHORE PRODUCTION FACILITY WITH 

DISCHARGE TO SURFACE WATERS 

86 
DIMENSIONS VAIY FOI VOLUME NEEDED ·-t··t-·· 

• ------~--Nk-----­

z 

~ 

DEPTH WILL VARY WITH 

OPE tAT IONS CONDIT I ON S 

NOTE 

PITS ARE EQUIPPED WITH PIPE DRAINS FOR SKIMMING OPERATIONS 

TO OBTAIN OIL-FREE WATER DRAINAGE 

Fig. 8 TYPICAL CROSS SECTION UNLINED EARTHEN 

OIL-WATER PIT 

87 
United States. The term "disposal" as used here refers to 

injection of produced fluids, ordinarily into a formation foreign 

to their origin. This injection is for disposal only and plays 

no intentional part in secondary recovery systems. (Injection 

for pressure maintenance or secondary 'recovery refers to the 

emplacement of produced fluids into the producing formation to 

stimulate recovery of additional hydrocarbons and is not 

considered end-of-pipe treatment.) current industry practice is 

to apply minimal or no treatment to the ~ter prior to disposal. 

If water destined for disposal requires treatment, it is usually 

confined to the application of a corrosion inhibitor and 

bactericide; a sequestering agent may be added to waters having 

scaling tendencies. ~he amount of treatment depends on the 

formation properties, water characteristics, and the availability 

and cost of storage and stand-by wells. 

Corrosion is ordinarily caused by 

Bactericides serve to inhibit the 

and slime producing organisms. 

frequently combined into a single 

under various trade names. (6) 

low pH, plus dissolved gasses. 

development of sulfate-reducing 

Chemicals and bactericides are 

commercial product and sold 

A wide range of stable, semipolar, surface-active organic 

compounds have been developed to control corrosion in oil field 

injection and disposal systems. The inhibitors are designed to 

provide a high degree of protection against dissolved gasses 

(carbon dioxide, oxygen, and hyGrogen sulfide) , organic and 

mineral acids, and dissolved salts. The basic action of the 

inhibitors is to temporarily "plant" or form a film on the metal 

surfaces to insulate the metal from the corrosive elements. The 

life of the film is a function of the volume and velocity of 

passing fluids. Inhibitors may be water soluble or dispersible 

in fresh water or brine. They may be introduced full strength or 

diluted. Treatment, usually in the range of 10 to 50 parts per 

million, may be continuous or intermittent (batch or slug). 

Effectiveness of corrosion inhirition is determined in several 

ways, including corrosion coupons, hydrogen probes, chemical 

analyses, and electrical resistivity measurements. 

Three primary types of bacteria attach oil field injection and 

disposed systems and cause corrosion: 

1. Anaerobic sulfate-reducing bacteria 

(Desulfovibrio--desulfuricans). Tnese bacteria promote 

corrosion by removing hydrogen from metal surfaces, 

thereby causing pitting. The hydrogen then reduces 

sulfate ions present in the water, yielding highly 

corrosive hydrogen sulfide, which accelerates corrosion 

in the injection or disposal system. 

2. Aerobic slime-forming bacteria. These may grow in great 

numbers on steel surfaces and serve to protect growths 

88 
of underlying sulfate-reducing bacteria. In extreme 

instances, great masses of cellular slime may be formed 

1Nhich may plug filters and sandface. 

3. Aerobic bacteria that react with iron. Sphaerotilus and 

Gallionella convert solu~le ferrous iron ~n injection 

water to insoluble hydrated ferric oxides, which in turn 

may plug filters and sandface. Oxygen entry into a 

system may also cause the formation of ferric oxide. 

Treatment to com~at bacterial attack ordinarily consists of 

applying either a continuous injection of 10 to 50 ppm 

concentration of a bactericide or ~atching once or twice a week. 

Scale inhibitors are commonly used in the injection or disposal 

system to combat the development of carbonate and sulfates of 

calcium, magnesium, barium, or strontium. Scale solids 

precipitate as a result of changes in temperature, pressure, or 

pH. They may also be developed by combining of waters containing 

nigh concentrations of calcium, magnesium, barium, or strontium 

with waters containing high concentrations of bicarbonate, 

carbonate, or sulfate. Scale inhibitors are basically chemicals 

which chelate, complex, or otherwise inhibit or sequester the 

scale-forming cations. 

The most widely used scale sequestrants are inorganic 

polymetaphosphates. Relatively small quantities of these chem~cals w~ll prevent the precipitation and deposition of 

calcium carbonate scale. Dimetallic phosphates or the so-called 

"controlled solul::ility" varieties are now widely used by the oil 

industry in scale control and are preferred over the 

polyphosphates. 

The downhole completion of a typical injection well is shown in 

Figure 9. A producing well ~s shown for comparison. Injection 

wells may be completed in a complicated fashion with multiple 

strings of tubing, each injected into a separate zone. If the 

disposal well is equipped with a single tubing string, and 

injection takes place through tubing separated from casing by 

packer, the annular space between tubing and casing is filled 

with noncorrosive fluids such as low-solids water containing a 

combination corrosion inhibitor bactericide, or hydrocarbons such 

as kerosene and diesel oil. All surface casing is cemented to 

the ground surface to prevent contamination of fresh water and 

shallow ground water. Pressure gauges are installed on the 

casing head, tubing head, and tubing to detect anomalies in 

pressure. Pressure may also be monitored by continous clock 

recorders which are commonly equipped with alarms and automatic 

shutdown systems if a pipe ruptures. 

The injection well designed for pressure maintenance and 

secondary recovery purfoses is coufleted in a manner identical to 

89 
INJECTION WELL PRODUCING WELL 

' FRESH WATER 

<.!Jj 

~r ,-r~ ~I (> :~ ,?, z ~~ ' 

PROTECTED WITH '<5/ a: 

r~·"'"'" () 

- -Q) 

co a: ~ ~~~ ' (/) (/) CASING AND CEMENT ' 

::::> 0 -· UJ :.• I -:::~ Casing I I ·.O·U ::. I f- ::.:: (); :,8u . I ... L- ."Q. .A' ~co 

0 Q) 

' II rr :::1 :::1 

.. > a. .. o; - 0 

~. f- (.!) -n ~~-. u z _(t) 

- 2. 3 co 

::::> (t) (t) 

n :::1 

\0 ~ ~ Jrna::l f- ............ 

0 . (t) - ·-. H'ol!£itt¢1'9t!"2iP.n V$04{ ... !"1~ .. iimV'&J3il!:f:,Cj~'fjt~~·'iiS,;!.Y~ ...... ~ a_ 0.""0 -

~~ 

1t 

Q) (t) 

u~ ; 3 

PROTECTED WITH OIL 

~m <t: ',• .., (t) 

Q.. '·' (/) :::1 

STRING AND CEMENT I " ...... c 

:::1 z 

a.m 

m n .., (t) 

co (/) .., (/) 

0 Q) 

c: .., :::~< 

a.-

0 

.., 

FISURE 9 

TYPICAL COMPLETION OF AN INJECTION WELL AND A PRODUCING WELL 
that of the disposal well, except that injection is into the 

producing horizon. Treatment prior to injection may vary from 

that applied to the disposal well in as much as water injected 

into the reservoir sandface must £e as free of suspended solids, 

bacterial slimes, sludges, and ~recipitates as is economically 

possible. ordinar~ly, selection of injection well sites poses 

few if any environmental problems. In many instances where 

injection is used for secondary recovery, the well site is fixed 

by the geometry of the waterflood configuration and cannot be 

altered. 

water for injection into oil and gas reservoirs requires 

treatment facilities and processes which yield clear, sterile, 

and chemic~lly stable water. A typical open injection water 

treatment system includes a skim pit or tank (steel or concrete 

equipped with over-and-under baffles to remove any vestiges of 

non-soluable material remaining after pretreatmen~ ; an aeration 

facility, if necessary to remove undesirable gasses such as 

hydrogen sulfide; a filtering system; seepage-proof backwash pit; 

accumulator tank (sometimes referred to as a clear well or clear 

water tank) to retain the finished water prior to injection; and 

a chemical house for storing and dispensing treatment chemicals. 

In the system described above no attempt is made to exclude air. 

Closed systems, on the other hand, are designed to exclude air 

(oxygen) • This is desirable because the water is less corrosive 

or requires less treatment to make it noncorrosive. The truly 

"closed" system is difficult to attain because of the many 

potential points of entry of air into the production system. 

Air, for example, can be introduced into the system on the 

downstroke of a pumping well through worn stuffing box packing or 

seals. In a few ir.stances, closed injection (or disposal) system 

is used where product waters ordinarily have minimal corrosive 

characteristics. That is, where salt water is gathered from 

relatively few wells, fairly close together; where wells produce 

from a common reservoir; or where a one-owner operation is 

involved. 

There are instances in which a closed input or produced water 

disposal system can be developed. In these systems all vapor 

space must be occupied by oxygen-tree gas under pressure greater 

than atmospheric. If oxygen (air) enters the system, it is 

scavenged. 

The "open" injection system has a much greater 

operational flexibility than does the closed system. 

more desirable factors are: 

degree of 

Among its 

1. Wider range, type, and control of treatment methods. 

2. Ability to handle greater quantities of water from different 

sources (diverse leases and fields) and differing formations. 

91 
3. Anility to properly treat waters of differing composition. 

This factor enables incompatible waters to be successfully 

combined and treated on the surface prior to injection. 

Disposal zone 

The choice of a brine disposal zone is extremely important to the 

success of the injection program. Prior to planning a disposal 

program, detailed geologic and engineering evaluations are 

prepared by the production divisions of oil producing companies. 

Appraisal of the geologic reservoir must include the answers to 

questions such as: 

1. How much reservoir volume is available? 

2. Is the receiving formation porous and permeable? 

3. What are the formation's physical and chemical properties? 

4. what geological, geochemical and hydrologic controls govern 

the suitability of the formation for injection or disposal? 

5. What are the short-term 

consequences of disposal? 

and long-term environmental 

The geologic age of significru1t disposal and injection reservoirs 

throughout the nation, ranges from relatively young rocks of 

Cambro-Ordovician period. Depths of disposal zones oridinarily 

range from only a few hundred feet to several thousand. However, 

prudent operators usually cons~der it inadvisable to inject into 

formations above 1,000 feet, particularly where the receiving 

formation has low permeability and injection pressures must be 

high. If the desired daily average quantity of water cannot be 

disposed of, except at surface ~ressures which exceed 0.5 pounds 

per square inch surface guage pressure per foot of depth to the 

disposal zone, particularly in shallow wells, an alternate zone 

is usually sought. 

It is necessary to be familiar with both the lithology and water 

chemistry of the receiving formation. If interstitial clays are 

present, their chemical composit~on and compatibility with the 

injected fluid must be determined. The fluids in the receiving 

zone must be compatible with those injected. Chemical analyses 

are performed on both to determine whether their combination will 

result in the formation of solids that may tend to plug the 

formation. 

The petroleum industry recognizes that the most carefully 

selected injection equipment means nothing if the disposed water 

is not conf~ned to the formation into wnich it is placed. 

consequently, the injection area must be thoroughly investigated 

to determine any previously drilled holes. These include holes 

92 
drilled for oil and gas tests, deep stratigraphic tests, and deep 

geophysical tests. If any exist, further information as to 

method of plugging and other technological data germane to the 

disposal project is assembled and evaluated. 

On the California coast there is a definite trend for all onshore 

process systems which handle offshore production fluids to 

reinject produced water for disposal. Field investigations made 

in California were confined to OCS waters, with visits being made 

to five installations. Each of these facilities were performing 

some subsurface disposal; none were injecting for secondary 

recovery or pressure maintenance. Four of these installations 

were sending all or part of the produced fluids to shore for 

treatment. All five installations were disposing of treated 

water in wells on the ~latform. ~wo were sending all fluids to 

snore, separating the oil and water, and then pumping the treated 

water back to the platforms for disposal. One installation was 

separating the oil and water on the platform and further treating 

the water so that it could be injected into disposal wells on the 

platform. Two of the platforms had been treating all fluids on 

the platform and injecting treated water. Since the total fluids 

produced are presently greater than the capacity of the disposal 

system, the excess treated water is being discharged overboard. 

Plans were being formulated to increase the capacity of the 

disposal system to return all produced water underground. 

Produced water disposal is commonly handled on a coo~erative or 

commercial basis, with the producing facility paying on a 

per-barrel basis. The disposal facility may be owned and 

operated by an individual, a cooperative association, or a joint 

interest group who may operate a central treatment or disposal 

system. The waste water may be trucked or piped to the facility 

for treatment and disposal. Two examples of cooperative systems 

are operating in the East Texas Field and the Signal Hill and 

Airport Fields at Long Beach, Calfornia. 

Alternate Handling 

During major breakdown and overhaul of waste treatment equipment, 

it is common practice to continue production and by pass the 

treatment units requiring repair. This does not create a serious 

problem at large onshore complexes where dual treatment units are 

available, but at sualler facilities and on offshore platforms 

there may not be an alternate unit to use. Alternate handling 

practices vary considerably from facility to facility. The 

following methods are currently practiced offshore: 

1. Discharge overboard without treatment. 

2. Discharge after removal of free oil in surge tank. 

93 
3. Discharge to a sunken pile with surface skimmer to remove 

free oil. 

4. Discharge of produced water to oil pipeline for onshore 

treatment. 

5. Retention on the facility using available storage. 

6. Production shutdown. 

The method used depends upon the design and system configuration 

for the paricular facility. 

End-of-Pipe Technology for wastes Other than Produced water 

Deck Drainage 

Where deck drainage and deck washings are treated in the Gulf 

Coast, the water is treated by gravity separation, or transferred 

to the production water treatment system and treated with 

production water. Platforms in California pipe the deck drainage 

and deck washings along with produced fluids to shore for 

treatment. In cook Inlet, these wastes are being treated on the 

platform. 

Field investigations conducted on platforms at cook Inlet 

indicate that the most efficient system for treatment of deck 

drainage ~aste water in this area is gas flotation. L1mited data 

indicate an average effluent of 25 mg/1 can be obtained from this 

system. The field investigations found that deck drainage 

systems operate much better when cranKcase oil is collected 

separately and when detergents are not used in washing the rigs. 

The practice of allowing inverted emulsion muds to get into the 

deck drain system, during drilling or workovers, also seemed to 

adversely effect treatment. 

Sand Remova~ 

Tne fluids produced with o~l and gas may contain small amounts of 

sand, which must be removed from lines and vessels. This may be accomp~ished by opening a series of valves in the vessel 

manifolds that create high fluid velocity around the valve. The 

sand is then flushed through a drain valve into a collector or a 

55-gallon drum. Produced sand may also be removed in cyclone 

separators when it occurs in appreciable amounts. 

The sand that bas been removed is collected and taken to shore 

for disposal; or the oil is removed with a solvent wash and the 

sand is discharged to surface waters directly. 

Field investigations have 

facilities have sand removal 

indicated 

equipment 

94 

that 

that 

some Gulf 

flushes the 

coast 

sand 
through the cyclone drain valves, and then the untreated sand is 

bled into the waste water and discharged overboard. 

No sand problems have been indicated by the operators in the cook 

Inlet area. Limited data indicate that California pipes most of 

the sand with produced fluids to shore where it is separated and 

sent to State approved disposal sites. 

At least one system has been developed that will mechanically 

remove oil from produced sand. The sand washer systems consist 

of a bank of cyclone separators, a classifier vessel, followed by 

another cyclone. The water passes to an oil water separator, and 

the sand goes to the sand washer. After treatment, the sand is 

reported to have no trace of oil, and the highest oil 

concentration of the transferred water was less tnan 1 ppm of the 

total volume discharged. (6) 

Drill~ng Muds and Drill Cuttings (Offshore) 

Oil and gas drilling operations, including exploratory drilling, 

are accoU:plished offshore with the use of mobile drilling rigs. 

These drilling units are either self-propelled or towed units 

that are held over the drilling site by anchors or supported by 

the ocean floor. The wastes generated from drilling operations 

are drilling fluids or 11muds 11 used in the drilling process, rock 

cuttings removed from the wellbore by the drilling fluids, and 

sanitary wastes from human activity. 

Both water based and oil muds are used. (10) In-plant control 

techniques and drilling mud practices are affected by the type of 

mud used. conventional mud handling equipment is used for water 

based muds. Some of the water based muds are discharged into the 

surface waters, with no special control measures other than 

routine conservation and safety practices. Operation and 

maintenance procedures on drilling rigs using water based muds 

are routine housekeeping practices associated with cleanliness 

and safety. A conventional drilling mud system for water based 

muds consists of a circulating system including pumps and pipes, 

mud pits, and accessory cond~tioning equipment (shale shakers, 

desanders, desilters, degassers). 

In-plant control techniques for oil muds are much more 

restrictive. They are not discharged into surface waters. The 

in-plant practices include mud saving containers on board, in 

addition to the conventional mud handling system. Operations and 

maintenance practices on rigs using oil muds generally reflect 

spillage prevention and control measures, such as drill ~i~e and 

kelly wipers, and catchment pans. 

Cuttings from drilling operations are disposed into surface 

waters when water based muds are used. However, cuttings from 

oil mud drilling are usually collected and transported to shore 

95 
for disposal. Another method is to collect cuttings, clean them 

with a solvent water mixture, and subsequently dispose of the 

washed cuttings into the surface ~ater body. After washing, the 

solvent water is transferred to shore or contained in a closed 

liquid recovery system. (11) 

Dr~lling Muds and Drill Cuttings (Onshore) 

With onshore drilling, the discharge from shale shakers, 

desilters, and desanders is placed in a large earthen pit. ·when 

drilling operations terminate, the pit is backfilled and graded 

over. Remaining muds, either oil or water based, are reclaimed. 

Well Treatment 

Acidizing and fracturing performed as part of remedial service 

work on old or ne~ wells can produce ~astes. Additionally, the 

liquids used to kill a well so that it can be serv~ced might 

create a disposal problem. 

Spent acid and fracturing fluids usually move through the normal 

production system and through the waste water treatment systems. 

The fluids therefore do not appear as a discrete waste source. 

Their presence, however, in the waste treatment system may cause 

upsets and a higher oil contE:nt in the discharge water. 

Liquids used to kill wells az·e normally drilling mud, water, or 

an oil such as diesel oil. If oil ~s used it is recovered 

because of its value, either by collecting it directly or by 

moving it through the production system. If the killing fluid is 

mud it will be collected for reuse or discharged as described 

earlier in this section. I£ water is used it will be moved 

through the production and treatment systems and disposed. 

Sanitary (Offshore) 

The vo~ume and concentration o£ sanitary wastes vary wide~y with 

time, occupancy, platform characteristics, and operational 

situation. The waste water primarily contains body waste but, 

depending upon the sanitary system for the particular facility, 

other waste may be contained in the waste stream. Usually the 

toilets are flushed with water but, in some cases brackish or sea 

fresh water is used. 

The concentrations of waste are significantly different from 

tbose for municipal domestic discharges, since the otfshore 

operations require regimented work cycles which impact waste 

concentrations and cause fluctuation in flows. waste flows have 

been found to fluctuate up to 300 percent of the daily average, 

and bOD concentrations have varied up to 400 percent. (12) 

96 
There are two alternatives to handling of sanitary wastes from 

offshore facilities. The wastes can be treated at the offshore 

location or they may be retained and transported to shore 

facilities for treatment. Offshore facilities usually treat 

waste at the source. The treatment systems presently in use may 

be categorized as physical/chemical and biological. 

Physical/chemical treatment may consist of 

evaporation-incineration, maceration-chlorination, and chemical 

addition. With the exception of maceration-chlorination, these 

types of units are often used to treat wastes on facilities with 

small complements of men or which are intermittently manned. The 

incineration units may be either gas fired or electric. The 

electric units have been difficult to maintain because of salt 

water corrosion and heating coil failure. The gas units are not 

subject to these problems but create a potential source of 

ignition which could result in a safety hazard at some locations. 

some facilities have chemical toilets which require hauling of 

waste and create odor and maintenance problems. 

Macerator-chlorinators have not been used offshore but would be 

applicable to frovide minimal treatment for small and 

intermittently manned facilities. At th~s time, there does not 

appear to be a totally satisfactory system for small operations. 

A much more complex physical/chemical system that bas been 

installed at an offshore platform in cook Inlet consists of: 

primary solids separation; chemical feed; coagulation; 

sedimentation; sand filtration; carbon adsorption; and 

disinfection. All solids and sludge are incinerated. Because of 

start-up difficulties, no data is available for this facility. 

It has been reported that physical/chemical sewage treatment 

systems have performed well in testing on land, but offshore they 

have develo~ed problems associated with the unique offshore 

environment including abnormal waste loadings and mechanical 

failure due to weather exposure. (12) 

The most common biological system applied to offshore operations 

is aerocic digestion or extended aeration processes. These 

systems usually include: a comminutor which grinds the solids 

into fine particles; an aeration tank with air diffusers; a 

gravity clarifier return sludge system; and a tank. These 

biological waste treatment systems have proven to be technically 

and economically feasible means of waste treatment at offshore 

facilities which have more than ten occupants and are 

continuously manned. 

Because of the special characteristics of sanitary waste 

generated by offshore operations, the design parameters in Table 

24 have been recommended. Table 25 shows average eftluent 

concentrations for various types of treatment units which are in 

use at offshore facil~ties in the coastal waters of Louisiana. 

97 
Domestic Wastes 

Domestic wastes result from laundries, galleys, showers, etc. 

Since these wastes do not contain fecal coliform, which must be 

chlorinated, they must only be ground up ·so as not to cause 

floating solids on discharge. Traceration by a comminutor should 

be sufficient treatment. 

98 
TABLE 24 

Design Requirements 

for Offshore Sanitary Wastes (13) 

Parameters 

Design Requirement 

Per Capita Per Day 

BOD 

5 

Total suspended Solids 

Flow 

Average Effluents 

0.22 lb 

0.15 lb 

15 gal 

TABLE 25 

of Sanitary Treatment 

LOuisiana coastal (13) 

BOD suspended 

5 solids 

company No. of Units mq/1 mq/1 

A 11 35 24 

B 6 13 39 

c 1.1 15 43 

D 9 25 36 

E 6 86 77 

99 

Systems 

Chlorine 

Residual 

mq/1 

1. 2 

1. 8 

1. 9 

2.5 

1. 3 
SEC'IION VII 

Bibliography 

1. University of Texas-Austin. Petroleum EXtension Service. and 

Texas Education Agency Trade and Industrial Service, 1962. 

"Treating oil Field Emulsions .•• 2nd. ed. rev. 

2. Offshore Operators committee, Technical Subcommittee. 1974. 

"Subsurface Disposal For Offshore Produced Water 

source. Gulf of Mexico. 11 New orleans, Louisiana. 

New 

3. u.s. Environmental Protection Agency, National Environmental 

Research Center, Raleigh. North carolina. 1973. ''Petroleum 

Systems Reliability Analysis. 11 Vol. II: Apfiendices. 

Prepared by computer Sciences corporation under contract No. 

68-01-0121. 

4. Offshore Operators COmmittee, Sheen Technical Subcommittee. 

1974. "Determination of Best Practicable control Technology 

Currently Available To Remove Oil From Water Produced With 

Oil and Gas. 11 Prepared by Brown and Root, Inc. , Houston • 

Texas. 

5. Sport, M.C. 1969. "Design and Operation of Gas Flotation 

Equipment for the Treatment of Oilfield Produced Brines." 

Paper presented at the Offshore Technology conference, 

Houston. Texas. May 18-21. 1969. Preprint No. OTC 1051, Vol. 

1: 111-145 1-152. 

6. Sawow, Rondal D. 1972. "Pretreatment of Industrial waste 

Waters for Subsurface Injection" and. "Underground Waste 

Management and Environmental Implications." In: AAPG Memoir 

18, pp.93-101. 

7. 

a. 

Hanby, Kendall 1?.. Kidd, Robert 

1973. "Subsurface Disposal of 

Alabama." Paper presented at 

symposium on Underground waste 

Recharge. New Orleans, Louisiana, 

E., and LaMoreaux, P.E. 

Liquid Industrial Wastes in 

the second International 

Management and Artificial 

September 26-30, 1973. 

Ostroff, A.G. 1965. "Introduction 

Technology." l?rentice Hall. Inc. 

to Oil Field Water 

9. McKelvey. V.E. 1972. "Underground Space -- An Unappraised 

Resource." In: "Underground Waste Management and 

Environmental Implications." AAPG Memoir 18, pp. 1-5. 

10. Hayward. B.S., Williams, R.B., and Methven, N.E. 1971. 

"Prevention of Offshore Pollution From Drilling Fluids." 

Paper presented at the 46th Annual SPE of AIME Fall Meeting, 

100 
New Orleansr Louisianar October 3-6r 1971. Preprint No. 

SPE-3579. 

11. cranf~eldr J. 1973. 11Cuttings Clean-Up Meets offshore 

Pollution Specifications ... Petrol. Petrochem. ~·r Vol. 13: 

No. 3r PP• 54-56r 59. 

12. Martinr James c. 1973. 11Domestic waste Treatment in the 

Offshore Environment... Pafer presented at the 5th Annual 

Offshore Technology conference. Preprint No. OTC 1737. 

13. u.s. Department of the Interior. 11Sewage Effluent Data." 

(Unputlished Report) August 16r 1972. 

101 
SECTION VIII 

COST, ENERGY, AND NONWAiER-QUALITY ASPECTS 

This section will discuss the costs incurred in applying 

different levels of pollution control technology. The analysis 

will also describe energy requirements, nonwater-quality aspects 

and their magnitude, and unit costss for treatment at each level 

of technology. Treatment cost for small, medium, and large oil 

and gas producing facilities have teen estimated for BPCT, BAT, 

and new sources end-of-pipe technologies. For existing 

facilities in the oil and gas extraction industry presently 

discharging formation water, the estimated capital cost required 

to comply with BPCT effluent limitation by 1977 is $147,307,000 

and the annual costs for debt service, depreciation, operation 

and maintenance, and energy are $43,609,000. 

cost Analysis 

section IV discusses the major categories of industry operations 

or activities and identifies subcategories within each one. For pur~oses of cost analys~s of end-of-pipe treatment three waste 

streams are considered -- produced water with discharge, produced 

water reinjected, and sanitary wastes (offshore). The cost of 

water treatment or disposal for produced water generated in the 

offshore and coastal subcategories is significantly affected by 

availability of space. The cost analysis has therefore been 

subdivided into two areas; offshore water disposal and onshore 

water disposal. The onshore water disposal has been further 

subdivided regionally. Deck drainage is considered to be 

treatable with the production water. Handling of drilling muds, 

well treatment wastes, and produced sands do not add any 

significant costs because the regulations requirements are common 

industry practice. In some instances offshore, the produced 

water is transferred to shore along with the crude, while in 

others the waste treatment system is installed on the platforms. 

Therefore, not all platforms will need to add all of toe 

treatment eq~pment or incur all of the incremental costs 

indicated to br~ng their raw discharges into compliance with the 

effluent limitations. Existing water treatment systems include 

sumps and sump piles, pits, tanks, plate coalescers, fibrous and 

loose media coalescers, flotation systems and reinjection 

systems. 

Oftshore Produced Water Disposal 

The systems currently used or needed for the treatment of process 

waste water (formation water) resulting from the production of o~l and gas involve physical separation, sometimes aided by 

chemical application, prior to discharge. Shallow well injection 

has also been successfully used for disposal of ~roduced wastes 

103 
at onshore locations and at several offshore locations in 

California. 

The methods examined for offshore us~ include the following 

arrangement of components: 

Al. 

A2 

Gravity separation using tanks, then discharge 

surface lNater. 

Gravity separation using 

discharge to surface water. 

plate coalescers, 

to 

then 

B Separation by coalescence, using flotation equipment, 

then discharge to surface water. 

c separation by coalescence, using flow equilization 

(surge tanks), desanders, and flotation, then discharge 

to surface lNater. 

D Separation using filters, then discharge to surface 

water. 

E1 Separation usLng flow equalization (surge tank) and 

filter with disposal by shallow well injection. 

E2 separation 

de sanders 

injection. 

using flow 

and filters, 

equalization (surge tank) 

with disposal by shallow well 

The data available for analysis suggest sizing treatment 

facilities for produced water based on these flow rates (barrels 

per day): 200, 1,000, 5,000, 10,000, 40,000. Where flow 

equalization ~s provided for the atove systems, surge tanks of 

these sizes were used (barrels): 20, 100, 500, 1,000, 3,000, 

respectively. 

Because of the nature of the problem, development of realistic 

cost estimates for the treatment cf produced water should be very 

generalized. costs have been develo~ed for the systems 

identified based on the following assumptions: 

1. All cost data were 

corresponding to 

construction cost 

computed in terms of 1973 dollars 

an Engineering Hews Record (ENR) 

index value of 1,895 unless otherwise 

stated. 

2. The annualized costs for capital and depreciation are based 

on a loan rate of 15 percent lNhich is equivalent to an annual 

average cost of 20 percent of the initial investment 

comprised of 10 percent for depreciation and 10 percent for 

average interest charges. 

104 
3. costs will 

Therefore, 

options: 

vary greatly depending upon platform space. 

investment costs have been prepared for three 

a. Option (a) assumes that adequate platform space is 

available because existing requirements for waste 

treatment are contained in the offshore leases. (1) ~herefore, no additional space will be needed. Rather, 

the space will be reused by facilities with more eff~cient removal capacity. 

b. Option (t) assumes that, because of the high costs 

involved in building platforms, they have been built to 

the minimum size needed for production. Therefore space 

is not generally available for water treatment equipment 

and ancillary facilities. Space is provided by 

cantilevered additions up to 1,000 square feet. Space 

re~uirements greater than this amount will require an 

auxiliary platform. (2) 

c. Option (c) is for new Flatforms being planned. 

needed space would be provided as a basic part of 

platform design and the costs apportioned at $350 

square foot. 

The 

the 

per 

In all three cases estimates are based on platforms located 

offshore in 200 feet of water. This depth is assumed to be an 

average for the period to 1983. 

Where electric energy is required, generating equipment of 

adequate capacity for the treatment equipment is provided for all 

requirements exceeding 5 horsepower. 

Operation and maintenance costs of components of the various 

systems are based on operating costs of the equipment. (2) The 

resulting percentage of investment cost is shown in Table 26. 

105 
TABLE 26 

Operating Cost Offshore 

Facility 

Tanks 

Plate Coalescers 

Flotation Systems' 

Filtersl 

Subsurface Disposal' 

Electrical Supply Facilities 

Platforms 

Basis for Calculating 

Annual 0 & M costs 

(Percentage of 

Investment 

11 

33 

11 

11 

9 

10 

2 

'EXcludes electrical power supply cost. 

Energy and power for low demand iE computed as 2 percent of the 

investment cost. For high demands an electric power cost of 2-

l/2 cents ~er kilowatt hour is assumed. 

The capital costs and annualized costs for the six alternative 

produced water treatment systems, for offshore installation, are 

contained in Tables 27-31. Options (a), (b), and (c), as defined 

above, reflect equipment costs, installation, and the cost of 

platform space requirements. 

Onshore Produced Water Disposal 

The waste water treated onshore will result from either onshore 

production facilities or offshore produced water sent to shore 

for treatment. The costs for treatment of offshore wastes, which 

are sent to shore, treated and then discharged will be somewhat 

less than the costs quoted abOve. These lower costs result from 

cheaper construction costs onshore, no costs for platform space, 

lower 0 and M costs, etc. ~he costs shown here are for 

subsurface disposal onshore. 

The typical system for injection for disposal only is a flow 

equalizing or surge tank, high pressure pumps, and a suitable 

well. Chemicals may be added to prevent corrosion or scale 

formation. 

106 
Capita 1 Costs 

... 

0 

-.J Annualized Costs 

Capital 

Depreciation 

0 & M 

Energy 

Total Annualized Costs 

Cost of water disposal $/bbl 

Table 27 

Formation Water Treatment Equipment Costs 

Offshore Installations 

200 Barrels Per Day Flow Rate 

EQUIPMENT COSTS (Thousands of 1974 dollars) 

Al B c El 

59.3 69.7 87.1 348.7 

5.93 6.97 8.7 34.9 

5.93 6.97 8.7 34.9 

2.95 4.7 6.4 28.0 

- - - 2.4 

14.8 18.6 23.8 100.2 

.20 .25 .33 l. 37 

E2 

400.5 

40.0 

40.0 

31.8 

2.0 

113.8 

1.55 
Table 28 

Formation Water Treatment Equipment Costs 

Offshore Installations 

1,000 Barrels Per Day Flow Rate 

EQUIPMENT COSTS (Thousands of 1974 dollars) 

Al B c El E2 

- Capital Costs 101 143 176.3 373.3 432.2 

_. Annualized Costs 

0 

(X) 

Capital 10.1 14.3 17.6 37.3 43.2 

Depreciation 10.1 14.3 17.6 37.3 43.2 

0 & M 6.7 11.6 14.3 29.7 38.0 

Energy - 1.5 1.5 3.3 4.4 

Total Annualized Costs 26.9 41.7 51.0 107.6 128.8 

Cost of water disposal .07 .114 .14 .30 .35 

$/bbl 
Table 29 

Formation Water Treatment Equipment Costs 

Offshore Installations 

5,000 Barrels Per Day Flow Rate 

(Thousands of 1973 dollars) 

Al A2 B c D E2 

- - - - - -

Capital Costs 

Option (a) 47 21 88 131 74 451 

Option (b) 1 ,452 55 146 204 117 518 

Option (c) 432 43 274 423 157 683 ...l 

0 

\0 Annualized Costs 

Capital & Depreci ation 

Option (a) 9.4 4.2 17.6 26.2 14.8 90.2 

Option (b) 290.4 11.0 29.2 40.8 23.4 103.6 

Operation & 

Maintenance 4.32 6.51 8.27 12.23 6.96 39.88 

Energy 0.94 0.42 1. 76 2.62 1.48 9.02 

Total - Option (a) 14.66 11.13 27.63 41.05 23.24 139.1 

Option (b) 295.66 17.93 39.23 55.65 31.84 152.5 

Cost of Water Disposal - $/bbl 

Option (a) 0.008 0.006 0.015 0.023 0.013 0.076 

Option (b) 0.16 0.0098 0.022 0.031 .017 0.084 
Table 30 

Formation Water Treatment Equipment Costs 

Offshore Installations 

10,000 Barrels Per Day Flow Rate 

(Thousands of 1973 dollars) 

Al A2 B c D E2 - - - - - -

Capital Costs 

Option (a) 60 31 148 206 108 563 

Option (b) 2 '140 68 228 1 ,626 161 1 ,972 

Option (c) a 66 488 708 259 979 

.... Annualized Costs .... 

0 Capital & Depre- ciation 

Option (a) 12 6.2 29.6 41.2 21.6 112.6 

Option (b) 428 13.6 45.6 325.2 32.2 394.4 

Operation & 

Maintenance 5.52 8.28 13.91 19.33 10.12 52.14 

Energy 1. 20 0.62 2.96 4.12 2.16 11.26 

Total - Option (a) 18.7 15.1 46.5 64.7 33.9 176 

Option (b) 434.7 22.5 62.5 348.7 44.5 457.8 

Cost of Water Disposal - $/bbl 

Option (a) 0.005 0.004 0.013 0.018 0.009 0.048 

Option (b) 0.117 0.006 0.017 0.096 0.012 0.125 

a 

Not considered to be a viable alternative because of large space requirement. 
Table 31 

Formation Water Treatment Equipment Costs 

Offshore installations 

40,000 Barrels Per Day Flow Rate 

(Thousands of 1973 dollars) 

Al A2 B c D E2 

- - -

Capital Costs 

Option (a) a 60 355 448 170 907 

Option (b) a 98 1 ,780 1 ,913 230 2,354 

Option (c) a 102 880 1 ,254 369 1 ,585 

...l Annualized Costs ...l 

...l 

Capital & Depreciation 

Option (a) 12 71 89.6 34 181.4 

Option (b) 20.4 356 382.6 46.0 470.8 

Operation & 

Maintenance 18.60 33.60 . 42.04 15.90 89.56 

Energy 1.20 7.10 8.96 3.40 18.14 

Total - Option (a) 31.8 111.7 140.6 53.3 289.1 

Option (b) 40.2 396.7 433.6 65.3 578.5 

Cost of Water Disposal - $/bbl 

Option (a) 0.002 0.0077 0.01 0.004 0.020 

Option (b) 0.0028 0.027 0.030 .005 0.040 

a No estimate made - method considered to be impractical because of l~rge space requirements. 
When produced water is treated and returned to the producing 

formation for secondary recovery, the costs should not be 

considered as a disposal cost, but rather as a necessary cost in 

production of oil. When ~reduced water cannot be returned to the 

formation for secondary recovery or for water flooding, the costs 

for treating it and providing the injection equipment becomes a 

legitimate disposal cost. 

Generalized cost estimates for onshore disposal of produced 

formation water were developed to include flow equalization tanks 

for 1,000, 5,000 and 10,000 tarrels-per-day water production, 

pumps sized for these flow rates and 700 pounds per square inch 

pressure, and disposal wells of 3,000 foot depth. A max~mum well 

capacity of 12,000 barrels-per-day was assumed. In addition, 

costs for this system include a lined pond to provide standby 

capability for continuing production for seven days while ~ump 

re~airs are being made or the injection system is being worked 

on. The capital costs and annualized costs for these systems are 

contained in Tables 32 and 33. 

Well completion costs are based on data contained in the Joint 

Association Survey of the u.s. Oil and Gas Producing Industry for 

1972. (2) The costs are adjusted upwards by use of the ENR 

construction cost index using a value of 1895 for 1973. Energy 

(power) costs are computed at 2-l/2 cents per kilowatt hour. 

Operation and maintenance costs were computed at 9 percent of the 

capital cost based on an industry-sponsored report. (2) 

Other costs for reinjecting produced formation water have been 

developed from field surveys conducted by the EPA during the 

first half of 1976. The sites surveyed were selected as being re~resentative of re~njection disposal technology within the 

various states. The actual data, which can be found in 

Supplement B, was taken from data formats subm~tted by industry 

for the selected sites and is presented for the most part without 

major adjustment. In two cases, Pennsylvania and Texas/Louisiana 

nearshore platforms, field data was not available and engineering 

estimates were developed. The values for ca~ital and operating 

costs shown in Tables 32 and 33 are from regression analysis of 

the field data. 

112 
TABLE 32 

Capital costs (1) for onshore Disposal 

by Reinjection of Produced Formation Water 

From Field surveys in Selected States 

(Thousands of 1975 Dollars) 

State DescriEtion # of Sites Reinjection CaEacitl!:, 

.1Q 1.QQ 1000 

California Land-based 6 74 146 

Wyoming Land-based 11 80 117 

Texas and Land-based 14 40 140 

Louisiana 

Pennsylvania Land-based 

case I (2), (4) 28 5.~: 190 

Land-based 

case II (3),(4) 15 24 61 

Texas Nearshore 

Platforms (4) 400 500 

Louisiana Nearshore 

Platforms (4) 400 470 

(1) Regression analysis data points. 

bbl/da~ 

10,000 

280 

300 

375 

470 

110 

1600 

1680 

(2) Production sites without existing reinjection facilities. 

(3) Production sites presently reinjecting fresh water. 

(4) Engineering estimates. 

113 
TABLE 33 

Annual Operating''> costs for Onshore Disposal by Re~njection of Produced Formation 

Water From Field Surveys in Selected States 

('Ihousands of 1975 Dollars) 

state Descri:etion t of Sites Reinjection CaEacitl!, bbl/day 

1Q 100 1000 10,000 

California Land-based 6 5.6 15.5 

Wyoming Land-based 1 1 8.8 18.5 

Texas and Land-based 14 12.5 25 

Louisiana 

Pennsylvania Land-based 

case I c:2), <4> 7.6 14 46 

Land-based 

case II (3), (4) 5 6.5 16.5 

Texas Nearshore 

Platforms (4) 40 45 

Louisiana Nearshore 

Platforms (4) 40 45 

(1) Regression analysis data ~oints exclud~ng capital and 

depreciation charges. 

(2) Production sites without existing reinjection facilities. 

(3) Production sites presently reinjecting fresh water. 

(4) Engineering estimates. 

As an alternative to no discharge - reinjection technology, cost 

estimates ~ere developed for discharge to navigable waters. The 

subcategories of product~on facilities selected for separate 

estimates were tbose described in section IV, Industry 

Subcategorization. The treatment technology selected for each 

category was the most efficient type of treatment observed in 

general use during the 1976 f~eld survey. 

Treatment technology for tbe stripper well category was selected 

as a surge tank followed by chemical addition and ponds. The 

steel surge tank has 2-10 day storage. The three unlined ponds 

in series have a 5-foot operating depth and a retention time of 

100-600 hours, depending upon the system's capacity. Annual 

costs consist of: operation at 1-3 hours per day, mainten&lce at 5~ of constructed value, electrical power at 4¢ per kilowatt 

hour, chemical costs at 5 mils per barrel and capital plus 

depreciation at 20~ of constructed value. The capital and 

114 

52 

32 

50 

100 

32 

122 

134 
operating costs for stripper well facilities in the size range 

10-10,000 bbl/day are shown on Table 34. 

Treatment technology for beneficial dischargers was selected as 

surge tank, skim basin, chemical feed and gas flotation followed 

by ponds. The surge tank bas a 1-2 hour storage capacity and the 

skim basin is provided with an automatic skimming device. The 

gas flotation system uses induced air and the ponds have a 

12-hour retention time. A standby pond of 48 hours retention 

time is also provided. Annual costs consist of: operation at 

6-12 hours per day, maintenance at 8J of equipment constructed 

value, electrical costs at 4¢ per kilowatt hour and chemicals at 

3 3/4 mils per barrel. The ca~ital and operating costs for 

beneficial dischargers in the size range 5,000-100,000 bbl/day 

are shown on Table 35. 

Treatment technology for the coastal platforms was selected as a 

surge tank followed by chemical feed and gas flotation. 

Additional platform space was assumed required to accommodate the 

treatment system. Design criteria and costing methods were 

patterned after the 1975 Brown and Root Report (3). The capital 

and operating costs so devised for coastal platforms are shown on 

Table 36. Details of cost estimating procedure for all 

categories is available in Supplement 11B11 • 

TAELE 34 

Cost Estimates for Treatment in Ponds and 

Disposal by Discharge for Stripper Well Facilities 

(Thousands of 1976 Dollars) 

System Capacity Produced Water, Bbl/day 

cost Item 1Q 50 100 500 1000 5000 10,000 

construction 12 19.6 24 30.1 36 65.7 90 

Operation & 

Maintenance 5.6 7.5 8.7 13.8 18.8 38.1 53.2 

115 
TABLE 35 

Cost Estimates for Treatment by Gas Flotation 

& Ponds & Discharge for Beneficial Dischargers 

(Thousands of 1976 Dollars) 

S~stem ca12acit~ Produced water 1 Bbl/da~ 

cost Item 500 1000 5000 10,000 25,000 so,ooo 100,000 

Construction 92 96 155 198 289 425 

Operation & 

Maintenance 32 37 72 85 13 7 220 

'IABLi". 36 

cost Estimates for Treatment by Gas 

Flotation & Discharge for Coastal Platforms 

(Thousands of 1976 Dollars) 

s~stem ca12acit~ Produced Water, Bbl/da~ 

cost Item 100 1000 5000 15,000 25,000 

construction 55 133 267 394 482 

Operation & 

Maintenance 8 43 83 132 172 

Offshore Sanitary Wastes 

600 

343 

Cost estimates for biological systems utilized on offshore 

platforms are for the aerobic digestion process or extended 

aeration treatment plants. The estimates anticipate the use of a 

system including a comminuter to grind the solids into fine 

particles, an aeration tank with air diffusers, gravity clarifier 

return sludge system and a disinfection tank. 

Based on the design requirements stated in Table 24 costs were 

developed for systems to serve 25 persons (2,000 gallons), 50 

persons (4,000 gallons) and 75 persons (6,000 gallons). These 

costs are contained in Table 37. 

Energy Requirements for OJ2erat~ng Flotation Systems 

Table 38 ~resents several estimates of horsepower requirements of 

flotation systems for the three levels of production. 

116 
Actual installations w~ll probably comprise a mix of 

manufacturers• units and the typical horsepower requirements will 

be some weighted average of the values in Table 38. For the 

purpose of estimating energy requirements, the average 

requirements are assumed to be 15, 25, and 60 horsepower for the 

5,000, 10,000 and 40,000 bbls per day production levels. (The 

118 Hp. figure for the 40,000 bbls per day unit was rejected as 

spurious - an incorrect linear extrapolation on a graph.) 

Table 39 presents the calculations that translate these basic 

horsepower requirements into total energy requirements. 

One way to evaluate the energy requirements of flotation systems 

~s to compare their consumption with that of the oil production 

associated with their use. Water production rates do not vary 

regularly with crude oil production rates. 

In some instances, the 5,000 bbl/day of produced water may be 

associated with a crude oil production of only 5,000 bbl/day. In 

other cases, crude production rates may be 50 to 100 times the 

rate of water production or vice versa. Given these variation 

and the variable products and costs of refining the crude oil, it 

would be a meaningless exercise to attempt to estimate the net 

BTU equivalent in terms of barrels of diesel oil for the oil 

production associated with the typical water flows. One can, 

however, usefully examine a range of possible levels of net 

production to get a general impression of the relative energy 

requirements of flotat~on systems. For example, it is reasonable 

to assume that the 5,000 bbl/day water production could be 

associated with a net energy production of anywhere from 50 to 

50,000 bbl/day of diesel oil. Siu~larly the 10,000 and 40,000 

bbl/day water flows could be associated with ranges of net diesel 

oil equivalent flows from 100 and 100,000 and 400 and 400,000 

bbl/day, respectively. Table 40 presents a summary of tne 

flotation systems• energy consumption data as compared to such 

associated oil production rates. 

It ~s clear from Table 40 that the energy required for flotation 

relative to the net energy being produced is very sma~l. Even in 

such a rare case as when water production is 100 times that of 

crude oil production, the flotation energy requirements amount to 

only 1.5 percent of the net energy being produced. 

Nonwater-Quality Aspects 

Evaluation of in-plant process control measures and waste 

treatment and disposal systems for best practicable control 

technology, best available technology, and new source performance 

standards indicates that there will be no significant impact on 

air quality. A minimal impact is expected, however, for solid 

waste dis~osal from offshore facilities. The collection, and 

subsequent transport to shore of oily sand, silt, and clays from 

117 
the addition of desanding units, where appropriate, will generate 

a possible need for additional approved land disposal sites. 

There are no known radioactive substances used in the industry 

other than certain instruments such as well-logging instruments. 

Therefore, no radiation problems are expected. Noise levels will 

not be 1ncreased other than that which may be caused by the 

possible addition of power generating equipment on some offshore 

facilities. 

118 
TABLE 37 

Estimated Treatment Plant Costs 

For Sanitary Wastes For Offshore Locations 

Package Extended Aeration Process 

(Thousands of 1973 dollars) 

Treatment Plant Capacity 

(gallons/day) 

2,000 4,000 6,000 

Capital Cost 18,000 23,000 28,000 

Total Annual Costs 6,010 7,660 9,360 

capital 1,800 2,300 2,800 

depreciation 1,800 2,300 2,800 

operation & maintenance 2,050 2,600 3,200 

energy and power 360 460 560 

119 
Level of 

Production 

bbl/day 

5,000 

10,000 

40,000 

Table 38 

Estimated Horsepower Requirements 

for the Operation of 

Flotation Treatment Systems 

Source 

Brown 

& Root !/ WEMCO !:_/ NATCO 1/ 

(Hp.) (Hp.) (Hp.) 

14 13 6 

25 21 13 

118 61 47 

l/ Brown and Root. III-11 

~/ Wemco Data Sheet, F8-D2, dated 4-19-73 

Rheem 4/ 

(Hp. )-

20 

25 

50 

11 Letter dated June 12, 1974, from National Tank Com. to Mr. R. W. 

Thieme, OTA, EPA, plus telephone communication, Friday, July 19, 

1974, with Mr. E. Cliff Hill, NATCO 

i/ Telephone communication with Mr. Ken Sasseen, Rheem-Superior Corp., 

California. 

Komlin 5/ 

Sanderson 

Engring Corp. 

(Hp.) 

17-1/2 

81-1/2 

11 Telephone conversation with Mr. Arthur Albohn, Komline, 201-234-1000 

July 24, 1974. 

120 
TABLE 39 

Estimated Incremental Energy 

Requirements Flotation Systems 

5,000 bbl/day of water treated: 

15 Hp. for 1 yr. = 3.35 x 108 BTU/yr. 

1 bbl diesel oil = 6 x 106 BTU 

15 Hp. - yr. = 55.8 bbl diesel oil/yr. 

Assume 20% conversion efficiency, then 15Hp. - yr = 279 bbl 

diesel oil/yr. 

10,000 bbl/day of water treated: 

464 bbl diesel oil/yr. 

40,000 bbl/day of water treated: 

1115 bbl diesel oil/yr. 

121 
Produces Water 

Flow - bbl/day 

5,000 

10,000 

40,000 

TABLE 40 

Energy Requirements for Flotation Systems as 

Compared to Net Energy Production 

Associated with the Produced Water Flows 

Assumed Level of Net Energy Energy for Flotation 

Production in Diesel Oil Units Diesel Oil 

Equivalents - bbl/day Equivalents - bbl/day 

50 to 50,000 0.76 

100 to 100,000 1.27 

400 to 400,000 3.05 

122 
SECTION VIII 

Bibliography 

1. Offshore Operators committee, Sheen Technical subcommittee. 

1974. "Determination of Best Practicable Control Technology 

currently Availa£le TO Remove Oil From Water Produced With 

Oil and Gas." Prepared by Brown and Root, Inc., Houston, 

Texas. 

2. Joint Association Survey of the u.s. Oil and Gas Producing 

Industry. 1973. "Drilling Costs and Expenditures for 

Exploration, Development and Production 1972. 11 American 

Petroleum Institute, washington, D. c. 

3. Offshore Operators Committee, Sheen Technical Subcommittee 

1975 11Potential Impact of EPA Guidelines for Produced water 

Discharges from the Offshore and coastal Oil and Gas 

Extraction Industry," Prepared by Brown and Root, Inc., 

Houston, Texas. 

123 
SECiiON IX 

EFFLUENT LIMliATIONS FOR 

BESi PRACTICABLE CCNTROL TECHNOLOGY 

Based on the information contained in the previous sections of 

this report, effluent limitations commensurate with best 

practicable control technology (BPCi) currently available have 

been established for each subcategory. The limitations, which 

must be achieved not later than July 1, 1977, explicitly set 

numerical values for allowable pollutant discharges of 

oil/grease, chlorine residual and floating solids. BPCT is based 

on control measures and end-of-pipe technology widely used by 

industry. 

Produced Water Technology 

BPCTCA process control measures include the following: 

1. Elimination of raw waste water discharged from free water 

knockouts or other process equipment. 

2. Supervised operations and maintenance on oil/water level 

controls, including sensors and dump valves. 

3. Redirection or treatment of waste water or oil discharges 

from safety valve and treatment unit by-pass lines. 

BPCTCA end-of-pipe treatment can consists of some, or all of the 

following: 

1. Equalization (surge tanks, skimmer tanks). 

2. Solids removal desanders. 

3. Chemical addition (feed pumps). 

4. Oil and/or sol~ds removal. 

a. Flotation. 

b. Filters. 

6. Plate coalescers. 

d. Ponds. 

e. Grav~ty Tanks. 

5. Subsurface disposal. 

1~5 
Specific treatability studies are required prior to application 

of a specific treatment system to an individual facility. 

Procedure for Development of ~ Effluent Limitations 

The effluent guidelines limitations for produced water were 

determined using effluent data fox oil and grease. This data was prov~ded by the oil and gas producing industry, Department of the Inter~or (U.s. Geological Survey), several States, EPA regional 

offices, as well as EPA data obtained during three field 

verification studies and four field surveys of operating 

platforms in the Gulf Coast; Cook Inlet, Alaska; and Coastal 

California. 

The oil-grease effluent data were analyzed to assess average 

operating efficiency and variatility for various types of 

treatment. The end-of-pipe technologies assessed for offshore 

and coastal facilities were; flotation units, plate coalescers, 

and fibrous media/loose media filters. For onshore facilities 

that discharge the end-of-pipe technologies assessed were; 

filters, flotation units, and ponds. 

Information was also obtained from the industry that included 

schematics, diagrams, and narratives of operation and maintenance 

for 25 selected producing facilities. 

A review of the effluent data showed a wide range of treatment 

efficiencies from facility to facility with similar treatment, 

variability between different treatment methods, and variability 

of effluent levels within an individual facility. Additional 

information was reviewed in detail to determine the reasons for 

these v~riations. It was concluded that treatment efficiency is 

affected by uncontrollable factors related to geological 

formation and controllable factors related to industry operations 

and analytical procedures. The factors considered uncontrollable 

by current technology are: 

1. Physical and chemical properties of the crude oil, 

including solubility in water. 

2. Sus~ended solids concentrations. 

3. Fluctuations in flow rate. 

4. Droplet sizes of the entrained oil (some 

possible). 

5. Degree of emulsification (some control possible). 

6. Characteristics of the produced water. 

The factors considered controllatle are: 

126 

control 
1. Operator training. 

2. Sample collection and analysis methods. 

3. Process equipment 

heater-treaters and 

and sump pumps. 

malfunction--for example in 

their dump valves, chemical pumps 

4. Lack of proper equipment--for example, desanders or 

large tanks. 

5. Noncompatible operations. 

The major objective of the detailed data analysis was to reject 

inadequate treatment technology and select facilities utilizing a 

sound technical rationale. 

Offshore and coastal - Initially, 138 treatment systems (94 off 

Louisiana, 36 off Texas, and 8 off Alaska) were evaluated. The 

treatment systems included gas flotat~on, plate coalescers, 

fibrous media filters, loose media filters, and gravity 

separation. 

EPA survey data show that the majority of the simple gravity 

systems produced highly variable effluents and were only 

minimally effective in removal of oil. The data from the 36 

gravity systems in Coastal Texas were derived from extreme 

variations in analytical procedures. EPA attempts to verify this 

data failed and all of this data had to be rejected. 

Ten of the 9q treatment systems off Louisiana had 10 or less data 

points; they were rejected. £ata from the 84 remain~ng units 

were analyzed along with the data collected from 25 facilities 

visited in the EPA verification study. The variance in treatment 

efficiencies was reflected in the data for all types of treatment 

methods. Both loose med~a and fibrous media filters are capable 

of producing low average effluents, but because of O&M 

difficulties the units are being phased out. 

The plate coalescer and gas flotation treatment units in 

Louisiana with greater than 10 data points were analyzed with 

respect to O&M reliability. A comparison was made to determine 

the effect~veness of physical separation of oil and ability to 

handle uncontrollable variation in raw waste cnaracteristics. 

The treatment efficiencies of plate coalescers were significantly 

below those for gas flotation units. This is su~ported by an 

analysis of the design parameters for plate coalescers, which are 

similar to API gravity separators. A review of O&M records and 

findings from EPA field surveys indicate that these units are 

subject to plugging from solids, iron, and other produced water 

constituents. When the parallel plate becomes plugged, frequent 

back washing, manual cleaning, or replacement of plates is 

127 
required. The 

concentrations 

uncontrollable 

efficiencies. 

consideration. 

effluent data showed highly variable oil 

which indicated that both controllable and 

factors significantly affected treatment 

Therefore, plate coalescers were eliminated from 

The remaining 32 Louisiana treatment units were dissolved gas 

flotation systems with chemical treatment. Historical data and 

reports ~ere available on nine of the units. Each was evaluated 

to determine the acceptability of the data and the causes of 

significant effluent variations. A review of the design 

parameters for the various systems showed that the systems were 

designed for the uaximum expected water production. None was 

designed to handle overload conditions which may occur during 

start-up, process malfunctions, or poor operating practices. 

Data were rejected which followed unit installation (start-up), 

when chem~cal treatment rates were modified, and when significant 

equipment maintenance or other O&M procedures which affect normal 

efficiency of the treatment unit was teing performed. Treatment 

data from some of the facilities analyzed were highly variable 

with no apparent explanation. In this case, all of the treatment 

data were accepted since it appeared highly unlikely that 

efficiency could be normalized with better O&M procedures. More 

likely tne varibility seen is attributable to the geological 

formation. Units with influent data in excess of 200-300 mg/1 

were suspect, since historical data indicated that high influents 

could be attributed to dump valve malfunctions in the process 

units. These units were investigated, and if the causes of their 

high concentrations were found, they were rejected; otherwise 

they were accepted. Units without historical data, but which had 

variations similar to those which were rejected were evaluated 

and if the variations were judged to be caused by controllable 

malfunctions, they were eliminated. Three systems were rejected 

because of reported process and treatment malfunctions, six 

months of data were rejected from two other systems due to 

operational and start-up problems. For the remaining units, data 

points were eliminated since a strong indication of errors in 

sample collection and analysis. 

Additional data were obtained for a number of the units from the 

oil companies, the Department of the ~nterior and the Brown and 

Root report. These data were screened and evaluated in a manner 

similar to that previously described. A total of 28 units, 27 

off the Louisiana coast and one in coastal Alaska were selected 

as potentially usable facilities. These facilities represent 

approximately 66 percent of the 41 facilities with the treatment 

technology to qualify as BPC'r. Of the 28 units, 12 have in 

excess of 90 data points and one facility has 508 data points 

covering an 18-month period. 

The EPA field survey included 

flotation units off Louisiana. 

128 

nine of the 28 selected gas 

The results of the field survey 
supports the rationale used for selection of exemplary technology 

and establishing the data base for determining effluent 

limitations. 

Upon com~letion of the technical evaluation of the data and 

units, a detailed statistical analysis was conducted to determine 

the form of the statistical distribution and to search for 

anomalous means or variances which might indicate a need to 

subcategorize based upon flow rates and space limitations. The 

initial review indicated that the selected units data were 

similar in distribution, and alttough the observed means and 

variances differed from unit to unit, no basis for further 

subcategorization was discovered. 

The statistical analysis indicated that the data were log 

normally distributed over most of the data. The various units 

could be separated statistically into three groups: 1) five high; 

2) 13 low; and 3) nine average. The means and 99 percent 

probability of occurance levels were calculated for the low, 

high, and total groups. Even though the group of 27 flotation 

units could be broken down further (into 3 subgroups), it was 

felt that at the current level of experience, with this 

technology, the entire industry could not be expected to achieve 

the same level of treatment as the very best units are now 

achieving. Therefore, data from all 27 Louisiana units were 

included in determin~ng the effluent limits for oil. 

Further analysis of the data base showed that some of the 

reported data were composites (4 grab samples taken in a 24 hour 

period, analyzed separately and the results averaged) and the 

rest were individual grab samples. It was determined that the 

grab samples had a higher variance than the composites and that 

the compositing technique would result in more re~resentative 

results. The compositing would greatly decrease the effect of 

sampling and analytical variance, which is potentially s~gnificant in oil and grease monitoring. 

The compos~ted data were 

different techniques were 

simulate composite sampling. 

than analyzed separately and two 

used on the grab samples analysis to 

A maximum monthly average was also calculated from the modified 

(composite) data base. To utilize all of the data, two different a~proaches were used to determine the monthly averages: 1) based 

on dates of observed values - this method averages a given number 

of samples (N) which are 30/N days apart, with the analysis being 

performed on these averages; 2) based on randomized observed 

values this method divides the 2262 data points into 2262/N 

groups, each group containing N randomly selected points. The 

analysis is performed on the averages of each group. 

129 
The first method is free of assumptions, but is limited in data 

base since only 9 of the units had more than 2 data points per 

month. The second method is simple and utilizes all of the data, 

but ignores autocorrelation. Figure 10 is a plot of the results 

of these two methods being applied to the data base. As can be 

seen the plots begin separating at 4 samples per month because of 

the effects of autocorrelation. 

The results of the above analyses are as follows: 

1. Long term average (1 year) - 25 mg/1 

2. Maximum monthly average (weekly sampling) - 48 mg/1 

3. Maximum day (composited) - 72 mg/1 

The data in Figure 11 represent a cumulative plot of the modified 

daily concentrations for the 27 Louisiana flotation units. The 

plot is essentially linear over the last 90 percent of the range, 

and the straight line represents a log normal distribution. Of 

the 2,262 samples, 99 percent have oil concentrations less than 

72 mg/1. 

A statistical analysis was also conducted to determine the 

distribution, and variance for the one flotation unit ~n coastal 

Alaska which treated produced waters. The average oil content in 

the effluent is approximately 15 mg/1. The operation of this 

unit appears very similar to the low group units for Louisiana. 

Beneficial use - Data for this sutcategory were collected from 

n~ne facilities in wyoming representing filters, flotation and 

ponds as end-of-pipe technology. ~hese facilities were visited 

by the technical contractor and were considered to have well run 

and well maintained operat~ons. An analysis of the data from the 

individual units showed no significant difference between the 

three technologies used. In addition to this data, 292 data 

points which represented sampling done throughout Wyoming by 

Region 8 were analyzed. 

Since there is no apparent difference in the first nine units, 

this data (160 points) were combined and analyzed. This data 

base has a mean of 10.0 and a daily maximum of 45 (both mg/1 of 

oil and grease). 

The Region VIII data base analysis showed a mean of 7.2 and a 

daily maximum of 45. 

An additional analysis was run combin~ng all the above data 

points (452 ~oints) and this data base had a mean of 8.2 and a 

daily maximum of 44. 

130 
....... 

~ . 

s 

J 

i 

....... 

·.-I 0 

Figure 10 

99th Percentile of M:>nthly Average Oil and Grease 

70 

60 

so 

1 

(30) 

Concentration vs. 

Frequency Of Sanpling Each M:>nth 

1 

I --·--·-··--t·------------·· ·:- . ---- ·---·- .. ·- -· 

2 

(15) 

0 

3 

(10) 

• actual 

-randanized 

• ' 

0 

4 

(8) (7) 

0 

5 

(6) 

--·-

·-----·-

. - -----

• 

6 

(5) 

Number of Sarrples Per M:>nth (Days Bet~ Sarrples) 

131 
FIGURE 11 

CUmulative Plot of Effluent Concentrations of All 

Selected Flotation Units in the Iouisiana Gulf Coast Area 

100 

79 

63 

50 

40 

-r-1 

g 

- 32 

25 

til 

a 

·r-l 20 

tJ 

~ 16 

~ 13 

~ 10 i 

r-1 

------ ·-· ;-·-

·r-l 

0 7.9 I 

•• 

~ I 

6.3 

r-1 • 

4-l I 

4-l ---+--~ --· -~ ---~,. . .,.,_. 

rz:l I 

I 

I 

4.0 j 

3.2 

1 2 5 

1----

+ ! 

10 

l --t . . __ L ___·t 

I 

.. ·t- -+---··- .. ; .... 

f

' i ' 

. .. f .. ·- - ! .. - !--

! + + ' :- -' __ T ____ l -- - r 

I I ' • I 

-... -- -- i I --- : . ! 

i 

I 

I 

i 

I 

, .. 

i 

20 30 40 50 60 70 80 

- - -f1 

I 

90 

____ J 

95 

Per of Sanp1es Equal 'lb Or less Than Ordinate Value 

132 

J 

I 

i I. 

98 99 
Figure 12 represents a cumulative plat of the combined data base. 

A slight modification was made to the analysis . procedure 

described for the offshore data. In order to have the data form 

a straight line over the entire range, rather than the upper 80-

90% of the range, a constant is added to each data point so that 

log (X+A) is plotted rather than log x. Since the affect of the 

constant A is more pronounced for smaller values of X the result 

is a straight line fit over the total range of data. once the 

99th percentile is determined for the distribution of X+A the 

constant is subtracted and the resulting value is the best fit to 

the distribution of X; this methcd is called the three parameter 

log normal analysis. 

Sanitary wastes -- Offshore and coastal Manned Facilities With 10 

or More People 

BPCT for sanitary wastes from offshore manned facilities with 10 

or more people is based on end-of-pipe technology consisting of 

biological waste treatment systems (extended aeration). The 

system may include a comminutor, aeration tank, gravity 

clarifier, return sludge system, and disinfection contact chamber 

or other equivalent system. Studies of treatability, operational 

performance, and flow fluctuations are required prior to 

application of a specific treatment system to an individual 

facility. 

The effluent limitations were based on effluent data provided by 

industry to the u.s. Geological Survey. Chlorine residual, BOD, 

and suspended solids concentrations for the biological treatment 

systems were within the range of values which would meet fecal 

coliform requirements. 

The only limitation being set on sanitary wastes is for chlorine 

residual. This requirement is set to control the fecal coliform 

level in this effluent. Limits on BOD or suspended solids for 

these wastes are not justified since the BOD and 'I'SS content of 

the produced waters are likely to be several hundred times 

greater. 

The limit for residual chlorine is greater than 1 mg/1, but as 

close to 1 mg/1 as possible. The facilities for chlorination on 

offshore platforms are much less sophisticated then typical 

municipal treatment plants and the flows much more variable. 

Therefore, it is felt that the standard residual chlorine limit 

of 1 mg/1 plus or minus 40 I is unrealistic. There has been no 

upper limit set because of a lack of valid data to be used to set 

such a limit. 

BPCT for sanitary wastes from small offshore facilities and 

intermittently manned facilities is based on end-of-pipe 

technology currently used by the oil and gas production industry 

and by the boating industry. These devices are physical and 

133 
..... 

......... 

en 

E 

z 

0 

-I-

~ Iz 

LLJ 

(..) 

z 

0 

(..) 

LLJ 

V') 

ex: 

LLJ 

0::: 

tD 

~ 

_,j 

-

0 

100 

90 

80 

70 

60 

50 

40 

30 

20 

lf 

8 

7 

6 

5 

4 

3 

2 

/ 

,/ 

-

• 

/ 

/ / 

L v· 

! I v /I 

vv 

/ • I 

/ .. v 

. ../ -

Ia y/' --1---· 

/ v 

~ 

v 

/ 

v. 

/ 

v.· 

• 

• 

10 20 30 40 50 60 70 80 9() 

PERCENT OF SAMPLES EQUAL TO OR LESS THAN ORDINATE VALUE 

Fig.12- Cumulative Plot of Effluent Concentrations 

of All Wyoming Data (values are plotted as X·+ 1.3) 

134 

. 95 98 99 
chemical systems which may include chemical toilets, gas fired 

incinerators, electric incinerators or macerator-chlorinators. 

None of these systems bas proved totally adequate. Therefore, 

the effluent limitations are based on the discharge technology 

which consists of a macerator-chlorinator. For coastal and 

estuarine areas where stringent water quality standards are 

applicable, a higher level of waste treatment may be required. 

The attainable level of treatment provided by BPCT is the 

reduction of waste such that there will be no floating solids. 

Domestic Wastes - Offshore and coastal 

Since these wastes contain no fecal coliform, chlorination is 

unnecessary. Treatment, such as the use of macerators, is 

required to guarantee that this discharge will not result in any 

floating solids. 

Deck Drainage - Offshore and coastal 

BPCT for decK drainage is based on control practices used within 

the oil producing industry and include the following: 

1. Installation of oil separator tanks for collection of deck 

washings. 

2. Minimizing of dumping of lubricating oils 

from leaks, drips and minor spillages 

collection systems. 

and 

to 

oily wastes 

deck drainage 

3. Segregation of deck washings from drilling and workover 

operations. 

4. O&M practices to remove all of the wastes possible prior to 

deck washings. 

BPCT end-of-pipe treatment technology for deck drainage consists 

of treating this water with waste waters associated with oil and 

gas production. The combined systems may include pretreatment 

(solids removal and gravity separation) and further oil removal 

(chemical feed, surge tanks, gas flotation). The system should 

be used only to treat polluted waters. All storm water and deck 

washings from platform members containing no oily waste should be 

segregated as it increases the hydraulic loading on the treatment 

unit. 

The limits for deck drainage are the same as for produced waters 

offshore. 

135 
Alternate Handling - Offshore and coastal 

Alternate handling of waste water may be necessary when equipment 

becomes inoperative or requires maintenance. Waste fluids must 

be controlled during these conditions to prevent discharges of 

raw wastes into surface waters. Control practices currently used 

in offshore and coastal operations are: 

1. waste fluids are temporarily stored onboard until the waste 

treatment unit returns to operation. 

2. Waste fluids are directed to onshore treatment facilities 

through a pipeline. 

3. Placing waste fluids in a barge for transfer to shore 

treatment. 

4. Waste fluids are piped to a primary treatment unit (gravity 

separation) to remove free oil and discharged to surface 

waters. 

Drilling Muds 

BPCT for drilling muds includes control practices widely used in 

both offshore and onshore drilling operations: 

1. Accessory circulating equipment such as shaleshakers, 

agitators, desanders, desilters, mud centrifuges, degassers, 

and mud handling equipment. 

2. Mud saving and housekeeping equipment such as pipe and kelly 

wipers, mud saver sub, drill pipe pan, rotary table catch 

pan, and mud saver box. 

3. Recycling of oil based muds. 

BPCT end-of-pipe treatment technology is based on existing waste 

treatment processes currently used by the oil industry in 

drilling operations. 

The limitations for offshore and coastal drilling muds are as 

follows: 

1. water based and natural muds shall contain no free oil when 

discharged. 

2. oil based and emulsion muds shall not be discharged to 

surface waters. These muds are to be transported to shore 

for reuse or disposal in an approved disposal site. 

136 
The limitations for onshore drilling muds are as follows: 

1. The muds shall be discharged to surface waters. These muds 

are to be transported to and disposed of in an ap~roved 

disposal site. 

Drill Cuttings 

BPCT for drill cutt~ngs is based on existing treatment and 

disposal methods used by the oil industry. 

The limitations for offshore drill cuttings are as fo~lows: 

1. Cuttings in natural or water cased muds shall contain no free 

oil when ~scharged. 

2. cuttings in oil based or emu~sion muds shall not be 

discharged to surface waters. cuttings should be collected 

and transported to shore for disposal in an a~proved disposal 

site. 

The limitation for onshore drill cuttings areas follows: 

1. No drill cuttings shall be discharged to surface waters. 

These drill cuttings are to be transported to and disposed of 

in an approved disposal site. 

Well Treatment 

Workover fluids other than water, or water based muds are to be 

recovered and reused. Materials not consumed during workovers 

and completions are to be transported to and disposed of in an 

approved site. 

The effluent limitations were determined using data supplied by 

~ndustry and service companies serving the oil producing 

industry. The limitation for wastes from well treatment offshore 

is: well treatment wastes shall contain no free oil when 

discharged. 

137 
section IX 

Bibliography 

1. Offshore Operators Oommitteer Sheen Technical Subcommittee. 

1974. "Determination of Best Practicable Control Technology 

currently Availa~le to Remove Oi~ From Water Produced With 

Oil and Gas. 11 Prepared by Brown and Rootr Inc. r Houstonr 

Texas. 

138 
SECTION X 

EFFLUENT LIMI~·ATIONS FOR 

BEST AVAILABLE TECHNOLOGY ECONOMICALLY ACHIEVABLE 

The application of best availa~le technology economically 

achievable is defined as improved O&M practices and tighter 

control of the treatment process for the far offshore 

subcategory. BATEA for the near offshore and coastal 

subcategories are defined as subsurface disposal for produced 

waters. BATEA for the onshore, beneficial use, and stripper 

subcategories are the same as BPTCA. These effluent limitations 

are to go into effect no later than July 1, 1983. 

The limitations for all subcategories are the same as BPTCA for 

drilling muds, drill cuttings, sanitary and domestic wastes, well 

treatment, and produced sands. Additionally the BATEA limitation 

for deck drainage in the near offshore subcategory is the same as 

for BP'ICA. 

Near Offshore and Coastal Subcategories - Produced Water 

The BATEA limitations for produced water in the coastal and near 

offshore subcategories is no discharge to surface waters. This 

can be accomplished ty reinjection or by end-of-pipe technologies 

such as, evaporation ponds and holding pits (when ·wastes are 

transferred to shore) or injection to disposal wells. About 401 

of those producing facilities with no discharge use one of these 

end-of-pipe technologies. 

Existing no discharge systems were reviewed to select the best 

technology for the purpose of esta~lishing effluent limitations. 

Holding pits were found to be the least desirable because of 

frequent overflow, dike failure, and infiltration of salt water 

into fresh water aquifiers. If properly constructed and lined, 

evaporation lagoons may result in no discharge in arid and 

semiarid regions. However, erosion, flooding, and overflow may 

·still occur during wet weather. £isposal well systems which may 

consist of skim tanks, aeration facilities, filtering systems, 

backwash holding facilities, clear water accumulators, pumps, and 

wells provide the best method for disposal of produced water. 

These systems are equally applicable to onshore and offshore 

operations and are the primary method used to dispose of produced 

water on the California coast and in the inland areas. 

Far Offshore Subcategory - Produced Water and Deck Drainage 

The BATEA limitations for produced water and deck drainage in the 

far offshore subcategory are based on the same end-of-pipe 

technology as used for BPTCA. It is expected that the industry 

will have gained sufficient experience in the reduction of raw 

waste loads and operation of end-of-pipe technologies to improve 

139 
their operation by 1983. In order to define this level of 

discharge a statistical analysis was carried out on the data from 

the 27 flotation units, used to define BPTCA, tQ determine if any 

units were significantly better in effluent quality than the 

rest. A group of 10 flotation units were separated on that basis 

and their data analyzed. The resulting BATEA limitations for oil 

and grease are, 52 mg/1 daily maximum (composited) and 30 mg/1 

maximum monthly average. Figure 13 is a cumulative plot of the 

effluent concentrations of these 10 selected flotation units. 

When the BPTCA limitations were derived, it was concluded that 

they should be based on what was being achieved by all facilities 

using the BPTCA. 

This conclusion was reached on the basis of industry experience. 

Since the industry will have, by 1983, 8 additional years of 

experience . in waste abatement, there should be no significant 

problems in atta~ning effluent qualities now being met by many 

facilities. 

140 
100 

90 

80 

70 

60 

50 

40 

30 

20 

10 

9 

8 

7 

6 

5 

4 

3 

2 

• 

• / 

A 

/. 

/. /-

• 

v ~ 

• 

../ ~ ---

v ~ v y ~ _/ --

•7 v ,..---- ---- -~~-- -- ---- ---- ------ -- ---- f-------f----

/.. v 

_/ v 

/ ... 

.. 

2 5 

--

10 20 30 40 50 60 70 80 90 95 98 99 

PERCENT OF SAMPLES EQUAL TO OR LESS THAN ORDINATE VALUE 

Fig. 13-Cumulative Plot of Effluent Concentrations 

of Ten Selected Flotation Units in the 

Louisiana Gulf Coast Area 

141 

" 

1.-

/ 

99.8 
SECTION XI 

NEW SOURCE PERFORMANCE STMDARDS 

The effluent limitations for new source performance standards are 

the same as the BA~EA limitations for each subcategory. The 

facilities defined here will be built after this regulation is in 

affect. These facilities should therefore, be built with raw 

waste load reduction and waste treatability in mind. As a 

result, the number and magnitude of ooth preventable and 

unpreventable wastes should be minimized. 

143 
SECTION XII 

ACKNOWLEDGEMENTS 

The initial draft report was prepared by the special Oil Extract~on Task Force which EPA Headquarters estab~ished to study 

the oil and gas extraction point source category. 

The following members of the Task Force furnished technical 

support and legal advice for the study: Russel H. Wyer, Oil and s~ecial Materials Control Division (OSMCD), co-chairman; H. D. 

VanCleave, OSMCD, Co-Chairman; William Bye, OSMCD; Thomas 

Charlton, OSMCD; Harold Snyder, OSMCD; Kenneth Adams, OSMCD; Hans 

Crump-Weisner, OSMCD; Arthur Jenke, OSMCD; R. w. Thieme, Office 

of Enforcement and General counsel; Jeffrey Howard, Office of 

Enforcement and General counsel; Charles Cook, Office of water 

Planning and Standards; Martin Halper, Effluent Guidelines 

Division; Dennis Tirpak, Office of Research and Develo~ment; 

Thomas Belk, Fermit Programs Division; Richard Insinga, Office of 

Planning and Evaluation; stephen Dorrler, Edison Water Quality 

Research Laboratory, Edison, N.J. 

Martin Halper, Project Officer, Effluent Guidelines Division, 

contributed to the overall supervision of this study and perpared 

this Development Document. Allen Cywin, Director; Ernst Hall, 

Deputy Director; Harold Coughlin, Branch Chief, and John 

cunningham, all Effluent Guidelines Division, offered guidance 

during th~s program. 

Special appreciation is given to Mary Lou Ameling, Charles cook, 

Richard Insinga, and Henry Garson for their contributions to this 

effort. 

In addition to the Headquarters EPA personnel, Regions V, VI, and 

X were extremely helpful in support~g this study. Special 

acknowledgement is made to personnel of the surveillance and 

Analysis Division, Region VI, for their dedicated effort in 

support of the EPA Field Verification Study, and to Russ 

Diefenbach of Region V who assisted with data acquisition for 

onshore technology. Regions IV and VIII assisted in onshore data 

acquisition. 

Special appreciation is extended to the EPA Robert s. Kerr 

Research Laboratory (RSKRL), Ada, Oklahoma, for its technical 

support. RSKRL managed and conducted the entire analytical study 

phase for field verification in Coastal Louisiana, Texas, and 

California. 

Special recognition is due EPA Edison Water Quality Research 

Laboratory, Edison, New Jersey, for its participation in field 

studies of oil and gas operations and its review of 

145 
contractor-operated analytical laboratories in the Gulf coast 

area. 

Acknowledgement is made to Richard Krahl, Robert Evans, and Lloyd 

Hamons, Department of the Interior, u.s. Geological Survey, for 

their contribution to the EPA Field Verification Study in the 

coastal Louisiana area. 

Many state offices assisted in the study by providing data and 

assisting in field studies. Among those contributing: Alabama, 

Arizona, Arkansas, California, Colorado, Florida, Illinois, 

Louisiana, Missouri, Nebraska, Nevada, New Mexico, North Dakota, 

Ohio, Pennsylvania, Utah, and Wyoming. 

Our special thanks to Mrs. Irene Kiefer for her editorial 

services. Appreciation is extended to the secretarial staffs of 

the Oil and Special Materials control Division and the Effluent 

Guidelines Division for their efforts in typing many drafts and 

revisions to this report. 

Appreciation is extended to the following trade associations and 

corporations for their assistance and cooperation: American Oil 

company; American Petroleum Institute, Onshore Technical 

Committee, Seth Abbott, Chairman; Ashland Oil, Inc.; Atlantic 

Richfield company; Brown and Root, Inc.; c. E. Natco; Champlin 

Petroleum company; Chevron Oil Company; Continental Oil Company; 

Exxon Oil company; Gulf Oil Company; Marathon Oil company; Mobil 

Oil Company; Noble Drilling company; Offshore Operators 

committee, Sheen Technical sutcommittee, William M. Berry, 

Chairman; Oil Operators, Inc.; Phillips Petroleum; Pollution 

control Engineers; Rbeem superior; Shell Oil company; Sun Oil 

com~any; Texaco, Inc.; Tretolite Corporation; United States 

Filters; Union Filter company; and WEMCO. 

146 
SECTION XIII 

GLOSSARY AND ABBREVIATIONS 

Acidize To put acid in a well to dissolve limestone in a 

producing zone, forming passages through which oil or gas can 

enter the well bore. 

Air/Gas Lift - Lifting of liquids by injection of air or gas 

directly into the well. 

Annulus ~ Annular Space - The space between the drill stem and 

the wall of the hole or casing. 

API - American Petroleum Institute. 

~ Gravity - Gravity (weight per unit of volume) of crude oil as 

measured by a system recommended by the API. 

Attapulgite Clay - A colloidial, viscosity-build~ng clay used 

principally in salt water muds. Attapulgite, a special 

fullers earth, is a hydrous magnesium aluminum silicate. 

Back Pressure - Pressure resulting from restriction of full 

----natural flow of oil or gas. 

Barite 

mud. 

Barium sulfate. An additive used to weight drilling 

Barite Recovery Unit {Mud centrifuge} - A means of removing less 

dense drilled solids from weighted drilling mud to conserve 

barite and maintain proper mud weight. 

Barrel - 42 United States gallons at 60 degrees Fahrenheit. 

Bentonite - An additive used to increase viscosity of drilling 

mud. 

Blowcase - A pressure vessel used to propel fluids intermittently 

by pneumatic pressure. 

Blowout A wild and uncontrolled flow of subsurface formation 

fluids to the earth's surface. 

Blowout Preventer (BOP) - A device to control formation pressures 

in a well by closing the annulus when pipe ~s suspended in 

the well or by closing the top of the casing at other times. 

Bottom-Hole Pressure - Pressure at the bottom of a well. 

Brackish water water containing low concentrations of any 

soluble salts. 

147 
Brine - Water saturated with or containing a high concentration 

of common salt (sodium chloride) : also any strong saline 

solution containing such other salts as calcium chloride, 

zinc chloride, calcium nitrate. 

BS&W Bottom Sediment and water carried 

Generally, pipeline regulations limit BS&W to 

the volume of oil. 

with the 

1 percent 

oil. 

of 

Casing - Large steel pipe used to 11 seal off 11 or 11 shut out11 water 

and prevent caving of loose gravel formations when drilling a 

well. When the casings are set, drilling continues through 

and telow the casing with a smaller bit. The overall length 

of this casing is called the string of casing. More than one 

string inside the other xnay be used in drilling the same 

well. 

Centrifuge A device for the mechanical separation of solids 

from a liquid. usually used on weighted muds to recover the 

mud and d~scard solids. 'Ihe centrifuge uses high-speed 

mechanical rotation to achieve this separation as 

distinguished from the cyclone-type separator in which the 

fluid energy alone provides the separating force. Also see 

"Desander - Cyclone." 

Chemical-Electrical Treater A vessel which utilizes 

surfactants, other chemicals and an electrical field to break 

oil-water emulsions. 

Choke - A device with either a fixed or variable aperture used to 

release the flow of well fluids under controlled pressure. 

Christmas Tree - Assembly of fittings and valves at the top of 

the casing of an oil well that controls the flow of oil from 

the well. 

Circulate - The movement of fluid from the suction pit through 

pump, drill pipe, bit annular space in the hole and back 

again to the suction pit. 

Closed-In A well capable of producing oil or gas, but 

temporarily not producing. 

coagulation The combination or aggregation of semi-solid 

particles such as fats or froteins to form a clot or mass. 

This can be brought about by addition of appropriate 

electrolytes. Mechanical agitation and removal of stabiliz~ng ~ons, as ~n dialysis, also cause coagulation. 

Coalescence The 

form a larger 

union of two or more droplets of a liquin to 

droplet, brought about when the droplets 

148 
approach one another close-by enough to overcome their 

individual surface tensions. 

condensate - Hydrocarbons which are in the gaseous 

reservoir conditions but which become liquid 

passage up the hole or at the surface. 

state under 

either in 

connate Water - Water that probably was laid down and entrapped 

with sedimentary deposits as distinguished from migratory 

waters that have flowed into deposits after they were laid 

down. 

Crude Oil A mixture of hydrocarbons that existed in liquid 

phase in natural underground reservoirs and remains liquid at 

atmospheric pressure after passing through surface separating 

facilities. 

cut Oil - Oil that contains water, also called wet oil. 

cuttings - Small pieces of formation that are the result of the 

chipping and/or crushing action of the bit. 

Derrick and Substructure Combined foundation 

structure to provide for hoisting and lowering 

drilling. 

and overhead 

necessary to 

Desander Cyclone Equipment, usually cyclone 

removing drilled sand from tne drill~ng mud stream 

produced fluids. 

type, 

and 

for 

from 

Desilter Equipment, normally cyclone type, for removing 

extremely fine drilled solids from the drill~ng mud stream. 

Development Well A well drilled for production from an 

established field or reservoir. 

D~sposal Well - A well through which water (usually salt water) 

is returned to subsurface formations. 

Drill Pipe - Special pipe designed to withstand the torsion and 

tension loads encountered in drilling. 

Drilling Mud A suspens~on, generally aqueous, used in rotary 

drilling to clean and condition the hole and to 

counterbalance formation fressure; consists of various 

substances in a finely divided state, among which bentonite 

and barite are most common. 

~ Valve - A mechanically or pneumatically operated valve used 

on separators, treaters, and other vessels for the purpose of 

draining, or "dumping•• a batch or oil or water. 

149 
Emulsion - A substantially permanent heterogenous mixture of two 

or more liquids which are not normally dissolved in each 

other, but which are held in suspension or dispersion, one in 

the other, by mechanical agitation or, more frequently, by 

adding small amounts of su~stances known as emulsifiers. 

Emulsions may be oil-in-water, or water-in-oil. 

EPA - Un~ted States Environmental Protection Agency. 

Field - The area around a group of producing wells. 

Flocculat~on - The combination or aggregation of suspended solid 

particles in such a way that they form small clumps or tufts 

resembling wool. 

Flowing well - A well which produces oil or gas without any means 

of artificial lift. 

Fluid Injection - Injection of gases or liquids into a 

to force oil toward and into producing wells. 

"Water Flooding • 11 ) 

reservoir 

(See also 

Formation - Various subsurface geological strata penetrated by a 

well bore. 

Formation Damaqe - Damage to the froductivity of a well resulting 

from invasion of mud particles into the formation. 

Fracturing - Application of excessive hydrostat~c pressure which 

fractures the well bore (causing lost circulation of drilling 

fluids.) 

Freewater Knockout - An oil/water separation tank at atmospheric 

pressure. 

~ Lift - A means of stimulating flow by aerating a fluid column 

with compressed gas. 

Gas-Oil Ratio Number of cubic feet of gas produced with a --- barrel of oil. 

Gathering Line - A pipeline, usually of small diameter, used in 

gathering crude oil from the oil field to a point on a main 

pipeline. 

Gun Barrel - An oil-water separation vessel. 

Header - A section of pipe into which several sources, of oil 

such as well streams, are combined. 

Heater-Treater 

heat. 

A vessel used to break oil water emulsion with 

150 
Hydrogen Ion Concentration A measure of the acidity or 

alkalinity of a solution, nor~ally expressed as pH. 

Hydrostatic He~d - Pressure which exists in the well bore due to 

the weight of the column of drilling fluid; expressed in 

pounds per square inch (psi). 

Inhibitor An additive which prevents or retards undesirable 

changes in the product. Particularly, oxidation and 

corrosion; and sometimes paraffin formation. 

Invert Oil jEmulsion Mud) - A water-in-oil 

or salt water is in dispersed phase and 

some other oil is the continuous phase. 

viscosity and oil reduces the viscosity. 

emulsion where fresh 

diesel, crude, or 

Water increases the 

Kill ~ Well - To overcome pressure in a well by use of mud or 

water so that surface pressures are neutralized. 

Location (Drill Site} 

been drilled. 

Place at which a well is to be or has 

Mud Pit - A steel or earthen tank which is part of the surface 

drill~ng mud system. 

Mud Pump A reciprocating, high pressure pump used for 

circulating drilling mud. 

Multiple complet~on A well completion which provides for 

simultaneous production from separate zones. 

ocs - Outer Continental Shelf. 

Offshore - In this context, the submerged lands between shoreline 

and the edge of the continental shelf. 

OHM - Oil and Hazardous Material. 

Oil Well - A well completed for the production of crude oil from 

at least one oil zone or reservoir. 

Onshore - Dry land, inland bodies and bays, and tidal zone. 

OSMCD - Oil and Special Materials Control Division. 

Paraffin - A heavy hydrocarbon sludge from crude oil. 

Permeability - A measure of ability of rock to transmit a 

one-phase fluid under condition of laminar flow. 

151 
Pressure Maintenance The amount of water or gas injected vs. 

the oil and gas production so that the reservoir pressure is 

maintained at a desired level. 

Pump, Centrifugal - A pump whose propulsive effort is effectuated 

by a rapidly turning impeller. 

Rank Wildcat - An exploratory well drilled in an area far enough 

removed from previously drilled wells to preclude 

extrapolation of expected hole conditions. 

Reservoir Each separate, unconnected body of producing 

formation. 

Rotary Drilling - 'I'he method of drilling wells that depends on 

the rotation of a column of drill pipe with a bit at the 

bottom. A fluid is circulated to remove the cuttings. 

Sand - A loose granular material, most often silica, resulting 

from the disintegration of rocks. 

Se~rator - A vessel used to separate oil and gas by gravity. 

Shale - Fine-grained clay rock with slatelike cleavage, sometimes 

containing an o~l-yielding substance. 

Shaleshaker Mechanical vibrating screen to separate drilled 

formation cuttings carried to the surface with drilling mud. 

Shut In - To close valves on a well so that it stops producing; 

said of a well on which the valves are closed. 

Skimmer A settling tank in which oil is permitted to rise to 

the top of the water and is then taken off. 

Stripper Well 'Marginal Well) - A well which produces such a 

small volume of oil that the gross income therefrom provides 

only a small margin of profit or, ~n many cases, does not 

even cover actual cost of production. 

Stripping Adding or removing pipe when a well is pressured 

without allowing vertical flow at the top of the well. 

Tank - A bolted or welded atmospheric pressure container designed 

for receipt, storage, and discharge of oil or other liquid. 

Tank Battery - A group of tanks to which crude oil flows from 

producing wells. 

1Q§ - Total Disolved Solids. 

TOC - Total Organic Carbon. 

152 
Total Depth (T.D.) - The greatest depth reached by the drill bit. 

Treater - Equipment used to break an oil - water emulsion. 

TSS - Total suspended Solids. 

USCG - United States coast Guard. 

Y§§2 - United States Geological survey. 

Water Flooding water is injected under pressure into the 

formation via injection wells and the oil is displaced toward 

the producing wells. 

Well Completion - In a potentially productive formation, the 

completion of a well in a manner to permit production of oil; 

the walls of the hole above the producing layer (and within 

it if necessary) must be supported against collapse and the 

entry into the well of fluids from formations other than the ~roducing layer must be prevented. A string of casing is 

always run and cemented, at least to the top of the producing 

layer, for this purpose. some geological formations require 

the use of additional techniques to "complete" a well such as 

casing the producing formation and using a "gun perforator" 

to make entry holes, the use of slotted pipes, consolidating 

sand layers with chemical treatment, and the use of 

surface-actuated underwater robots for offshore wells. 

Well Head - Equipment used at the top of a well, including casing 

head, tubing head, hangers, and the Christmas Tree. 

Wildcat well A well drilled to test formations nonproductive 

within a 1-mile radius of previously drilled wells. It is 

expected that probable hole conditions can be extrapolated 

from previous drilling experience data from that general 

area. 

Wiper, Fipe-Kell~ - A disc-shaped device with a center hole used 

to wipe off mud, oil or other li~uid from drill pipe or 

tubing as it is pulled out of a well. 

Work Over - To clean out or otherwise work on a well in order to 

increase or restore production. 

Work ~ Fluid Any type of fluid used in the workover 

operation of a well. 

153 
MULTIPLY (ENGLISH UNITS) 

TABLE 41 

METRIC TABLE 

CONVERSION TABLE 

by TO OBTAIN (METRIC UNITS) 

ENGLISH UNIT ABBREVIATION CONVERSION ABBREVIATION ~1ETRIC UNIT 

acre ac 0.405 ha hectares 

acre - feet ac ft 1233.5 cu m cubic meters 

British Thermal 

Unit BTU 0.252 kg cal kilogram - calories 

British Thermal 

Unit/pound BTU/lb 0.555 kg cal/kg kilogram calories/kilogram cubic feet/minute cfm 0.028 cu m/min cubic meters/minute 

cubic feet/second cfs 1.7 cum/min cubic meters/minute 

cubic feet cu ft 0.028 cu m cubic meters 

cubic feet cu ft 28.32 1 1 i ters 

cubic inches cu in 16.39 cu em cubic centimeters 

degree Fahrenheit Of 0.555(°F-32)* oc degree Centigrade feet ft 0.3048 m meters 

ga 11 on gal 3.785 1 1 i ters 

gallon/minute gpm 0.0631 1/sec liters/second 

horsepower hp 0.7457 kw killowatts 

inches in 2.54 em centimeters 

inches of mercury in Hg 0.03342 atm atmospheres 

pounds lb 0.454 kg kilograms 

million gallons/day mgd 3,785 cu m/day cubic meters/day 

mile mi 1.609 km kilometer 

pound/square inch (gauge) psig (0.06805 psig +1)* atm atmospheres (absolute) 

square feet sq ft 0.0929 sq m square meters 

square inches sq in 6.452 sq em square centimeters 

ton (short) ton 0.907 kkg metric ton (1000 kilograms) 

yard yd 0.9144 m meter 

* Actual conversion, not a multiplier 

154