## EPA 440/1-76/055-a Group 

## II 

# DevelopmentDocumentforInterim FinalEffuentLimitationsGuidelines and ProposedNewSourcePerformance Standardsforthe


# OIL& 

# GASEXTRACTION

PointSourceCategory

UNITED STATES ENVIRONMENTAL PROTECTION AGENCY SEPTEMBER 1976

### DEVELOPMENTDOCUMENT for INTERIMFINAL EFFLUENTLIMITATIONS GUIDELINES and PROPOSEDNEWSOURCEPERFORMANCESTANDARDS forthe OILANDGAS EXTRACTION

POINTSOURCECATEGORY

Russell E. 

### Train Administrator
AndrewW. Breidenbach AssistantAdministratorfor WaterandHazardousMaterials EckardtC. Beck DeputyAssistantAdministratorfor WaterPlanningand Standards

RobertB. Schaffer Director, EffluentGuidelines Division
Martin Halper ProjectOfficer September, 1976 

### EffluentGuidelines Division OfficeofWaterandHazardousMaterials

U.S. Environmental ProtectionAgency Washington, D. C. 20460ABSTRACT Thisdevelopment document presents the findings of an extensive study of theOil andGasExtraction Industryfor 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 developedfor the Oil andGas Extraction Industry, which was**div~ded** into 6 subcategories. Effluent limitations guidelines contained herein set forth the degree of effluentreduction 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 availabletechnology economically achievable (BATEA) which must be achieved 

### by existing point sources**~Y** July 1, 1977 andJuly 1, 1983, respectively. The new source performance standards (NSPS) contained herein set forth the degreeof effluent reduction which areachievablethrough the application of the best available demonstrated control technology, processes, operating methods, or otheralternatives.**Suppor~ng** data andrationale for the development of proposed effluent**1imitat~ons** guidelines and standards of performance are contained in this**develo~ment** document.

iSection

I II III

IV



### v

VI TABLE OF CONTENTS
ABSTRACT CONCLUSIONS RECOMMENDATIONS IN'I'RODUCTION Purpose andAuthority General Descriptionof Industry Industry Distribution Industry Growth Bibliography INDUSTRY SUBCATEGORIZATION Rationaleof Subcategorization Developmentof Subcategories Descriptionof subcategories Bibliography WASTE CHARACTERISTICS waste Constituents Bibliography SELECTION OF POLLUTANT PARAMETERS Parameters for EffluentLimitations 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-plantControl/Treatment Techniques 65 Analytical Techniques andField 

### 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 ProducedWater 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

- Producedwater 

### 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

### TableNo. 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 EffluentLimitation

- BATEA and New Source 

## u.s. Supply andDemand ofPetroleum andNaturalGas 

## u.s. Offshore Oil Production**Po~lutants** 

### in

### ProducedWater, LouisianaCoastal**Pol~utants** 

### containedinProducedWater, coastalCalifornia Range of constituents inProduced FormationWater--OffshoreTexas Rangeofconstituents in

### Produced FormationWater--Onshore**Ca~ifornia** 

### Range of COnstituents inProduced FormationWater--wyoming Rangeof COnstituents inProduced FormationWater--Pennsylvania Range of constituents inProduced FormationWater--Onshore Louisiana Rangeof Constituents in

### Produced Formationwater--OnshoreTexas Volume of Cuttings andMuds in 

### Typical 10,000Foot**Dril~ing** 

### Operation TypicalRaw combinedSanitaryand DomesticWastes from OffshoreFacilities Effluent**Qualit~** 

### Requirementsfor ocean Waters ofCalifornia Effectof**Acidif~cation** 

### onOil andGreaseData Oil and GreaseData, 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 DesignRequirements for Offshore Sanitary wastes Average Effluents of SanitaryTreatment 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, 1,000Barrels Per Day Flow Rate Formation Water Treatment Equipment costs, Offshore Installation, 5,000 Barrels Per Day FlowRate 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 Fieldsurveys in Se.lected States

viii 73


### 74 75

84

84


### 99
99 

### 106 107

108

109

110



### 111

113

### TableNo. Title Page No. 33 

### Annual Operating cost for onshore Disposal 

### 114 byReinjection of ProducedFormationWater From Field surveys in 

### SelectedStates 34 

### costEstimates for Treatmentin 

### Ponds and 

### 115 Disposal by Discharge for StripperWell Facilities 35 

### cost Estimates for**~reatment** 

### by Gas 

### 116 Flotationand Pond and Discharge for BeneficialDischargers 36 

### costEstimates for TreatmentbyGas 

### 116 Flotation and Discharge for coastal Platforms 31 

### EstimatedTreatment Plant Costs for 

### 119 SanitaryWastes for OffshoreLocations Package ExtendedAerationProcess 38 

### EstimatedHorsepowerRequirements for the 

### 120 Operationof Flotation Treatment Systems 39 

### EstimatedIncrementalEnergyRequirements, 

### 121 Flotation systems 40 

### EnergyRequirements forFlotation Systems 

### 122 as Comparedto Net Energy Production Associatedwiththe ProducedwaterFlows 

### 41 

### ConversionTable 154

ix

### Fi9:ureNo. 1 2

3

4 5 6

7

8

9

10

11

13 

### LIST OF FIGURES Title Rotary DrillingRig 

### Shale Shaker and Blowout Preventer Central Treatment Facility in EstuarineArea Horizontal Gas Separator Vertical Heater-Treater Rotor-Disperser andLissolvedGas FlotationProcesses for Treatment of ProducedWater OnshoreProductionFacilitywith Discharge to surfacewaters TypicalCross SectionUnlined Earthern Oil-Water Fit Typicalcompletion of anInjection Well and a ProducingWell 99thPercentile of MonthlyAverage Oil andGreaseconcentrationvs. Frequency of SamplingEachMonth Cumulative Plot Effluent Concentrations of all SelectedFlotationUnits inthe LouisianaGulf CoastArea CumulativePlot ofEffluentConcentrations of all Wyoming Data cumulativePlot of Effluentconcentrations of '!'en SelectedFlotationUnits in

### the LouisianaGulf coastArea

xi 

### PageNo. 

### 10 11


### 15
16 18 

### 77

86
87


### 90


### 131

132

134
141SECTION I CONCLUSIONS**Th~s** study covered the waste treatmenttechnology for the Oil and Gas ExtractionPoint Source Category. The Oil and Gas Extraction Point Source category covers the pollutants**ar~s~ng** from the production of crudepetroleum 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 producedwater, drilling muds, drill cuttings, well treatment, and produced sands for all subcategories and additionally, deck drainage, sanitary and domesticwastes 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 isbasedon a balanceof the costs with the potential environmental benefits and energy use (loss)• The subcategories developed for theoil 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. BeneficialUse

6. Stripper Operations Included All facilities within offshore State waters. All facilities inFederal 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 andgrease, fecal coliform, oxygen demanding parameters, heavy metals, total dissolved solids, and toxic materials. These wastewater constituentswere selected to 

### be the subjectof the effluent limitations. Effluent limitations commensurate with the best practicable control technology currently available are promulgated interim final for each sutcategory. These limitations, listedin Table 1 are explicit numericalvalues (whenever possible) or some other criteria. BPCTCA end-of-pipe technology is 

### basedonthe 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 wastewater treatment systemhas 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 limitationsare listed**~n** 

### Table 2. 

### The primary end-of-pipe treatment for the near offshore subcategory is the subsurface disposal of productionwater and for the far offshore subcategory it is 

### similar to that for BFCTCA. New source performance standards commensurate with thebest available demonstrated technology are the same as the BATEA limitations. These effluent limitations are listed inTable 2.

3**~** 

### Subcategory

A. Near Offshore B. FarOffshore D. 

### Coastal

C. Onshore E. Beneficial Use

Notes: TABLE 1 Oil and Gas Extraction Industry

EffluentLimitations

- BPCTCA WaterSource

producedwater deck drainage drillingmuds dri11 

### cuttings well treatment sanitaryMlO M9IMc domesticc produced sand producedwater dri11ingmuds drillcuttings well treatment produced sand Oil 

## &Grease

- mg/1 Maximumfor anyone day

72 72



### a a a N/A N/A N/A a
e Average ofdaily valuesforthirty consecutivedays sha11 

### notexceed 48d 48d 

### a a a 

### N/A N/A N/A a 

### N/A no discharge no discharge no discharge no discharge

a - No dischargeoffreeoil tothe surfacewaters. b - Minimumofl mg/1 andmaintained as closetothisconcentration as possible. c - There shall be nofloatingsolids as aresultofthedischargeofthesematerials. d - Not applicable to thecoastal subcategory. Residual Chlorine

- mg/1

N/A N/A N/A N/A N/A greaterthan 1b N/A N/A N/A N/A

e- Fortheonshore subcategory- no discharge; for thebeneficial use subcategory- 45mg/1.U'l 

### TABLE 2 Oil andGas Extraction Industry EffluentLimitations

- BATEAandNewSource PollutantParameter- EffluentLimitations Subcategory WaterSource Oil 

## &Grease

- mg/1 Maximumfor Averageofdaily anxone dax values forthirty consecutivedays shall notexceed A. NearOffshore producedwater No discharge D. Coastal deckdrainage 72 48 

### B. FarOffshore producedwater 52 

### 30 deckdrainage 52 

### 30 A. NearOffshore drillingmuds a a B. FarOffshore drill cuttings a a C. Onshore well treatment a a D. Coastal sanitaryM10 N/A N/A E. Beneficial Use M9IM N/A N/A domestic N/A N/A produced sand a a Notes:
a - TheseBATandNewSourcelimitations are identical tothose applicableforeach subcategoryas forBPTlistedin Table 1. Residual Chlorine

-mg/1

N/A N/A N/A N/A N/A N/A greaterthan 1 N/A N/A N/ASEC'IION III INTRODUC'IION Purpose andAuthority 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 thanpublicly owned treatment works. The limitations are to be based on applicationof the bestpracticable control technology currently available as definedby the Administrator pursuant to Section 304(b) of the Act. Section 301(b) also requires the achievement by not laterthanJuly 1, 1983, of more stringent effluent limitations for point sources, other thanpubliclyowned treatment works. The 1983 limitations are to be basedon 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 theAct. Section 306 of the Act requires the Administrator, within one year after a category of sources is included 

### in a listpublished 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, 

### inthe 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 tonew sources within the 

### Oil and Gas Extraction Industry. The listwill be amendedwhen proposedregulations for the**0~1** and Gas Extraction Industry arepublished 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 standardmay permit no discharge of pollutants. Section 304(b) of the Act requires theAdministrator 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 effluentreduction attainable through application of the bestpracticable control technology currently available. The degreeof effluent**reduct~on** attainable through of the best control measures and practices

7 application economicallyachievable including treatment techniques, process and procedure innovations, operatingmethods, and otheralternatives. The findings contained herein set guidelines pursuant to section 304(b) segments of the petroleumindustry. General Description of Industry forth effluent limitations of the Act for certain

The segments of the industry to be coveredby this study are the following Standard Industrial Classifications (SIC): 1311 crude Petroleumand 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 outboth onshore and in the estuarine, coastal, andouter Continental Shelf areas. The characteristics of wastes differ considerably for the different processes and operations. 

### In order to describe the waste derived from eachof the industry subcategories established in section IV, it is essential to evaluatethe sources and contaminants in the three broad activitiesin 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, andmagnetic, 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 mustbe followed by the drill since only drilling canprovethe actual existence of oil. Aside from sanitary wastes generatedby the personnel involved, only the drilling phase of exploration generates significant amounts of water pollutants. Exploratory drilling, whether

8shallow or deep, generally uses the same rotary drilling methods as development drilling. The discussionof wastes generatedby 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 significantnumber, however, are drilled to gain knowledge of geologic formation. This latter classof wellsmay be shallow and drilled in the initial exploratoryphase of operations, or may be deep exploration seeking todiscover**o~l** orgas bearing reservoirs. Most wells are drilled today by rotary drilling Basically the methods consist of: methods.
1. Machinery to turn thebit, to add sections on the drill pipe as thehole deepens, andto remove the drill pipe and the bit from the hole. 2. A system for circulating a fluid down throughthe drill pipe and tack up to the surface. This fluid removes the particles cut by thebit, cools and lubricates thebit 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 themthrough the drillpipe and back to the surface; and machinery to remove cuttings, fines, and gas from fluids returning to the surface (seeFigure 1). A system of valves controls the flow of drilling fluids from the well when pressures are so great that they cannot be controlled byweight of the fluid column. A situationwhere drilling fluids are ejected from the well by subsurfacepressures and thewell flows uncontrolled is calleda blowout, and the controlling valve system is called the blowoutpreventer (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 onbarges and rest on the bottom for drilling in shallow waters. Others, alsomounted onbarges 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. Afloating rig may be a vessel, with a typical ship's hull, or itmay be semisubmersible--essentially a floating platform with special submergedhulls and supportinga rigwell

9Fig. 1 A KELLY BSTANDPIPE and ROTARY HOSE C SHALESHAKER DOUTLET FOR DRILLING FLUID ESUCTION TANK FPUMP ---) FLOW OF DRILLING FLUID

E

F

-- ROTARY DRILLINGRIG 10

## ~~~-D .**~.** \

: I

I I

I I I I



# DRILLBIT-t ' 

# . ' ' ' ' 

# G

..._-...**:_...-4=~** ....,.-........,..,..,, 

# H

A KELLY C SHALESHAKER D OUTLET FOR DRILLING FLUID GHYDRAULICALLY OPERATED BLOWOUT PREVENTER H OUTLETS, PROVIDED WITH VALVES AND CHOKES FOR DRILLING FLUID DRILLING FLUID

Fig. 2

-- SHALESHAKERAND BLOWOUTPREVENTER

11above the water. Stationary rigs aremounted on pile-supported platforms. Onshore drilling rigs usedtoday are almost completely mobile. The derrick ormast and all drilling machinery are removed when the well is completed and used again in a new location. Rigs used in marsh areas are usuallybarge mounted, and canals are dredged to the drill sites so that the rigs can be floated in. The major source of pollution in thedrilling system is the drillingfluid or "mud" and the cuttings from the bit. In early wells arilledby 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 isquite 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 tobottom 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 theprevious sectionmust either be disposed of or converted for the next section. some mud is left in the completed well. Basic mud components include: bentoniteor attapulgite clays to increase viscosity and create a gel; barium sulfate (barite), a weighting agent; and lime and caustic sodato increasethe pH and control viscosity. (Additional**cond~tioning** constituents may consist of polymers, starches, lignitic material, and various other chemicals). Most muds havea waterbase, 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 usedwhere bottomhole temperatures are very high or where water based muds would hydratewater-sensitive clays or shales. They may alsobeused 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 itthe material cut and loosened by thebit, plus fluids which may enter the hole from the formation (water, oil, or gas)• When the mud arrives atthe 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, siltand sand are discharged

12overboardif they do notcontain oil. Some drilling mud clings to the sand and cuttings, andwhen this material reaches the water the heavier particles (cuttings and sand) sink to the bottom while the mud and fines are sweptdown currentawayfrom 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 endof the drilling operations. The removal of fines and cuttings is one of a number of steps in a continuingprocess of mud treatment and conditioning. This processing may be done to keep the mud characteristics constant or to change them as requiredby the drilling conditions. Many constituents of the drilling mud can be salvaged when the drilling is completed, and salvage plantsmay existeither 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 oilmuds would have served before. Oil muds always present disposal problems. Production System crude oil, natural gas, and gas liquids arenormally 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 suspendedsolids. 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 inthe caseof oil field brines, the water contains dissolved and**sus~ended** solids and hydrocarbon contaminants. The suspended solids arenormally sands, clays, or other fines from the reservoir. The oilcan varywidely in its physical and chemicalproperties. The most important properties are**~ts** density and viscosity. Density is usually measured by the "API Gravity" methodwhich assigns a number to the oilbased onits specific gravity. The oil can range from very light gasoline like**mater~als** (called qatural gasolines) toheavy, viscous asphalt like materials. The fluids are normally moved through tubing containedwithin the larger cased bore hole. For oil wells, the energy required to

13lift the fluids up the well can be suppliedby the natural pressures in the formation, or it can be providedor 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, whichwould 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 thewell tothe 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 canflow. In some cases, the choke is placed in the bottomof thewell 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 andmay be further processedto separate the two. The gas,**o~l,** and watermay be separated in a single vessel or, more commonly, in several stages. some gas is dissolved in the**o~l** and comes outof 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 andbrine 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 causedby various processes which tend tomix the oil andwater 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. Othertypes of chemicals and fine suspended solids tend to retard coalescence. The characteristics of the crude oil also affect the ease or difficultyof achieving process separation.(1) Fluids produced by oiland gas wells are usually introduced into a**ser~es** of vessels for a two-stage separation process. Figure 4 shows a gas separatorfor separating gas from the well stream.

14

# ... l11 CENTRALTREATMENTFACILITY INESTUARINEAREA

HIGHPRESSUREGAS
INTERMEDIATE PRESSURE GAS

# ~

_:wELL STREAM**~ ~-** 


# ---**~-** .:--..._.**~ ~** 



# ---**"'---=------~~**



### -:.----------==-=-_-**~** 

### --....._-:-..-«:::-=; 

### -=:..-:.
......**=--=-~~~~ ~** 

## ----;;-,

# f,

....,

- ..=......**~--**

# ---=-

# =**-~--=**

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

## ....**_:.~**__**~;'7** .:....:

### :......=-::--~~~

## -~"=--=.-.4..- . .

## ~

## ~~~-**~~**

WATFR TReATMENT POLLUTION CONTROL**--~:~~-~:==--=~~-:.=c::~ ~** **~~**-ar -**•-=_.~** 

### -- -- -- - - - - ·- -- -- :...De.-_-- ... -_- ...:.- ___:::-___::!_-TO CRUDE OILSALES M- :_ :...:**~** -- - --**~---- ''•••••••••••••••••••••••.._~~**  ----------**~------..-·-** Fig. 

### 3

-- CENTRAL TREATMENT FACILITY INESTUARINEAREA

### _. 0' 

### A

A-OILANDGASINLET B-IMPACTANGLE C-DE-FOAMlNG ELEMENT 0-WAVE BREAKERAND E-MIST EXTRACTOR G-DRAIN SELECTORPLATE F-G·As OUTLET H-OILOUTLET (DUMP VALVEI Fig. 4

-- HORIZONTAL GAS SEPARATORLiquids (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 gascomes 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, withthe**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 pipedto vessels for separating the oil from theproducedwater. Water which is not emulsified and separates easilymaybe removed in a simple separation vessel called a free water knockout. The**remain~ng** oil-watermixture 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 relativelypure 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 addedbefore the liquid enters this vessel, the vessel itself is often heated to facilitate breaking the emulsion, and some units employ an electrical gridto charge the liquid and to help break the emulsion. A combination of treatmentmethods is often employed in a single vessel. In three-phase separation, gas, oil, andwater 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 tobe marketable. The producedwater or producedwater/solids mixtures discharged atthis point contain too much oil to be**d~sposed** of into a water body. The object of processing through this pointisto 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 increasethe 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 shorewhere bodies of salt or brackish water are available for disposal. Injection**~s** widely used onshore where bodies of saltwater are not available for

17EMULSION INL.E:T 0 nO 0**Oo~**



# - 0 0 

# ..... ) 0 o• 0

0 oO 0 ""- 

# l

. -i

- 

# .. HEAT EXCHANGER

EXSELSIOR

FILTER (OTHERTYPESOFUNITS MIGHTCONTAINTHEGRID OFANELECTRICDEHYDRATOR INPLACEOFTHEFILTERSECTION)



## \

OILOUT

EMULSION IN/ DRAIN

__ 

# __J..------

Fig. 5 VERTICAL HEATER-TREATER

18 z 0

### ~ Cl:**~** 

# "" en en 4 C)

C) z ::::;



# ... 

# ... "" en**~** 5

WATER LEGsurface disposal. (produced water tobe disposed of byinjection may stillrequire 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 majorityof present offshore and near shore (marsh) facilities intheGulf of Mexico and mostfacilities incook Inlet, Alaska, treat and dispose of their produced water to surface salt orbrackish water bodies. The sophistication of the treatment employed by dischargers of produced water is dependentupon the regulation governing such discharges. For instance in the**A~palachian** states most produced water is discharged to local streams after only treatmentin 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. Oftenwater will be injected into a producing oil resorvoir to maintain reservoir pressure, and stabilize reservoir conditions. In a similar operation calledwater flooding, water is**~njected** into the reservoir in such a way as to move oilto theproducing 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 successfulwater flooding project 

### will increase the amountof 

### oil being produced ata field. It will also increaseproduced water volume and thus affect the amount of water that must be treated. Pressure**ma~ntenance** of water injectionmay also increase the amount of water produced and treated. Injectionis also feasible solely as a disposal method. It (injection) is extensivelyused in onshore**product~on** areas exceptin theAppalchian 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 permeabilityof the receiving formation. Inmost all cases corrosion-inhibitingchemicals 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 andtreatment (see Figure 3). As the industry moved farther offshore, the wells still tended tobe 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 couldbe developed from one structure. OffshoreLouisiana multiple-well flatforms include all processing and treatment, in offshore California andin cook Inletfacilities, gas separation takes place on the platforms, with the liquids usually sent ashore for**separat~on** and treatment. All forms of primary and secondaryrecovery 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. Atypical 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 wastewater andthe demands of the injection system and receiving reservoir), surge tank, and injection well. Injection might either be for pressure maintenance and secondaryrecovery or solely for disposal. In the latter case, the well would probably be shallow and operate at lower pressure. The system might include a pitto hold waste water should the injection system shut down. A more recent production technique andonewhich may become a significant source ofwaste 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 (flowingwells by natural reservoir pressure, pumping, or gas lift) orby secondary recovery. Tertiary recovery is usually classifiedbythe substance injected into the**reservo~r** and includes: 1. Thermal recovery 2. Miscible hydrocarbon

203. 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, andwater 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 inCanadian 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 tertiaryrecovery used. Field Service Anumber of satellite**~ndustries** specialize in providing certain services to the production sideof the**o~l** industry. Some of these service industriesproduce a particular class of waste that can be identifiedwiththe service they provide. Of the wasteproducing**serv~ce** industries, drilling (which is usually done by a contractor) is the largest.**Drill~ng** fluids andtheir disposal have already been discussed. Other services include completions, workovers, well acidizing, andwell fracturing. When a company decides that an oilor gas well is a commercial producer, certainequipment willbe installed in the well and on the well head to bring the well into production. The equipment from this process--called 11completion11--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 sufficientfluid by natural flow, various types of pumps or gas lift systems may be installed in the well. Sinceheavyweights and high lifts are normally involved, a rig is usually used. The

21rig may be the same one that drilled the well, or it may be a special (normally smaller) workover rig installedover 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 limitedby impermeability in the producing geological formation. This**cond~tion** may**ex~st** when the well is first drilled, itmay worsen with the passage of time, or both situationsmay 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 immediatevicinity of the well. The two most common methods to increasewell 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 alsocontain sand or some similar material that keeps the fracture propped open once the pressure is released. When a new well is being completedor 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 sufficientweight is introduced into the well to control the down hole pressures. When the work is completed, the liquidused 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 disposedof. 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 inpits or may ne

22salvaged. Contaminatedoil is usually disposed by burning at the site. Inacidizing 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, contaminatedoil and other liquids are barged ashore for treatment and disposal; contaminatedsolids are buried. The fines and chemicals contained in oilfrom wells puton stream after acidizing or fracturing have seriouslyupset 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 millionbarrels-per-day (bpd) of oil and 1.7 millionbpd of gas liquids, for a totalproduction of 10.5 bpd; down slightly from the four previous years. (3) Total importswere 6.1 million bpd for 1974. There are approximately half a**m~llion** producing oilwells and 126,000 gas and condensate wells in the United States. Of the 30,000 new**we~ls** drilled eachyear, about 55 percentproduce oil or gas. Oil ispresently producedin 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 Stateswere: 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 inAlaska. 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 Statewaters inthe Gulf of Mexico and 6,000 on the ocs. over 90 percent are in Louisiana, with the remainder inTexas. Recent lease sales havebeenheld on the ocsoff 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

23can be installed, development**dril~ing** completed, and pipelines laid. Leases have been granted deep areaswill 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
Inaddition to offshore activities, onshore production in Texas for 1974 accounted for 1,226 millionbarrels of oil and 7,942,352 million cubicfeet of gas, the largest contribution of any state. Oil production has been on a decline inTexas 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 oilwells. The amount of producedwater generated is dependent on the method of oil production and the field location. Higherwater cutratios are experienced near the Gulf. Regulation by the State Railroad Commission prohibits discharge of producedwater to fresh waterbodies, and therefore reinjection for recovery and disposal technology has been developed to a high degree. Onshore activity inLouisiana 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 estuariesor fresh water streams. The discharge of production water to fresh water streams is limited to the southernand 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/separatorponds. Where reinjection is practiced the facilities are unsophisticated, consistingof a pximary separator and sedimentation. The disposal formations are at 2000-5000 foot depth and arevery permeable, resulting inlowwell head pressure and power costs. Approximately 601 of the oil production under stateonshore leases isgenerated at facilities which discharge their producedwater. California There has been a general moratoriumon drilling and development inthe offshore areas of California since the Santa Barbara blowout of 1969. (4) Present offshore productionin Statewaters comes from the area around Long Beach and Wilmington and also from the santa Barbara

24area farther north. ocs production is confined to the Santa Barbara area. Except for one facility, all productionfrom both state and Federal leases is piped ashore for treatment. A large and increasing amount of the producedbrine 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 havebeen 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 erectionof 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 separatedonthe platform, with the water and 

### oil sent ashore for separation and treatment. Produced water would be disposedof by subsurface injection ashore. Additional lease saleshave been made on the OCS off Santa Barbara in southern California. Total 

### oilproduction inCaliforniafor 1974 was approximately 390 million barrels (83 million barrels offshore), a decline from the previous year. In addition tooffshore facilities, the major areas of production inCalifornia are in the southern San Jacquin Valley, centered around the city of Bakersfield, and inthe Long Beach-Wilmington area. In California, steam, hotwater, and water flooding methodsof secondary recovery areused. The total produced water is approximately 2,044**mill~on** barrels per year, the majority of which is either reinjected for recoveryor 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 andhas been relatively staticfor the past 5 years. The demarcation line between Federal and Statewaters 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 theplatforms, sending the produced water and 

### oil ashore for separation and treatment. some platforms areproducing increasing amounts of producedwater, and this, plus the occasional pluggingof oil/waterpipelineswith ice in the winter, will encourage a change to platform**se~ration,** treatment, and disposal ofproduced 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 

### characterizedbymarginal production of 0.3 barrles per day perwell 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 independentoperators dominate the industry, accounting for 65-701 of the production. Theoil fields are located primarily in thenorthwest sectionof the State, McKean county alone accounting for 50iof 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 aerationand separation/sedimentationin earthen ponds. Where water flooding is practiced, groundwater is used after treatment as the source. There are plans on some of the larger leases to utilizeproductionwaterfor flooding, despite earlier failure of this method from plugging of the formation strata. current discharge**pract~ces** 

### are in

### partjustifiedby the absence of formations acceptable for reinjection due to permeability, surface outcroppings, lack of void space and substandard well abandonment procedures inthe past. Industry Growth From 1960 to 1970, the Nation•s demand for energyincreasedat an average rate of 4.3 percent. Table 3 gives the projected**nat~onal** 

### demands for oil 

### and gas through 1985 andTable4 the 

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

## u.s. offshoreproduction declined by about 78,500 barrels/day from 1972 to 1973. Offshore**~reduction** 

### amounts toapproximately 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 onshoreproduction. 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 inwhich 

### ocs lease sales will very probably te held by 1978 include the Atlantic Coast (George1

### s Bank, Baltimore Canyon, andGeorgia Embayment) and the Gulf of Mexico.



### 26Not only will new areas be opened to exploration and ultimate development, but production willmove farther offshore and into deeper waters in areas of present development. Movement intomore 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 minimumnumber of platforms. Offshore leasing, explorationr and**deve~opment** will rapidly expand over the next 10 yearsr andoffshore productionwill make up an increasing proportion of our domesticallyproduced supplies of gas and oil.

27TABLE 3

u.s.**su~ply** and Demandof 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 1.59SECTION 

### III Bibliography


### 1. University of Texas-Austin, PetroleumExtension Service, and Texas Education Agency, Trade and Industrial Serivce. 1962. "Treating Oil FieldEmulsions.'' 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 PetroleumAssociation of America. "United States Petroleum statistics 2974 (Revised)." wash.Lngton, D.C. 4. u.s. Departmentof 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.

29SECTION IV INDUSTRY SUBCATEGORIZATION 

### Rationale For sutcategorization The Standard Industrial Classification's subcategorize industry intovarious 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, andwaste volumes 3. Process technology 4. Climate 5. wastewater characteristics 6. Location of**facil~ty** 

### Field surveys, waste treatment technology, and effluentdata indicate that the most important factors are the type of facility, the facility's size, age, wastewater volume, waste water characteristics, and location. The factor of climate is 

### significant with respect to operationalpracticesbuthas less influenceonwaste treatment technology. Process technology was found tohave very little**~nfluence** 

### on the selectionof pollution control technology. An 

### evaluationof industry•s productionunits (barrels of oilper day or thousands of cubicxeet of gasperday) andwaste volumes indicated no relationship between them. Produced water productionmay vary from less than 1 to 90 percent of the production fluids. High volumes of produced waters are**assoc~ated** 

### with olderproduction fields andrecovery methods used to extract crude oil 

### from partially depleted formations. Similarly, the amount of waste generated during drilling**operat~ons** 

### is dependentupon 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 onwaste loadper unit of production.

31Development of Subcategories Based upon the type of facility, the industrymay be subdivided into three major categories with similar type operations or activities: 1) crude petroleum andnatural gas production; 2) oil and gas well field exploration and drilling; and 3) 

### oil and gas well completions andworkover. Further subdivision can be made within each to reflect location

- offshore and onshore

- and any wastesrequiring specific effluentlimitations 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 andDomestic waste II 

### Oil and Gas Well Field Exploration and Drilling A. DrillingMuds 

### B. Drill Cuttings

c. sanitary andDomestic 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 onoffshoreplatforms 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 designedto 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.

32For 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 andwater), ponds of sufficient size are feasible for smaller facilities while mechanical systems (such as flotation) are required where larger amounts of produced water arehandled. Smaller facilities are least likely to have the type cf operating staff required for sophisticatedwater treatment systems and are more likely to receive operating variances from localregulatory authorities. The types of treatment for sanitarywastes for large and small offshore facilities are different, as are facilities which are intermittently manned. For small and intermittently manned facilities, thewaste may be incinerated or chemically treated,**result~ng** in no discharge. Becauseof operational problems and safety considerations, other types of treatment systems thatwill result in a discharge are being considered. Thus sanitary wastes must be sutcategorizedbased on facility size. The state of the art and treatment technology for Category I has been improving over the past several years; the majorityof the facilities regardless of age have installed waste treatment facilities. However, the age of the production**f~eld** canimpact 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 alsobe affected by methodof recovery. If wastes are to be treated off shore, the initialdesign 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/waterprocess 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 itsconfiguration are based in part on the characteristics of the**~roduced** fluids. Forexample, if the fluids contain entrainedoil in a 11tight11 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 causedby malfunctions in the process equipment. Itwas concluded that there isno basis for subcategorization because of differences in process systems.

33Climate**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 toclimatic 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 consideredfor subcategorization. Produced water may be high in dissolved solids (TDS), oxygen demanding wastes, heavy metals, and taxies, inaddition to the**o~l** and grease contamination. The currenttreatment**technolog~es** for producedwater 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 producedwater treatability and cost effectiveness may also have had an effect. (1,2,3) Factors which may affectproducedwater 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 entrainedoil emulsification. 5. Other characteristics of the produced water. The impactof these variables can be minimized by existing process and treatment technology, which include desanders, surge tanks, and chemical treatment.

34Location 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 treatmentmethodbased on location are as follows: 1. Availabilityof space and site conditions, such as, dry land, marsh area, or openwater. 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 isto 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 evaporationpond, if properly maintained, may provide for acceptable disposal of the produced waters; however, inhumid areas in the East and South, evaporation ponds may notbe acceptable. In**~nland f~elds**  where produced waters are sufficientlylowin total solids, discharges have beenused 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 northwestportion of Pennsylvania, discharge of produced water is the rule, not the exception. Treatment consisting of ripple aeration and**semimentation/se~aration** in ponds achievesa highdegree 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 ensureno discharge to surface

35waters, 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 extractionindustry has been**su~categorized** as follows: Subcategory

Subcategory A - near offshore (facilities located in offshore statewaters) 

### 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 intermittantlymanned. 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 mannedwith 10 or more 

### people

36b. M9IM

- facilities with 9 or less**peo~le** or intermittantlymanned. 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 producingformations. Sometimes the terms "formation water" or 11brinewater" are used to describe produced water. Most oiland 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 caseswater 

### 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 recoveredby 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 andwork 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 thewell, lubricatethe drilling bit, remove drill cuttings from the well, or stabilize the walls of the well during drilling or workover.

38Generally, two basic types of muds (water-based andoilmuds) are used in drilling. Various additives maybe used depending upon the specific needs of the drillingprogram. water-based muds are usually mixtures of fresh water or sea water withmuds and clays from surface formations, plus gelling compounds, weighting agents, andvarious other components. Oilmuds are referred to as**o~l** based muds, invert emulsion muds, and oil emulsionmuds.**0~1** muds are used for special drilling requirements such as**t~ghtly** consolidated subsurface formations andwater sensitive clays and shales. (5) (6)(7) Drill Cuttings Drill cuttings are particles subsurfacegeologic**format~ons.** the surface of the wellwith the from the drilling mud. Treatment of Wells generated by drilling into**~rill** cuttings are circulated to drilling mud and separatedthere

Treatmentof wells includes acidizing andhydraulic fracturing to improve oil recovery. Hydraulic fracturing involves the parting of a desired section of the formation by the application of hydraulic pressure. Selectedparticles added to the fracturing fluid are transported into the fracture, and act as propping agents tohold 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 permeablerock 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 tuildup andblock flow of fluids.

39SECTION J:V Bibliography
1. Bassett, M.G. 1971. 11Wemco Depurator TM System." Paper presented at the SPE ofAJ:ME RockyMountainRegional Meeting, Billings, Montana, June 2-4, 1971. Preprint No. SPE-3349. 2. Boyd, J.L., "Treatment standards." Dahlstrom, D.A. 1972. Shell, G.L., and of Oily waste AJ:ChE Symposium. waters to Meet Regulatory SerialNO. 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 outerContinental 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 46thAnnual 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 PetroleumInstitute. Divisionof Production. 1973. "Primer of Oil and Gas Production." 3rd. ed. Dallas, Texas.

40SECTION V WASTE CHARACiERISTICS wastes generated ty the oil and gas industry are produced by drilling exploratory or developmentwells, by the productionor extractionphase of the industry, and, in the case of offshore**fac~lities,** sanitary wastes generated

### b¥ personnel occupying the platforms. Drillingwastes are generally

### in the form of drill cuttings and mud, andproduction wastes are generally produced water. (1) Additionally, well workover andcompletion operations can produce wastes, butthey are generally**sim~lar** tothose from drilling or production operations. Approximatelyhalf a million producingoilwells onshore generate produced water 

### in excess of 20 millionbarrels-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 orgas. 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 atoffshore and onshore wells and structures. The discussion of drilling wastes canbe applied to any area of the United States since these wastes do not change significantly with locality. Other than**o~ls,** theprimary waste constituents oxygen demanding pollutants, heavy metals, dissolved solids contained in drillingmuds 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 situationswhere sanitarywastes are produced from fixed platforms or structures. Drilling or exploratory rigs that are vessels are not part of this discussion. Waste constituents Production Productionwastes 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 containoils, toxic metals, and

41a 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 obtainedduring the verification survey conducted by EPA 

### in 1974. The only influentdata 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 salinitylevels 

### in the influent, and thatthese constituents couldbe satisfactorily characterizedby analyzing only the effluent. Total organic carbon (TOC) is alsotatulated under effluent in Table 5, but itis 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 reducedby the treatment process. TABLE 5 Pollutants in ProducedWater 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

42Industry 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 platformhad a high oil content. Sandhas been reported to beproduced at approximately 1 barrel sand per 2,000 barrels oil.(5,6)



### 43TABLE 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 ofconstituentsinProduced Formationwater--Offshore Texas(8) PollutantParameter Arsenic cadmium Total Chromium Copper Lead Mercury Nickel Silver Zinc


### Phenolic compounds BOD 

### COD Chlorides TDS SuspendedSolids 

### < - less than

45 

### Range, mq/1 <0.01

- <0.02
<o.02

- 

## o.193 <0.10

- 

## 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

- 656As part of a recent EPA study (1976) to collect information on treatment technologies and costs, surveys weremade of onshore productionfacilities in California, Wyoming, Texas, Louisiana and Pennsylvania. The data refresentedin tables 8-12 is from the effluent of the treatment facilities prior to reinjection for secondary recovery or disposal. Itcould be expected that the quality of the untreated produced water fromtheproduction separatorwould 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 unaffectedby treatment. The analytical methods used were from "StandardMethods 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 areknown to be a part of the crude oil, are not comparableto data in otherparts of this report and are shown only for information.

'IABLE 8 Range of Constituents inProduced FormationWater--Onshore California
Pollutant Parameter Oil and Grease suspended SOlids Total Dissolved Solids Phenol Arsenic Chromium Cadmium Lead Barium
<

# =less than Range, mg/1 16-191

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 0.3TAl3LE 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 8.6TAbLE 11**~ange** of constituents inProduced FormationWater--Onshore Louisiana
PollutantParameter 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 Rangemg/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 attempthas been made to qualitatively identify cuttings. The two basic classes of drillingmuds used muds and oil muds. In general, much of the the well hole is eventually displaced requires disposal or recovery.(13) today are waterbased mud introduced into out of the hole and
Water basedmuds 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 saltwater is the liquid**~base** for these muds. The additives areused for such functions as pH

48controlr corrosion emulsification.**inh~bitionr** lubricationr weightingr and
The additives that shouldbe 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 thevolumes of cuttings and muds used in the Bureau'sexample 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 willparallel 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 drillingoperations 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 inthe 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 andhigh-flash diesel oil.(14r15) The oils are theprincipal ingredients and so are the liquid phase. Muds displaced from the well hole also contain solids from thehole.**~here** are two types of**emulsif~ed** oil muds: 1) oil**emuls~on** mudsr which areoil-in-water emulsions; and 2) inverted emulsionmuds, which are water-in-oil emulsions. The principal differences between these two muds and oil based muds is the**addit~on** of fresh or saltwater intothe 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.

49Sanitary and Domestic Waste The sanitary wastes from offshore oiland gasfacilities are composed of human body waste and domestic waste such as kitchen and generalhousekeepingwastes. The volume and concentration of these wastes vary widely with time, occupancy, platform characteristics, and Oferational situation. Usually the toilets are flushed w1th brackishwater or seawater. Due to the**com~act** nature of the facilities the wastes have less dilutionwater than common municipal wastes. This results 

### in greater waste concentrations. Table 14 indicates**ty~ical** waste flow for offshore facilities and vessels.



### soTable 13 Volume ofCuttings andMuds inTypical 10,000-FootDrillingOperation (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 seawater 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 950 424,000No. of Men

76

l1' 66 IV 67 42 10-40 Flow Table 14 TypicalRaw Combined SanitaryandDomestic Wastes fromOffshore 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 TreatmentPractices inLouisiana 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 BestPracticableControl Technology currentlyAvailableto 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, andMcMahan (ed.). The Conservation Foundation, washington, D.c. 5. Garcia, J.A. 1971• 11A system for theRemoval and Disposal of Produced Sand." Paper presented atthe 47th Annual SPE of AIME Fall Meeting, SanAntonio, 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 OffshoreProduction 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 GasAssociation and the Water Quality Board, State of California. 8. Offshore Operatorscommittee. 9. crawford, J.G. 1964. "Rocky Mountain Oil Field Waters."

1

### o. Chemical and Geological Laboratories, casper, Wyoming. Sacks, BernardR. 1969. "Extended Aeriation Sewage Treatment on u.s. corps of Engineers Dredges." u.s. Department of the Interior, Federal water Pollution control Administration.

5311. Amoco Production Company. 1974. 11Draft 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 andRefining company's Offshore Platforms with Living Quartersin the Gulf of Mexico. 11 Prepared by Waldermar 

## s. Nelson COmFany, Engineers andArchitects, 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 SPEof 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

- DrillingMud."

54SECTION VI SELECTION OF POLLUiANT PARAMETERS Oil and grease from produced water, deck drainage, muds, cuttings, andproduced 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 willbe established. The rationale for inclusion of these parameters are discussed below. Parameters for EffluentLimitations Freon Extractables

- Oil and Grease No solvent is known which willdirectly dissolve only oil or grease, thus the manual 11Metnods for the Chemical Analysis of water and wastes 197411 distributed by the Environmental ProtectionAgency statesthat 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 otherhydrocarbons and some inorganic compounds, such as sulfur, will be included in the freon extraction procedures. The majority of materialremoved 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 theCOD, TOC, TOD, and usually the BOD tests wherehigh test values will result. The oxygen demand potential of these freon extractables is only one of the detrimental effects exertedon water bodies by this class of compounds. Oil emulsions may adhere to the gills of fish or coat and destroy algaeorother plankton. Depostion of oil in the bottom sediments can serve to inhibit normal benthic growths, thus interrupting the aquatic food chain. Soluble and emulsifiedmaterials ingested

### b¥ fish may taint the flavor of the fisn flesh. Water soluble components may exert toxic action on fish. The water insolublehydrocarbons and free floating emulsified oils in a waste water will affect stream ecology by interferingwith oxygen transfer, by damaging the plumage and coats of water animals and fowls, andby contributing taste and toxicity froblems. The effectof oil spillsupon boats and shorelines and their production of oil slicks and iridenscence upon the surfaceof waters iswell known. Fecal coliform (ChlorineResidual) The concentration of fecal coliform bacteria can serve as an indication of the potential pathogencity of waterresulting from the disposal of human wastes. Fecal coliform levels have been

55established 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 coliformlevels inthe effluent for a period representing a normal cycle of operations. This approach may be applicable to onshore installations; howeverr for offshore operations the logisticsbecome complexr and simplified methods are desirable. Howeverr the presence of specific levelsof suspended solids and chlorine residual in an effluent are indicative of corresponding levels of fecal coliforms. In generalif suspended solids levels in the effluent are less than 150 mg/1 andthe chlorine residual is maintained at 1.0 mg/lr the fecal coliform level shouldbe 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. Itmay be considered desirable, however, that a study of each sanitary treatment systembe made at leastonce 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 andminimize chlorineusage. Floating Solids**Mar~ne** waters should be capable of**su~porting** indigenous life forms and should be free of substances attributableto discharges orwastes 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 intermittentlymannedoffshore facilities.
Other Pollutants Some produced formation waters are known to**conta~n** heavy metalsr toxic substancesr constituents with substantialoxygen demand, and inorganic salts. Insufficient data exist to warrant comprehensive control of these parameters and there is no discharge technologynow in use by the industry to remove these pollutants, although some concomitant reduction in oxygen demanding constituentsmay takeplace as a result of treatment not specifically designed for their removal.

56Heavy Metals Produced waters havebeen 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 dischargeof 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 otherlethal 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**  toMcKee 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 concentratedby planktonfrom theirhabitat by factors of 1,000 to 5,000 or more. Leadhas been shown to be toxic to fish in concentrations as low as 0.1 mg/1, nickel at a concentrationof 0.8 mg/1, and silver at a concentration of 0.0005 mg/1. Zinc was shown to**~e** toxictotrout eggs and larvae at a concentration of 0.01 mg/1. TDS Dissolved solids in producedwaters consist mainlyof 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 communitiesin the United States use water containing from 2,000to 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 potablewater**w~ll** dictate acceptable standards. The following is a summary of a literature survey indicating the levels of dissolved solids which shouldnot interfere with the indicated beneficial use:

57Domestic water Supply Irrigation**L~vestock** watering Freshwater Fish andAquatic

Life lrOOO mg/1 700 mg/1. 2r500 mg/1 2r000 mg/1

Estuaries aretypicallybilaminar 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 organicmaterials from sunlight and C02; it also produces oxygen 

### in excess of respiration so that this upper layer is characteristically supersaturatedwith02 during the daylight hours. The bottom higher salinity layer**funct~ons** as the catabolic side of the cycler (microbial breakdown of organicmaterial with subseliuent02 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 stressesresulting 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 depressedtrophic levels.(7) Chlorides Chloride ion is one of the major anions found inwater and produces a salty taste at a concentration of about 250 mg/1. Concentrations of 1000mg/1 may te undetectable 

### inwaters which contain appreciable amounts of calcium andmagnesium ions.
some produced water associated with naturally occurring subsurface hydrocarbons may contain extremely highamounts of sodium chloride. These 11so-called11 connate brines developed because the particular geologic formation has not allowed the entrance of surfacewater 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 willdepend 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 uponthe concentration of the metallic ionwith 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

58this salt**w~ll** probably govern the amount of chlorides in waste streams. Itis extremely chloride salt concentrations and poultry. difficult to pinpoint the exact amountof sodium necessary to result in toxicity inwaters. Large have been proven toxic to sheep, swine, cattle.

In swine fed diets of swill containing 1.5 to**2.0~** saltby weight, poisoning symptoms canbe 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 suppressedDO. 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 discussedbelow: 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 notin itself cause direct harm to a water system, but it does exert an indirect effect by depressing the oxygen contentof the water. sewage and

59otherorganic 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. Thewater vapor and carbon dioxides from the combustion chamber (where the water vapor is removed) is condensed and sent to an infrared analyzer, where the carbondioxide is monitored. This carbon dioxide value corresponds to the totalinorganic value. Another portionof 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 tofish and other aquatic animals. Also, chlorophenols produce an unpleasant taste in fish flesh that destroys their recreational and commercial value. Itisnecessary to limitphenolic compounds in raw water used for drinking water supflies, as conventional treatment methods used by water**su~ply** facilities do notremovephenols. The ingestion

60

### of concentrated solutionsof phenols willresult in severe pain, renal irritation, sbock andpossibly death. Phenols also reduce the utilityof water for certainindustrial uses, notably food and beverage processing, where it creates unpleasant tastes andodors intheproduct. As seen from the above discussion on the potentialharmfrom produced water discharges, the effects of toxicants, high salinity, low dissolved oxygen, and high organic matter can combine to**~roduce** 

### an ecological enigma. The Stateof California, recognizing the potential impact of industrial wastes in the coastal areas, has adopted effluent limitations for oceanwaters undex its jurisdiction (see Table 15. They were arrived atby first applying safetyfactors to known toxicity levels and a considerationof control technology. This produced proposed standards which were subjectedto the publichearing process, revised accordingly, and then declared. To meet the coastal water quality standards, the oil and gas extractionindustry has developed a no discharge technology (reinjection of production water)•

61TABLE 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 CaliforniaAdministrative Code.

62SECTION VI Bioliography 1. GreatLakes 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. OceanWater of California." 4. Adams, J.K. 1974. "The Relative Effects of Light and Heavy Oils." u.s. Environmental ProtectionAgency, Divisionof Oil and Special Materials control, washington, D.c. Pub. No. EPA-520/9-74-021. 5. Evans, D.R., andRice, 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 QualityControlBoard. 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 conservationSECTION VII CONTROL AND**TREAT~£NT** TECHNOLOGY Petroleum production, drilling, and exploration wastes vary in quantity andquality from facility tofacility. Awide range of control and treatment technologies has been developed to treat these wastes. The results of industry surveysindicate that techniques for in-process controls and end-of-pipetreatment 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 bemore efficient and cost effective. Reduction or Eliminationof waste Streams The two**ty~es** of in-plant techniques that reduce the waste load tothe treatment systemor to the environment are reuse and recycle of waste products.**Exam~les** ofreuse are: 1)**reinject~on** of produced water to increase reservoir pressures; and 2) utilization of treatedproductionwater (softened, if necessary) for steam generation. An example of a recycle systemis the conservation and reuse of drilling muds. waste Character Change Examples of character change inwaste stream would be: 1) the substitution of a positive displacementpump for a high speed centrifugalpump; and 2) substitutionof a downhole choke for a well head choke, therebyreducing the amount of emulsion created. (1) Proper pretreatment andmaintenance practices are alsoeffective inreducing waste flows and**~mproving** treatment efficiencies. Return of deck drainage to the process units andelimination of waste crankcase oil from the deck drainage or produced water treatment systems are examples of good offshorepretreatment 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

65maintenance shouldbe free of**sus~ended** solids, bacterial slimes, oxygen, sludges, and precipitates. In some cases the quantity of produced water is insufficient toprovidethe neededwater 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 beused 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 injectionpumps. (2) Reinjection of producedwater 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 reinjectedfor secondaryrecovery. 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 handleover 170,000 barrels per day. Producedwater reinjection systems for presure maintenance and water flooding are less common in the Gulf Coast, andnone are in use inCook 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 limitedby space availability but must be specifically designed to fit offshore platforms. Two limiting factors which affect produced water reinjection are insuffiecintquantities of produced water to meet the requirementfor 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 oilfrom producing formations. The addition of steam or otherfluids into the formation canimprove ultimate recovery. Asystem which reuses produced water for steam generation is operatingon the West coast. The systemconsists 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 reconditionboth water based and**o~l** based muds. With the systemoperating properly, mud losses are limited to deck splatter and the mud clinging to drill cuttings.

66Pretreatment 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 priorto 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 thatpipe all produced crude oil and water to shore for processing and brine treatment. Operation andMaintenance 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 deckwashdown 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 

### oilprocessing system. 5. Reduction of oil gathered inthe pig (pipeline scraper) traps**~Y** channeling oil back into the gathering line system insteadof 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) selectionof 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 causedexcessive oil loading. A change in the type of level controlsand reducedproduction which lowered the beatingrequirements andhelped**allev~ate** 

### the problem during start-up of the produced water treatmentunit. Further improvements were achieved by careful selection of chemicals for treating

### oil and froduced water, and the chemical**inject~on** 

### andrecylcing pumps were replaced. The precedingparagraph 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 andmaintenance 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 dischargedto the waste treatment system and the efficiency of the system. carefulplanning, 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** 

### andmaintenance are realized. AnalyticalTechniques and Field verification Studies Data on the types of treatment equipment and performance of the systems in this reportwere providedby the industry. An 

### early analysis of data indicated a need to bothverify the information and determine currentwaste 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** 

### toverifyperformance data. Inaddition, three field surveys were made to determine the**ade~uacy** 

### of laboratory analytical techniques, sample collection procedures, operation and maintenance procedures, and generalpractices 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 treatmentprocesses.**var~ance** 

### in Analytical Results for Oil 

### andGrease concentrations Effluent oil and greasevalues 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. Themethod used by a contractor is usually governed by regulatory authority, theperson incharge 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) datedoctober 30, 1970,**specif~es** to F·ederal leasees that oil content values for effluents shall be determined and reportedinaccordance with the American Society for Testing and Materials Method Dl340, "Oily Matter in Industrial waste water.11 Aregional water quality board in California specifies APHA Standard Methods, 13th Edition, "Oil and Grease" Test No. 137 (Gravimetric). The

## u. s. EnvironmentalProtectionAgency lists theAPHA Standard for oil and grease determination under theprovisions of 40 CFR Part 136 "Guidelines Esta.l::lishingTest Procedures for the Analysis of Pollutants." The manner in which the sample isprepared for**analys~s** is equally critical. For example, Table 16 shows oil/greaseconcentrations of acidized and unacidized samples from facilities in California (both analyzedbythe same method).

TABLE 16 Effect ofAcidificationon Oil and GreaseData 

### 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 convertsmany of the water salts to water insoluble acias that hydrocarbon solvents. explanation is that the soluble organic acid arethen extractableby
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 producedwater sample except asphaltenes or bitumen. This limitation would affect thereported 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 watereffluentsfrom offshore facilities were highly variable within and between geographical areas. The available informationdid 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 analyticalmethods (gravimetric and infrared) measuring Freon extractible oil/grease and those values determinedby petroleumether extraction using 

### the gravimetric method. This study was conducted by the EPA Robert

## s. Kerr Research Laboratory (RSKRL) atAda, Oklahoma.

70Table 17 Oil and Grease Data

- Texascoastal 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

11.2The 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 samemethod by EPA andtheindustry labs inTexas and California (EPA'sresults did correlate well to the contract labs during the Louisianaverification study). Therefore the low oil and grease concentrations reportedby Texas and California appear to bemore 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 conclusionwas validatedby a statisticalanalysisof the data,**w~ch** is contained in Supplement B. The analysis indicated a highcorrelation with theresults of the two analytical methods performed within theEPA laboratory and little orno 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 inSupplementB, verified the data collectedover the years by coastal**Louis~ana** facilities. In addition, the study found a veryhigh correlation between analytical results of contractor laboratories and the EPA laboratory. The selectionof facilities for the Gulf Coast verification study was based on a general cross sectionof the production industry and did not favor the more efficient systems. Table 19 indicates types of treatmentunits, the performance observed during the survey, and long termperformance basedon historical data for each facility. Tables 20 and 21 indicatethe comparative oil and grease concentration data for 'Iexas and California offshore facilities and onshore treatment of offshore producedwater treatment units.

72TABLE 19 Performance of Individual Units Louisiana coastal Long TermMean 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 surveyResults 

### 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 16TABLE 20

Texas coastal Verification Data Facility Freon Extractibles Freon Extractibles Identification Gravimetric Method InfraredMethod 

### 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 VerificationofOilandGreaseData CaliforniaCoastal RSKRL, Ada, Oklahoma
Freon Freon PetroleumEther 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 

### 106.1 22.3 126.0 16.0 76.0 5.0 01 

### 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 55.01 6.01 24.2 15.0 59.01 19.9 15.0 102.01
1. 

### Carbon tetrachlorideextractibles.End-of-pipe control technology for offsboretreatment 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 availabilityof space, waste characteristics, volumes ofwaste 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 attachthemselves to any oildropletin their path, and the gas and oil rise to the surfacewhere they may be skimmed off as a froth. Two types of gas flotation systems arepresentlyused in oil production: 1) Dispersed gas flotation these units use specially shaped rotating mines or dispersers toform small gas bubbles which float to the surfacewith the contacted oil. The gas is drawn down into the water phasethrough thevortex created by the rotors, from a gas blanket maintained above the surface. The risingbubbles 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 tothe 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 dispersedgas flotation because the gas bubbles are createdby a change inpressure which lowers the dissolved gas solubility, releasing tiny bubbles. A portion of the waste water streamis 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 andthen through a contact tank filled with gas. The waste water leaves the contact tankwith 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 solubilityof the gas decreases and the excess gas is released as microscopic bubbles. These bubbles then riseto the surface contacting the oil and bringing itto the surface where it is skimmed off. Dissolvedgas flotation units areusually 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. Aflow diagramof the two typical flotation units is shown inFigure 6.

76CRUDE OIL PRODUCTION PROCESSING

L.P.GAS GAS I.P.GAS TO

## ~ H.P.GAS SALES OILTOSALES ,.t::.**~** ........_ PROCESS01L· ,:::::_ :::::::. LOWPRESSUREOILWEL/r ......._ L. WATERSEPARATION .....---- p (HEATERTREATER, INTERMEDIATE\ 1.

. CHEMICAL,ELEC 

### t--r. PRESSUREOIL 

# f<} HIGH P. TRICAL, SURGETANK.

WELL 

# T<-t: PRESSURE GUNBARREL,FREE SKIMMERTANK 

## <: b- SEPARATOR**-~** WATER KNOCKOUT. 

### I.:C:P**~** ETC.)**~** 

## CP H-AT BRINE \.

....... t: to.......
-- ..._ ..... HIGHPRESSURE 

# 11**-~** OILWELL v**~** OILANDBRlNE v ·•

# 7 ' I SKIMMEDOILRECYCLE FROM GAS CHEMICALINJECTION FLOTATION
-.J "\ -.J WASTE WATER TO EITHER



### - ./

SKIMMEDOILRECYCLE • ROTOR-DISPERSERS 

# u- 

# - GASORAIR DISCHARGE 1----" ANDCHEMICALS

# ~

# ::~ 

# vo- rVERBOAR')_

# ~**~b**

## ~~)/~b FLOTATION**~** UNIT 

# lf Ct:TACT

### ~
_ TANK
- SKIMMEDOILRECYCLETOPROCESSSEPARATION 

### ..._ 

# - 

# - ROTOR-DISPERSERGAS FLOTATIONPROCESS DISSOLVED GAS FLOTATION PROCESS Fig. 6

-- ROTOR-DISPERSERAND DISSOLVED GAS FLOTATIONPROCF.SSES FORTREATMENT OFPRODUCEDWATER

### 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 periodof quiescence provided by the surge tank allows some gravity separation and coalescence to take place, and dampens out surges inflow from the process units. This**~rovides** 

### a more constant hydraulic loading to the treatment unit, which, inturn, aids in the oil removal process. The verification survey conducted on Coastal Louisiana facilities includea 10 flotation systems whichvariedin 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 

### inoperations. Information obtained during the field survey of onshore treatment systems for cook Inletindicated that one of the four onshore systems utilized a dissolved gas flotation systemcomparable 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 thecookInlet platforms use flotation cells for treatmentof deck drain wastes. Field surveys on the west Coast found that physical/chemical treatment is the primarymethod of treating produced water for either discharge to coastal waters orfor reinjection and that flotation is the most widely used of the physical/chemical methods. on the west coast, all treatment systemsexceptone are located onshore and produced fluids arepipedto these complexes. The majority of the waste water treatment systemshave been converted to reinjection systems. However, some of those that still discharge are somewhat different from the systems in the Gulf coast andCook 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** 

### systemhandles 50,000 barrels-per-day. surveys of onshore production facilities 

### in California revealed induced gas flotation being used for treatment of producedwater for recovery, disposal by reinjection and discharge. Atotal of

78seven units were observed, three of whichwere utilized ahead of sand filters and one unitwas followed bya pond. The sizerange of the entire groupwas from 10,500to 350,000 Bbl/day. Surge tanks normally preceded the flotation units withthe 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 producedwater treatment capacities of the two systems surveyed were 70,000 and 340,000 Bbl/day respectively. Parallel Flate Coalescers Parallel plate coalescers are gravity separatorswhich contain a pack of parallel, tiltedplates arranged so that 

### oil droplets passing through the pack need only rise a shortdistance before striking the underside of the plates. Guided by the tilted plate, the droplet then rises, coalescing withother droplets until it reaches the tipof the packwherechannels 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 anAPI seFarator. suspended particles, which tend to sink, move down a short distancewhen 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 surfaceof the plate; then they move down along the plate surfaces, requiring periodic removal and cleaning of the platepack. Where stable emulsions are present, orwhere 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 producedwater 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.

79No plate coalescers are in use in cook Inlet or California, either onshore or offshore. Filter Systems (Loose orFibrous Media Coalescers) Another type of producedwater treatment system is filters. They may be classified into two general classes basedonthemedia 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 onthe filter media. This eventuallyoverloads 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 elementused. 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 amountof oil removed, filter performance has generally been good (provided that the units arebackwashed sufficiently often): however, problems of excessive maintenance and disposal have caused the industry inthe Gulf coast tomove away from this type of unit, and a number of them have been replaced with gas flotation systems. The Gulf Coast survey information indicated thatwhen 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 theseunits. On the West Coast andCook Inlet, no filter systems are in use as the primary tzeatment method. Filters are however, used for final treatment ininjection systems in**Cal~fornia** and several steps of filtration are usedprior to seawater injection incook Inlet. on the westcoast, these units are precededby a surge tank, flotation unit, and other treatmentunits which remove most

80of the oil and suspendedparticles. Theseunits, when used 

### in series with other systems, performwell. In Wyoming a site was visitedwhere**ap~roximately** 6,600 Bbl/day was being treated by a mixed sand media pressure filter. Earthen pondsbothpreceded 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 isretained for a sufficient time for the oil and water to separate. Tanks, pits, and, occasionally, barges are used as gravity separationvessels. 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 systemcanbenefitfrom 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 theGulf Coast are gravity separation systems. The majority are located onshore andhave 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 producedan 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 settlingtanks and pits. No gravity systems were reported tobe 

### 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 onshoreproduction sites were tanks and ponds when utilized as the single treatment process. As previouslymentioned, tanks do not afford the retention times of ponds, but whether or not theirprimary function is separation they are effective in skimming readilyremoved free oil. In**Cal~fornia** four sites were visitedwhichutilized 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.

81InWyoming a total of 37 production facilities were visitedwhich utilized either tanks or ponds as the method of treatment. Of the 23 sites using tanks for treatmentranging 

### 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 pondsfor treatment, nine were discharging, two were reinjecting for recovery. while the remaining three both discharged and reinjectedfor recovery. In Pennsylvania, where disposal**~y** discharge is than the exception, 11 sites were**v~sited** which for separation treatmentranging 

### in capacity from of produced water capacity. Distillation the rule rather utilized ponds 2-8,000 Bbl/day

InCalifornia a site was visitedwhich utilizedproduced water as boiler feedwater. Theboiler was fired by field natural gas and discharged condensate to the localgroundwater table. The steam was utilized to heat onsite crude storage tanks andthe boiler blowdown containing oiland qreaseresiduewas 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 streamis 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 additionof a coagulating agent could increase efficiencies approximately 

### 15 percent and the**ad~tion** of a polyelectrolyte and a coagulatingchemical could increase efficiencies 20 percent. (5) Three basic types of**che~cals** areused for wastewater 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 emulsionbreakers. 2. coagulatingChemicals

- 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.

823. Folyelectrolytes

- These chemicals are long chain, high molecular weight polymers used to assistinremoval of colloidal and extremelyfine suspended solids. The results of two EPA surveys of 33 offshore facilities using chemical treatment in the Gulf Coast disclosedthe following: 1. Surface active agents and polyelectrolytes are the most commonly used chemicals for wastewater treatment. 2. The chemicals are injectedinto the wastewater upstream from the treatment unit and do not require premixing units. 3. Chemicals areused toimfrove 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
Asimilar survey of facilities incook 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 inthe 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 notreturnedto 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-dayof 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 chemicalsor application rate in the waste stream. Other chemicals may alsobe added to reduce corrosion andbacterial growths which may interfere with both process and waste treatment systems. Effectiveness of Treatment Systems Table 22 gives the relative long termperformance of existing waste water treatment systems. The general superiority of gas flotation units and loosemedia filters over the other systems is

83readily 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 FibrousMedia 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 4zero Discharge Technologies

water produced along with liquid or gaseoushydrocarbons 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 afterprocessing varies with the use or ultimate disposition of the water. Thewater 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 locatedon 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. Inmuch of theRocky Mountain 

### oil and gas producing area, the total dissolved solids of the produced waters are relatively low. These waters are discharged to pits and putto 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. Across section of the individual pit is shown in Figure 8. A producing 

### oil field in Nevada discharges produced water to a closed salinebasin. 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

85DETAIL 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



### -- ONSHOREPRODUCTIONFACILITYWITH DISCHARGETO SURFACEWATERS

86DIMENSIONS VAIY FOI VOLUME NEEDED 

# ·-t··t-··

•**------~--Nk-----­** z**~**

DEPTH WILL VARY WITH OPEtATIONSCONDITIONS

NOTE PITS ARE EQUIPPED WITH PIPE DRAINS FOR SKIMMING OPERATIONS TO OBTAIN OIL-FREE WATER DRAINAGE

Fig. 8 TYPICALCROSS SECTIONUNLINED EARTHEN OIL-WATERPIT

87United States. The term "disposal" as used here refers to injection of produced fluids, ordinarilyinto 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 consideredend-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 ordinarilycausedby Bactericides serve to inhibit the and slime producing organisms. frequently combined into a single under various trade names. (6) lowpH, 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 havebeen 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 onthemetal surfaces to insulate the metal from the corrosive elements. The life of the film is a function ofthevolume andvelocity of passing fluids. Inhibitors may be water soluble or dispersible infresh water or brine. They may be introduced full strengthor diluted. Treatment, usually in the range of 10 to 50 partsper 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 injectionor disposal system. 2. Aerobic slime-forming bacteria. These may grow ingreat 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 inturn may plug filters and sandface. Oxygen entryinto a system may also causethe formation of ferric oxide. Treatment to**com~at** 

### bacterial attack ordinarily consists of applying either a continuous injection of 10 to 

### 50 ppm concentrationof a bactericide or**~atching** 

### once or twice a week. Scale inhibitors are commonly usedin 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 intemperature, 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. Scaleinhibitors 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. Dimetallicphosphates 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 completionof a typical injection well is 

### shown in Figure 9. Aproducingwell**~s** 

### shownfor comparison. Injection wells may be completedin a complicated fashion with multiple strings of tubing, each injectedinto a separate zone. If the disposal well is 

### equipped with a single tubing string, and injection takes place through tubing separatedfrom casingby packer, the annular space between tubing and casing is filled with noncorrosive fluids such as low-solids water containing a combination corrosion inhibitorbactericide, orhydrocarbons such askerosene and diesel oil. All surface casing is 

### cemented to the ground surface toprevent contamination of fresh water and shallow groundwater. 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 equippedwith alarms and automatic shutdown systems if a pipe ruptures. The injection well designed for pressure maintenance and secondaryrecovery purfoses is coufleted ina manner identical to

89INJECTION 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

.**~co** I

... L- ."Q. .A' 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.nV$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 mn

.., (t) co (/)
.., (/) 0 Q) c: ..,**:::~<** a.- 0 ..,

FISURE 9 

### TYPICALCOMPLETION OF AN INJECTION WELL AND APRODUCING WELLthat of the disposal well, except that injection is into the producinghorizon. Treatmentprior 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 pitor 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 toinjection; 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 thewater 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 stuffingbox 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 relativelyfew wells, fairly close together; where wells produce from a common reservoir; or where a one-owner operation is involved. There are instances inwhich 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, itis 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.

913. Anility to properly treat waters of differing composition. This factor enables incompatible waters tobe successfully combined and treatedon the surfaceprior to injection. Disposal zone The choice of a brine disposal zone is extremely important to the success of the injectionprogram. 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 mustinclude the answers to questions such as: 1. How much reservoir volume is available? 2. Is the receiving formation porous andpermeable? 3. What are the formation's physical and chemical properties? 4. what geological, geochemical and hydrologic controls govern the suitability of the formation for injectionor 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** itinadvisable to injectinto 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 surfaceguagepressureper foot of depth to the disposal zone, particularly in shallow wells, an alternate zone is usually sought. Itis 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 compatiblewith those injected. Chemical analyses are performed on both to determine whethertheir 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 isnot**conf~ned** to the formation into wnich it is placed. consequently, the injection area mustbe thoroughly investigated to determine any previously drilled holes. These include holes

92drilled for oil and gas tests, deep stratigraphic tests, and deep geophysical tests. If any exist, further information as to method of plugging and other technologicaldata 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 producedwater for disposal. Field investigations made inCalifornia were confinedto 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. Fourof these installations were sending all orpartof 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 installationwas separating the oil and water on the platform and further treating the water so that it could be injectedinto 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 isbeing 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 groupwho 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 ofwaste 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 notbe an alternate unit to use. Alternate handling practices vary considerably from facility to facility. The following methods are currently practicedoffshore: 1. Discharge overboardwithout treatment. 2. Discharge after removal of free oil in surge tank.

933. Discharge to a sunkenpile with surface skimmer to remove free oil. 4. Dischargeof produced water to 

### oil pipeline for onshore treatment. 5. Retention on the facility 

### using available storage. 6. Production shutdown. The methodused 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 aretreated in the Gulf Coast, thewater 

### is treatedby gravity separation, or transferred to the production water treatment system and treated with productionwater. Platforms 

### inCaliforniapipe the deck drainage and deck washings along with produced fluids to shore for treatment. Incook Inlet, these wastes arebeing 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 

### inthis area 

### is gas flotation. L1mited data indicate an average effluent of 25 mg/1 can be obtainedfrom 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 inwashing the rigs. The practice of allowinginverted emulsionmuds to get into the deck drain system, during drilling or workovers, also seemed to adversely effect treatment. Sand**Remova~** Tne fluids producedwith**o~l** and gas may contain small amounts of sand, which must be removed from 

### lines andvessels. This may be**accomp~ished** by opening a series of valves 

### in the vessel manifolds thatcreatehigh fluid velocity aroundthe valve. The sand is thenflushed through a drainvalve into a collectoror a 55-gallon drum. Produced sandmay also be removed in cyclone separators when itoccurs in appreciable amounts. The sand that bas beenremoved 

### is collected and taken to shore for disposal; or the 

### oil is removedwith a solventwash and the sand is discharged to surfacewaters directly. Field investigations have facilities have sandremoval indicated equipment

94 that that some Gulf flushes the coast sandthrough 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 theoperators in thecook Inlet area. Limited data indicate thatCalifornia pipes most of the sand with produced fluids to shore where it is separated and sent to State approved disposal sites. Atleast one systemhas been developed that will mechanically remove oil from produced sand. The sandwasher 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 sandwasher. After treatment, the sand 

### is reported to have no trace of oil, and the highest oil concentrationof the transferred waterwas less tnan 1 ppm of the total volume discharged. (6)**Drill~ng** Muds and DrillCuttings (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 siteby anchors or supportedby the ocean floor. The wastes generatedfrom drilling operations are drilling fluids or 11muds11 used inthe drilling process, rock cuttings removed from the wellborebythe drilling fluids, and sanitary wastes from human activity. Both water based andoil muds are used. (10) In-plant control techniques and drilling mud practices are affectedby the type of mud used. conventionalmud handling equipment isused for water basedmuds. Some of the water basedmuds 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 waterbasedmuds are routine housekeeping practices associated with cleanliness and safety. A conventional drilling mud systemfor waterbased 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 conventionalmud handling system. Operations and maintenance practices on rigs using oilmuds 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

95for disposal. Another method is to collectcuttings, 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 shoreor contained in a closed liquid recovery system. (11)**Dr~lling** Muds and DrillCuttings (Onshore) With onshore drilling, the discharge from shale shakers, desilters, and desanders is placed ina large earthenpit. ·when drilling operations terminate, the pitisbackfilled and graded over. Remaining muds, either oil or waterbased, arereclaimed. Well Treatment Acidizing and fracturing performed as part of remedial service work on oldor**ne~** wells canproduce**~astes.** Additionally, the liquids used to kill a well sothat it can be**serv~ced** might create a disposal problem. Spent 

### acid and fracturing fluids usuallymove through the normal production system and through thewastewater treatment systems. The fluids therefore do not appear as a discrete waste source. Their presence, however, in the waste treatment systemmay 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 itis recovered because of its value, either by collecting it directly or by moving itthrough 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£ sanitarywastes vary**wide~y** with time, occupancy, platform characteristics, and operational situation. The waste water primarily contains body waste but, depending upon the sanitary systemfor the particular facility, other waste may be contained inthewaste stream. Usually the toilets are flushed withwater 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 percentof the daily average, andbOD concentrationshave variedup to 400 percent. (12)

96

### There are two alternatives to handlingof sanitary wastesfrom 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 becategorized as physical/chemical andbiological. 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 treatwastes onfacilities with small complements of men or which are intermittently manned. The incinerationunits may be either gas fired or electric. The electric units have been difficult to maintainbecause of salt water corrosion and heating coil failure. The gasunits are not subject to these problems but create a potential source of ignition which could result in 

### a safetyhazard at some locations. some facilities have chemical toiletswhich require hauling of waste and create odor and maintenance problems. Macerator-chlorinatorshave not been usedoffshorebut would be applicable to frovide minimal treatment for small and intermittentlymanned facilities. At**th~s** 

### time, there does not appear to be a totally satisfactory systemfor small operations. A much more complex physical/chemical system that basbeen installedat 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. Becauseof start-up difficulties, no data is available for this facility. It has been reported that physical/chemical sewagetreatment systems have performedwell in testing onland, butoffshorethey have**develo~ed** 

### problems associated with the unique offshore environment including abnormal waste loadings andmechanical 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 comminutorwhich 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 systemshave proven to be technically and economically feasible means ofwaste 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 designparameters inTable 24 have been recommended. Table 25 shows average eftluent concentrations for various types of treatment units whichare in 

### use at offshore**facil~ties** 

### in the coastalwaters ofLouisiana.

97Domestic 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. Tracerationby a comminutor should be sufficient treatment.

98TABLE 24 Design Requirements for Offshore Sanitary Wastes (13)

Parameters Design Requirement PerCapita Per Day BOD5 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 1.3SEC'IION VII Bibliography
1. Universityof 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 ProtectionAgency, National Environmental Research Center, Raleigh. North carolina. 1973. ''Petroleum Systems Reliability Analysis. 11 Vol. II: Apfiendices. Prepared by computer Sciencescorporation under contract No. 68-01-0121. 4. Offshore Operators COmmittee, Sheen Technical Subcommittee. 1974. "Determination of Best Practicable control Technology CurrentlyAvailable 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 andArtificial 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. 11

### Cuttings Clean-Up Meets offshore Pollution Specifications

... Petrol. Petrochem.**~·r** 

### Vol. 13: No. 3r 

### PP• 54-56r 59. 12. 

### Martinr James

### c. 1973. 11

### Domestic waste Treatment in the Offshore Environment... Pafer presented atthe 5thAnnual Offshore Technology conference. Preprint No. OTC 1737. 13. 

## u.s. Departmentof the Interior. 11

### Sewage Effluent Data." (UnputlishedReport) August 16r 1972.

101SECTION VIII COST, ENERGY, AND NONWAiER-QUALITY ASPECTS This section will discuss the costs incurred in applying different levels ofpollution 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 estimatedcapital 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 withineach one. For**pur~oses** of cost**analys~s** of end-of-pipe treatment three waste streams are considered

-- producedwater with discharge, produced water reinjected, and sanitarywastes (offshore). The costof water treatment or disposal for producedwater generated in the offshore and coastal subcategories is significantly affectedby availability of space. The cost analysis has therefore been subdivided into two areas; offshorewater disposal and onshore water disposal. The onshore water disposal has been further subdivided regionally. Deck drainage 

### is considered to be treatablewiththe productionwater. 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 onthe 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 effluentlimitations. Existing water treatment systems include sumps and sump piles, pits, tanks, plate coalescers, fibrous and loose media coalescers, flotation systems and reinjection systems. Oftshore ProducedWater Disposal The systems currently used or needed for the treatmentof process waste water (formation water) resultingfrom the production of**o~l** and gas involve physical separation, sometimes aided by chemical application, prior to discharge. Shallowwell injection has also been successfully used for disposal of**~roduced** wastes

103at 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 Separationby coalescence, using flotation equipment, then discharge to surfacewater. 

### 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 shallowwell injection. E2 separation desanders injection. using flow and filters, equalization (surge tank) with disposal by shallowwell
The data available for analysis suggest sizing treatment facilities for producedwaterbased 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 identifiedbased 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 15percent 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.

1043. 

### costs will Therefore, options: vary greatly depending upon platform space. investment costs have been preparedfor 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 spacewillbe 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

### buildingplatforms, they havebeen builtto the minimum size needed for production. Therefore space is 

### not generally available for water treatmentequipment and ancillary facilities. Space is 

### provided by cantilevered additions up to 1,000 square feet. Space**re~uirements** 

### greater thanthis amount will require an auxiliaryplatform. (2)


### c. Option (c) is for new Flatforms being planned. needed space would be providedas a basicpart of platform design and the costsapportioned at $350 square foot. The the per
In all three cases estimates are basedonplatforms located offshore in 

### 200 feet of water. This depthis 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 andmaintenance costs of components of the various systems are basedon operating costsofthe equipment. (2) The resulting percentage of investmentcost is 

### shownin Table 26.

105TABLE 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 andpower for low demand iE computed as 2 percent of the investment cost. Forhigh demands an electricpower costof 2- l/2 cents**~er** kilowatthour 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 productionfacilities or offshore producedwater sent to shore for treatment. The costsfor treatment ofoffshorewastes, 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 disposalonly 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

### Capita1

### Costs



# ... 0 -.J 

### AnnualizedCosts Capital Depreciation 0

### &M Energy Total AnnualizedCosts
Costofwaterdisposal $/bbl Table 27 FormationWaterTreatmentEquipmentCosts Offshore Installations 200

### BarrelsPerDay FlowRate EQUIPMENTCOSTS (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 FormationWaterTreatmentEquipmentCosts Offshore Installations 1,000Barrels PerDay Flow Rate EQUIPMENTCOSTS (Thousands of1974dollars)
Al B 

## c El E2



# - Capital Costs 101 143 176.3 373.3 432.2

_. 

### AnnualizedCosts 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 AnnualizedCosts 26.9 41.7 51.0 107.6 128.8
Costofwaterdisposal .07 .114 .14 .30 .35 $/bbl

### Table 29 FormationWaterTreatmentEquipmentCosts Offshore Installations 5,000Barrels PerDay Flow Rate (Thousands of1973dollars) 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 

### AnnualizedCosts 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 CostofWaterDisposal

- $/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 

### FormationWaterTreatmentEquipment Costs Offshore Installations 10,000Barrels PerDay Flow Rate (Thousands of1973dollars) 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



## .... AnnualizedCosts



## .... 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 CostofWaterDisposal

- $/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 aNotconsideredtobe aviablealternativebecause oflargespacerequirement.

### Table 31 FormationWaterTreatmentEquipmentCosts Offshore installations 40,000 BarrelsPerDay FlowRate (Thousands of1973dollars) 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 

### AnnualizedCosts ...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 CostofWaterDisposal

- $/bbl Option (a) 0.002 0.0077 0.01 0.004 0.020 Option (b) 0.0028 0.027 0.030 .005 0.040 aNoestimatemade

- methodconsideredtobeimpractical because of**l~rge** space

### requirements.When producedwater is treated and returned to the producing formation for secondary recovery, the costs should not be considered as a disposalcost, butrather as a necessary cost in productionof oil. When**~reduced** water cannot bereturned to the formation for secondary recovery or for water flooding, the costs for treating it and providing the injection equipmentbecomes a legitimate disposal cost. Generalized cost estimates for onshore disposal of produced formation water were developed to includeflow equalizationtanks 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 wasassumed. 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 costswere computed at 9 percentof the capital costbasedon an industry-sponsoredreport. (2) Other costs for reinjecting produced formation waterhavebeen developed from field surveys conducted by the EPA during the first half of 1976. The sites surveyedwere selected as being**re~resentative** of**re~njection** disposal technology within the various states. The actual data, which can be found 

### in SupplementB, was takenfrom data formats**subm~tted** by industry for the selected sites and is presented for the most part without major adjustment. In two cases, Pennsylvania andTexas/Louisiana nearshore platforms, field data was notavailable and engineering estimates were developed. The values for**ca~ital** and operating costs shown inTables 32 and 33 are from regression analysis of the field data.

112

### TABLE 32 

### Capital costs (1) 

### for onshoreDisposal byReinjection of ProducedFormationWater From Fieldsurveys 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 datapoints.**bbl/da~** 10,000 280 300 375

470 110

1600
1680 (2) 

### Production sites without existingreinjectionfacilities. (3) 

### Production sitespresently reinjectingfresh water. (4) 

### Engineering estimates.

113TABLE 33 Annual Operating''> costs for Onshore Disposalby**Re~njection** of Produced Formation Water From Field Surveys in Selected States ('Ihousands of 1975 Dollars)

state Descri:etion t of Sites ReinjectionCaEacitl!, 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 reinjectionfacilities. (3) Production sitespresently reinjecting fresh water. (4) Engineering estimates.
As an alternative to no discharge

- reinjection technology, cost estimates**~ere** developed for discharge to navigablewaters. 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 stripperwell categorywas selected asa surge tank followed by chemical addition and ponds. The steel surge tank has 2-10 day storage. The three unlinedponds in serieshave a 5-footoperating depth and a retention time of 100-600 hours, depending upon the system's capacity. Annual costs consist of: operation at 1-3hours 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

134operating costs for stripper well facilities in the size range 10-10,000 bbl/day are shown onTable 34. Treatment technology for beneficial dischargers was selected as surge tank, skim basin, chemical feed and gas flotation followed by ponds. The surge tankbas a 1-2 hour storage capacity and the skim basin is providedwith an automatic skimming device. The gas flotation system uses induced 

### air and the ponds have a 12-hour retention time. A standbypond 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 kilowatthour and chemicals at 3 3/4 mils per barrel. The**ca~ital** and operating costs for beneficial dischargers inthe 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. Additionalplatform spacewas assumedrequired 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 coastalplatforms are shown on Table 36. Details of cost estimating procedure for all categories is available in Supplement 11B11 •
TAELE 34 Cost Estimates for Treatmentin Ponds and Disposal by Discharge for StripperWell Facilities (Thousands of 1976 Dollars) SystemCapacity ProducedWater, 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

115TABLE 35 Cost Estimates for Treatment by Gas Flotation 

### &Ponds 

### &Discharge for Beneficial Dischargers (Thousands of 1976 Dollars)**S~stem ca12acit~**  Produced water1**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 85 137 220

'IABLi". 36 cost Estimates for Treatmentby Gas Flotation 

### &Discharge for Coastal Platforms (Thousands of 1976 Dollars)**s~stem ca12acit~**  ProducedWater,**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 SanitaryWastes 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 statedin 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.

116Actual 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 unitwas rejected as spurious

- an incorrect linear extrapolation on a graph.) Table 39 presents the calculations that translate these basic horsepowerrequirements into total energy requirements. One way to evaluate the energy requirements of flotation systems**~s** to compare their consumptionwith that of the oil production associated with their use. Water production rates do notvary regularly with crude oilproduction rates. In some instances, the 5,000 bbl/day of produced water may be associatedwith 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 exerciseto attempt to estimate the net BTU equivalentin termsof barrels of diesel oil for the oil production associated with the typicalwater flows. One can, however, usefully examine a range of possible levels of net production to get a general impressionof 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 productionof anywhere from 50 to 50,000 bbl/day of diesel oil.**Siu~larly** the 10,000 and 40,000 bbl/day waterflows 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 oilproduction, the flotation energyrequirements amount to only 1.5 percent of the net energybeing 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 thatthere will beno 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

117the 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 aswell-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.

118TABLE 

### 37 EstimatedTreatment Plant Costs For SanitaryWastesForOffshoreLocations PackageExtendedAerationProcess (Thousands of 1973 dollars) TreatmentPlant Capacity (gallons/day) 2,000 4,000 6,000 CapitalCost 18,000 23,000 28,000 TotalAnnual 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 energyandpower 360 460 560

119Level of Production

bbl/day

5,000 10,000 40,000 Table 38 EstimatedHorsepower Requirements for the Operationof FlotationTreatment 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 datedJune 12, 1974, fromNationalTankCom. toMr. R. W. Thieme, OTA, EPA, plus telephone communication, Friday, July 19, 1974, withMr. E. CliffHill, NATCO 

### i/ Telephone communicationwithMr. Ken Sasseen, Rheem-Superior Corp., California. Komlin 5/ Sanderson Engring Corp. (Hp.) 17-1/2

81-1/2



### 11 Telephone conversationwithMr. ArthurAlbohn, Komline, 201-234-1000 July 24, 1974.

120TABLE 39

Estimated IncrementalEnergy Requirements Flotation Systems
5,000bbl/day ofwater treated: 15Hp. for 1 yr.

### =3.35x 108BTU/yr.

1bbldiesel oil

### =6 x 106BTU 15Hp.

- yr. = 55.8bbldiesel oil/yr. Assume 20% conversion efficiency, then 15Hp.

- yr

### =279 bbl diesel oil/yr. 10,000bbl/dayofwater treated: 464 bbldieseloil/yr. 40,000bbl/dayofwater treated: 1115bbl diesel oil/yr.

121ProducesWater Flow

- bbl/day 5,000 10,000 40,000 TABLE 40 EnergyRequirements for Flotation Systems as Compared toNet EnergyProduction Associatedwiththe ProducedWater Flows

Assumed LevelofNet Energy Energy for Flotation ProductioninDiesel Oil Units DieselOil Equivalents

- bbl/day Equivalents

- bbl/day 50 to 50,000 0.76 100 to 100,000 1.27 400 to 400,000 3.05

122SECTION VIII Bibliography
1. Offshore Operators committee, Sheen Technical subcommittee. 1974. "Determination of BestPracticable Control Technology currentlyAvaila£le TO Remove Oil From Water Produced With Oil and Gas." Prepared by Brown and Root, Inc., Houston, Texas. 2. JointAssociation 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.

123SECiiON 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 isbased oncontrolmeasures 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 requiredprior to application of a specific treatment systemto an individual facility. Procedure for Developmentof**~** 

### EffluentLimitations The effluent guidelines limitations for produced waterwere determinedusing effluent data fox oil andgrease. This data was**prov~ded** 

### by the oil and gas producing industry, Department of the**Inter~or** 

### (U.s. Geological Survey), severalStates, 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; CookInlet, Alaska; and Coastal California. The oil-grease effluentdata 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, andponds. Informationwas also obtained from the industry that included schematics, diagrams, and narratives of operationand maintenance for 25 selectedproducing facilities. A review of the effluent data showed a wide range of treatment efficienciesfrom facility to facility with similar treatment, variability between different treatmentmethods, and variability of effluentlevels within an individual facility. Additional information was reviewed in detail to determine the reasons for these**v~riations.** 

### Itwas concluded that treatment efficiency is affected by uncontrollable factors related to geological formation and controllable factors related to industryoperations and analytical procedures. The factors considereduncontrollable by currenttechnology are: 1. Physical and chemical properties of the crude oil, including solubility inwater. 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 

### control1. Operator training. 2. Sample collection and analysis methods. 3. Process equipment heater-treaters and and sump pumps. malfunction--for example in their dump valves, chemicalpumps
4. Lack of proper equipment--for example, desanders or large tanks. 5. Noncompatibleoperations. The major objectiveof the detailed data analysiswas 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 offAlaska) 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 themajority 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 analyticalprocedures. EPA attempts to verify this data failed and all of this datahad to berejected. Ten of the 9q treatment systems off Louisiana had 10 or less data points; they were rejected. £ata fromthe 84**remain~ng** units were analyzed alongwiththe data collected from 25 facilities visited inthe EPA verification study. The variance in treatment efficiencies was reflected in the data for alltypes 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 Louisianawith 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 rawwaste cnaracteristics. The treatmentefficiencies 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. AreviewofO&M records and findings from EPA field surveys indicate that these units are subject to plugging from solids, iron, and otherproduced water constituents. When the parallel platebecomes plugged, frequent back washing, manual cleaning, or replacement of plates is

127required. 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 onnine of the units. Each was evaluated to determine the acceptability of the data andthe 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 

### teingperformed. 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 inexcess 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 selectionof 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 statisticalanalysiswasconducted todetermine the form of the statistical distribution and to search for anomalous means or variances which might indicate a needto subcategorizebased upon flow rates and space limitations. The initial review indicated that the selected units datawere similar in 

### distribution, and alttough the observed means and variances differed from unit to 

### unit, no basis for further subcategorizationwas discovered. The statistical analysis indicated that the data were log normally distributed over most of the data. The variousunits could be 

### separated statistically into threegroups: 1) five high; 2) 13 low; and 3) nine average. The means and 99 

### percent probability of occurance levels were calculatedfor the low, high, and total groups. Even though the group of 27 flotation units could be broken down further (into 3 subgroups), itwas felt that at the current level of experience, with this technology, the entireindustry couldnotbe expected to achieve the same level of treatment as the very best units are now achieving. Therefore, data from all 27 Louisianaunitswere included in**determin~ng** 

### the effluent limitsfor 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. Itwas determined that the grab samples had a highervariance than the composites and that the compositing technique would resultinmore**re~resentative** 

### results. The compositingwould greatlydecrease the effect of sampling and analytical variance, which is 

### potentially**s~gnificant** 

### in 

### oiland 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
Amaximum monthly averagewas also calculated from the modified (composite) data base. To 

### utilize allof the data, two different**a~proaches** 

### were used to determine the monthly averages: 1) 

### based on dates of observed values

- thismethod averages a given number of samples (N) which are 30/N days apart, withthe analysis being performed on these averages; 2) based on randomized observed values this method divides the 2262 datapoints into 2262/N groups, each group containing Nrandomly selected points. The analysis isperformed onthe averages of eachgroup.

129The first method is free of assumptions, but is limited in data base sinceonly 9 of the units had more than 2 data points per month. The secondmethod is simple andutilizes 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 plotsbegin separating at 4 samples per monthbecause 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 plotof the modified daily concentrations for the 27 Louisiana flotation units. The plot is essentially linear over the last 90 percentof 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 groupunits for Louisiana. Beneficial use - Data for this sutcategory were collected from**n~ne** facilities in wyoming representingfilters, flotation and ponds as end-of-pipe technology.**~hese** facilities were visited by the technical contractor and were considered tohave well run and well maintained**operat~ons.** An analysis of the data from the individualunits 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 RegionVIII 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 basehada mean of 8.2 and a daily maximum of 44.

130.......

# ~ 

# . 

# s 

# J i

....... ·.-I 0 Figure 10 99thPercentileofM:>nthlyAverageOilandGrease

70

60



### so

1

(30) Concentrationvs. FrequencyOfSanplingEachM:>nth

1 I --·--·-··--t·------------···:- .---- ·---·-..·--·

2 (15) 0

3 (10) • actual -randanized



# • ' 0

4 (8) (7) 0

5 

### (6) --·-

·-----·-

. - -----

# •

6 (5)

NumberofSarrples PerM:>nth (Days**Bet~**Sarrples) 

### 131FIGURE 11 CUmulativePlotofEffluentConcentrationsofAll SelectedFlotationUnits intheIouisianaGulfCoastArea

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
PerofSanp1esEqual 'lbOrlessThanOrdinateValue

132 J I i 

## I.

98 99Figure 12 represents a cumulative platof the combined data base. A slight modification was made to the analysis

.procedure described for the offshore data. 

### In orderto havethe data form a straight 

### line over the entire range, rather than the upper 80- 90% of the range, a constant is addedto each datapoint so that log (X+A) is plotted rather than log

## x. Since the affect of the constant A ismore pronounced for smaller values of Xthe 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 theresultingvalue is the best fit to the distribution of X; this methcd is called the three parameter log normal analysis. Sanitary wastes

-- Offshore and coastalManned Facilities With 10 orMore People BPCT for sanitarywastes from offshore manned facilities with 10 or more people is basedon end-of-pipe technology consisting of biologicalwaste 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. Chlorineresidual, BOD, and suspended solids concentrations for the biological treatment systems were within the range of values which wouldmeet fecal coliform requirements. The only limitation being set on sanitarywastes is for chlorine residual. This requirement is set to control the fecal coliform level in this effluent. Limits onBOD or suspended solids for these wastes are notjustified sincetheBOD and 'I'SS content of the producedwaters 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 aspossible. 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 standardresidual chlorine limit of 1 mg/1 plus or minus 40 I is unrealistic. There has been no upper limit setbecauseof a lack of validdata tobe used to set such a limit. BPCT for sanitary wastes from small offshorefacilities and intermittently manned facilities is based on end-of-pipe technology currently used by theoil 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


# .../

- Iay/'

--1---· 

## / 

## v**~**

# v / 

# v. 

# / 

# v.·
• •

10 20 30 40 

### 50 60 70 

### 80 9() 

### PERCENTOFSAMPLESEQUALTOORLESSTHANORDINATEVALUE Fig.12- CumulativePlotofEffluentConcentrations

ofAll WyomingData (values areplottedasX·+ 1.3)

134 

# . 95 

### 98 99chemical systems which may include chemical toilets, gas fired incinerators, electric incinerators or macerator-chlorinators. None of these systemsbas provedtotally 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 beno 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 dischargewill 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 beused only to treat pollutedwaters. All stormwater and deck washings from platformmembers containing no oilywaste 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.

135Alternate Handling

- Offshore and coastal Alternatehandling 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 surfacewaters. Control practicescurrentlyused inoffshore and coastaloperations are: 1. waste fluids are temporarily stored onboard until the waste treatmentunitreturns to operation. 2. Waste fluids are directed to onshore treatment facilities through a pipeline. 3. Placingwaste fluids in a barge for transfer to shore treatment. 4. Waste fluids are piped to a primarytreatment unit (gravity separation) to remove free oil and dischargedto surface waters. Drilling Muds BPCT for drilling muds includes control practiceswidely 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 andhousekeeping equipment such as pipe and kelly wipers, mud saver sub, drill pipe pan, rotary table catch pan, andmud saver box. 3. Recycling of oil basedmuds. BPCT end-of-pipe treatment technology isbased 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 basedand emulsion muds shall not be discharged to surface waters. These muds are tobe transported to shore for reuse or disposal in an approved disposal site.

136The limitations for onshore drilling muds are as follows: 1. The muds shallbe discharged to surface waters. These muds are to be transported to and disposed of in an**ap~roved** disposal site. DrillCuttings BPCT for drill**cutt~ngs** is based on existing treatment and disposal methods used by the oil industry. The limitations for offshore drillcuttings are as**fo~lows:** 1. Cuttings in natural or water casedmuds 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 thanwater, orwater basedmuds are to be recovered and reused. Materials not consumed during workovers and completions are to betransportedto 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.

137section 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.

138SECTION 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 effectno 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 subcategoryis the same as for BP'ICA. Near Offshore and Coastal Subcategories

- ProducedWater The BATEA limitations for producedwater in the coastal and near offshore subcategories is no discharge to surfacewaters. This can be accomplished ty reinjection orby end-of-pipe technologies such as, evaporation ponds and holding pits (when ·wastes are transferred to shore) or injection todisposal wells. About 401 of those producing facilities withno 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 desirablebecause of frequent overflow, dike failure, and infiltrationof salt water into fresh water aquifiers. If properlyconstructed and lined, evaporation lagoons may result in no discharge in arid and semiarid regions. However, erosion, flooding, and overflowmay ·still occur during wet weather. £isposalwell systems which may consist of skim tanks, aeration facilities, filtering systems, backwash holding facilities, clearwater accumulators, pumps, and wells provide the bestmethod for disposal of produced water. These systems are equally applicable to onshore and offshore operations and are the primary methodusedto dispose of produced water on the California coast and 

### in the inland areas. Far Offshore Subcategory

- Produced Water and DeckDrainage 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 

### willhave gained sufficient experience 

### in the reduction of raw waste loads and operation of end-of-pipetechnologies to improve

139their 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, usedto 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, 52mg/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 bebased 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 shouldbe 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 

### PERCENTOFSAMPLES EQUALTOORLESSTHANORDINATEVALUE Fig. 13-CumulativePlotofEffluentConcentrations ofTenSelectedFlotationUnits inthe LouisianaGulfCoastArea

141 

# " 1.- 

# /

99.8SECTION 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 definedhere will be built after this regulationis 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 unpreventablewastes shouldbe minimized.

143SECTION 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; KennethAdams, OSMCD; Hans Crump-Weisner, OSMCD; Arthur Jenke, OSMCD; R. w. Thieme, Office of Enforcement and General counsel; JeffreyHoward, 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, EdisonWater Quality Research Laboratory, Edison, N.J. Martin Halper, Project Officer, Effluent Guidelines Division, contributed tothe 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 GuidelinesDivision, offered guidance during**th~s** program. Special appreciation is given toMary LouAmeling, Charles cook, Richard Insinga, and Henry Garson for their contributions to this effort. Inaddition 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 assistedwith 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 conductedthe entire analytical study phase for field verification in Coastal Louisiana, Texas, and California. Special recognition is due EPA EdisonWater QualityResearch Laboratory, Edison, New Jersey, for its participation in field studies of oil and gas operations and its review of

145

### contractor-operatedanalytical laboratories in the Gulf coast area. Acknowledgement ismade to Richard Krahl, Robert Evans, andLloyd 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 studyby providing data and assisting in 

### field studies. Among those contributing: Alabama, Arizona, Arkansas, California, Colorado, Florida, Illinois, Louisiana, Missouri, Nebraska, Nevada, NewMexico, North Dakota, Ohio, Pennsylvania, Utah, andWyoming. Our special thanks to Mrs. Irene Kiefer for her editorial services. Appreciation is extended tothe secretarial staffs of the Oil and SpecialMaterials controlDivision and the Effluent GuidelinesDivisionfor 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, SethAbbott, Chairman; Ashland Oil, Inc.; Atlantic Richfield company; Brown andRoot, Inc.; c. E. Natco; Champlin Petroleumcompany; Chevron Oil Company; ContinentalOil Company; Exxon Oilcompany; Gulf OilCompany; 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 Filtercompany; andWEMCO.

146SECTION 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

- Liftingof 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 systemrecommended by theAPI. 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 toweight drilling
Barite Recovery Unit {Mud centrifuge} - A means of removing less dense drilled solids from weighted drilling mud to conserve barite and maintainproper 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 deviceto 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 saturatedwith 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, pipelineregulations limit

### BS&W to the volume of oil. with the 1 percentoil. of Casing

- Large steel pipe used to 11

### seal off11 

### or 11

### shut out11 

### water andprevent caving of loose gravel formations when drilling 

### a well. When the casings are set, drilling continues through and telow the casingwith a smallerbit. The overall length of this casing is calledthe stringof casing. More than one stringinside 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-typeseparator inwhich 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 tobreak oil-wateremulsions. Choke - Adevice with either a fixed or variable aperture used to release the flow of well fluids under controlledpressure. Christmas Tree

- Assembly of fittings andvalves at the top of the casing of an oilwell that controls the flow of oilfrom the well. Circulate

- The movementof fluid from the suction pit through pump, drill pipe, bit annular space in the hole andback again to the suctionpit. 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 toform 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

148approach 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 thehole 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 thathave 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 calledwetoil. cuttings

- Small piecesof formation that are the result of the chipping and/or crushing actionof thebit. 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 - Awell through whichwater (usually saltwater) 

### is returned to subsurface formations. Drill Pipe

- Special pipe designed to withstandthe 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 - Amechanically or pneumatically operatedvalve used on separators, treaters, and othervessels for the purpose of draining, or "dumping•• a batchor oilor water.

149Emulsion - A substantially permanent heterogenous mixture of two or more liquids which are not normally dissolved in each other, butwhich areheld in suspension or dispersion, one in the other, by mechanical agitation or, more frequently, by adding small amounts of**su~stances** known as emulsifiers. Emulsionsmay 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 theyform small clumps or tufts resembling wool. Flowing well - Awell 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 penetratedby 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 - Ameans 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

- Apipeline, 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 ofpipe into which several sources, of oil such as well streams, are combined. Heater-Treater heat. A vessel used to break oil water emulsion with

150Hydrogen 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 preventsor retards undesirable changes in the product. Particularly, oxidation and corrosion; and sometimes paraffin formation. Invert Oil jEmulsionMud) - Awater-in-oil or salt water is in dispersedphase and some other oil is the continuous phase. viscosity and oil reduces the viscosity. emulsionwhere fresh diesel, crude, or Water increases the
Kill**~** Well

- To overcome pressure in a well by use of mud or water so that surfacepressures are neutralized. Location (Drill Site} been drilled. Place at which a well is tobe orhas
Mud Pit - A steel or earthen tankwhich ispart of the surface**drill~ng** mud system. Mud Pump A reciprocating, high pressure pump used for circulating drillingmud. Multiple**complet~on** A well completion which provides for simultaneous production from separatezones. 

## 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 - Awell completedfor the production of crude oilfrom at least one oil zone or reservoir. Onshore

- Dry land, inland bodies andbays, and tidal zone. OSMCD

- Oil and SpecialMaterials ControlDivision. Paraffin - Aheavyhydrocarbon sludge fromcrude oil. Permeability - A measure of ability of rock to transmit a one-phasefluid under conditionof laminar flow.

151Pressure 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 - Apump 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 expectedhole 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 drillpipe 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** - Avessel usedto separate oiland gasby gravity. Shale

- Fine-grained clayrock with slatelike cleavage, sometimes containing an**o~l-yielding** substance. Shaleshaker Mechanical vibrating screen to separate drilled formation cuttings carriedto the surfacewith drillingmud. 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 settlingtank inwhich oilis permitted to rise to the top of the water and is then takenoff. 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 pipewhen a well is pressured without allowing vertical flow at the top of the well. Tank - A bolted or welded atmosphericpressure 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.

152Total Depth (T.D.)

- The greatest depth reached bythe drill bit. Treater

- Equipment usedto 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 andthe 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 itif necessary) mustbe supported against collapse and the entry into the wellof 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 theproducing layer, for this purpose. some geological formations require the use of additionaltechniques to "complete" a well such as casing the producingformation and using a "gun perforator" to make entry holes, the use of slottedpipes, 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 Awell drilled to test formations nonproductive within a 1-mile radius of previously drilled wells. It is expected that probable hole conditions canbe extrapolated from previous drilling experience data from that general area. Wiper,**Fipe-Kell~** 

### - Adisc-shaped device with a center hole used towipe 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 operationof a well.

153

### MULTIPLY (ENGLISH UNITS) TABLE 41 

### METRIC TABLE CONVERSIONTABLE by TO OBTAIN (METRICUNITS) ENGLISH UNIT ABBREVIATION CONVERSION ABBREVIATION**~1ETRIC**

### UNIT
acre ac 0.405 ha hectares acre- feet ac ft 1233.5 cum cubicmeters BritishThermal Unit BTU 0.252 kg cal kilogram

- calories BritishThermal Unit/pound BTU/lb 0.555 kg cal/kg kilogramcalories/kilogram cubicfeet/minute cfm 0.028 cum/min cubicmeters/minute cubicfeet/second cfs 1.7 cum/min cubicmeters/minute cubicfeet cu ft 0.028 cum cubicmeters cubicfeet cu ft 28.32 1 1 iters cubic inches cu in 16.39 cu em cubiccentimeters degreeFahrenheit Of 

### 0.555(°F-32)* 

# oc degreeCentigrade feet ft 0.3048 m meters ga11on gal 3.785 1 1 iters gallon/minute gpm 0.0631 1/sec liters/second horsepower hp 0.7457 kw killowatts inches in 2.54 em centimeters inches ofmercury inHg 0.03342 atm atmospheres pounds lb 0.454 kg kilograms milliongallons/day mgd 3,785 cum/day cubicmeters/day mile mi 1.609 km kilometer pound/square inch (gauge) psig (0.06805 psig+1)* atm atmospheres (absolute) squarefeet sq ft 0.0929 sqm squaremeters squareinches sq in 6.452 sq em squarecentimeters ton (short) ton 0.907 kkg metricton (1000 kilograms) yard yd 0.9144 m meter 

## *Actual conversion, notamultiplier

154