EPA 440/1-76/055-a
Group II
  Development Document for Interim
 Final Effuent Limitations Guidelines
                 and
  Proposed New Source Performance
           Standards for the
 OIL & GAS EXTRACTION
        Point Source Category

UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
              SEPTEMBER 1976

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          DEVELOPMENT DOCUMENT

                   for

              INTERIM FINAL

     EFFLUENT LIMITATIONS GUIDELINES

                   and

PROPOSED NEW SOURCE PERFORMANCE STANDARDS

                 for the

         OIL AND GAS EXTRACTION
          POINT SOURCE CATEGORY
            Russell E. Train
              Administrator
          Andrew W. Breidenbach
       Assistant Administrator for
      Water and Hazardous Materials

             Eckardt C. Beck
   Deputy Assistant Administrator for
      Water Planning and Standards
           Robert B. Schaffer
 Director, Effluent Guidelines Division
              Martin Hal per
             Project Officer
             September, 1976

      Effluent Guidelines Division
 Office of Water and Hazardous Materials
  U.S. Environmental Protection Agency
        Washington, D. C.  20460

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                            ABSTRACT

This development document presents the findings of  an  extensive
study  of the Oil and Gas Extraction Industry for the purposes of
developing effluent limitations guidelines,  for  existing  point
sources   and  standards  of  performance  for  new  sources,  to
implement Sections 301, 304, 306 and 307  of  the  Federal  Water
Pollution  Control  Act,  as  amended  (33 U.S.C. 1551, 1314, and
1316, 86  Stat.  816  et.  seq.)  (the  "Act").   Guidelines  and
standards were developed for the Oil and Gas Extraction Industry,
which was divided into 6 subcategories.

Effluent  limitations  guidelines  contained herein set forth the
degree of effluent reduction attainable through  the  application
of  the  best  practicable control technology currently available
(BPCTCA) and the degree of effluent reduction attainable  through
the  application  of  the  best available technology economically
achievable (BATEA) which  must  be  achieved  by  existing  point
sources  ty July 1, 1977 and July 1, 1983, respectively.  The new
source performance standards (NSPS)  contained  herein  set  forth
the degree of effluent reduction which are achievable through the
application   of   the   best   available   demonstrated  control
technology, processes, operating methods, or other alternatives.

Supporting data and rationale for  the  development  of  proposed
effluent  limitations guidelines and standards of performance are
contained in this development document.

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                        TABLE OF CONTENTS
Section                                               Pace

         ABSTRACT                                         1

I        CONCLUSIONS                                      1

II       RECOMMENDATIONS                                  3

III      INTRODUCTION                                     7

              Purpose and Authority                       7

              General Description of Industry             8

              Industry Distribution                       23

              Industry Growth                             26

              Bibliography                                29

IV       INDUSTRY SUBCATEGORIZATION                       31

              Rationale of Subcategorization              31

              Development of Subcategories                32

              Description of Subcategories                36

              Bibliography                                40

V        WASTE CHARACTERISTICS                            41

              Waste Constituents                          41

              Bibliography                                53

VI       SELECTION OF POLLUTANT PARAMETERS                55

              Parameters for Effluent Limitations         55

              Other Pollutants                            56

              Oxygen Demand Parameters                    59

              Phenolic Compounds                          60

              Bibliography                                63
                               111

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 Section                                                   Page Np_.

VII      CONTROL AND TREATMENT TECHNOLOGY                 65

              In-plant Control/Treatment Techniques       65

              Analytical Techniques  and field             68
              Verification Studies

              Zero Discharge Technologies                 85

              End-of-Pipe Technology for Wastes  Other    94
              than Produced Water

              Bibliography                               100

V11I     COST, ENERGY, AND NONWATER                      103
         QUALITY ASPECTS

              Cost Analysis                              103

              Offshore Produced Water Disposal           103

              Onshore Produced Water Disposal            106

              Offshore Sanitary Waste                   116

              Energy Requirements for Operating          116
              Flotation Systems

              Nonwater-Quality Aspects                  117

              Bibliography                               123

IX       EFFLUENT LIMITATIONS FOR BEST                  125
         PRACTICABLE CONTROL TECHNOLOGY

              Produced Water Technology                  125

              Procedure for Development of              126
              BPCT Effluent Limitations

              Bibliography                               138

X        EFFLUENT LIMITATIONS FOR BEST AVAILABLE        139
         TECHNOLOGY ECONOMICALLY ACHIEVABLE

              Near Offshore and Coastal Subcategories - 139
              Produced Water

              Far Offshore Subcategory -  Produced Water 139
              and Deck Drainage

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Section                                                  ^i No.
XI        NEW SOURCE PERFORMANCE STANDARDS                143
XII       ACKNOWLEDGEMENTS                                 ^45
XIII      GLOSSARY AND ABBREVIATIONS                      147

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                         LIST OF TABLES
Table No.               Title                         Page No.
    1         Effluent Limitation - BPCTCA                 4
    2         Effluent Limitation - BATEA and              5
              New Source
    3         U.S. Supply and Demand of Petroleum         28
              and Natural Gas
    4         U.S. Offshore Oil Production                28
    5         Pollutants in Produced Water,               42
              Louisiana Coastal
    6         Pollutants contained in Produced Water,     44
              coastal California
    7         Range of Constituents in Produced           45
              Formation Water—Offshore Texas
    8         Range of Constituents in Produced           46
              Formation Hater—Onshore California
    9         Range of Constituents in Produced           47
              Formation Water—Wyoming
    10        Range of Constituents in Produced           47
              Formation Water—Pennsylvania
    11        Range of Constituents in Produced           48
              Formation Water—Onshore Louisiana
    12        Range of Constituents in Produced           48
              Formation Water—Onshore Texas
    13        Volume of Cuttings and Muds in              51
              Typical 10,000 Foot Drilling
              Operation
    14        Typical Raw Combined Sanitary and           52
              Domestic Wastes from Offshore Facilities
    15        Effluent Quality Requirements for           62
              Ocean Waters of California
    16        Effect of Acidification on Oil              69
              and Grease Data
    17        Oil and Grease Data, Texas Coastal          71
                               vii

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Table No.                      Title                             page J

    18        Oil and Grease Data, California                    71
              Coastal

    19        Performance of Individual Units,                   73
              Louisiana Coastal

    20        Texas Coastal Verification Data                    74

    21        Verification of Oil and Grease Data,               75
              California Coastal

    22        Performance of Various Treatment                   84
              Systems, Louisiana Coastal

    23        Performance of Various Treatment                   84
              Systems, Wyoming and Pennsylvania

    24        Design Requirements for                            99
              Offshore Sanitary Wastes

    25        Average Effluents of Sanitary Treatment            99
              Systems, Louisiana Coastal

    26        Operating Cost Offshore                           106

    27        Formation Water Treatment Equipment               107
              Costs, Offshore Installations, 200
              Barrels Per Day flow Rate

    28        Formation Water Treatment Equipment Costs,        108
              Offshore Installation, 1,000 Barrels
              Per Day Flow Rate

    29        Formation Water Treatment Equipment Costs,        109
              Offshore Installation, 5,000 Barrels Per
              Day Flow Rate

    30        Formation Water Treatment Equipment Costs,        110
              Offshore Installation, 10,000 Barrels
              Per Day Flow Rate

    31        Formation Water Treatment Equipment Costs,        111
              Offshore Installation, 40,000 Barrels
              Per Eay Flow Rate

    32        Capital Costs for Onshore Disposal by             113
              Reinjection of Produced Formation Water
              From Field Surveys in Selected  States
                              Vlll

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Table No.                Title                               Page No.

   33         Annual Operating Cost for Onshore Disposal      114
              by Reinjection of Produced Formation Water
              From Field  Surveys in Selected States

   34         Cost Estimates for Treatment in Ponds and       115
              Disposal  by Discharge for Stripper Well
              Facilities

   35         Cost Estimates for Treatment by Gas             116
              Flotation and Pond and Discharge for
              Beneficial  Dischargers

   36         Cost Estimates for Treatment by Gas             116
              Flotation and Discharge for Coastal
              Platforms

   37         Estimated Treatment Plant Costs for             119
              Sanitary  Wastes for Offshore Locations
              Package Extended Aeration Process

   38         Estimated Horsepower Requirements for the       120
              Operation of Flotation Treatment Systems

   39         Estimated Incremental Energy Requirements,      121
              Flotation Systems

   40         Energy Requirements for Flotation Systems       122
              as Compared to Net Energy Production
              Associated  with the Produced Water Flows

   41         Conversion  Table                                   154

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                         LIST OF FIGURES

Figure No.              Title                               Page No.

    1         Rotary Drilling Rig                               10

    2         Shale Shaker and Blowout                          11
              Preventer

    3         Central Treatment Facility in                     15
              Estuarine Area

    H         Horizontal Gas Separator                          16

    5         Vertical Heater-Treater                           18

    6         Rotor-Disperser and Cissolved Gas                 77
              Flotation Processes for Treatment
              of  Produced Water

    7         Onshore Production Facility with                  86
              Discharge to Surface Waters

    8         Typical Cross Section Unlined                     87
              Earthern Oil-Water Pit

    9         Typical Completion of an Injection                90
              Well and a Producing Well

    10        99th Percentile of Monthly Average Oil           131
              and Grease Concentration vs. Frequency
              of Sampling Each Month

    11        Cumulative Plot Effluent Concentrations          132
              of all Selected Flotation Units in the
              Louisiana Gulf Coast Area

    \±        Cumulative Plot of Effluent Concentrations       134
              of all Wyoming Data

    13        Cumulative Plot of Effluent Concentrations       141
              of Ten Selected Flotation Units in the
              Louisiana Gulf Coast Area

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                            SECTION I

                           CONCLUSIONS

This study covered the waste treatment technology for the Oil and
Gas Extraction Point Source Category.  The Oil and Gas Extraction
Point Source Category covers  the  pollutants  arising  from  the
production  of  crude petroleum and natural gas, drilling oil and
gas wells, and oil and gas field exploration services.

The  wastes  associated  with  this  category  result  from   the
discharge  of produced water, drilling muds, drill cuttings, well
treatment,  and  produced  sands  for   all   subcategories   and
additionally, deck drainage, sanitary and domestic wastes for the
offshore and coastal subcategories.

Since  the  raw  waste  loads  and treatability of the wastes are
independent of size, location  and  climate  and  the  volume  of
production  water varies with the age and nature of the producing
formation, the limitations are set in terms of concentration  and
the subcategorization is based on a balance of the costs with the
potential  environmental  benefits  and  energy  use  (loss).  The
subcategories developed for the oil and gas  extraction  industry
for  the  purpose  of  establishing  effluent  limitations are as
follows:

    Subcategory         Operations Included

1.  Near-offshore       All facilities within offshore State
                        waters.
2.  Far-Offshore        All facilities in Federal waters.
3.  Onshore             All facilities landward of the territorial
                        seas (except as defined by 4, 5, and 6
                        below).
4.  Coastal             All facilites in the coastal bays and
                        estuaries of Louisiana and Texas.
5.  Beneficial Use      These facilites with low TDS content
                        produced waters who* s discharge serves
                        some beneficial use.
6.  Stripper            All facilities with less than 10 barrels
                        of crude oil per calendar day of
                        production.

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                           SECTION II

                         RECOMMENCATIONS

The  significant   or   potentially   significant   waste   water
constituents are oil and grease, fecal coliform, oxygen demanding
parameters,  heavy  metals,  total  dissolved  solids,  and toxic
materials.  These waste water constituents were  selected  to  be
the subject of the effluent limitations.

Effluent  limitations  commensurate  with  the  best  practicable
control technology currently available  are  promulgated  interim
final for each sutcategory.  These limitations, listed in Table 1
are  explicit  numerical values (whenever possible)  or some other
criteria.

BPCTCA end-of-pipe technology is based on the application of  the
existing  waste  water  treatment processes currently used in the
Oil and Gas Extraction Industry.  These consist of  equalization,
chemical  addition, and gas flotation (or its equivalent) for the
treatment of produced water and deck drainage.   The  variability
of  performance  of this type of waste water treatment system has
been  recognized  in  the  development  of  the  BPCTCA  effluent
limitations.

Effluent   limitations   commensurate  with  the  best  available
technology  economically  achievable  are   proposed   for   each
subcategory.   These  effluent limitations are listed in Table 2.
The  primary  end-of-pipe  treatment  for   the   near   offshore
subcategory  is  the  subsurface disposal of production water and
for the far offshore  subcategory  it  is  similar  to  that  for
BPCTCA.

New  source  performance  standards  commensurate  with  the best
available demonstrated technology  are  the  same  as  the  BATEA
limitations.  These effluent limitations are listed in Table 2.

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Subcategory
A. Near Offshore
B. Far Offshore
D. Coastal
C. Onshore
E. Beneficial Use
Notes:
                                                  TABLE 1
                                       Oil and Gas Extraction Industry
                                        Effluent Limitations - BPCTCA
Water Source
produced water
deck drainage
drilling muds
drill cuttings
well treatment
sanitary M10
         M9IMC
domestic0
produced sand

produced water
drilling muds
drill cuttings
well treatment
produced sand
        Oil & Grease - mq/1
                       Residual Chlorine - mg/1
                                              Maximum for
                                              any one day
 72
 72
  a
  a
  a
N/A
N/A
N/A
  a
Average of daily
values for thirty
consecutive days
shall not exceed

     48^
     48d
       a
       a
       a
     N/A
     N/A
     N/A
       a
         no discharge
         no discharge
         no discharge
         no discharge
                     N/A
       N/A
       N/A
       N/A
       N/A
       N/A
greater than 1D
       N/A
       N/A
       N/A

       N/A
a - No discharge of free oil to the surface waters.
b - Minimum of 1 mg/1 and maintained as close to this concentration as possible.
c - There shall be no floating solids as a result of the discharge of these materials.
d - Not applicable to the Coastal subcategory.
e - For the onshore subcategory - no discharge;  for the beneficial use subcategory - 45 mg/1

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Subcategory
A. Near Offshore
D. Coastal

B. Far Offshore
A. Near Offshore
B. Far Offshore
C. Onshore
D. Coastal
E. Beneficial Use
Notes:
                                                TABLE  2
                                     Oil  and  Gas Extraction Industry
                              Effluent Limitations  -  BATEA and New Source
Water Source
produced water
deck drainage

produced water
deck drainage

drilling muds
drill cuttings
well treatment
sanitary M10
         M9IM
domestic
produced sand
                                                               Pollutant Parameter - Effluent Limitations
      Oil & Grease - mg/1
                    Residual Chlorine - mg/1
                                              Maximum for
                                              any one day
                                  Average of daily
                                  values for thirty
                                  consecutive days
                                  shall not exceed
 72

 52
 52

  a
  a
  a
N/A
N/A
N/A
  a
       No discharge
 48

 30
 30

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

       N/A
       N/A

       N/A
       N/A
       N/A
greater than 1
       N/A   -
       N/A
       N/A
a - These BAT and New Source limitations are identical  to those applicable for each
    subcategory as for BPT listed in Table 1.

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                           SECTION III

                          INTRODUCTION

Purpose and Authority

Section  301(b)  of  the  Federal  Water  Pollution  Control  Act
Amendments of  1972 requires the achievement  by  not  later  than
July  1,  1977,  of effluent limitations for point sources, other
than publicly owned treatment works.  The limitations are  to  be
based  on  application of the best practicable control technology
currently available as defined by the Administrator  pursuant  to
Section  304(b)  of  the  Act.  Section  301(b) also requires the
achievement by not later than July 1,  1983,  of  more  stringent
effluent limitations for point sources, other than publicly owned
treatment  works.   The  1983  limitations  are  to  be  based on
application  of  the  best  available   technology   economically
achievable  which  will  result  in  reasonable  further progress
toward the national goal of  eliminating  the  discharge  of  all
pollutants,  as  determined in accordance with regulations issued
by the Administrator pursuant to Section 304(b) of the Act.

Section 306 of the Act requires  the  Administrator,  within  one
year  after a category of sources is included in a list published
pursuant  to  section  306 (b)  (1) (A)  of  the  Act,   to   propose
regulations  establishing  Federal  standards of performances for
new sources within such categories.  The Administrator published,
in the Federal Register of January 16, 1973  (38  F.R.  1624) ,  a
list  of  27  source  categories.  Publication of an amended list
will constitute announcement of the Administrator's intention  of
establishing,   under   section  306,  standards  of  performance
applicable to new sources  within  the  Oil  and  Gas  Extraction
Industry.  The list will be amended when proposed regulations for
the  Oil and Gas Extraction Industry are published in the Federal
Register.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, processes, operating methods, or
other  alternatives;  where practicable, a standard may permit no
discharge of pollutants.

Section 304 (b) of the Act requires the Administrator  to  publish
within  one  year  of enactment of the Act, regulations providing
guidelines for effluent limitations.  The guidelines are  to  set
forth:

The  degree  of effluent reduction attainable through application
of the best practicable control technology currently available.

The degree of effluent reduction attainable  through  application
of   the   best   control  measures  and  practices  economically

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achievable including treatment techniques, process and  procedure
innovations, operating methods, and other alternatives.

The  findings  contained  herein  set  forth effluent limitations
guidelines pursuant to Section 304(b)  of  the  Act  for  certain
segments of the petroleum industry.

General Description of Industry

The  segments of the industry to be covered by this study are the
following Standard Industrial Classifications (SIC):

         1311  Crude Petroleum and Natural
               Gas

         1381  Drilling Oil 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  activities
carried out both onshore and in the estuarine, coastal, and outer
Continental Shelf areas.

The   characteristics  of  wastes  differ  considerably  for  the
different processes and operations.  In  order  to  describe  the
waste derived from each of the industry subcategories established
in  Section  IV,  it  is  essential  to  evaluate the sources and
contaminants in the three broad activities in  the  oil  and  gas
industry—exploring,  drilling,  and  producing—as  well  as the
satellite industries that support those activities.

Exploration

The exploration process usually consists of  mapping  and  aerial
photography  of  the  surface  of  the earth, followed by special
surveys such as seismic, gravimetric, and magnetic, to  determine
the  subsurface  structure.  The special surveys may be conducted
by vehicle, vessel,  aircraft,  or  on  foot,  depending  on  the
location and the amount of detail needed.

These  surveys  can  suggest  underground conditions favorable to
accumulation of oil or gas deposits, but they must be followed by
the drill since only drilling can prove the actual  existence  of
oil.

Aside  from  sanitary wastes generated by the personnel involved,
only the drilling  phase  of  exploration  generates  significant
amounts  of  water  pollutants.   Exploratory  drilling,  whether
                               8

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shallow or deep, generally uses the same rotary drilling  methods
as  development  drilling.  The discussion of wastes generated by
exploratory drilling are discussed under "Drilling System".

Drilling System

The majority of wells  drilled  by  the  petroleum  industry  are
drilled  to  obtain  access  to  reservoirs  of  oil  or  gas.  A
significant number, however, are drilled  to  gain  knowledge  of
geologic  formation.   This  latter class of wells may be shallow
and drilled in the initial exploratory phase  of  operations,  or
may  be  deep  exploration seeking to discover oil or gas bearing
reservoirs.

Most  wells  are  drilled  today  by  rotary  drilling   methods.
Basically the methods consist of:

    1.   Machinery to turn the bit, to add sections on the  drill
         pipe  as  the hole deepens, and to remove the drill pipe
         and the bit from the hole.

    2.   A system for circulating a fluid down through the  drill
         pipe and back up to the surface.

This  fluid  removes  the  particles  cut  by  the bit, cools and
lubricates the bit as it cuts, and, as the well deepens, controls
any pressures that the bit may encounter in its  passage  through
various  formations.   The fluid also stabilizes the walls of the
well bore.

The drilling fluid system consists of tanks to formulate,  store,
and  treat the fluids; pumps to force them through the drill pipe
and back to the surface; and machinery to remove cuttings, fines,
and gas from fluids returning to the surface (see Figure  1).   A
system  of  valves  controls the flow of drilling fluids from the
well when pressures are so great that they cannot  be  controlled
by weight of the fluid column.  A situation where drilling fluids
are  ejected  from  the well by subsurface pressures and the well
flows uncontrolled is called a blowout, and the controlling valve
system is called the blowout preventer (see Figure 2).

For  offshore  operations,  drilling  rigs  may  be   mobile   or
stationary.   Mobile  rigs  are  used  for  both  exploratory and
development  drilling,  while  stationary  rigs  are   used   for
development  drilling  in  a  proven field.  Some mobile rigs are
mounted on barges and rest on the bottom for drilling in  shallow
waters.   Others,  also mounted on barges are jacked up above the
water on legs for drilling in deeper water (up to 300  feet).   A
third  class of mobile rigs are on floating units for even deeper
operations.  A floating rig may  be  a  vessel,  with  a  typical
ship's hull, or it may be semisubmersible—essentially a floating
platform  with  special submerged hulls and supporting a rig well

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                        A KELLY
                        B STANDPIPE and  ROTARY HOSE
                        C SHALESHAKER
                        D OUTLET FOR DRILLING  FLUID
                        E SUCTION TANK
                        F PUMP

                          FLOW OF DRILLING FLUID
Fig.  1    — ROTARY  DRILLING RIG

               10

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j 	 --••?—
n
fit
il
^ 	 A
h — :>
  CASING
            1
DRILL PIPE
DRILL  BIT
A  KELLY
C  SHALESHAKER
D  OUTLET FOR DRILLING  FLUID
G  HYDRAULICALLY OPERATED  BLOWOUT  PREVENTER
H  OUTLETS, PROVIDED WITH VALVES
      AND CHOKES FOR  DRILLING FLUID
— FLOW OF DRILLING FLUID
             Fig. 2 -- SHALESHAKER AND BLOWOUT PREVENTER
                           11

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above the water.
platforms.
Stationary rigs are mounted  on  pile-supported
Onshore  drilling  rigs  used today are almost completely mobile.
The derrick or mast and all drilling machinery are  removed  when
the well is completed and used again in a new location.

Rigs  used  in  marsh areas are usually barge mounted, and canals
are dredged to the drill sites so that the rigs  can  be  floated
in.

The  major  source  of  pollution  in  the drilling system is the
drilling fluid or "mud" and the cuttings from the bit.  In  early
wells drilled by the rotary method, water was the drilling fluid,
The  water mixed with the naturally occurring soils and clays and
made up the mud.   The  different  characteristics  and  superior
performance  of  some  of  these  natural  muds  were  evident to
drillers,  which  led  to  deliberately  formulated  muds.    The
composition of modern drilling muds is quite complex and can vary
widely,  not only from one geographical area to another, but also
in different portions of the same well.

The drilling of a well from top to bottom  is  not  a  continuous
process.   A  well is drilled in sections, and as each section is
completed it is lined with a  section  of  pipe  or  casing   (see
Figure 2).  The different sections may require different types of
mud.   The  mud from the previous section must either be disposed
of or converted for the next section.  Some mud is  left  in  the
completed well.

Basic  mud components include:  bentonite or attapulgite clays to
increase viscosity and create a gel; barium sulfate   (barite),  a
weighting agent; and lime and caustic soda to increase the pH and
control  viscosity.    (Additional  conditioning  constituents may
consist of polymers, starches,  lignitic  material,  and  various
other  chemicals).  Most muds have a water base, but some have an
oil base.  Oil based muds are  used  in  special  situations  and
present   a  much  higher  potential  for  pollution.   They  are
generally used where bottom hole temperatures are  very  high  or
where  water  based  muds  would hydrate water-sensitive clays or
shales.  They may also be used to  free  stuck  drill  pipes,  to
drill in permafrost areas, and to kill producing wells.

As the drilling mud is circulated down the drill pipe, around the
bit,  and  back up in annulus between the bore hole and the drill
pipe, it brings with it the material cut and loosened by the bit,
plus fluids which may enter the hole from the  formation   (water,
oil,  or  gas) .   When  the mud arrives at the surface, cuttings,
silt, and  sand  are  removed  by  shaleshakers,  desilters,  and
desanders.   Oil  or  gas from the formation is also removed, and
the cleansed mud is cycled through  the  drilling  system  again.
With  offshore  wells, the cuttings, silt and sand are discharged
                                12

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overboard if they do not contain oil.  Some drilling  mud  clings
to  the  sand  and  cuttings,  and when this material reaches the
water the heavier particles  (cuttings  and  sand)   sink  to  the
bottom  while  the mud and fines are swept down current away from
the platform.

Onshore, discharges from the shaleshakers and cyclone  separators
(desanders  or  desilters)   usually  go to an earthen (slush)  pit
adjacent to the rig.  To dispose of  this  material  the  pit  is
backfilled at the end of the drilling operations.

The  removal of fines and cuttings is one of a number of steps in
a continuing process of mud  treatment  and  conditioning.   This
processing  may  be done to Jceep the mud characteristics constant
or to change them as required by the drilling  conditions.   Many
constituents  of  the  drilling  mud  can  be  salvaged  when the
drilling is completed, and salvage plants may exist either at the
rig or at another location, normally at the  industrial  facility
that supplies mud or mud components.

Where drilling is more or less continuous, such as on a multiple-
well  offshore  platform,  the  disposal  of  mud should not be a
frequent occurrence since it can fce conditioned and recycled from
one well to another.

The drilling of deeper, hotter holes  may  increase  use  of  oil
based  mud.   However,  new mud additives may permit use of water
based muds where only oil muds would  have  served  before.   Oil
muds always present disposal problems.

Production System

Crude  oil,  natural  gas,  and gas liquids are normally produced
from geological reservoirs through a  deep  bore  well  into  the
surface  of  the  earth.   The fluid produced from oil reservoirs
normally consists of oil, natural gas, and salt  water  or  brine
containing  both  dissolved  and suspended solids.   Gas wells may
produce dry gas but usually also produce  varying  quantities  of
light  hydrocarbon  liquids  (known as gas liquids or condensate)
and salt water.  As in the case of oil field  brines,  the  water
contains   dissolved   and   suspended   solids  and  hydrocarbon
contaminants.  The suspended solids are normally sands, clays, or
other fines from the reservoir.  The oil can vary widely  in  its
physical  and chemical properties.  The most important properties
are its density and viscosity.   Density is  usually  measured  by
the  "API Gravity" method which assigns a number to the oil based
on its specific gravity.  The  oil  can  range  from  very  light
gasoline  like  materials  (called  natural  gasolines)  to heavy,
viscous asphalt like materials.

The fluids are normally moved through tubing contained within the
larger cased bore hole.  For oil wells, the  energy  required  to
                               13

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lift  the  fluids  up  the  well  can  be supplied by the natural
pressures in the formation, or it can be provided or assisted  by
various  man-made  operations  at  the  surface.  The most common
methods of supplying man-made energy to extract the oil are:   to
inject  fluids   (normally  water  or  gas)   into the reservoir to
maintain pressure, which would otherwise drop during  withdrawal;
to  force gas into the well stream in order to lighten the column
of fluid in the bore and assist in lifting as the gas expands  up
the  well;  and  to  employ  various  types  of pumps in the well
itself.  As the fluids rise in the well to the surface, they flow
through various valves and flow control devices which make up the
well head.  One of these is an orifice  (choke)  which  maintains
required  back  pressure  on the well and controls, by throttling
the fluids, the rate at which the well can flow.  In some  cases,
the  choke is placed in the bottom of the well rather than at the
well head.

Once at the surface,  the  various  constituents  in  the  fluids
produced  by  oil  and  gas  wells  are  separated:  gas from the
liquids, 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 disposed of after further treatment.  At
this stage, the gas may  still  contain  significant  amounts  of
hydrocarbon  liquids and may be further processed to separate the
two.

The gas, oil, and water may be separated in a single  vessel  or,
more  commonly,  in several stages.  Some gas is dissolved in the
oil and comes out of solution  as  the  pressure  on  the  fluids
drops.   Fluids  from  high-pressure  reservoirs  may  have to be
passed through a number  of  separating  stages  at  successively
lower pressures before the oil is free of gas.  The oil and brine
do  not separate as readily as the gas does.  Usually, a quantity
of oil and water is present as an emulsion.   This  emulsion  can
occur  naturally  in  the  reservoir  or can be caused by various
processes which tend to mix the oil and water vigorously together
and cause droplets to form.  Passage of the fluids  into  and  up
the  well  tends  to mix them.  Passage through well head chokes,
through  various  pipes,  headers,  and   control   valves   into
separation  chambers,  and  through  any centrifugal pumps in the
system,  tends  to  increase  emulsification.    Moderate   heat,
chemical  action,  and/or  electrical  charges  tend to cause the
emulsified liquids to separate or coalesce, as does  the  passage
of  time  in  a  quiet environment.  Other types of chemicals and
fine  suspended  solids  tend   to   retard    coalescence.    The
characteristics  of  the  crude  oil  also  affect  the  ease  or
difficulty of achieving process separation.(1)

Fluids produced by oil and gas wells are usually introduced  into
a series of vessels for a two-stage separation process.  Figure 4
shows  a  gas  separator for separating gas from the well stream.

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                                      CENTRAL TREATMENT FACILITY IN ESTUARINE AREA
                                                      HIGH PRESSURE GAS
Ln
                              II-  L.    XL    Jl
                               Fig.   3   .— CENTRAL TREATMENT FACILITY IN ESTUARINE AREA

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A  B
                     C-DE-FOAMING
 A-OIL AND GAS INLET     ELEMENT           E_M|SJ EXTRACTOR   6-DRAIN
                     D-WAVE BREAKER AND
 B-IMPACT ANGLE
SELECTOR PLATE
F-GAS OUTLET
  H-OIL OUTLET
(DUMP VALVEl
                  Fig.  4   —  HORIZONTAL GAS SEPARATOR

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Liquids (oil or oil and  water)  along  with  particulate  matter
leave  the separator through the dump valve and go on to the next
stage:  oil-water separation.  Because gas comes out of  solution
as  pressure  drops,  gas-oil  separators  are  often arranged in
series.  High-pressure, intermediate, and low-pressure separators
are the most common arrangement, with the  high-pressure  liquids
passing  through  each stage in series and gas being taken off at
each stage.  Fluids from lower-pressure wells would  go  directly
to the most appropriate separator.  The liquids are then piped to
vessels  for  separating  the oil from the produced water.  Water
which is not emulsified and separates easily may be removed in  a
simple separation vessel called a free water knockout.

The  remaining  oil-water mixture will continue to another vessel
for more elaborate treatment  (see  Figure  5) .   In  this  vessel
(which  may  be called a heater-treater, electric dehydrator, gun
barrel,  or  wash  tank,  depending  on  configuration  and   the
separation  method employed), there is a relatively pure layer of
oil on the top, relatively pure trine on the bottom, and a  layer
of  emulsified  oil  and brine in the middle.  There is usually a
sensing unit to detect the oil-water interface in the vessel  and
regulate   the   discharge  of  the  fluids.   Emulsion  breaking
chemicals are often added before the liquid enters  this  vessel,
the  vessel  itself  is  often  heated to facilitate breaking the
emulsion, and some units employ an electrical grid to charge  the
liquid  and  to  help  break  the  emulsion.   A  combination  of
treatment methods is often  employed  in  a  single  vessel.   In
three-phase  separation, gas, oil, and water are all separated in
one unit.  The gas-oil and oil-water interfaces are detected  and
used to control rates of influent and discharge.

Oil from the oil-water separators is usually sufficiently free of
water  and sediment (less than 2 percent) so as to be marketable.
The produced water or produced water/solids  mixtures  discharged
at this point contain too much oil to be disposed of into a water
body.   The object of processing through this point is to produce
marketable products (clean oil and dry gas).   In  contrast,  the
next  stages  of treatment are necessary to remove sufficient oil
from the produced water so that  it  may  be  discharged.   These
treatment operations do not significantly increase the quality or
quantity of the saleable product.  They do decrease the impact of
these wastes on the environment.

Typical  produced  water  from  the  last  stage of process would
contain several hundred to perhaps a thousand or more  parts  per
million  of  oil.   There are two methods of disposal:  treatment
and discharge to  surface   (salt)  waters  or  injection  into  a
suitable subsurface formation in the earth.  Surface discharge is
normally  used  offshore  or  near  shore where bodies of salt or
brackish water are available for disposal.  Injection  is  widely
used  onshore  where  bodies  of salt water are not available for
                               17

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                                                                                GAS OUT
                                         OAS OUTLET
                            EMULSION
                              INLET
          EXCELSIOR
(OTHER TYPES OF UNITS
MIGHT CONTAIN THE GRID
OF AN ELECTRIC DEHYDRATOR
IN PLACE OF THE FILTER SECTION)
            OILOUT
                                                                                    WATER OUT
                  EMULSION IN
                                    Fig.   5    —  VERTICAL HEATER-TREATER
                                            18

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surface disposal.  (produced water to be disposed of by injection
may still require some treatment).

Some of the same operations used to facilitate separation in  the
last  stage of processing (chemical addition and retention tanks)
may be used in waste water treatment, and other methods  such  as
filtering,  and  separation  by  gas flotation are also used.  In
addition,  combinations  of  these  operations  can  be  used  to
advantage to treat the waste water.  The vast majority of present
offshore  and near shore (marsh) facilities in the Gulf of Mexico
and most facilities in Cook Inlet, Alaska, treat and  dispose  of
their produced water to surface salt or brackish water bodies.

The  sophistication  of  the treatment employed by dischargers of
produced water is dependent upon the  regulation  governing  such
discharges.  For instance in the Appalachian states most produced
water  is  discharged  to  local  streams after only treatment in
ponds; while in California dischargers utilize a high  degree  of
treatment.   The state of Wyoming allows discharge for beneficial
use if  the  produced  water  meets  oil  and  grease  and  total
dissolved solids (IDS) requirements.

Several  options are available in injection systems.  Often water
will be injected into  a  producing  oil  reservoir  to  maintain
reservoir  pressure,  and  stabilize  reservoir conditions.  In a
similar operation called water flooding, water is  injected  into
the reservoir in such a way as to move oil to the producing wells
and  increase  ultimate recovery.   This process is one of several
known as secondary recovery since it  produces  oil  beyond  that
available  by  primary  production  methods.   A successful water
flooding project will increase the amount of oil  being  produced
at a field.  It will also increase produced water volume and thus
affect  the  amount  of  water  that  must  be treated.  Pressure
maintenance of water injection may also increase  the  amount  of
water produced and treated.  Injection is also feasible solely as
a disposal method.  It (injection) is extensively used in onshore
production areas except in the Appalchian states of Pennsylvania,
West  Virginia,  New  York  and  Kentucky,  where useable shallow
horizons do  not  exist.   In  California,  produced  water  from
offshore  facilities  is  transported  to  shore  for disposal by
reinjection.

The  treatment  associated  with  produced  water   disposal   by
injection  is  dependent  upon  the permeability of the receiving
formation.  In most all cases corrosion-inhibiting chemicals  are
necessary,  but the treatment can range from simply skim tanks to
gas flotation followed by mixed-media filtration.

Evolution of Facilities

Early offshore development tended to place  wells  on  individual
structures,   bringing  the  fluids  ashore  for  separation  and
                               19

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treatment  (see  figure  3),   As  the  industry  moved   farther
offshore,  the  wells  still  tended  to be located on individual
platforms with the output to a central platform  for  separation,
treatment,  and  discharge  to a pipeline or barge transportation
system.

With  increasing  water  depth,  multiple-well   platforms   were
developed  with  20  or  more  wells drilled directionally from a
single platform.  Thus an entire field or a large  portion  of  a
field  could be developed from one structure.  Offshore Louisiana
multiple-well platforms include all processing and treatment,  in
offshore  California ard in Cook Inlet facilities, gas separation
takes place on the  platforms,  with  the  liquids  usually  sent
ashore for separation and treatment.

All forms of primary and secondary recovery as well as separation
and  treatment  are  performed  on  platforms,  which may include
compressor 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 operating environment.   Cook  Inlet
platforms  are enclosed for protection from the elements and have
a structural support system designed to withstand ice  floes  and
earthquakes.  Gulf Coast platforms are usually open, reflecting a
mild   climate.    Support  systems  are  designed  to  withstand
hurricane-generated waves.

A typical onshore production facility would consist of wells  and
flowlines,  gas-liquid  and  oil-water  production  separators, a
waste  water  treatment  unit   (the  level  of  treatment   being
dependent  on  the  quality of the waste water and the demands of
the injection system and receiving reservoir) ,  surge  tank,  and
injection   well.    Injection   might  either  be  for  pressure
maintenance and secondary recovery or solely  for  disposal.   In
the  latter  case, the well would probably be shallow and operate
at lower pressure.  The system might include a pit to hold  waste
water should the injection system shut down.

A  more  recent  production  technique and one which may become a
significant source of waste in the  future  is  called  "tertiary
recovery."  The process usually involves injecting some substance
into the oil reservoir to release or carryout additional oil  not
recovered by primary recovery  (flowing wells by natural reservoir
pressure, pumping, or gas lift) or by secondary recovery.

Tertiary recovery is usually classified by the substance injected
into the reservoir and includes:

    1.   Thermal recovery

    2.   Miscible hydrocarbon
                               20

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    3.   Carbon dioxide

    4.   Alcohols, soluble oil, micellar solutions

    5.   Chemical floods,  surfactants

    6.   Gas, gas/water, inert gas

    7.   Gas repressuring, depletion

    8.   Polymers

    9.   Foams, emulsions, precipitates

The material is injected into the reservoir and moves through the
reservoir  to  the  producing  wells.   During  this  passage, it
removes and carries  with  it  oil  remaining  in  pores  in  the
reservoir rocks or sands.  Oil, the injected fluid, and water may
all  be  moved  up the well and through the normal production and
treatment system.

Nine economically successful applications  of  tertiary  recovery
have  been  documented   (two  of  them  in Canadian fields):  one
miscible hydrocarbon application;  three  gas  applications;  two
polymer   applications,   and   three  combinations  of  miscible
hydrocarbon with gas drive.

At this time very little is known about the wastes that  will  be
produced  by  these  production  processes.   They will obviously
depend on the type of tertiary recovery used.

Field Service

A number of satellite industries specialize in providing  certain
services  to  the  production  side of the oil industry.  Some of
these service industries produce a particular class of waste that
can be identified with the service they provide.  Of  the  waste-
producing  service industries, drilling (which is usually done by
a contractor) is the largest.  Drilling fluids and their disposal
have already been discussed.  Other services include completions,
workovers, well acidizing, and well fracturing.

When a company decides that an oil or gas well  is  a  commercial
producer,  certain equipment will be installed in the well and on
the well head to bring the well into production.   The  equipment
from  this  process—called  "completion"—normally  consists  of
various valves and sealing  devices  installed  on  one  or  more
strings  of  tubing  in  the  well.  If the well will not produce
sufficient fluid by natural flow, various types of pumps  or  gas
lift  systems  may be installed in the well.  Since heavy weights
and high lifts are normally involved, a rig is usually used.  The
                               21

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rig may be the same one that drilled the well, or  it  may  be  a
special   (normally  smaller) workover rig installed over the well
after the drilling rig has been moved.

After a well has been in service for a while it may need remedial
work to keep it producing at an acceptable  rate.   For  example,
equipment in the well may malfunction, different equipment may be
required,  or  the  tubing  may  become plugged up by deposits of
paraffin.  If it is necessary to remove and reinstall the  tubing
in  the well, a workover rig will be 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 systeir, tools may be forced into  the
well by pumping them down with fluid.  Where possible, the use of
a rig is avoided, since it is expensive.

In  many  wells,  the  potential  for  production  is  limited by
impermeability  in  the  producing  geological  formation.   This
condition may exist when the well is first drilled, it may worsen
with  the passage of time, or both situations may occur.  Several
methods may be used, singly or in combination,  to  increase  the
well  flow  by altering the physical nature of the reservoir rock
or sand in the immediate vicinity of the well.

The two most common methods to increase well flow  are  acidizing
and  fracturing.   Acidizing  consists  of introducing acid under
pressure through the well and into the producing formation.   The
acid  reacts with the reservoir material, producing flow channels
which allow a larger volume of fluids  to  enter  the  well.   In
addition  to  the acid, corrosion inhibitors are usually added to
protect the metal in the well system.  Wetting agents,  solvents,
and other chemicals may also be used in the treatment.

In  fracturing,  hydraulic  pressure  forces  a  fluid  into  the
reservoir, producing fractures, cracks, and channels.  Fracturing
fluids may contain acids so that chemical disintegration, as well
as fracturing takes place.  The fluids also contain sand or  some
similar  material  that  keeps the fracture propped open once the
pressure is released.

When a new well is being completed or when  it  is  necessary  to
pull  tubing to worx over a well, the well is normally "killed"—
that is, a column of drilling mud, oil, water, or other liquid of
sufficient weight is introduced into the well to control the down
hole pressures.

When the work is completed, the liquid used to kill the well must
be removed so that the well will flow again.  If mud  is used, the
initial flow of oil from the well will be contaminated  with  the
mud  and  must  be  disposed of.  Offshore, it may be disposed of
into the  sea if  it  is  not  oil  contaminated,  or  it  may  be
salvaged.   Onshore, the mud may te  disposed of in pits or may be
                                22

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

In acidizing and fracturing, the spent fluids  used  are  wastes.
They  are  moved  through  the production, process, and treatment
systems after the well begins to flow again.  Therefore,  initial
production  from  the  well  will  contain  some of these fluids.
Offshore, contaminated oil and other liquids  are  barged  ashore
for treatment and disposal; contaminated solids are buried.

The fines and chemicals contained in oil from wells put on stream
after  acidizing  or  fracturing  have  seriously upset the waste
water treatment units of production facilities.  When the sources
of these upsets have been  identified,  corrective  measures  can
prevent or mitigate the effects. (2)

Industry Distribution

1974,  domestic  production was 8.8 million barrels-per-day  (bpd)
of oil and 1.7 million bpd of gas liquids, for a total production
of 10.5 bpd; down slightly from  the  four  previous  years.  (3)
Total imports were 6.1 million bpd for 1974.

There  are  approximately  half a million producing oil wells and
126,000 gas and condensate wells in the United  States.   Of  the
30,000  new wells drilled each year, about 55 percent produce oil
or gas.

Oil is presently produced in 32 of the 50  states  and  from  the
Outer  Continental  Shelf   (OCS)  off  of  Louisiana,  Texas, and
California.  Exploratory drilling is underway on the OCS  off  of
Mississippi,  Alabama,  and  Florida.   In 1972, the five largest
oil-producing States were: Texas, Louisana, California, Oklahoma,
and Wyoming.  With development of the North Slope oil fields  and
construction  of  the  Alaska pipeline, Alaska will become one of
the most important oil producing States.

Offshore oil production is presently concentrated in three  areas
in  the  United  States:   the  Gulf  of  Mexico,  the  coast  of
California, and Cook Inlet in Alaska.  Offshore oil production in
1973 was approximately 62 million barrels from  Cook  Inlet,  116
million  from  California,  and  215  million  from Louisiana and
Texas,

Gulf of Mexico - Texas and Louisiana

Approximately 2,000 wells now produce oil and gas in State waters
in the Gulf of Mexico and 6,000 on the OCS.  Over 90 percent  are
in  Louisiana,  with  the remainder in Texas.  Recent lease sales
have been held on the OCS off  Texas  and  off  the  Mississippi,
Alabama, and Florida coasts.  Discoveries have been made in those
areas,  and  development  will take place as quickly as platforms
                               23

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can be installed, development drilling completed,  and  pipelines
laid.

Leases  have  been  granted  in water as deep as 600 feet.  These
deep areas will probably  be  served  by  conventional  types  of
platforms,   but  their  size  and  cost  increase  rapidly  with
increasing depth.

In addition to offshore activities, onshore production  in  Texas
for 1974 accounted for 1,226 million barrels of oil and 7,942,352
million cubic feet of gas, the largest contribution of any state.
Oil production has been on a decline in Texas since the peak year
of  1972.   Oil  and  gas  production  in  Texas  is  widespread,
involving 212 out of 254 counties and approximately 165,000  gas,
condensate,  and  crude  oil wells.  The amount of produced water
generated is dependent on the method of oil  production  and  the
field location.  Higher water cut ratios are experienced near the
Gulf.   Regulation  by  the  State  Railroad Commission prohibits
discharge of produced water to fresh water bodies, and  therefore
reinjection   for  recovery  and  disposal  technology  has  been
developed to a high degree.

Onshore activity in Louisiana is also significant, accounting for
307 million barrels of crude in 1974 originating from 61  out  of
the 64 parishes  (counties) in the State.  There are approximately
11,500  wells  producing  crude  oil  onshore  and  less than one
percent of these wells are in the stripper  category   (less  than
ten barrels per day production).  Of the 1,068 million barrels of
produced  water generated in 1974 the majority was rexnjected for
either  recovery  or  disposal  purposes;   the   remainder   was
discharged  to  unlined  puts, saltwater estuaries or fresh water
streams.  The  discharge  of  production  water  to  fresh  water
streams is limited to the southern and central parts of the State
where   drilling   of  reinjection  wells  is  extremely  costly.
Discharge to saltwater estuaries  is  practiced  along  the  Gulf
Coast.   Treatment  prior to discharge consists of skim tanks and
settling/separator ponds.  Where  reinjection  is  practiced  the
facilities are unsophisticated, consisting of a primary separator
and sedimentation.  The disposal formations are at 2000-5000 foot
depth and are very permeable, resulting in low well head pressure
and  power  costs.  Approximately 60% of the oil production under
State onshore leases is generated at facilities  which  discharge
their produced water.

California

There  has  been a general moratorium on drilling and development
in the offshore areas  of  California  since  the  Santa  Barbara
blowout of 1969.  (4)

Present  offshore  production in State waters comes from the area
around Long Beach and Wilmington and also from the Santa  Barbara
                               24

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area  farther  north.   OCS  production  is confined to the Santa
Barbara area.  Except for one facility, all production from  both
State  and Federal leases is piped ashore for treatment.   A large
and increasing amount of the produced brine  is  disposed  of  by
subsurface injection.

Exxon  Corporation  has  applied  for  permits to develop an area
leased prior to 1969 in the northern Santa Barbara  Channel  (the
"Santa Ynez Unit").  Several fields have been discovered on these
leases  in  water  depths  from 700 to over 1,000 feet.  Proposed
development of the shallower portion of one of these areas  calls
for  erection of a multiple-well drilling and production platform
in 850 feet of water.  If gas and oil  are  found  in  commercial
quantities,  the gas would be separated on the platform,  with the
water and oil sent ashore for separation and treatment.  Produced
water would be disposed of by subsurface injection ashore.

Additional lease sales have  been  made  on  the  OCS  off  Santa
Barbara in Southern California.

Total oil production in California for 1974 was approximately 390
million barrels (83 million barrels offshore), a decline from the
previous  year.   In  addition  to offshore facilities, the major
areas of production in California are in the southern San Jacquin
Valley, centered around the city of Bakersfield, and in the  Long
Beach-Wilmington  area.   In  California,  steam,  hot water, and
water flooding methods of secondary recovery are used.  The total
produced water is approximately 2,044 million barrels  per  year,
the  majority  of  which  is  either  reinjected  for recovery or
disposal or evaporated in ponds.  Only  eight  producers  in  the
State have discharge to navigable waters.

Cook Inlet, Alaska

Offshore  production  in  Cook  Inlet comes from 14 multiple-well
platforms on four oil fields and one gas field.  Development took
place in the 1960's and has been relatively static for the past 5
years.  The demarcation line between Federal and State waters  in
lower  Cook  Inlet  is  under litigation.  The settlement of this
dispute  will  probably  lead  to  leasing  and  development   of
additional areas in the Inlet.

Present practice is to separate gas on the platforms, sending the
produced water and oil ashore for separation and treatment.  Some
platforms are producing increasing amounts of produced water, and
this,  plus  the  occasional plugging of oil/water pipelines with
ice  in  the  winter,  will  encourage  a  change   to   platform
separation, treatment, and disposal of produced waters.

Cook  Inlet  platforms are presently employing gas lift and treat
Inlet sea water for water flooding.
                               25

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Appalachia - Pennsylvania

Oil was discovered  over  100  years  ago  in  Pennsylvania,  the
earliest  discovery  in  the  United  States.  Today the State of
Pennsylvania's  oil   production   industry,   like   the   other
Appalachian  states,  is  characterized by marginal production of
0.3 barrles per day per well average  for  the  31,000  producing
wells  in  the  State,  operating  on approximately 2,300 leases.
Although the amount of oil production is low (only  0.1%  of  the
U.S.  total), Pennsylvania crudes supply 20% of all U.S. lube oil
production.  Small independent operators dominate  the  industry,
accounting  for  65-70*  of  the  production.  The oil fields are
located primarily in the northwest section of the  State,  McKean
County  alone  accounting for 50* of the State's production.  The
oil-bearing strata is shallow  (1000-2000  feet)  and  relatively
impermeable  (1-20 millidarcies).

All  produced  water  generated  is  discharged  to  the  surface
following ripple aeration and separation/sedimentation in earthen
ponds.  Where water flooding is practiced, ground water  is  used
after  treatment  as  the source.  There are plans on some of the
larger leases to utilize production water for  flooding,  despite
earlier  failure  of  this  method from plugging of the formation
strata.  Current discharge practices are in part justified by the
absence  of  formations  acceptable  for   reinjection   due   to
permeability,  surface  outcroppings,  lack  of  void  space  and
substandard well abandonment procedures in the past.

Industry Growth

From 1960 to 1970, the Nation's demand for energy increased at an
average rate  of  4.3  percent.   Table  3  gives  the  projected
national  demands  for  oil  and gas through 1985 and Table H the
U.S. offshore oil production from 1970 through  1973.

U.S. offshore production declined  by  about  78,500  barrels/day
from  1972 to 1973.  Offshore production amounts to approximately
10  percent  of  U.S.  demand  and  about   15  percent  of   U.S.
production.

While  offshore  production  declined slightly from 1972 to 1973,
the potential for increasing offshore production is much  greater
than  for  increasing  onshore production.  The Department of the
Interior has proposed a schedule of three or four lease sales per
year through 1978, mainly on remaining acreage  in  the  Gulf  of
Mexico  and  offshore  California.  Additional areas in which OCS
lease sales will very  probably  be  held   by   1978  include  the
Atlantic  Coast   (George's  Bank,  Baltimore  Canyon, and Georgia
Embayment) and the Gulf of Mexico.
                                26

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Not only will new areas be opened  to  exploration  and  ultimate
development,  but  production will move farther offshore and into
deeper waters in areas of present development.

Movement into more distant and isolated  environments  will  mean
even  more  self-sufficiency  of  platform  operations,  with all
production, processing, treatment, and disposal  being  performed
on  the  platforms.  Movement into deeper waters will necessitate
multiple-well structures, with a maximum number of wells  drilled
from a minimum number of platforms.

Offshore  leasing,  exploration,  and  development  will  rapidly
expand over the next 10 years, and offshore production will  make
up an increasing proportion of our domestically produced supplies
of gas and oil.
                               27

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                             TABLE 3



               U.S. Supply and Demand of Petroleum



                       and Natural Gas  (5)



                                             1971    1980   1985



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
% of Total U.S. Energy Demand
Projected Domestic Supply
% gas demand fulfilled
by domestic supply
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

                             TABLE 4



    U.S. Offshore Gil Production - (million barrels/day)  (6)



         1970           1971            1972            1973




         1.58           1.69            1.67            1.59
                               28

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                           SECTION III

                          Bibliography


1.  University of Texas-Austin/ Petroleum Extension Service,  and
    Texas  Education Agency, Trade and Industrial Serivce.  1962.
    "Treating Oil Field Emulsions." 2nd. ed. rev.

2.  Gidley, J.L. and Hanson, H.R.  1974.  "Central-Terminal Upset
    from Well Treatment is Prevented."  Oil and Gas Journal, Vol.
    72: No. 6: pp. 53-56.

3.  Independent Petroleum Association of America.  "United States
    Petroleum Statistics 2974  (Revised)." Washington, D.C.

4.  U.S. Department of the Interior,   Geological  Survey.   1973.
    Draft  Environment  Impact Statement.  Vol. 1:  Proposed Plan
    of Development Santa Ynez Unit, Santa  Barbara  Channel,  Off
    California." Washington, DC

5.  Dupree, W.G., and West, J.A.  1972.   "United  States  Energy
    Through   the   Year  2000."  U.S.  Department  of  Interior.
    Washington, D.C.

6.  McCaslin, John C.  1974.  "Offshore  Oil  Production  Soars."
    Oil and Gas Journal, Vol. 72: No. 18: pp. 136-142.
                               29

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                           SECTION IV

                   INDUSTRY SUBCATEGORIZATION

Rationale For Subcategorization

The  Standard  Industrial Classification's subcategorize industry
into various groups for  the  purpose  of  analyzing  production,
employment,  and  economic  factors  which  are  not  necessarily
related to the type of wastes  generated  by  the  industry.   In
development of the effluent limitations and standards, production
methodology,   waste  characteristics,  and  other  factors  were
analyzed  to  determine  if  separate  limitations  need  to   be
designated for different segments of the industry.  The following
factors   were  examined  for  delineating  different  levels  of
pollution control technology  and  possibly  subcategorizing  the
industry:

    1.   Type of facility or operation

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

    3.   Process technology

    4.   Climate

    5.   Waste water characteristics

    6.   Location of facility

Field  surveys,  waste  treatment  technology,  and effluent data
indicate  that  the  most  important  factors  are  the  type  of
facility,  the  facility's  size,  age, waste water volume, waste
water characteristics, and location.  The factor  of  climate  is
significant  with  respect  to operational practices but has less
influence on waste treatment technology.  Process technology  was
found to have very little influence on the selection of pollution
control technology.

An  evaluation of industry's production units  (barrels of oil per
day or thousands of cubic feet of gas per day) and waste  volumes
indicated   no   relationship   between   them.   Produced  water
production may vary from  less  than  1  to  90  percent  of  the
production   fluids.    High   volumes  of  produced  waters  are
associated with older production fields and recovery methods used
to  extract  crude  oil  from  partially   depleted   formations.
Similarly,   the   amount  of  waste  generated  during  drilling
operations is dependent upon the depth of  the  well,  subsurface
characteristics,   recovery   of   drill   muds,  and  recycling.
Therefore,  industry  subcategorization  could  not  include   an
analysis  of  segmenting  the  industry on waste load per unit of
production.
                               31

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Development of Subcategories

Based upon the type of facility, the industry may  be  subdivided
into  three  major  categories  with  similar  type operations or
activities:  1)  crude petroleum and natural  gas  production;   2)
oil  and  gas well field exploration and drilling; and 3)  oil  and
gas well completions and workover.  Further  subdivision  can   be
made within each to reflect location - offshore and onshore -  and
any wastes requiring specific effluent limitations and standards.
Since  sanitary  wastes  for  onshore  operations  normally don't
result in a discharge and since deck drainage is  not  applicable
to onshore operations, these subcategories are only applicable to
offshore facilities.  Therefore, considering location and wastes,
the major groups are subcategorized as follows:

I     Crude Petroleum and Natural Gas Production

       A.  Produced Water

       B.  Deck Drainage

       C.  Sanitary and Domestic Waste

II     Oil and Gas Well field Exploration and Drilling

       A.  Drilling Muds

       B.  Drill Cuttings

       C.  Sanitary and Domestic Waste

III    Oil and Gas Well Completions and Workover

       A.  Chemical Treatment of Wells

       B.  Production Sands

Facility's Size, Age and Waste Volumes

Offshore  facilities  in  Category I differ little in the type of
process or produced water treatment technology for large, medium,
or  small  facilities.   One  of  the  most  significant  factors
affecting  the  size of the facility is the availability of space
for central  treatment  systems  to  handle  waste  from  several
platforms or fields.  Treatment systems on offshore platforms are
usually  limited  to  meet  the needs of the immediate production
facility and are designed for 5,000 to  40,000  barrels/day.   In
contrast,  onshore  treatment  systems  for  offshore  production
wastes may be designed to handle  100,000  barrels/day  or  more.
For small facilities, wastes may require intermediate storage and
a  transport  system  to  deliver  the  produced water to another
facility  for  treatment  and  disposal.   comparable   treatment
technology has been developed for both large and small systems.
                               32

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For  onshore  facilities,  the  type  of produced water treatment
technology does tend to differ  according  to  the  size  of  the
facility but there are notable exceptions.  Since for the primary
unit  treatment  process (the separation of oil and water), ponds
of sufficient size are  feasible  for  smaller  facilities  while
mechanical  systems (such as flotation)  are required where larger
amounts of produced water are handled.   Smaller  facilities  are
least  likely  to  have  the type cf operating staff required for
sophisticated water treatment systems  and  are  more  likely  to
receive operating variances from local regulatory authorities.

The  types  of  treatment for sanitary wastes for large and small
offshore facilities are different, as are  facilities  which  are
intermittently  manned.   For  small  and  intermittently  manned
facilities, the waste may be incinerated or  chemically  treated,
resulting  in  no discharge.  Because of operational problems and
safety considerations, other types of treatment systems that will
result in a discharge are being considered.  Thus sanitary wastes
must be sutcategorized based on facility size.

The state of the art and treatment technology for Category I  has
been  improving  over the past several years; the majority of the
facilities regardless  of  age  have  installed  waste  treatment
facilities.   However, the age of the production field can impact
the quantity of waste water generated.  Many new fields  have  no
need to treat for a number of years until the formation begins to
produce   water.   The  period  before  initiating  treatment  is
variable, depending on  the  characteristics  of  the  particular
field, and can also be affected by method of recovery.  If wastes
are  to  be  treated off shore, the initial design should provide
for the necessary space and  energy  requirements  that  will  be
needed  for  the  treatment  systems  to  be  installed  over the
expected life of the platform.

Process Technology

Process technology was reviewed  to  determine  if  the  existing
equipment  and  separation systems influenced the characteristics
of the produced waste.  Most oil/water process  separation  units
consist of heater-treaters, electric dehydration units or gravity
separation  (free  water  knockout  or  gun barrel).  The type of
process equipment and its configuration are based in part on  the
characteristics  of  the  produced  fluids.   For example,  if the
fluids contain entrained oil in a "tight" 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 process units.   When high influent
concentrations to the produced water  treatment  facilities  were
observed  they  were  found  to  be caused by malfunctions in the
process equipment.  It was concluded that there is no  basis  for
subcategorization because of differences in process systems.
                               33

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Climate

Climate  was  considered  because  conditions  in  tiie production
regions differ widely.  All regions treat by  gravity  separation
or  chemical/physical  methods.  These systems are less sensitive
to climatic changes than biological  treatment.   Sanitary  waste
treatment  can  be affected by extreme temperatures, but in areas
with  cold  climates,   facilities   are   enclosed,   minimizing
temperature  variations.   The volume or hydraulic loading due to
rainfall may be significant with respect  to  the  offshore  Gulf
Coast,  but  the  waste  contaminants  (residual oils from drips,
leaks, etc.) from deck  drainage  are  independent  of  rainfall.
Proper   operation   and   maintenance   can   reduce  waste  oil
concentrations to minimal levels, thus  reducing  the  effect  of
rainfall.  Therefore, no sufccategorization is required to account
for climate.

Waste Water Characteristics

Treatability  and other characteristics of produced water are one
of the most significant factors considered for subcategorization.
Produced water may be high  in  dissolved  solids   (TDS) ,  oxygen
demanding  wastes,  heavy  metals, and toxics, in addition to the
oil and grease contamination.  The current treatment technologies
for produced water are either subsurface disposal or oil  removal
prior  to  discharge.   The technology developed for each area of
the country has been primarily  influenced  by  local  regulatory
requirements  (water quality and individual state or local laws),
but other factors associated with produced water treatability and
cost effectiveness may also have had an effect.  (1,2,3)

Factors which may affect produced water treatability are:

    1.   Physical and  chemical  properties  of  the  crude  oil,
         including solubility.

    2.   Concentration of suspended and settleable solids.


    3.   Fluctuation of flow rate and production method.

    4.   Droplet sizes of the entrained oil emulsification.

    5.   Other characteristics of the produced water.

The impact of  these  variables  can  be  minimized  by  existing
process  and treatment technology, which include desanders, surge
tanks, and chemical treatment.

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Location of Facility

The location of the facility affects  the  applicable  treatment,
the  cost  of  that  treatment,  and  the  makeup  of  the wastes
produced.  The factors that affect the treatment method based  on
location are as follows:

    1.   Availability of space and site conditions, such as,  dry
         land, marsh area, or open water.

    2.   Proximity to shore.

    3.   Type and depth of  subsurface  formations  suitable  for
         injection of produced 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 body.

Location is a significant factor  specifically  with  respect  to
areas  where  saline produced water discharges are not permitted.
The usual procedure in inland areas is to reinject  the  produced
water   to   the   producing   formation,   where  the  formation
configuration permits (to assist in oil recovery) ,  or  to  other
subsurface  formations  for disposal only.  Evaporation ponds are
used in some inland areas, with the assumption that all  produced
waters  are  evaporated  and  no  discharge  occurs.   In an arid
Western oil field an evaporation pond,  if  properly  maintained,
may  provide  for  acceptable  disposal  of  the produced waters;
however, in humid areas in the East and South, evaporation  ponds
may not be acceptable.

In  inland  fields  where produced waters are sufficiently low in
total solids, discharges have been used for  stock  watering  and
other  beneficial  uses  where  the  treated produced water is of
sufficient  quality   to   meet   the   regulations   for   other
constituents, such as oil and grease.

In  the  Appalachian  area,  typified by the northwest portion of
Pennsylvania, discharge of produced water is the  rule,  not  the
exception.    Treatment   consisting   of   ripple  aeration  and
semimentation/separation in ponds achieves a high degree of  free
oil removal apparently due to the separability of the crude.

The  technology  for disposal of drilling muds, cuttings, solids,
and other materials differs depending upon the location.  In  the
open  water  offshore  areas, the materials, if properly treated,
are  normally  discharged  into  the  saline   waters.    Onshore
technology  has  been developed to ensure no discharge to surface
                               35

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waters, and waste materials are  disposed  of  in  approved  land
disposal sites.

Description of Sufccategories

Based  upon  the  above  rationale and discussion the oil and gas
extraction industry has been sutcategorized as follows:
Subcategory
Subcategory
A - near offshore  (facilities located in
                    offshore state waters)
              1.

              2.

              3.

              a.

              5.

              6.
7.

8.

B -


1.

2.

3.

4.

5.

6.
     produced water

     deck drainage

     drilling muds

     drill cuttings

     well treatment

     sanitary wastes

     a.
                        M10 continuously manned with 10  or  more
                        people
                   b.
          M9IM - facilities with 9 or
          or intermittantly manned.
                                  less  people
domestic wastes

produced sand

far offshore (facilities located in
               federal waters)

produced water

deck drainage

drilling muds

drill cuttings

well treatment

sanitary wastes

a.   Mlu continuously manned with 10  or  more
     people
                               36

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                   b.   M9IM - facilities with 9 or  less  people
                        or intermittantly manned.
              7.   domestic wastes

              8.   produced sand

Subcategory  C -  onshore

              1.   produced water

              2.   drilling muds

              3.   drill cuttings

              4.   well treatment

              5.   produced sand

Subcategory  D -  coastal

              1.   produced water

              2.   deck drainage

              3.   drilling muds

              4.   drill cuttings

              5.   well treatment

              6.   sanitary wastes
                   a.   M10 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

              U.   well treatment
                               37

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              5.   produced sand

Subcategory  F -  stripper

              1.   produced water

              2.   drilling muds

              3.   drill cuttings

              4.   well treatment

              5.   produced sand


Produced Water

Produced  water  includes  all  waters  and  particulate   matter
associated  with oil and gas producing formations.  Sometimes the
terms "formation water" or "brine water"  are  used  to  describe
produced water.  Most oil and gas producing geological formations
contain  an  oil-water or gas-water contact.  In some formations,
water is produced with the oil and gas in  the  early  stages  of
production.  In others, water is not produced until the producing
formation has been significantly depleted and in some cases water
is  never produced.  (4) The amount of produced water generated is
also dependent on the method of oil recovery.  If water injection
is used some of the injected water is recovered by the production
causing higher percentage water cuts.

Deck Drainage

Deck  drainage  includes  all  waste  resulting   from   platform
washings,  deck  washings,  and  run-off from curbs, gutters, and
drains including drip pans and work areas.

Sanitary Waste

Sanitary waste includes human body waste discharged from  toilets
and urinals.

Domestic Waste

Domestic  wastes  are  materials  discharged from sinks, showers,
laundries, and galleys.

Drilling Muds

Drilling muds are those materials used  to  maintain  hydrostatic
pressure  control in the well, lubricate the drilling bit, remove
drill cuttings from  the well, or stabilize the walls of the  well
during drilling or workover.
                               38

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Generally, two basic types of muds (water-based and oil muds)  are
used  in  drilling.  Various additives may be used depending upon
the specific needs of the drilling program.  Water-based muds are
usually mixtures of fresh water or sea water with muds and  clays
from   surface  formations,  plus  gelling  compounds,  weighting
agents, and various other components.  Oil muds are  referred  to
as  ox!  based muds, invert emulsion muds, and oil emulsion muds.
Oil muds are used  for  special  drilling  requirements  such  as
tightly  consolidated  subsurface  formations and water sensitive
clays and shales.   (5) (6) (7)

Drill Cuttings

Drill  cuttings  are  particles  generated   by   drilling   into
subsurface geologic formations.  Erill cuttings are circulated to
the surface of the well with the drilling mud and separated there
from the drilling mud.

Treatment of Wells

Treatment of wells includes acidizing and hydraulic fracturing to
improve  oil recovery.  Hydraulic fracturing involves the parting
of a desired section of  the  formation  by  the  application  of
hydraulic  pressure.   Selected particles added to the fracturing
fluid are transported into the  fracture,  and  act  as  propping
agents  to hold the fracture open after the pressure is released.
Chemical  treatments  of  wells  consists  of  pumping  acid   or
chemicals  down  the well to remove formation damage and increase
drainage in the permeable rock formations.(8)

Produced Sand

Produced sand or solids for this subcategory consist of particles
used in hydraulic fracturing  and  accumulated  formation  sands,
which  are  generated  during  production.   These  sands must be
removed when they build up and block flow of fluids.
                               39

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                           SECTION IV

                          Bibliography


1.  Bassett, M.G.  1971.    "Wemco  Depurator  TM  System."  Paper
    presented at the SPE of AIME Rocky Mountain Regional Meeting,
    Billings, Montana, June 2-4, 1971.  Preprint No.  SPE-3349.

2.  Boyd,  J.L.,  Shell,   G.L.,  and   Dahlstrom,   D.A.    1972.
    "Treatment   of   Oily   Haste   Waters  to  Meet  Regulatory
    Standards."  AIChE Symposium.  Serial NO. 124, pp.  393-401.

3.  Ellis, M.M., and Fischer, P.W.  1973.  "Clarifying  Oil  Field
    and  Refinery Waste Waters by Gas Flotation." Paper presented
    at the SPE  of  AIME  Evangeline  Section  Regional  Meeting,
    Lafayette, Louisiana, November 9-10, 1970.  Preprint No. SPE-
    3198.

4.  U.S. Department of  the  Interior,  Federal  Water   Pollution
    Control  Administration.   1968.   Report of the Committee on
    Water Quality Criteria.

5.  U.S. Department of the Interior, Bureau of  Land Management.
    1973.   Draft  Environmental Impact Statement, "Proposed 1973
    Outer Continental  Shelf  Oil  and  Gas  General Lease  Sale
    Offshore  Mississippi,  Alabama,  and  Florida."  Washington,
    D.C.

6.  Hayward, B.S.,  Williams,  R.H.,  and  Methven,  N.E.   1971.
    "Prevention  of  Offshore  Pollution  from  Drilling Fluids."
    Paper presented at the 46th Annual SPE of AIME  Fall  Meeting
    at  New  Orleans, Louisiana, October 3-6, 1971.  Preprint No.
    SPE-3579.

7.  Cranfield,  J.   1973.   "Cuttings  Clean-Up  Meets  Offshore
    Pollution  Specifications,   "  Petrol. Petrochem. Int., Vol.,
    13: No. 3: pp. 54-56, 59

8.  American Petroleum Institute.  Division of Production.  1973.
    "Primer of Oil and Gas Production."  3rd. ed.  Dallas, Texas.
                               40

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                            SECTION V

                      WASTE CHARACTERISTICS

Wastes generated by the oil and  gas  industry  are  produced  by
drilling  exploratory  or development wells, by the production or
extraction phase of the industry, and, in the  case  of  offshore
facilities,  sanitary wastes generated by personnel occupying the
platforms.  Drilling wastes are generally in the  form  of  drill
cuttings  and  mud,  and production wastes are generally produced
water. (1) Additionally, well workover and completion  operations
can  produce wastes, but they are generally similar to those from
drilling or production operations.

Approximately half a million producing oil wells onshore generate
produced water in excess of 20 million barrel s-per-day  of  which
it   is  estimated  50 %  is  reinjected  for  recovery  purposes.
Approximately 17,000 wells have been  drilled  offshore  in  U.S.
waters,  and  approximately 11,000 are producing oil or gas.  The
offshore  Louisiana  OCS  alone  produces  approximately  410,000
barrels  of  water  per  day  (2) ;  by  1983,  coastal  Louisiana
production will generate an estimated  1.54  million  barrels  of
water per day. (3)

This  section characterizes the types of wastes that are produced
at offshore and onshore wells and structures.  The discussion  of
drilling  wastes  can be applied to any area of the United States
since these wastes do not change significantly with locality.

Other than oils, the primary waste  constituents  considered  are
oxygen   demanding   pollutants,  heavy  metals,  toxicants,  and
dissolved solids contained in drilling muds  or  produced  water.
Sanitary  wastes  are  also  produced  during  both  drilling and
production operations both onshore and  offshore,  but  they  are
discussed  only for offshore situations where sanitary wastes are
produced  from  fixed  platforms  or  structures.   Drilling   or
exploratory   rigs   that  are  vessels  are  not  part  of  this
discussion.

Waste Constituents

Production

Production wastes include produced  waters  associated  with  the
extracted  oil,  sand  and other solids removed from the produced
waters,  deck  drainage  from  the  platform  surfaces,  sanitary
wastes, and domestic wastes.

The  produced  waters  from  production  platforms  generate  the
greatest concern.  The wastes can contain oils, toxic metals, and
                               41

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a  variety  of  salts,  solids  and   organic   chemicals.    The
concentrations   of  the  constituents  vary  somewhat  from  one
geographical area to another, with the most  pronounced  variance
in  chloride  levels.   Table  5  shows the waste constituents in
offshore Louisiana production facilities in the Gulf  of  Mexico.
The  data  were obtained during the verification survey conducted
by EPA in 1974.  The only influent data obtained  in  the  survey
were  on oil and grease.  In planning the verification survey, it
was decided that offshore  produced  water  treatment  facilities
would  have  virtually no effect on metals and salinity levels in
the influent, and that these constituents could be satisfactorily
characterized by analyzing only the effluent.

Total organic carbon  (TOC) is also tabulated  under  effluent  in
Table  5,  but it is reasonable to assume that actual analysis of
the influent would be higher.  Since TOC is a measurement of  all
organic carbon in the sample and oil is a major source of organic
carbon,  it  is  logical to assume removal of some organic carbon
when oil is removed in the treatment process.   Suspended  solids
are  also expressed as effluent data, and this parameter would be
expected to be reduced by the treatment process.

                             TABLE 5

                  Pollutants in Produced Water
                      Louisiana Coastal (a)

Pollutant Parameter             Range mq/1
Oil and Grease
Cadmium
Cyanide
Mercury
Total Organic Carbon
Total suspended solids
Total dissolved solids
Chlorides
7 -
<0.005 -
<0.01 -
30 -
22 -
32,000 -
10,000 -
1300
.675
0.01
1580
390
202,000
115,000
                  Average mq/1

                     202
                  <0.068
                   <0.01
                 <0.0005
                     413
                      73
                 110,000
                  61,000
Flow  (bbl/day)
250 - 200,000
15,000
 (a) - results of 1974 EPA survey of 25 discharges

 <  - less  than
                                42

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Industry data for offshore California describes a  broader  range
of  parameters   (see  Table  6).   Similar data were provided for
offshore Texas (see Table 7).  Except as noted on the tables, all
data are from effluents.

Sand and other solids are produced along with the produced water.
Observations made by EPA personnel during field surveys indicated
that drums of these sands stored on the platform had a  high  oil
content.   Sand has been reported to be produced at approximately
1 barrel sand per 2,000 barrels oil.(5,6)

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                             TABLE 6

             Pollutants Contained in Produced Water
                    Coastal Calif ornia (a) (7)
Pollutant
Parameter

Arsenic

Cadmium

Total Chromium

Copper

Lead

Mercury

Nickel

Silver

Zinc
Range, mq/1

0.001 - 0.08

0.02 -  0.18

0.02 - 0.04

0.05 - 0.116

0.0 -  0.28

0.0005 - 0.002

0. 100 - 0.29

0.03

0.05 - 3.2

0.0 - 0.004
Cyanide

Phenolic Compounds 0.35 - 2.10
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  reinjection.
                                44

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                         TABLE 7



            Range of constituents in Produced



           Formation Water—Offshore Texas(8)



Pollutant Parameter                Range, mg/1



Arsenic                            <0.01 - <0.02



Cadmium                            <0.02 - 0.193



Total Chromium                     
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As part of a recent EPA study (1976)  to  collect  information  on
treatment  technologies  and  costs,  surveys were made of onshore
production facilities in California,   Wyoming,  Texas,  Louisiana
and  Pennsylvania.   The  data represented in tables 8-12 is from
the effluent of the treatment facilities prior to reinjection for
secondary recovery or disposal.  It could be  expected  that  the
quality  of  the  untreated  produced  water  from the production
separator would range from 200-1000 mg/1 oil and grease and  100-
400  mg/1  suspended  solids.   The  remainder  of  the  analyzed
constituents such as TDS,  phenols  and  heavy  metals  would  be
unaffected by treatment.

The analytical methods used were from "Standard Methods for Waste
and  Wastewater"  13th  edition  (16)  with  the exception of the
procedure for oil and grease.  Prior to the  utilization  of  the
freon  extraction  method  for  oil  and grease, the samples were
screened for organic acids and if they were present in quantities
greater than 100 mg/1 the sample was not  acidified.   Therefore,
the  results  for  oil  and  grease  as  reported in tables 8-12,
particularly in California where organic acids are known to be  a
part  of the crude oil, are not comparable to data in other parts
of this report and are shown only for information.
                             TABLE 8

                Range of Constituents in Produced

               Formation Water—Onshore California


Pollutant Parameter          Range, mq/1         Median, mg/1

Oil and Grease                   16-191              75
Suspended Solids                  3-51               31
Total Dissolved Solids          580-27,300        6,300
Phenol                         0.07-0.15           0.11
Arsenic                       <0.01-0.03           0.11
Chromium                      <0.01               <0.01
Cadmium                      <0.005-0.02         <0.005
Lead                          <0.05               <0.05
Barium                         <0.2-0.4             0.3

< = less than
                               46

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                             TABLE 9

                Range of Constituents in Produced

                    Formation Water—Wyoming
Pollutant Parameter

Oil and Grease
Suspended Solids
Total Dissolved Solids
Phenol
Arsenic
Chromium
Cadmium
Lead
Barium

< = less than
Range, mq/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
Median, mq/1

    67
  12.8
13,800
  0.16
  0.01
 <0.01
<0.005
 <0.05
   0.9
                            TABLE 10

                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
Median, mg/1

    25
   107
29,000
  0.19
 <0.01
 <0.01
<0.005
 <0.05
   8.6
                               47

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                            TABLE 11

                Range of Constituents in Produced

               Formation Water—Onshore Louisiana
Pollutant Parameter

Oil and Grease
Suspended Solids
Total Dissolved Solids
Range, mg/1

    16-441
  20.8-155
42,600-132,000
Median, mg/1

   165
    82
73,900
                            TABLE 12

                Range of Constituents in Produced

                 Formation Water—Onshore Texas
Pollutant Parameter

Oil and Grease
Suspended Solids
Total Dissolved Solids
Range mq/1

    57-1,200
    30-473
42,600-132,000
Median, mg/1

   460
   143
94,000
Drilling

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
drilling  location  to  another,  and no attempt has been made to
qualitatively identify cuttings.

The two basic classes of drilling muds used today are water based
muds and oil muds.  In general, much of the mud  introduced  into
the  well  hole  is  eventually  displaced  out  of  the hole and
requires disposal or recovery.(13)

Water based muds are formulated using naturally  occurring  clays
such  as  bentonite  and attapulgite and a variety of organic and
inorganic  additives  to   achieve   the   desired   consistency,
lubricity,  or  density.  Fresh or salt water is the liquid phase
for these muds.  The additives are used for such functions as  pH
                                48

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control,   corrosion   inhibition,  lubrication,  weighting,  and
emulsification.

The additives that should be scrutinized  for  pollution  control
are ferrochrome lignosulfonate and lead compounds.(14)

Ferrochrome lignosulfonate contains 2.6 percent iron, 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 development, the drilling  operation  of  a  typical
10,000-foot development well (not exploratory) used 32,900 pounds
of  ferrochrome  lignosulfonate mud which contained 987 pounds of
chromium.(2)  Table 13 presents the volumes of cuttings  and  muds
used  in the Bureau's example of a "typical" 10,000-foot drilling
operation.  The amount of lead additives used in mud  composition
varies from well to well, and no examples are available.

Drilling  constituents for onshore operations will parallel those
for offshore, except for  the  water  used  in  the  typical  mud
formulation.    Onshore  drilling  operations normally use a fresh
water based mud, except where drilling operations encounter large
salt domes.  Then the mud system would be converted either  to  a
salt clay mud system with salt added to the water phase, or to an
oil  based  mud  system.   This  change  in  the  liquid phase is
intended to prevent dissolving salt in the  dome,  enlarging  the
hole, and causing solution cavities in the formation.

In  offshore  operations,  the  direct  discharge of cuttings and
water  based  muds  create  turbidity.   Limited  information  is
available  to  accurately  define the degree of turbidity, or the
area or volume of water affected ty such turbid  discharges,  but
experienced observers have described the existence of substantial
plumes of turbidity when muds and cuttings are discharged.


Oil-based  muds contain carefully formulated mixtures of oxidized
asphalt, organic acids, alkali, stabilizing agents and high-flash
diesel oil. (14,15)  The oils are the principal ingredients and  so
are  the  liquid  phase.   Muds displaced from the well hole also
contain solids from the hole.  There are two types of  emulsified
oil muds: 1)  oil emulsion muds, which are oil-in-water emulsions;
and  2) inverted emulsion muds, which are water-in-oil emulsions.
The principal differences between these two muds  and  oil  based
muds  is the addition of fresh or salt water into the mud mixture
to provide some of  the  volume  for  the  liquid  phase.   Newer
formulations  can  contain from 20 to 70 percent water by volume.
The water is added by adding emulsifying and stabilizing  agents.
Clay solids and weighting agents can also be added.

-------
Sanitary and Domestic Waste

The  sanitary  wastes  from  offshore  oil and gas facilities are
composed of human body waste and domestic waste such  as  kitchen
and general housekeeping wastes.  The volume and concentration of
these   wastes   vary   widely  with  time,  occupancy,   platform
characteristics, and operational situation.  Usually the  toilets
are flushed with brackish water or sea water.  Due to the compact
nature of the facilities the wastes have less dilution water than
common   municipal   wastes.    This  results  in  greater  waste
concentrations.   Table  14  indicates  typical  waste  flow  for
offshore facilities and vessels.
                               50

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                Table 13
Volume of Cuttings and Muds in Typical

  10,000-Foot Drilling Operation (2)


Interval,
Feet
0-1,000

1,000-3,500

3,500-10,000

Hole
Size,
inches
24

16

12

Vol. of
Cuttings,
bbl.
562

623

915

Wt. of
Cuttings,
pounds
505,000

545,000

790,000


Drilling
mud
sea water
& natural
mud
Gelled sea
water
Lime base
Vol of
Mud com-
ponents ,
bbl
variable

700

950
Wt. of
Mud com-
ponents
pounds


81,500

424,000

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IP
K)
                                               Table  14


                             Typical Raw Combined Sanitary and Domestic

                                   Wastes from Offshore Facilities
                                 BOD, mg/1          Suspended
No. of
Men
76

A9

Flow 5
gal/day Average Range
5,500 460 270-770

9 i cc 77 c 	
7 OHO Q9H 	
Solids, mg/1
Average Range
195 14-543
1 r\9c — —
con 	
99CI — —

Total
Coliform
(X 10)
10-180



Reference
(10)


fT\\

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                            SECTION V

                          Bibliography


1.  Biglane, K.E.  1958.   "Some Current Waste Treatment Practices
    in Louisiana Industry."  Paper 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
    Mississippi, Alabama, Florida."  Washington, D.C.

3.  Offshore Operators Committee, Sheen  Technical  Subcommittee.
    1974.   "Determination of Best Practicable Control Technology
    Currently Available to Remove Oil from  Water  Produced  with
    Oil  and  Gas."   Prepared  by Brown and Root, Inc., Houston,
    Texas.

4.  Moseley, F.N., and Copeland, E.J.   1974.   "Brine  Pollution
    System."   In:   "Coastal  Ecological  Systems  of the United
    States." Odum, Copeland, and McMahan (ed.).  The Conservation
    Foundation,  Washington, D.C.

5.  Garcia, J.A.  1971.  "A System for the Removal  and  Disposal
    of Produced Sand."  Paper presented at the 47th Annual SPE of
    AIML  Fall  Meeting,  San Antonio, Texas, October 8-11, 1972.
    Preprint No. SFE-4015.

6.  Frankenberg,  W.G.,  and  Allred,   J.H.    1969.     "Design,
    Installation,  and  Operation  of a Large Offshore Production
    Complex;"  and  Bleakley,  W.G.,  "Shell  Production  Complex
    Efficient, Controls, Pollution—.  "Oil and Gas Journal, Vol.
    67:No. 36: pp. 65-69.

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

8.  Offshore Operators committee.

9.  Crawford, J.G.  1964.  "Rocky  Mountain  Oil  Field  Waters."
    Chemical and Geological Laboratories, Casper, Wyoming.

10.  Sacks, Bernard R.   1969.    "Extended    Aeriation    Sewage
    Treatment   on   U.S.  Corps  of  Engineers  Dredges."   U.S.
    Department of the Interior, Federal Water  Pollution  Control
    Administration.
                               53

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11.   Amoco  Production Company.   1974.   "Draft Comments Regarding
    Rationale and Guideline Proposals for Treatment  of  Sanitary
    Wastes from offshore Production Platforms."

12.  Humble Oil and Refining Company.  1970.   "Report on the Human
    Waste on Humble Oil and Refining Company's Offshore Platforms
    with Living Quarters in the  Gulf  of  Mexico."   Prepared  by
    Waldermar  S.  Nelson  Company, Engineers and Architects, New
    Orleans, Louisiana.

13.  Hayward, B.S.,  Williams, R.H.,  and Methven,  N.E.    1971.
    "Prevention  of  Offshore Pollution  from  Drilling Fluids."
    Paper presented at the 46th  Annual SPE of AIME Fall  Meeting,
    New  Orleans, Louisiana, October 3-6, 1971.  Preprint No. SPE
    3579.

14.  Gulf Publishing Company.  "Drilling  Fluids  File."  Special
    compilation from World Oil,  January 1974.

15.  The University of Texas, Petroleum Extension Service.    1968.
    "Lessons in Rotary Drilling  - Drilling Mud."
                               54

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                           SECTION VI

                SELECTION OF POLLUTANT PARAMETERS

Oil   and  grease  from  produced  water,  deck  drainage,  muds,
cuttings, and produced sands and solids,  and  residual  chlorine
 (as  an  indicator  of  fecal  coliform) and floating solids from
sanitary  and  domestic  sources  have  been  selected   as   the
pollutants  for  which  effluent limitations will be established.
The rationale for inclusion of  these  parameters  are  discussed
below.

Parameters  for Effluent Limitations

Freon Extractables - Oil and Grease

No  solvent  is  known  which  will directly dissolve only oil or
grease, thus the manual "Metnods for  the  Chemical  Analysis  of
Water   and   Wastes   1974"  distributed  by  the  Environmental
Protection Agency states that their method  for  oil  and  grease
determinations includes the freon extractable matter from waters.

In  the  oil  and gas extraction industry, oils, greases, organic
acids, various other hydrocarbons and some  inorganic  compounds,
such  as  sulfur,  will  be  included  in  the  freon  extraction
procedures.  The majority of material removed  by  the  procedure
from   a  produced  water  will,  in  most  instances,  be  of  a
hydrocarbon nature.  These hydrocarbons,  predominately  oil  and
grease  type compounds, will make their presence felt in the COD,
TOC, TOD,  and usually the BOD tests where high test values  will
result.   The oxygen demand potential of these freon extractables
is only one of the detrimental effects exerted on water bodies by
this class of compounds.  Oil emulsions may adhere to  the  gills
of  fish  or coat and destroy algae or other plankton.  Depostion
of oil in the  bottom  sediments  can  serve  to  inhibit  normal
benthic  growths,  thus  interrupting  the  aquatic  food  chain.
Soluble and emulsified materials ingested by fish may  taint  the
flavor  of  the  fisxi  flesh.  Water soluble components may exert
toxic action on fish.  The water insoluble hydrocarbons and  free
floating  emulsified  oils  in  a  waste water will affect stream
ecology by interfering with  oxygen  transfer,  by  damaging  the
plumage and coats of water animals and fowls, and by contributing
taste and toxicity problems.  The effect of oil spills upon boats
and   shorelines   and   their   production  of  oil  slicks  and
iridenscence upon the surface of waters is well known.

Fecal Coliform (Chlorine Residual)

The concentration of fecal coliform  bacteria  can  serve  as  an
indication  of the potential pathogencity of water resulting from
the disposal of human wastes.  Fecal coliform  levels  have  been
                               55

-------
established  to  protect  beneficial  water  use  (recreation and
shellfish propagation) in the coastal areas.

The most direct method to  determine  compliance  with  specified
limits  is  to  measure the fecal coliform levels in the effluent
for a period representing a normal  cycle  of  operations.   This
approach may be applicable to onshore installations; however, for
offshore  operations the logistics become complex, and simplified
methods are desirable.

However, the presence of specific levels of suspended solids  and
chlorine  residual in an effluent are indicative of corresponding
levels of fecal coliforms.  In general if suspended solids levels
in the effluent are less than 150 mg/1 and the chlorine  residual
is  maintained  at  1.0  mg/1, the fecal coliform level should be
less  than  200  per  100  ml.   Properly  operating   biological
treatment systems on offshore platforms have effluents containing
less  than  150  mg/1  of  suspended  solids; therefore, chlorine
residual is a reasonable control parameter.

It may be considered desirable, however, that  a  study  of  each
sanitary treatment system be made at least once a year to measure
influent   and  effluent  biochemical  oxygen  demand,  suspended
solids, and fecal coliform.  The purpose  of  the  survey  is  to
determine  the  treatment  efficiencies,  to  evaluate  operating
procedures, and to adjust the system to obtain maximum  treatment
efficiencies and minimize chlorine usage.

Floating Solids

Marine  waters  should  be  capable of supporting indigenous life
forms and should be free of substances attributable to discharges
or wastes which will settle  float  on  the  water,  and  produce
objectionable  odors.   Floating  solids  have been selected as a
control parameters for domestic wastes and sanitary  wastes  from
small or intermittently manned offshore facilities.


Other Pollutants

Some produced formation waters are known to contain heavy metals,
toxic  substances,  constituents  with substantial oxygen demand,
and  inorganic  salts.   Insufficient  data  exist   to   warrant
comprehensive  control  of  these  parameters  and  there  is  no
discharge technology now in use by the industry to  remove  these
pollutants,   although   some  concomitant  reduction  in  oxygen
demanding constituents may take place as a  result  of  treatment
not specifically designed for their removal.
                               56

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Heavy Metals

Produced  waters  have been shown to contain cyanide cadmium, and
mercury.   Section  307 (a) (1)  of  the  Federal  Water  Pollution
Control   Act  Amendments  of  1972  requires  a  list  of  toxic
pollutants and  effluent  standards  or  prohibitions  for  these
substances.  The proposed effluent standards for toxic pollutants
state  that  there  shall be no discharge of cyanide, cadmium, or
mercury into streams, lakes or estuaries with  a  low  flow  less
than  or equal to 0.283 cubic meters per second (M3/sec) (10 cubic
feet per second) or into lakes with an area less than or equal to
200 hectares  (500 acres).  Many estuarine areas  fall  into  this
category.

The  harmful  effects  of  these  toxicants, which include direct
toxicity to humans and other animals,  biological  concentration,
sterility,  mutagenicity,  teratogenicity,  and  other lethal and
sublethal effects, have been well documented in  the  development
of the Section 307 (a) (1)  proposed regulations.

Produced  formation  waters  have  also  been  shown  to  contain
arsenic, chromium, copper,  lead,  nickel,  silver,  and  zinc  as
pollutants.   According  to McKee and Wolfe (6), arsenic is toxic
to aquatic life in concentrations as low as 1 mg/1.  The toxicity
of chromium is very much dependent upon environmental factors and
has been shown to be as low as 0.016 mg/1 for aquatic  organisms.
Copper  is  toxic  to aquatic organisms in concentrations of less
than 1 mg/1 and is concentrated by plankton from their habitat by
factors of 1,000 to 5,000 or more.  Lead has  been  shown  to  be
toxic  to  fish in concentrations as low as 0.1 mg/1, nickel at a
concentration of 0.8 mg/1,   and  silver  at  a  concentration  of
0.0005 mg/1.  Zinc was shown to be toxic to trout eggs and larvae
at a concentration of 0.01  mg/1.

TDS

Dissolved solids in produced waters consist mainly of carbonates,
chlorides,  and  sulfates.    U.S.  Public Health Service Drinking
Waters Standards for total  dissolved solids are set at  500  mg/1
on the basis of taste thresholds.  Many communities in the United
States use water containing from 2,000 to 4,000 mg/1 of dissolved
solids.   Such  waters  are not palatable and may have a laxative
effect on certain people.  However, the geographic  location  and
availability  of potable water will dictate acceptable standards.
The following is a summary  of a literature survey indicating  the
levels  of  dissolved  solids which should not interfere with the
indicated beneficial use:
                               57

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         Domestic Water Supply         1,000 mg/1
         Irrigation                      700 mg/1
         Livestock Watering            2,500 mg/1
         Freshwater Fish and Aquatic   2,000 mg/1
          Life
Estuaries are typically bilaminar  systems,  stratified  to  some
degree,  with  each layer dependent upon the other for cycling of
minerals, gases, and energy.  The upper, low  salinity,  euphotic
zone  supports  production of organic materials from sunlight and
CO2; it also produces oxygen in excess  of  respiration  so  that
this  upper  layer  is  characteristically supersaturated with 02
during the daylight hours.   The  bottom  higher  salinity  layer
functions   as  the  catabolic  side  of  the  cycle,  (microbial
breakdown of organic material with subsequent O2 utilization  and
CO2 production).  In a healthy estuarine system, these two layers
are  in  precarious  synchrony,  and  the  alteration of density,
minerals, gases, or organic material is  capable  of  causing  an
imbalance in the system.

Apparently  due  to  the stresses resulting from salinity shocks,
anamalous ion ratios, strong buffer systems,  high  pH,  and  low
oxygen  solubility,  few  organisms  are  capable  of adapting to
brine-dominated  systems.   This  results  in  low  diversity  of
species, short food chains, and depressed trophic levels. (7)

Chlorides

Chloride  ion  is  one  of  the  major  anions found in water and
produces a salty taste at a  concentration  of  about  250  mg/1.
Concentrations  of  1000 mg/1 may te undetectable in waters which
contain appreciable amounts of calcium and magnesium ions.

Some  produced  water   associated   with   naturally   occurring
subsurface  hydrocarbons  may  contain  extremely high amounts of
sodium chloride.   These  "so-called"  connate  brines  developed
because  the  particular  geologic  formation has not allowed the
entrance of surface water for  dilution.   In  the  mid-continent
region where these brines are found, they average 174,000 mg/1 of
dissolved solids.

The  toxicity  of  chloride salts will depend upon the metal with
which  they  are  combined.    Because   of   the   rather   high
concentration  of  the  anion  necessary  to initiate detrimental
biological effects, the limit set upon the concentration  of  the
metallic ion with which it may be tied, will automatically govern
its  concentration  in effluents, in practically all forms except
potassium, calcium, magnesium, and sodium.

Since sodium is by  far  the  most  common   (sodium  75  percent,
magnesium 15 percent and calcium 10 percent) the concentration of
                               58

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this  salt  will probably govern the amount of chlorides in waste
streams.

It is extremely difficult to pinpoint the exact amount of  sodium
chloride  salt  necessary to result in toxicity in waters.  Large
concentrations have been proven toxic to  sheep,  swine,  cattle,
and poultry.

In  swine  fed  diets  of  swill  containing  1.5 to 2.OX salt by
weight, poisoning symptoms can be  induced  if  water  intake  is
limited  and  other factors are met.  The 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
industrial  or  agricultural  purposes  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
appropriate  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 concentrations that make  them  less  competitive  and
able  to  sustain  their  species within the aquatic environment.
For  example,  reduced  DO  concentrations  have  been  shown  to
interfere  with fish population through delayed hatching of eggs,
reduced size and vigor of embryos, production of  deformities  in
young,  interference  with  food digestion, acceleration of blood
clotting, decreased tolerance to certain toxicants, reduced  food
efficiency   and  growth  rate,  and  reduced  maximum  sustained
swimming  speed.   Fish  food  organisms  are  likewise  affected
adversely  in  conditions  with suppressed DO.  Since all aerobic
aquatic  organisms  need  a  certain  amount   of   oxygen,   the
consequences  of total lack of dissolved oxygen due to a high BOD
can kill all inhabitants of the affected area.

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

Almost  without  exception,  waste  waters  from  oil   and   gas
extraction exert a significant and sometimes major oxygen demand.
The  primary  sources  are soluble biodegradable hydrocarbons and
inorganic sulfur compounds.

Biochemical Oxygen Demand  (BOD)

Biochemical oxygen demand is a measure of  the  oxygen  consuming
capabilities of organic matter.  The BOD does not in itself cause
direct  harm  to  a  water  system, but it does exert an indirect
effect by depressing the oxygen content of the water.  Sewage and
                               59

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other organic effluents during their processes  of  decomposition
exert  a  BOD,  which  can  have  a  catastrophic  effect  on the
ecosystem ty depleting the oxygen supply.  Conditions are reached
frequently where all of the oxygen is  used  and  the  continuing
decay  process  causes  the  production  of noxious gases such as
hydrogen sulfide and methane.  Water with a  high  BOD  indicates
the  presence  of  decomposing organic matter and subsequent high
bacterial counts that degrade its quality and potential uses.

If a high BOE 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
150°C.  The water vapor and carbon dioxides from  the  combustion
chamber  (where the water vapor is removed) is condensed and sent
to an infrared analyzer, where the carbon dioxide  is  monitored.
This  carbon  dioxide  value  corresponds  to the total inorganic
value.  Another portion of the same sample is thermally  oxidized
at  950°C, 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 reliable 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
compounds is cumulative.

Phenols  and  phenolic compounds are both acutely and chronically
toxic to fish and other  aquatic  animals.   Also,  chlorophenols
produce  an  unpleasant  taste  in fish flesh that destroys their
recreational and commercial value.

It is necessary to limit phenolic compounds in raw water used for
drinking water supplies, as conventional treatment  methods  used
by  water supply facilities do not remove phenols.  The ingestion
                               60

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of concentrated solutions of phenols will result in severe  pain,
renal irritation, shock and possibly death.

Phenols  also  reduce the utility of water for certain industrial
uses, notably food and  beverage  processing,  where  it  creates
unpleasant tastes and odors in the product.

As  seen  from  the  above  discussion on the potential harm from
produced  water  discharges,  the  effects  of  toxicants,   high
salinity,  low  dissolved  oxygen,  and  high  organic matter can
combine to produce an ecological enigma.

The State of California,  recognizing  the  potential  impact  of
industrial  wastes  in  the  coastal  areas, has adopted effluent
limitations for ocean waters under its  jurisdiction  (see  Table
15.   They  were  arrived  at by first applying safety factors to
known toxicity levels and a consideration of control  technology.
This  produced  proposed  standards  which  were subjected to the
public hearing process, revised accordingly, and  then  declared.
To  meet  the  coastal  water  quality standards, the oil and gas
extraction industry  has  developed  a  no  discharge  technology
(reinjection of production water).
                               61

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                            TABLE 15

                Effluent Quality Requirements for

                   Ocean Waters of California
                                  Concentration not to be
                                   exceeded more than;
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
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
10X 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
Arsenic

Cadmium

Total Chromium

Copper

Lead

Mercury

Nickel

Silver

Zinc

Cyanide

Phenolic Compounds

Total Chlorine
Residual

Ammoni a(expr esse d
as nitrogen)

Total Identifiable
Chlorinated Hydro-
carbons               mg/1             0.002          0.004

Toxicity Concen-
tration               tu               1.5            2.0

Radioactivity  not  to  exceed  the limits specified in Title 17,
Chapter 5r Subchapter 4, Group 3, Article 5,  Section  30285  and
30287 of the California Administrative Code.
                               62

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                           SECTION VI

                          Bibliography

1.  Great Lakes Hater Quality Agreement, April 1972.

2.  Federal Water  Pollution  Control  Act  Amendments  of  1972,
    Section 311 (b) (3).  40 CFR 1110.

3.  California  State  Water  Resources  Control  Board.    1972.
    "Water Quality Control Plan.  Ocean Water of California."

4.  Adams, J.K.  1974.  "The Relative Effects of Light and  Heavy
    Oils."  U.S.  Environmental Protection Agency, Division of Oil
    and  Special  Materials  Control, Washington, D.C.  Pub.  No.
    EPA-520/9-74-021.

5.  Evans, D.R.,  and Rice,  S.D.   1974.   "Effects  of  Oil  and
    Marine  Ecosystems:   A  Review for Administrators and Policy
    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."
    California State Water Quality Control Board.  Pub. No. 3-A.

7.  Moseley, F.N.,  and Copeland, B.J.   1974.   "Brine  Pollution
    System."    In:   "Coastal  Ecology  Systems  of  the  United
    States." Oduon,  Copeland, and McMahan, (ed) .   The Conservation
    Foundation, Washington, D.C.
                               63

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                           SECTION VII

                CONTROL AND TREATAiENT TECHNOLOGY

Petroleum production, drilling, and exploration  wastes  vary  in
quantity  and quality from facility to facility.  A wide range of
control and treatment technologies has been  developed  to  treat
these  wastes.   The  results  of  industry surveys indicate that
techniques for in-process controls and end-of-pipe treatment  are
generally   similar  for  each  of  the  industry  subcategories;
however,  local  factors,  discharge  criteria,  availability  of
space, and other factors influence the method of treatment.

In-plant control/Treatment Techniques

In-plant  control  or  treatment  techniques  are those practices
which result in: 1) reduction or elimination of a  waste  stream;
or 2) a change in the character of the constituents and allow the
end-of-pipe processes to be more efficient and cost effective.

Reduction or Elimination of Waste Streams

The  two  types of in-plant techniques that reduce the waste load
to the treatment system or  to  the  environment  are  reuse  and
recycle of waste products.  Examples of reuse are: 1)  reinjection
of  produced  water  to  increase  reservoir  pressures;  and  2)
utilization of treated production water (softened, if  necessary)
for  steam  generation.   An  example  of a recycle system is the
conservation and reuse of drilling muds.

Waste Character Change

Examples of character change in waste stream  would  be:  1)  the
substitution  of  a  positive  displacement pump for a high speed
centrifugal pump; and 2) substitution of a downhole choke  for  a
well head choke, thereby reducing the amount of emulsion created.
(1)

Proper  pretreatment and maintenance practices are also effective
in reducing waste flows  and  improving  treatment  efficiencies.
Return  of  deck drainage to the process units and elimination of
waste crankcase oil from the  deck  drainage  or  produced  water
treatment systems are examples of good  offshore pretreatment and
maintenance practices.

Process Technology

The  single  most  significant  change  in  process technology is
reinjection to the reservoir formation for secondary recovery and
pressure maintenance.  This is distinguished from  injection  for
disposal  purposes  only,  which  is  considered  as  end-of-pipe
treatment.  Waters  used  for  secondary  recovery  and  pressure
                               65

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maintenance should toe free of suspended solids,  bacterial slimes,
oxygen, sludges, and precipitates.  In some cases the quantity of
produced  water is insufficient to provide the needed water for a
secondary recovery and  pressure  maintenance  system.   In  this
case,  additional  make-up  water  must  be  found,  and wells or
surface water (including sea water)  may be used as  a  source  of
make-up  water.    There  may be problems of compatability between
produced water and make-up water.  A  typical  reinjection  water
treatment  facility  consists  of  a  surge tank, flotation cell,
filters, retention tank, and injection pumps. (2)

Reinjection of produced water for secondary recovery and pressure
maintenance is a very  common  practice  onshore.   It  has  been
estimated  that  60  percent  of  all  onshore  produced water is
reinjected for secondary recovery.

Produced  water  treatment  for  reinjection  is  similar,   both
offshore  and  onshore.   Existing  reinjection systems vary from
small units which treat less than 100 barrels per  day  of  brine
waste  to  large  complexes which handle over 170,000 barrels per
day.  Produced water reinjection systems for presure  maintenance
and  water  flooding  are less common in the Gulf Coast, and none
are in use in Cook Inlet, Alaska  (Cook Inlet water is treated and
injected for water flooding, because of   compatibility  problems
with the produced water),

Produced   water   treatment  and  reinjection  systems  are  not
generally limited by space availability but must be  specifically
designed  to  fit offshore platforms.  Two limiting factors which
affect produced water reinjection are insuffiecint quantities  of
produced  water  to  meet  the requirement for reservoir pressure
maintenance and incompatibility between  make-up  sea  water  and
produced water.

With  the  increasing  oil  demand,  new ("tertiary") methods are
being developed to recover greater amounts of oil from  producing
formations.   The  addition  of  steam  or  other fluids into the
formation can improve ultimate recovery.  A system  which  reuses
produced  water  for  steam  generation  is operating on the West
Coast.  The system consists of a  typical  reinjection  treatment
unit with water softeners added to the system.

Changes  in  process  technology  have  also occurred in drilling
operations.   Environmental  considerations  and  high  cost   of
drilling  muds  have  led to the development of special equipment
and procedures to recycle and recondition both  water  based  and
oil  based  muds.  With the system operating properly, mud losses
are limited to deck  splatter  and  the  mud  clinging  to  drill
cuttings.
                               66

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Pretreatment

The  main  pretreatment  process  which is applicable to offshore
production  systems  is  the  return  of  deck  drainage  to  the
production  process units to remove free oil prior to end-of-pipe
treatment.  This method of  pretreatment  is  not  applicable  to
facilities that flush drilling muds into the deck drainage system
during  rig  wash  down  or  to facilities that pipe all produced
crude oil and water to shore for processing and brine treatment.

Operation and Maintenance

A  key  in-plant  control  is  good  operation  and   maintenance
practices.   Not  only  do  they  reduce  waste flows and improve
treatment efficiencies, but they also reduce  the  frequency  and
magnitude of systems upsets.

Some examples of good offshore operations are:


    1.   Separation of waste crankcase oils  from  deck  drainage
         collection system.

    2.   Reduction of waste water  treatment  system  upset  from
         deck washdown by discriminant use of detergents.

    3.    Reduction  of  oil  spillage  through  good  prevention
         techniques  such  as  drip  pans  and  other  collection
         methods.

    4.   Elimination of oil drainage from transfer pump  bearings
         or  seals  by  pumping  into  the  crude  oil processing
         system.

    5.   Reduction of oil gathered in the pig (pipeline  scraper)
         traps  by  channeling  oil  back into the gathering line
         system instead of the sump system.

    6.   Elimination of extreme loading  of  the  produced  water
         treatment  system, when the process system malfunctions,
         by redirecting all production to  shore  for  treatment.
          (3)

Good maintenance practice includes: 1)   inspection of dump valves
for  sand  cutting  as  a preventive measure; 2)  use of dual sump
pumps for pumping drainage into surge tanks; 3)  use  of  reliable
chemical   injection  pumps  for  produced  water  treatment;  4)
selection of the best  combination  of  oil  and  water  treating
chemicals;  and  5)  use of level alarms for initiating shut down
during major system  upsets.   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

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with  the  heater-treaters  that  caused  problems with the water
treatment system: 1)  insufficient heat in the  treaters;  and  2)
malfunctioning level controls which caused excessive oil loading.
A  change  in  the  type of level controls and reduced production
which lowered the heating requirements and helped  alleviate  the
problem  during  start-up  of  the produced water treatment unit.
Further  improvements  were  achieved  by  careful  selection  of
chemicals  for  treating oil and produced water,  and the chemical
injection and recylcing pumps were replaced.

The preceding paragraph describes an actual case   where  detailed
failure  analysis  and  corrective  action  ended an upset in the
waste treatment system.   Evaluation  of  operational  practices,
process  and  treatment  equipment  and  correct   chemical use is
imperative  for  proper  operation  and  in  the   prevention  and
detection  of  failures  and  upsets.   The  description of these
operation and maintenance practices is not intended  to  advocate
their  universal  application.  Nevertheless, good operations and
maintenance  on  an  oil/gas  production  facility  can  have   a
substantial impact on the loads discharged to the waste treatment
system  and the efficiency of the system.  Careful planning, good
engineering, and a committment  on  the  part  of  operating  and
management  personnel are needed to ensure that the full benefits
of good operation and maintenance are realized.

Analytical Techniques and Field Verification Studies

Data on the types of treatment equipment and performance  of  the
systems  in  this report were provided by the industry.  An early
analysis of data indicated a need to both verify  the  information
and  determine current waste handling practices.   EPA conducted a
3-week  sampling  verification  study  for  facilities, off   the
Louisiana  Coast;  and  3-day studies were conducted in Texas and
California to verify performance data.  In addition, three  field
surveys  were  made  to  determine  the  adequacy  of  laboratory
analytical techniques, sample  collection  procedures,  operation
and  maintenance  procedures,  and general practices for handling
deck drainage.  Similar field surveys  were  made  of  facilities
located in Cook Inlet.

Performance  verification studies were also conducted to identify
the  most  efficient  onshore   facilities   and   to   determine
geographical  and process differences based on crude oil residual
separability and various produced water treatment processes.

Variance in Analytical Results for Oil and Grease concentrations

Effluent oil and grease values in  produced  water  recorded  and
reported  by  the  oil and gas industry are usually determined by
contracting  laboratories  using  various   analytical   methods.
Analytical   methods   presently   in   use   include   infrared,
gravimetric, utlraviolet- fluorescence,  and  colorimetric.   The
                               68

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method  used  by  a  contractor is usually governed by regulatory
authority, the person in charge of the laboratory, the client, or
some combination  of  these.   For  example.  Department  of  the
Interior,  U.  S.  Geological  Survey,  Outer  Continental  Shelf
Operating Order #8 (Gulf of Mexico area)  dated October 30,  1970,
specifies   to  Federal  leasees  that  oil  content  values  for
effluents shall be determined and reported in accordance with the
American Society for Testing and Materials  Method  D1340,  "Oily
Matter  in  Industrial  Waste  Water."   A regional water quality
board  in  California  specifies  APHA  Standard  Methods,   13th
Edition,  "Oil and Grease" Test No. 137 (Gravimetric).  The U. S.
Environmental Protection Agency lists the APHA Standard  for  oil
and  grease determination under the provisions of 40 CFR Part 136
"Guidelines Establishing Test  Procedures  for  the  Analysis  of
Pollutants."  The  manner  in  which  the  sample is prepared for
analysis is  equally  critical.   For  example,  Table  16  shows
oil/grease concentrations of acidized and unacidized samples from
facilities in California (both analyzed by the same method).
                            TABLE 16

                   Effect of Acidification on
                       Oil and Grease Data

                                Oil and Grease - mg/1
   Date of
Effluent Sample           Unacidized             Acidized

  7-26-74                    7.6                   26.3
  7-26-74                   36.3                   61.8
The values after pH adjustment were significantly higher than the
samples  that  were  not  acidified.  One explanation is that, the
acidification converts many of the  water  soluble  organic  acid
salts  to  water  insoluble  acids  that  are then extractable by
hydrocarbon solvents.

The solvent used for the extraction of  oil  and  grease  from  a
sample  is  another  critical  step  that  can  affect analytical
results.  For example, petroleum ether  extracts  all  crude  oil
constituents  from  a produced water sample except asphaltenes or
bitumen.  This limitation would affect the reported results of  a
sample  containing  high  asphaltic constituents.  Other solvents
used in  oil/grease  determinations  are  trichlorotrifluroethane
                               69

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 (Freon),  hexane,  carbon  tetrachloride, and methylene chloride,
with  each  being   somewhat   selective   in   the   hydrocarbon
constituents extracted.

Reported  oil/grease concentrations in waste water effluents from
offshore facilities  were  highly  variable  within  and  between
geographical  areas.   The available information did not show any
discernible  reason for this  variability  (difference  in  waste
treatability  or treatment technology).  Therefore, EPA undertook
field 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  oil/grease  in  effluent  waste  water
discharges and duplicate samples were provided  to  the  industry
for  independent  laboratory  analysis.  Tables 17 and 18 compare
the results of two analytical methods (gravimetric and  infrared)
measuring   Freon   extractible   oil/grease   and  those  values
determined by petroleum ether extraction  using  the  gravimetric
method.   This  study  was  conducted  by  the EPA Robert S. Kerr
Research Laboratory  (RSKRL) at Ada, Oklahoma.
                                70

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                            Table 17
               Oil and Grease Data - Texas Coastal
                   Analytical Procedure Study
                                   Oil and Grease - mq/1
                   RSKRL
Sample            Freon
Identif ication  Gravimetric
T-1I
T-1E
T-2I
T-2E
T-3I
T-3E
T-4I
T-4E
   32
  126
  372
  242
  643
   52
 1905
   46
 Freon
Infrared

  45
 154
 314
 197
 695
  62
1736
  51
           INDUSTRY LABS
              Freon
           Gravimetric

              2
              5
            178
            145
            685
             10
            968
              6
                            Table 18

            Oil and Grease Data - California Coastal
                   Analytical Procedure Study
Sample
Identification
C-1I
C-1E
C-2I
C-2E
C-3I
C-3E
                      RSKRL
  Freon
Gravimetric
  106
 22.3
359.6
 42.2
167.6
 46.1
 Freon
 Infrared
 126
  16
 473
  39
 197
  35
Pet. Ether
Gravimetric
INDUSTRY LABS
 Pet. Ether
 Gravimetric
   76
    5
  241
   27
  141
    7
   79
  3.1
  508
  3.6
189.1
 11.2
1 - unacidified samples

I - influent

E - effluent
                               71

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The preceding tables indicate that there was good correlation  in
analytical  results  when  EPA  uses two different methods on the
same sample.  There is no correlation  between  the  same  sample
analyzed by the same method by EPA and the industry labs in Texas
and  California (EPA's results did correlate well to the contract
labs during the Louisiana verification study).  Therefore the low
oil and grease concentrations reported by  Texas  and  California
appear to be more a function of the analytical techniques and the
laboratory rather than an indication of treatibility of the waste
water  produced  and/or  treatment  equipment  efficiency.   This
conclusion was validated by a statistical analysis of  the  data,
which  is  contained  in  Supplement B.  The analysis indicated a
high correlation with the results of the two  analytical  methods
performed  within the EPA laboratory and little or no correlation
with the  analytical  results  between  the  EPA  and  contractor
laboratories.

Field Verification Studies

The  EPA field verification study of coastal Louisiana facilities
included  sampling  for  oil/grease  in  effluent   waste   water
discharges.   Duplicate  samples  were  provided  to  the oil/gas
industry for independent- laboratory  analysis.   The  analytical
results  of  this  study, contained in Supplement B, verified the
data collected over the years by  coastal  Louisiana  facilities.
In  addition,  the  study  found  a very high correlation between
analytical  results  of  contractor  laboratories  and  the   EPA
laboratory.

The selection of facilities for the Gulf Coast verification study
was  based  on a general cross section of the production industry
and did not favor the more efficient systems.  Table 19 indicates
types of treatment units, the  performance  observed  during  the
survey,  and  long  term performance based on historical data for
each facility.  Tables 20 and 21 indicate the comparative oil and
grease concentration  data  for  Texas  and  California  offshore
facilities  and  onshore  treatment  of  offshore  produced water
treatment units.
                               72

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                            TABLE 19

                 Performance of Individual Units

                        Louisiana Coastal
                 Long Term Mean Effluent
              	Oil and Grease
Facility Identification      mq/1

Flotation Cells

GFV01                        22
GFV02                        23
GFS03                        31
GFS04                        29
GFS05                        32
GFT06                        18
GFG07                        24
GFS08
GFT09                        28
GFG10                        18

Parallel Plate Coalescers

GCC11                        35
GCC12                        66
GCM13                        43
GCC14
GCG15                        39
GCS16                        39
GCC17                        51

Loose Media Coalescers

GLG23                        25
GLT24                        18

Simple Gravity Separators

GPV18
GPT19
GPE20
GIM21
GTT22
GPE25

iSystem malfunctioning during survey.
EPA Survey Results
  Oil and Grease
     mg/l
     23
      6
     25
     21
     32
     24
    1481
     30
     31
     13
     21
     78
     34
     52
     19
     56
    118
     12
      8
     13
     26
     19
     44
     63
     16
                               73

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                            TABLE 20


                 Texas Coastal Verification Data
    Facility         Freon Extractibles      Freon Extractibles
Identification       Gravimetric Method        Infrared Method
T-l
T-2
T-3
T-4

Influent
32.0
28.9
830.0
49.0
199.0
36.0
333.0
372.0
301.0
327.0
352.0
286.0
1,250.0
643.0
1,626.0
154.0
667.0
1,169.0
1,583.0
921.0
1,710.0
1,844.0
1,905.0
1,007.0
Oil
Effluent
126.0
103.0
116.0
561.0
141.0
118.0
220.0
242.0
194.0
185.0
196.0
220.0
13.0
52.0
45.0
50.0
55.0
87.0
37.0
9.0
14.0
24.0
46.0

and Grease
Influent
45.0
57.0
1,230.0
130.0
300.0
64.0
305.0
314.0
336.0
351.0
293.0
312.0
1,350.0
695.0
1,635.0
206.0
1,242.0
1,215.0
1,520.0
1,578.0
1,677.0
1,780.0
1,736.0
1,884.0
- mg/1
Effluent
154.0
134.0
232.0
827.0
304.0
277.0
209.0
197.0
198.0
204.0
188.0
237.0
55.0
62.0
60.0
66.0
81.0
84.0
42.0
9.0
14.0
27.0
51.0

                               74

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                                                           TABLE  21

                                            Verification of Oil and Grease Data

                                                     California Coastal

                                                    RSKRL, Ada, Oklahoma
        Facility
      Identification
      Freon
   Extractibles,
   Gravimetric
      Method , mg/1

Influent  Effluent
                       Freon
                    ExtractibleSj
                      Infrared
                       Method, mg/1

                  Influent  Effluent
                                Petroleum Ether
                                 Extractibles,
                                 Gravimetric
                                    Method,  mg/1

                               Influent  Effluent
         C-l
01
         C-2
         C-3
         C-4
112.3
97.4
110.7
106.1
359.6
363.6
215.6
599.8
881.1
28.9
43.1
26.0
22.3
42.2
44.0
53.5
51.6
55.4
 165.6
 163.2
 202.2
 167.6
  56.7
54.0
                                  44.
                                  51.
                                  46.
19.1

24.2

19.9
94.0
101.0
122.0
126.0
437.0
446.0
323.0
851.0
1,214.0
188.0
148.0
206.0
197.0
18.0
18.0
18.0
16.0
39.0
40.0
54.0
47.0
53.0
39.0
34.0
37.0
35.0
                                                                               6.0
58.0
16.0
                                                                  15.0
                                                                  15.0
90.0
76.0
241.0
193.0
172.0
462.0
611.0
83.0
100.0

141.0

5.0
27.0
13.0
19.0
51.0
14.0
23.0
22.0
71.0
7.0
 55.0

 59.01

102.O1
6.0J
     1.  Carbon  tetrachloride extractibles.

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End-of-pipe control technology for offshore treatment of produced
water  from  oil  and  gas  production  primarily   consists   of
physical/chemical methods.  The type of treatment system selected
for  a  particular  facility  is  dependent  upon availability of
space, waste characteristics, volumes of waste produced, existing
discharge limitations, and other local factors.  Simple treatment
systems may consist of only gravity separation pits  without  the
addition  of  chemicals,  while  more complex systems may include
surge tanks, clarifiers, coalescers,  flotation  units,  chemical
treatment, or reinjection.

Gas Flotation

In a gas flotation unit gas bubbles are released into the body of
waste  water  to  be  treated.   As  the bubbles rise through the
liquid, they attach themselves to any oil droplet in their  path,
and the gas and oil rise to the surface where they may be skimmed
off as a froth.

Two  types  of  gas  flotation  systems are presently used in oil
production:  1)  Dispersed  gas  flotation  -  these  units   use
specially  shaped  rotating mines or dispersers to form small gas
bubbles which float to the surface with the contacted  oil.   The
gas is drawn down into the water phase through the vortex created
by  the  rotors, from a gas blanket maintained above the surface.
The rising bubbles contact the  oil  droplets  and  come  to  the
surface  as  a froth, which is then skimmed off.  These units are
normally arranged as a series of cells,  each  one  operating  as
outlined above.  The waste water flows from one cell to the next,
with  a  net  oil removal in each cell (some oil is recycled back
into the water phase by the  rotor  action) .   2)  Dissolved  gas
flotation  -  these units differ from the dispersed gas flotation
because the gas bubbles are created by a change in pressure which
lowers the dissolved gas solubility, releasing tiny  bubbles.   A
portion  of the waste water stream is recycled back to the bottom
of  the  cell  after  waste  water  has  been   gasified.    This
gasification is accomplished by passing the waste water through a
pump to raise the pressure and then through a contact tank filled
with  gas.   The  waste  water  leaves  the  contact  tank with a
concentration of gas equivalent to  the  gas  solubility  at  the
elevated   pressure.   When  the  recycled   (gasified)  water  is
released in the bottom of the cell  (at atmospheric pressure)  the
solubility of the gas decreases and the excess gas is released as
microscopic  bubbles.   These  bubbles  then  rise to the surface
contacting the oil and bringing it to the  surface  where  it  is
skimmed  off.  Dissolved gas flotation units are usually a single
cell only.

On production facilities it is  usual  practice  to  recycle  the
skimmed   oily   froth  back  through  the  production  oil-water
separating units.  A flow diagram of the  two  typical  flotation
units is shown in Figure 6.
                               76

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                           CRUDE OIL PRODUCTION  PROCESSING
   LOW PRESSURE OIL WELL'/''
 INTERMEDIATE
PRESSURE OIL
  WELL
                         HIGH
                       PRESSURE
                       SEPARATOR
HIGH PRESSURE
OILWELL
                                      HEAT
 PROCESS Ol L-
WATER SEPARATION
(HEATER TREATER,
CHEMICAL, ELEC
TRICAL,
GUN BARREL, FREE
WATER KNOCKOUT,
ETC.)
                                                            01 LTD SALES
OIL AND BRINE



1

c
H_
\
0



ROTOR-DISPERSERS
p n n n
k
ofc=> <=>*=> Xeie?
Y
SKIMMED OIL RECYCLE TO PROCESS SEPARATION
                                      SURGE TANK,
                                     SKIMMER TANK
                                                                                         GAS OR AIR
                                                                                       AND CHEMICALS
                                 WASTE WATER TO EITHER
                                                 J
    ROTOR-DISPERSER GAS FLOTATION PROCESS                  DISSOLVED  GAS FLOTATION PROCESS

           Fig.   6    —    ROTOR-DISPERSER AND DISSOLVED GAS FLOTATION PROCESSES
                                    FOR TREATMENT OF PRODUCED WATER

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The  addition  of  chemicals  can  increase  the effectiveness of
either type of gas flotation unit,  some chemicals  increase  the
forces  of  attraction  between  the  oil  droplets  and  the gas
bubbles.  Others develop a floe which eases the  capture  of  oil
droplets,   gas   bubbles,  and  fine  suspended  solids,   making
treatment more effective.

In addition to the use of chemicals to increase the effectiveness
of gas flotation systems, surge tanks upstream of  the  treatment
unit  also  increase its effectiveness.  The period of quiescence
provided by the surge tank allows  some  gravity  separation  and
coalescence  to  take  place, and dampens out surges in flow from
the process units.   This  provides  a  more  constant  hydraulic
loading  to  the  treatment unit, which, in turn, aids in the oil
removal process.

The verification survey conducted on Coastal Louisiana facilities
included 10 flotation systems which varied in  design  capacities
from   5,000   to   290,000  barrels-per-day  and  included  both
rotor/disperser and dissolved gas units.  The  designs  of  waste
treatment  systems  are  basically  the  same  for  both offshore
platform installations and onshore treatment complexes;  however,
parallel  units are provided at two of the onshore installations,
permitting greater flexibility in operations.

Information obtained during the field survey of onshore treatment
systems for Cook Inlet indicated that one  of  the  four  onshore
systems  utilized  a dissolved gas flotation system comparable to
those  used  in   the   Gulf   Coast.    This   system   provides
physical/chemical   treatment  and  consists  of  a  surge  tank,
chemical injection, and  a  dissolved  air  flotation  unit.   In
addition, two of the Cook Inlet platforms use flotation cells for
treatment of deck drain wastes.

Field  surveys  on  the  West  Coast found that physical/chemical
treatment is the primary method of treating  produced  water  for
either  discharge  to  coastal waters or for reinjection and that
flotation is  the  most  widely  used  of  the  physical/chemical
methods.  On the West coast, all treatment systems except one are
located onshore and produced fluids are piped to these complexes.
The  majority  of  the  waste  water  treatment systems have been
converted to reinjection systems.  However, some  of  those  that
still  discharge  are  somewhat different from the systems in the
Gulf Coast and Cook Inlet.   One  of  the  more  complex  onshore
systems  consists  of  pretreatment  and  grit  settling, primary
clarification, chemical addition   (coagulating  agent),  chemical
mixing,  final  clarification,  aeration,  chlorination,  and air
flotation.  This system handles 50,000 barrels-per-day.

Surveys of onshore production facilities in  California  revealed
induced  gas flotation being used for treatment of produced water
for recovery, disposal by reinjection and discharge.  A total  of
                               78

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seven  units were observed, three of which were utilized ahead of
sand filters and one unit was followed by a pond.  The size range
of the entire group was from 10,500 to  350,000  Bbl/day.    Surge
tanks  normally  preceded the flotation units with the floe going
to a sump or being recycled.

In Wyoming two dispersed air  flotation  systems  were  observed,
both  of  which discharge and reinjected for recovery the treated
produced water.  The system consisted of a skim  tank,  flotation
unit,  surge  tank  and  in the case of the discharged stream, an
earthen pond.  The addition of chemicals  was  used  to  increase
separation  efficiency.   The produced water treatment capacities
of the two systems  surveyed  were  70,000  and  340,000  Bbl/day
re spec ti vel y.

Parallel Plate Coalescers

Parallel  plate coalescers are gravity separators which contain a
pack of parallel, tilted plates arranged  so  that  oil  droplets
passing  through  the pack need only rise a short distance before
striking the underside of  the  plates.   Guided  by  the  tilted
plate,  the  droplet  then  rises, coalescing with other droplets
until it reaches the tip of the pack where channels are  provided
to  carry  the  oil  away.   In their overall operation, parallel
plate coalescers are similar to API gravity oil water separators.
The pack  of  parallel  plates  reduces  the  distance  that  oil
droplets  must  rise  in  order to be separated; thus the unit is
much more compact than an API  separator.   Suspended  particles,
which  tend  to sink, move down a short distance when they strike
the upper surface of the plate; then they  move  down  along  the
plate  to  the  bottom  of the unit where they are deposited as a
sludge and can be periodically drawn off.  Particles  may  become
attached  (scale)  to  the  plate surface of the plate; then they
move down along the plate surfaces,  requiring  periodic  removal
and cleaning of the plate pack.

Where  stable  emulsions  are  present, or where the oil droplets
dispersed in  the  water  are  relatively  small,  they  may  not
separate in passing through the unit.

The  verification survey of Coastal Louisiana facilities included
seven plate coalescer systems which had  design  capacities  from
4,500  to  9,000 tarrels-per-day.  A recent survey indicated that
approximately 10 percent of the units in  this  area  were  plate
coalescers  and  they treated about 9 percent of the total volume
of produced water in offshore Louisiana waters.   (4)   Both  the
long-term  performance data and the verification survey indicated
that performance of these units was considerably poorer than that
of flotation units.  In addition  to  the  physical  limitations,
coalescers1  operation  and  maintenance  data indicated that the
units require frequent cleaning to remove solids.
                               79

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No plate coalescers are in  use  in  Cook  Inlet  or  California,
either onshore or offshore.

Filter Systems (Loose or Fibrous Media Coalescers)

Another type of produced water treatment system is filters.   They
may  be  classified  into  two general classes based on the media
through which the waste stream passes.

    1.   Fibrous media, such as fiberglass, usually in  the  form
         of a replacable element or cartridge.

    2.   Loose  media  filters,  which  normally  use  a  bed  of
         granular  material  such as sand, gravel, and/or crushed
         coal.

Some filters are designed so that some coalescing and oil removal
take  place  continuously,  but  a  considerable  amount  of  the
contaminants   (oil  and  suspended  fines)  remain  on the filter
media.  This eventually overloads the filter media, requiring its
replacement or backwashing.  Fibrcus media filters may be cleaned
by special washing techniques  or  the  elements  may  simply  be
disposed  of  and  a  new  element used.  Loose media filters are
normally backwashed by forcing water through  the  bed  with  the
normal  direction  of  flow reversed, or by washing in the normal
direction of flow after gasifying and loosening the media bed.

Filters which require backwashing present somewhat of  a  problem
on  platforms  because  the  valving  and  controls  need regular
maintenance and disposal of  the  dirty  backwash  water  may  be
difficult.    Replacing  filter  media  and  contaminated  filter
elements also create disposal problems.

Measured by the amount of oil  removed,  filter  performance  has
generally  been  good  (provided  that  the  units are backwashed
sufficiently often); however, problems of  excessive  maintenance
and  disposal  have caused the industry in the Gulf Coast to move
away from this type of unit, and  a  number  of  them  have  been
replaced with gas flotation systems.

The  Gulf  Coast  survey  information  indicated that when filter
systems are used there is no initial pretreatment  of  the  waste
other  than  surge  tanks.   Backwashing, disposal of solids, and
complex instrumentation were reported as the main  problems  with
these units.

On the West Coast and Cook Inlet, no filter systems are in use as
the  primary  treatment  method.   Filters  are however, used for
final treatment in injection systems in  California  and  several
steps of filtration are used prior to sea water injection in Cook
Inlet.   On  the  west Coast, these units are preceded by a surge
tank, flotation unit, and other treatment units which remove most
                               80

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of the oil and suspended particles.  These units,  when  used  in
series with other systems, perform well.

In  Wyoming  a site was visited where approximately 6,600 Bbl/day
was being treated by a mixed sand media pressure filter.  Earthen
ponds both preceded and followed the filter  unit  with  backwash
feed  being  pumped  from  the  final  pond and discharged to the
primary pond.

Gravity Separation

The simplist  form  of  treatment  is  gravity  separation.   The
produced  water is retained for a sufficient time for the oil and
water to separate.  Tanks, pits, and,  occasionally,  barges  are
used  as gravity separation vessels.  Large volumes of storage to
permit sufficient retention times  are  characteristic  of  these
systems.   Performance  is  dependent upon the characteristics of
the waste water, water volumes, and availability of space.  While
total gravity  separation  requires  large  containers  and  long
retention  times, any treatment system can benefit from quiescent
retention prior to further treatment.  This retention allows some
gravity separation and dampens surges in volume and oil content.

About 75 percent of the systems on the Gulf  Coast  are   gravity
separation  systems.   The  majority are located onshore and have
limited  application  on  offshore  platforms  because  of  space
limitations.  Properly designed, maintained, and operated systems
can provide adequate treatment.  A 30,000-barrel-per-day  gravity
system  with  the  addition  of chemicals produced an effluent of
less than 15 mg/1 during the verification survey.

Two of the onshore treatment systems in Cook Inlet  use   gravity
separation  with  various  configurations  of  settling tanks and
pits.  No gravity systems were reported to be in use on the  West
Coast.   The four installations visited in 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 field surveys of California, Wyoming,
Texas, Louisiana and Pennsylvania onshore production  sites  were
tanks  and  ponds  when utilized as the single treatment process.
As previously mentioned, tanks do not afford the retention  times
of ponds, but whether or not their primary function is separation
they are effective in skimming readily removed free oil.

In  California  four sites were visited which utilized tankage as
the single method of treatment prior to disposal by  reinjection.
The capacity of these systems to treat produced water ranged from
6,000-35,000 Bbl/day.
                               81

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In Wyoming a total of 37 production facilities were visited which
utilized  either  tanks  or ponds as the method of treatment,   of
the 23 sites using tanks for treatment ranging in produced  water
capacity  from  920  to  34,000  Bbl/day, 11  were reinjecting  for
disposal  and  the  remainder  were  reinjecting  for   secondary
recovery  purposes.   Of  the 14 sites using  ponds for treatment,
nine were discharging, two were reinjecting for  recovery,  while
the remaining three both discharged and reinjected for recovery.

In  Pennsylvania,  where disposal ty discharge is the rule rather
than the exception, 11 sites were visited  which  utilized  ponds
for separation treatment ranging in capacity  from 2-8,000 Bbl/day
of produced water capacity.

Distillation

In California a site was visited which utilized produced water as
boiler  feedwater.  The boiler was fired by field natural gas  and
discharged condensate to the local groundwater table.  The  steam
was  utilized  to  heat onsite crude storage  tanks and the boiler
blowdown containing oil and grease residue was hauled to a  Class
I (California Classification) landfill site.   Reported daily fuel
costs for the 150 Bbl/day facility are $70.

Chemical Treatment

The  addition  of  chemicals  to  the  waste   water  stream is an
effective  means  to  increase  the  efficiencies  of   treatment
systems.   Pilot studies for a large onshore  treatment complex in
the Gulf of Mexico indicated that addition of a coagulating agent
could increase efficiencies approximately  15  percent  and   the
addition  of  a  polyelectrolyte and a coagulating chemical could
increase efficiencies 20 percent.  (5)

Three basic types of chemicals are used for waste water treatment
and, many different formulations of  these chemicals  have  been
developed   for   specific  applications.   The  basic  types  of
chemicals used are:

    1.   Surface Active  Agents  -  These  chemicals  modify  the
         interfacial  tensions between the gas, suspended solids,
         and liquid.  They are also referred  to  as  surfactants,
         foaming agents, demulsifiers, and emulsion breakers.

    2.   Coagulating Chemicals - Coagulating   agents  assist  the
         formation  of floe and improve the flotation or settling
         characteristics of the suspended  particles.   The  most
         common  coagulating  agents  are  aluminum  sulfate  and
         ferrous sulfate.
                               82

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    3.   Polyelectrolytes - These chemicals are long chain,  high
         molecular  weight  polymers used to assist in removal of
         colloidal and extremely fine suspended solids.

The results of two EPA surveys of 33  offshore  facilities  using
chemical treatment in the Gulf Coast disclosed the following:

    1.   Surface active agents and polyelectrolytes are the  most
         commonly used chemicals for waste water treatment.

    2.   The chemicals are injected into the waste water upstream
         from the treatment unit and  do  not  require  premixing
         units.

    3.   Chemicals are used to improve the treatment efficiencies
         of  flotation  units,  plate  coalescers,  and   gravity
         systems.

    4.   Recovered  oil,  foam,  floe,  and  suspended  particles
         skimmed  from  the  treatment  units are returned to the
         process system.

A similar survey of facilities in Cook  Inlet,  Alaska  indicated
that  a  facility uses coagulating agents and polyelectrolytes to
improve  treatment  efficiency.   Recovered  oil  and  floe   are
returned to the process system.

Chemical  treatment  procedures  on the West Coast are similar to
those used in the Gulf Coast and Cook Inlet.  However, there  are
exceptions  where  refined  clays and bentonites are added to the
waste stream to  absorb  the  oil  and  both  are  removed  after
addition  of  a high molecular weight nonionic polymer to promote
flocculation.  The  oil,  clay,  and  other  suspended  particles
removed  from  the  waste  stream are not returned to the process
system but are disposed of at approved land  disposal  sites.   A
14,000-barrel-per-day  treatment  system  using  refined clay was
reported to have generated 60 barrels-per-day of oily floe  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 chemicals used in  the  process  separation
systems may also require modification of chemicals or application
rate  in  the waste stream.  Other chemicals may also be added to
reduce corrosion and bacterial growths which may  interfere  with
both process and waste treatment systems.

Effectiveness of Treatment Systems

Table  22  gives  the  relative long term performance of existing
waste water treatment systems.  The general  superiority  of  gas
flotation units and loose media filters over the other systems is
                               83

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readily  apparent.   However,  individual units of other types of
treatment systems have produced comparable 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 Plate Coalescers           48                31

Filters
  Loose Media                       21                15
  Fibrous Media                     38                 7

Gravity Separation (4)
  Pits                              35                31
  Tanks                             42                48
Table  23  gives  the  performance  of  existing  produced  water
treatment  systems over a 6-month to one and one-half year period
of weekly and monthly sampling.  The data has been  divided  into
treatment systems according to State of location.
                            TABLE 23
            Performance of Various Treatment Systems
                    Wyoming and Pennsylvania


              Type of             Mean Effluent       No.  of Units
              Treatment           Oil and Grease      in Data
State         System              	mq/1	      Base	
Wyoming       Ponds                    8.2                 6
              Gas Flotation           10.6                 2
              Sand Filtration         12.5                 1

Pennsylvania  Ponds                    4.1                 4
                               84

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Zero Discharge Technologies


Water produced along with liquid or gaseous hydrocarbons may vary
in  quantity  from  a trace to as much as 98 percent of the total
fluid production.  Its quality may range from  essentially  fresh
to  solids-saturated  brine.  The no discharge control technology
for the treatment of raw waste water after processing varies with
the use or ultimate disposition of the water.  The water may be:

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

    2.   Injected into  formations  other  than  their  place  of
         origin.

Evaporation

In some  arid and semiarid producing areas, use of evaporation is
acceptable,  although  limited in its practice.  The surface pit,
pond, or reservoir can  only  be  used  where  evaporation  rates
greatly  exceed  precipitation and the quantity of emplaced water
is small.  The pit or pond is ordinarily located on flat to  very
gently  rolling  ground  and  not  within  any  natural  drainage
channel, so as to avoid danger of flooding.  Pit  facilities  are
normally  lined  with impervious materials 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
bexng wetted, no lining is normally applied and  sealing  depends
on  the  natual  swelling  properties of the clays.  All pits are
normally enclosed to prohibit or impede access.

In much of the Rocky Mountain oil and  gas  producing  area,  the
total dissolved solids of the produced waters are relatively low.
These  waters  are  discharged  to  pits and put to use for local
farmers and ranchers by irrigating land and  watering  stock.   A
typical produced water system widely in use is shown in Figure 7.
A cross section of the individual pit is shown in Figure 8.

A  producing  oil  field in Nevada discharges produced water to a
closed saline basin.  The basin  contains  no  known  surface  or
subsurface  fresh  water and is normally dry.  The field contains
13 wells and produces approximately 33 barrels of brine per  well
per day.

Subsurface Disposal

Injection and disposal of oil field produced water underground is
practiced  extensively  by  the petroleum industry throughout the
                               85

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              DETAIL MAP
THEATER
         I  IFWKO
        QHEADER
                      SAMPLE  POINT
f
§

o
m
t
PIT

•• 75'»-
PIT

1
\



                                                     -f
                                         DISCHARGE
                                     500  BBL
                                      WATER
                                    SETTLING
                                      TANK
                                       I
                                      500  BBL
                                    OIL  STORAGE
                                      TANKS
LACT
  Fig.  7    — ONSHORE PRODUCTION FACILITY WITH
                DISCHARGE TO SURFACE WATERS
                    86

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                      DIMENSIONS VARY FOR  VOLUME  NEEDED
                           DEPTH WILL VARY WITH
                          OPERATIONS CONDITIONS
                                 NOTE

PITS ARE EQUIPPED WITH  PIPE DRAINS FOR SKIMMING OPERATIONS
               TO  OBTAIN  OIL-FREE WATER  DRAINAGE
            Fig.   8    — TYPICAL CROSS SECTION UNLINED EARTHEN
                          OIL-WATER PIT
                                   87

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United States.  The  term  "disposal"  as  used  here  refers  to
injection of produced fluids, ordinarily into a formation foreign
to  their  origin.  This injection is for disposal only and plays
no intentional part in secondary  recovery  systems.   (Injection
for  pressure  maintenance  or  secondary  recovery refers to the
emplacement of produced fluids into the  producing  formation  to
stimulate   recovery   of  additional  hydrocarbons  and  is  not
considered end-of-pipe treatment.)  Current industry practice  is
to  apply minimal or no treatment to the water 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.   The  amount  of  treatment  depends on the
formation properties, water characteristics, and the availability
and cost of storage and stand-by wells.

Corrosion is ordinarily caused by low pH, plus dissolved  gasses.
Bactericides serve to inhibit the development of sulfate-reducing
and  slime  producing  organisms.  Chemicals and bactericides are
frequently combined into a single  commercial  product  and  sold
under various trade names. (6)

A   wide  range  of  stable,  semipolar,  surface-active  organic
compounds have been developed to control corrosion in  oil  field
injection  and  disposal systems.  The inhibitors are designed to
provide a high degree of  protection  against   dissolved  gasses
 (carbon  dioxide,  oxygen,  and  hydrogen  sulf ide),  organic and
mineral acids, and dissolved salts.   The  basic  action  of  the
inhibitors  is to temporarily "plant" or form a film on the metal
surfaces to insulate the metal from the corrosive elements.   The
life  of  the  film  is  a function of the volume and velocity of
passing fluids.  Inhibitors may be water soluble  or  dispersible
in fresh water or brine.  They may be introduced full strength or
diluted.   Treatment,  usually in the range of 10 to 50 parts per
million, may be  continuous  or  intermittent  (batch  or  slug).
Effectiveness  of  corrosion  inhibition 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).   These bacteria promote
         corrosion by  removing  hydrogen  from  metal  surfaces,
         thereby  causing  pitting.   The  hydrogen  then reduces
         sulfate ions  present  in  the  water,  yielding  highly
         corrosive  hydrogen sulfide, which accelerates corrosion
         in the injection or disposal system.

    2.   Aerobic slime-forming bacteria.  These may grow in great
         numbers on steel surfaces and serve to  protect  growths
                               88

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         of  underlying  sulfate-reducing  bacteria.   In extreme
         instances, great masses of cellular slime may be  formed
         which may plug filters and sandface.

    3.   Aerobic bacteria that react with iron.  Sphaerotilus and
         Gallionella convert soluble ferrous  iron  in  injection
         water to insoluble hydrated ferric oxides, which in turn
         may  plug  filters  and  sandface.   Oxygen entry into a
         system may also cause the formation of ferric oxide.

Treatment to  combat  bacterial  attack  ordinarily  consists  of
applying   either   a  continuous  injection  of  10  to  50  ppm
concentration of a bactericide or batching once or twice a week.

Scale inhibitors are commonly used in the injection  or  disposal
system  to  combat  the  development of carbonate and sulfates of
calcium,  magnesium,  barium,   or   strontium.    Scale   solids
precipitate  as  a result of changes in temperature, pressure, or
pH.  They may also be developed by combining of waters containing
nigh concentrations of calcium, magnesium, barium,  or  strontium
with   waters  containing  high  concentrations  of  bicarbonate,
carbonate, or sulfate.  Scale inhibitors are basically  chemicals
which  chelate,  complex,  or  otherwise inhibit or sequester the
scale-forming cations.

The  most  widely   used   scale   sequestrants   are   inorganic
polymetaphosphates.    Relatively   small   quantities  of  these
chemicals  will  prevent  the  precipitation  and  deposition  of
calcium  carbonate scale.  Bimetallic phosphates or the so-called
"controlled solubility" varieties are now widely used by the  oil
industry   in   scale   control   and   are  preferred  over  the
polyphosphates.

The downhole completion of a typical injection well is  shown  in
Figure  9.  A producing well is  shown for comparison.  Injection
wells may be completed in a  complicated  fashion  with  multiple
strings  of  tubing,  each injected into a separate zone.  If the
disposal well is  equipped  with  a  single  tubing  string,  and
injection  takes  place  through  tubing separated from casing by
packer, the annular space between tubing  and  casing  is  filled
with  noncorrosive  fluids  such as low-solids water containing a
combination corrosion inhibitor bactericide, or hydrocarbons such
as kerosene and diesel oil.  All surface casing  is  cemented  to
the  ground  surface  to prevent contamination of fresh water and
shallow ground water.   Pressure  gauges  are  installed  on  the
casing  head,  tubing  head,  and  tubing  to detect anomalies in
pressure.  Pressure may also  be  monitored  by  continous  clock
recorders  which  are commonly equipped with alarms and automatic
shutdown systems if a pipe ruptures.

The  injection  well  designed  for  pressure   maintenance   and
secondary recovery purposes is completed in a manner identical to
                               89

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            INJECTION WELL
PRODUCING WELL
vo
o
                                 FRESH  WATER —

                                PROTECTED WITH

                              CASING AND  CEMENT
                                INJECTION SAND
PROTECTED WITH OIL

STRING AND CEMENT

                                                             CO
                                                            t

           O
           < tl
           a.
                                                                      : Cement
                                 O
                               — QJ

                               S 2.

                               »«
                               -
                               O 0)
                               3 3

                               o tt
                               •* o
                               — co

                               =.3
                               CD (D
< o
Q) at
^* 3
re 3
-i re
Cfl 3
                                                                                    3 Z
                                                                                    Q. re
                                                                                    (0 O
                                                                                    i re
                                                                                    

                                                                                    3<
                                                                                    a -*
                                                                                     o
                                   FIGURE
            TYPICAL COMPLETION OF  AN  INJECTION WELL  AND  A PRODUCING  WELL

-------
that  of  the  disposal  well,  except that injection is into the
producing horizon.  Treatment prior to injection  may  vary  from
that  applied  to  the disposal well in as much as water injected
into the reservoir sandface must te as free of suspended  solids,
bacterial  slimes,  sludges,  and precipitates as is economically
possible.  Ordinarily, 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 chemically stable water.   A  typical  open  injection  water
treatment  system  includes a skim pit or tank (steel or concrete
equipped with over-and-under baffles to remove  any  vestiges  of
non-soluable  material remaining after pretreatment) ; an aeration
facility, if necessary  to  remove  undesirable  gasses  such  as
hydrogen sulfide; a filtering system; seepage-proof backwash pit;
accumulator  tank (sometimes referred to as a clear well or clear
water tank) to retain the finished water prior to injection;  and
a chemical house for storing and dispensing treatment chemicals.

In  the system described above no attempt is made to exclude air.
Closed systems, on the other hand, are designed  to  exclude  air
(oxygen).   This is desirable because the water is less corrosive
or requires less treatment to make it  noncorrosive.    The  truly
"closed"  system  is  difficult  to  attain  because  of the many
potential points of entry of  air  into  the  production  system.
Air,  for  example,  can  be  introduced  into  the system on the
downstroke of a pumping well through worn stuffing box packing or
seals.  In a few instances, closed injection (or disposal)  system
is used where product waters ordinarily  have  minimal  corrosive
characteristics.   That  is,  where  salt  water is gathered from
relatively few wells, fairly close together; where wells  produce
from  a  common  reservoir;  or  where  a  one-owner operation is
involved.

There are instances in which a closed  input  or  produced  water
disposal  system  can  be  developed.  In these systems all vapor
space must be occupied by oxygen-free gas under pressure  greater
than  atmospheric.   If  oxygen   (air)  enters  the system, it is
scavenged.

The  "open"  injection  system  has  a  much  greater  degree  of
operational  flexibility  than does the closed system.  Among its
more desirable factors are:

1.  Wider range, type, and control of treatment methods.

2.  Ability to handle greater quantities of water from  different
    sources (diverse leases and fields)  and differing formations.
                               91

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3.  Anility to properly treat waters  of  differing  composition.
    This  factor  enables  incompatible waters to be successfully
    combined and treated on the surface prior to injection.

Disposal Zone

The choice of a brine disposal zone is extremely important to the
success of the injection program.  Prior to planning  a  disposal
program,   detailed  geologic  and  engineering  evaluations  are
prepared by the production divisions of oil producing  companies.
Appraisal  of  the geologic reservoir must include the answers to
questions such as:

1.  How much reservoir volume is available?

2.  Is the receiving formation porous and permeable?

3.  What are the formation's physical and chemical properties?

U.  What geological, geochemical and hydrologic  controls  govern
    the suitability of the formation for injection or disposal?

5.  What  are  the   short-term   and   long-term   environmental
    consequences of disposal?

The geologic age of significant 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 consider it inadvisable to inject into
formations above 1,000 feet,  particularly  where  the  receiving
formation  has  low  permeability and injection pressures must be
high.  If the desired daily average quantity of water  cannot  be
disposed  of, except at surface pressures which exceed 0.5 pounds
per square inch surface guage pressure per foot of depth  to  the
disposal  zone,  particularly in shallow wells, an alternate zone
is usually sought.

It is necessary to be familiar with both the lithology and  water
chemistry  of the receiving formation.  If interstitial clays are
present, their chemical composition and  compatibility  with  the
injected  fluid  must be determined.  The fluids in the receiving
zone must be compatible with those injected.   Chemical  analyses
are performed on both to determine whether their combination will
result  in  the  formation  of  solids  that may tend to plug the
formation.

The  petroleum  industry  recognizes  that  the  most   carefully
selected  injection equipment means nothing if the disposed water
is not confined  to  the  formation  into  which  it  is  placed.
Consequently,  the injection area must be thoroughly investigated
to determine any previously drilled holes.  These  include  holes
                               92

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drilled for oil and gas tests, deep stratigraphic tests,  and deep
geophysical  tests.   If  any  exist,   further  information as to
method of plugging and other technological data  germane   to  the
disposal project is assembled and evaluated.

On the California coast there is a definite trend for all onshore
process  systems  which  handle  offshore  production  fluids  to
reinject produced water for disposal.   Field  investigations  made
in California were confined to OCS waters, with visits being made
to  five installations.  Each of these facilities were performing
some subsurface  disposal;  none  were  injecting  for  secondary
recovery  or  pressure  maintenance.  Four of these installations
were sending all or part of the  produced  fluids  to  shore  for
treatment.   All  five  installations  were  disposing of treated
water in wells on the platform.  Two were sending all  fluids  to
shore, separating the oil and water, and then pumping the treated
water  back  to the platforms for disposal.  One installation was
separating the oil and water on the platform and further  treating
the water so that it could be injected into disposal wells on the
platform.  Two of the platforms had been treating all  fluids  on
the platform and injecting treated water.  Since the total fluids
produced  are presently greater than the capacity of the  disposal
system, the excess treated water is being  discharged  overboard.
Plans  were  being  formulated  to  increase  the capacity of the
disposal system to return all produced water underground.

Produced water disposal is commonly handled on a  cooperative  or
commercial  basis,  with  the  producing  facility  paying  on  a
per-barrel  basis.   The  disposal  facility  may  be  owned  and
operated  by an individual, a cooperative association, or a joint
interest group who may operate a central  treatment  or  disposal
system.   The waste water may be trucked or piped to the  facility
for treatment and disposal.  Two examples of  cooperative   systems
are  operating  in  the  East Texas Field and the Signal  Hill and
Airport Fields at Long Beach, Calfornia.

Alternate Handling

During major breakdown and overhaul of waste treatment equipment,
it is common practice to continue  production  and  by  pass  the
treatment units requiring repair.  This does not create a serious
problem at large onshore complexes where dual treatment units are
available,  but  at  strailer facilities and on offshore platforms
there may not be an alternate unit to  use.   Alternate  handling
practices  vary  considerably  from  facility  to  facility.  The
following methods are currently practiced offshore:

1.  Discharge overboard without treatment.

2.  Discharge after removal of free oil in surge tank.
                               93

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3.  Discharge to a sunken pile with  surface  skimmer  to  remove
    free oil.

4.  Discharge of produced  water  to  oil  pipeline  for  onshore
    treatment.

5.  Retention on the facility using available storage.

6.  Production shutdown.

The method used depends upon the design and system  configuration
for the paricular facility.

End-of-Pipe Technology for Wastes Other than Produced Water

Deck Drainage

Where  deck  drainage  and  deck washings are treated in the Gulf
Coast, the water is treated by gravity separation, or transferred
to  the  production  water  treatment  system  and  treated  with
production water.  Platforms in California pipe the deck drainage
and  deck  washings  along  with  produced  fluids  to  shore for
treatment.  In Cook Inlet, these wastes are being treated on  the
platform.

Field   investigations  conducted  on  platforms  at  Cook  Inlet
indicate that the most efficient system  for  treatment  of  deck
drainage waste water in this area is gas flotation.  Limited data
indicate an average effluent of 25 mg/1 can be obtained from this
system.   The  field  investigations  found  that  deck  drainage
systems operate much  better  when  crankcase  oil  is  collected
separately  and when detergents are not used in washing the rigs.
The practice of allowing inverted emulsion muds to get  into  the
deck  drain  system, during drilling or workovers, also seemed to
adversely effect treatment.

Sand Removal

The fluids produced with oil and gas may contain small amounts of
sand, which must be removed from lines and vessels.  This may  be
accomplished  by  opening  a  series  of  valves  in  the  vessel
manifolds that create high fluid velocity around the valve.   The
sand  is then flushed through a drain valve into a collector or a
55-gallon drum.  Produced sand may also  be  removed  in  cyclone
separators when it occurs in appreciable amounts.

The  sand  that  has been removed is collected and taken to shore
for disposal; or the oil is removed with a solvent wash  and  the
sand is discharged to surface waters directly.

Field   investigations   have  indicated  that  some  Gulf  Coast
facilities have sand removal  equipment  that  flushes  the  sand

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through  the cyclone drain valves, and then the untreated sand is
bled into the waste water and discharged overboard.

No sand problems have been indicated by the operators in the Cook
Inlet area.  Limited data indicate that California pipes most  of
the  sand with produced fluids to shore where it is separated and
sent to State approved disposal sites.

At least one system has been  developed  that  will  mechanically
remove  oil  from produced sand.  The sand washer systems consist
of a bank of cyclone separators, a classifier vessel, followed by
another cyclone.  The water passes to an oil water separator, and
the sand goes to the sand washer.  After treatment, the  sand  is
reported   to   have  no  trace  of  oil,  and  the  highest  oil
concentration of the transferred water was less than 1 ppm of the
total volume discharged. (6)

Drilling Muds and Drill Cuttings  (Offshore)

Oil and gas drilling operations, including exploratory  drilling,
are  accomplished  offshore with the use of mobile drilling rigs.
These drilling units are either  self-propelled  or  towed  units
that  are  held over the drilling site by anchors or supported by
the ocean floor.  The wastes generated from  drilling  operations
are  drilling fluids or "muds" used in the drilling process, rock
cuttings removed from the wellbore by the  drilling  fluids,  and
sanitary wastes from human activity.

Both  water  based  and oil muds are used. (10)  In-plant control
techniques and drilling mud practices are affected by the type of
mud used,  conventional mud handling equipment is used for  water
based muds.  Some of the water based muds are discharged into the
surface  waters,  with  no  special  control  measures other than
routine  conservation  and  safety  practices.    Operation   and
maintenance  procedures  on  drilling rigs using water based muds
are routine housekeeping practices  associated  with  cleanliness
and  safety.   A conventional drilling mud system for water based
muds consists of a circulating system including pumps and  pipes,
mud  pits,  and  accessory conditioning equipment  (shale shakers,
desanders, desilters, degassers).

In-plant  control  techniques  for  oil  muds   are   much   more
restrictive.   They  are not discharged into surface waters.  The
in-plant practices include mud saving  containers  on  board,  in
addition to the conventional mud handling system.  Operations and
maintenance  practices  on  rigs using oil muds generally reflect
spillage prevention and control measures, such as drill pipe  and
kelly wipers, and catchment pans.

Cuttings  from  drilling  operations  are  disposed  into surface
waters when water based muds are used.   However,  cuttings  from
oil  mud  drilling are usually collected and transported to shore
                               95

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for disposal.  Another method is to collect cuttings, clean  them
with  a  solvent  water  mixture, and subsequently dispose of the
washed cuttings into the surface water body.  After washing,  the
solvent  water  is  transferred to shore or contained in a closed
liquid recovery system. (11)

Drilling Muds and Drill Cuttings (Onshore)

With  onshore  drilling,  the  discharge  from   shale   shakers,
desilters,  and desanders is placed in a large earthen pit.  When
drilling operations terminate, the pit is backfilled  and  graded
over.  Remaining muds, either oil or water based, are reclaimed.

Well Treatment

Acidizing  and  fracturing  performed as part of remedial service
work on old or new wells can produce wastes.   Additionally,  the
liquids  used  to  kill  a  well so that it can be serviced might
create a disposal problem.

Spent acid and fracturing fluids usually move through the  normal
production  system and through the waste water treatment systems.
The fluids therefore do not appear as a  discrete  waste  source.
Their  presence, however, in the waste treatment system may cause
upsets and a higher oil content in the discharge water.

Liquids used to kill wells are normally drilling mud,  water,  or
an  oil  such  as  diesel  oil.   If  oil is used it is recovered
because of its value, either by  collecting  it  directly  or  by
moving it through the production system.  If the killing fluid is
mud  it  will  be  collected for reuse or discharged as described
earlier in this section.  If water  is  used  it  will  be  moved
through the production and treatment systems and disposed.

Sanitary  (Offshore)

The  volume and concentration of sanitary wastes vary widely with
time,  occupancy,  platform  characteristics,   and   operational
situation.   The  waste  water primarily contains body waste but,
depending upon the sanitary system for the  particular  facility,
other  waste  may  be contained in the waste stream.  Usually the
toilets are flushed with water but, in some cases brackish or sea
fresh water is used.

The concentrations of  waste  are  significantly  different  from
those  for  municipal  domestic  discharges,  since  the offshore
operations require regimented  work  cycles  which  impact  waste
concentrations  and cause fluctuation in flows.  Waste flows have
been found to fluctuate up to 300 percent of the  daily  average,
and BOD concentrations have varied up to 400 percent.  (12)
                               96

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There  are  two  alternatives to handling of sanitary wastes from
offshore facilities.  The wastes can be treated at  the  offshore
location  or  they  may  be  retained  and  transported  to shore
facilities for  treatment.   Offshore  facilities  usually  treat
waste  at the source.  The treatment systems presently in use may
be categorized as physical/chemical and biological.

Physical/chemical      treatment       may       consist       of
evaporation-incineration,  maceration-chlorination,  and chemical
addition.  With the exception of  maceration-chlorination,  these
types  of units are often used to treat wastes on facilities with
small complements of men or which are intermittently manned.  The
incineration units may be either  gas  fired  or  electric.   The
electric  units  have  been difficult to maintain because of salt
water corrosion and heating coil failure.  The gas units are  not
subject  to  these  problems  but  create  a  potential source of
ignition which could result in a safety hazard at some locations.
Some facilities have chemical toilets which  require  hauling  of
waste    and    create    odor    and    maintenance    problems.
Macerator-chlorinators have not been used offshore but  would  be
applicable   to   provide   minimal   treatment   for  small  and
intermittently manned facilities.  At this time, there  does  not
appear to be a totally satisfactory system for small operations.

A  much  more  complex  physical/chemical  system  that  has been
installed at an offshore platform  in  Cook  Inlet  consists  of:
primary    solids   separation;   chemical   feed;   coagulation;
sedimentation;   sand   filtration;   carbon   adsorption;    and
disinfection.  All solids and sludge are incinerated.  Because of
start-up difficulties, no data is available for this facility.

It  has  been  reported  that  physical/chemical sewage treatment
systems have performed well in testing on land, but offshore they
have developed  problems  associated  with  the  unique  offshore
environment  including  abnormal  waste  loadings  and mechanical
failure due to weather exposure. (12)

The most common biological system applied to offshore  operations
is  aerobic  digestion  or  extended  aeration  processes.  These
systems usually include:  a comminutor which  grinds  the  solids
into  fine  particles;  an  aeration  tank  with air diffusers; a
gravity clarifier  return  sludge  system;  and  a  tank.   These
biological  waste treatment systems have proven to be technically
and economically feasible means of waste  treatment  at  offshore
facilities   which   have   more   than  ten  occupants  and  are
continuously manned.

Because  of  the  special  characteristics  of   sanitary   waste
generated  by offshore operations,  the design parameters in Table
24 have  been  recommended.   Table  25  shows  average  effluent
concentrations  for various types of treatment units which are in
use at offshore facilities in the coastal waters of Louisiana.
                               97

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Domestic Wastes

Domestic wastes result from  laundries,  galleys,  showers,  etc.
Since  these  wastes do not contain fecal coliform, which must be
chlorinated, they must only be ground  up  so  as  not  to  cause
floating solids on discharge.  Traceration by a comminutor should
be sufficient treatment.
                                98

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Parameters
BOD
            TABLE 24

       Design Requirements

for Offshore Sanitary Wastes (13)

                   Design Requirement
                   Per Capita Per Day
Total Suspended Solids

Flow
                       0.22 Ib


                       0.15 Ib

                       75 gal
                            TABLE 25

         Average Effluents of Sanitary Treatment Systems

                     Louisiana Coastal  (13)
Company
A
B
c
D
E
No. of Units
11
6
17
9
6
BOD
5
mg/1
35
13
15
25
86
Suspended
Solids
mq/1
24
39
43
36
77
Chlorine
Residual
mq/1
1.2
1.8
1.9
2.5
1.3
                               99

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                           SECTION VII

                          Bibliography


1.  University of Texas-Austin,  Petroleum Extension Service,   and
    Texas  Education  Agency  Trade and Industrial Service,  1962.
    "Treating Oil Field Emulsions."  2nd. ed.  rev.

2.  Offshore Operators Committee, Technical Subcommittee.    1974.
    "Subsurface  Disposal  For  Offshore  Produced  Water   -  New
    Source, Gulf of Mexico."  New Orleans, Louisiana.

3.  U.S. Environmental Protection Agency,  National Environmental
    Research Center, Raleigh, North Carolina.   1973.    "Petroleum
    Systems   Reliability   Analysis."    Vol.  II:   Appendices.
    Prepared by Computer Sciences corporation  under contract  No.
    68-01-0121.

4.  Offshore Operators Committee, Sheen  Technical  Subcommittee.
    1974.   "Determination of Best Practicable Control Technology
    Currently Available To Remove Oil From  Water  Produced  With
    Oil  and  Gas."   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.  Hanby, Kendall P.,  Kidd,  Robert  E.,  and  LaMoreaux,   P.E.
    1973.   "Subsurface  Disposal  of Liquid Industrial Wastes in
    Alabama."   Paper  presented  at  the  second   International
    Symposium  on  Underground  Waste  Management  and Artificial
    Recharge, New Orleans, Louisiana, September 26-30, 1973.

8.  Ostroff,  A.G.   1965.   "Introduction  to  Oil  Field  Water
    Technology."  Prentice Hall, Inc.

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.H.,  and  Methven,  N.E.    1971.
    "Prevention  of  Offshore  Pollution  From  Drilling Fluids."
    Paper presented at the 46th Annual SPE of  AIME Fall  Meeting,
                              100

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    New  Orleans,  Louisiana,  October  3-6,  1971.  Preprint No.
    SPE-3579.

11. Cranfield,  J.   1973.    "Cuttings  Clean-Up  Meets  Offshore
    Pollution  Specifications." Petrol. Petrochem. Int., Vol. 13:
    No. 3, pp. 54-56, 59.

12. Martin, James C.  1973.   "Domestic  Waste  Treatment  in  the
    Offshore  Environment."    Paper  presented  at the 5th Annual
    Offshore Technology Conference.  Preprint No. OTC 1737.

13. U.S. Department of the  Interior.   "Sewage  Effluent  Data."
    (Unpublished Report) August 16, 1972.
                              101

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                          SECTION VIII

           COST, ENEJRGY, AND NONWATER-QUALITY ASPECTS

This   section  will  discuss  the  costs  incurred  in  applying
different levels of pollution control technology.   The  analysis
will  also describe energy requirements, nonwater-quality aspects
and their magnitude, and unit costss for treatment at each  level
of  technology.   Treatment cost for small, medium, and large oil
and gas producing facilities have teen estimated for  BPCT,  BAT,
and   new   sources   end-of-pipe   technologies.   For  existing
facilities in the  oil  and  gas  extraction  industry  presently
discharging  formation water, the estimated capital cost required
to comply with BPCT effluent limitation by 1977  is  $147,307,000
and  the  annual  costs for debt service, depreciation, operation
and maintenance, and energy are $43,609,000.

Cost Analysis

Section IV discusses the major categories of industry  operations
or  activities and identifies subcategories within each one.  For
purposes of cost analysis of end-of-pipe  treatment  three  waste
streams are considered — produced water with discharge, produced
water  reinjected,  and  sanitary wastes (offshore).  The cost of
water treatment or disposal for produced water generated  in  the
offshore  and  coastal subcategories is significantly affected by
availability of space.  The  cost  analysis  has  therefore  been
subdivided  into  two  areas; offshore water disposal and onshore
water disposal.  The onshore  water  disposal  has  been  further
subdivided   regionally.   Deck  drainage  is  considered  to  be
treatable with the production water.  Handling of drilling  muds,
well  treatment  wastes,  and  produced  sands  do  not  add  any
significant costs because the regulations requirements are common
industry practice.  In  some  instances  offshore,  the  produced
water  is  transferred  to  shore  along with the crude, while in
others the waste treatment system is installed on the  platforms.
Therefore,  not  all  platforms  will  need  to  add  all  of tne
treatment  equipment  or  incur  all  of  the  incremental  costs
indicated  to bring their raw discharges into compliance with the
effluent limitations.  Existing water treatment  systems  include
sumps  and sump piles, pits, tanks, plate coalescers, fibrous and
loose  media  coalescers,  flotation  systems   and   reinjection
systems.

Offshore Produced Water Disposal

The systems currently used or needed for the treatment of process
waste  water  (formation  water) resulting from the production of
oil and gas  involve  physical  separation,  sometimes  aided  by
chemical application, prior to discharge.  Shallow well injection
has  also  been successfully used for disposal of produced wastes
                              103

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at  onshore  locations  and  at  several  offshore  locations  in
California.

The  methods  examined  for  offshore  use.  include the following
arrangement of components:

    Al   Gravity  separation  using  tanks,  then  discharge   to
         surface water.

    A2   Gravity  separation   using   plate   coaleseers,   then
         discharge to surface water.

    B    Separation by coalescence,  using  flotation  equipment,
         then discharge to surface water.

    C    Separation  by  coalescence,  using  flow   equalization
         (surge  tanks), desanders, and flotation, then discharge
         to surface water.

    O    Separation using  filters,  then  discharge  to  surface
         water.

    £1   Separation using  flow  equalization   (surge  tank)  and
         filter with disposal by shallow well injection.

    £2   Separation  using   flow   equalization    (surge   tank)
         desanders  and  filters,  with  disposal by shallow well
         injection.

The  data  available  for  analysis  suggest   sizing   treatment
facilities  for produced water based on these flow rates  (barrels
per  day):   200,  1,000,  5,000,  10,000,  40,000.   Where  flow
equalization  is  provided  for the above 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  developed   for   the   systems
identified based on the following assumptions:

1.  All  cost  data  were  computed  in  terms  of  1973  dollars
    corresponding   to   an   Engineering   News   Record    (£NK)
    construction cost  index  value  of  1,895  unless  otherwise
    stated.

2.  The annualized costs for capital and depreciation  are  based
    on a loan rate of 15 percent which 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.
                               10U

-------
3.  Costs  will  vary  greatly  depending  upon  platform  space.
    Therefore,  investment  costs  have  been  prepared for three
    options:

    a.   Option (a)   assumes  that  adequate  platform  space  is
         available   because   existing  requirements  for  waste
         treatment are contained  in  the  offshore  leases.  (1)
         Therefore,   no additional space will be needed.  Rather,
         the  space  will  be  reused  by  facilities  with  more
         efficient removal capacity.

    b.   Option (t)  assumes  that,  because  of  the  high  costs
         involved  in building platforms, they have been built to
         the minimum size needed for production.  Therefore space
         is not generally available for water treatment equipment
         and  ancillary  facilities.   Space   is   provided   by
         cantilevered  additions  up to 1,000 square feet.  Space
         requirements greater than this amount  will  require  an
         auxiliary platform.  (2)

    c.   Option (c)  is for  new  platforms  being  planned.   The
         needed  space  would  be provided as a basic part of the
         platform design and the costs apportioned  at  $350  per
         square foot.

In  all  three  cases  estimates  are  based on platforms located
offshore in 200 feet of water.  This depth is assumed  to  be  an
average for the period to 1983.

Where  electric  energy  is  required,  generating  equipment  of
adequate capacity for the treatment equipment is provided for all
requirements exceeding 5 horsepower.

Operation and maintenance costs  of  components  of  the  various
systems  are  based on operating costs of the equipment.  (2)  The
resulting percentage of investment cost is shown in Table 26.
                              105

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                            TABLE 26

                     Operating Cost offshore
Facility

Tanks

Plate Coalescers
Flotation Systems*
Filters*
Subsurface Disposal1

Electrical Supply Facilities

Platforms
Basis for Calculating
 Annual O & M Costs
   (Percentage of
  	Investment

        11

        33
        11
        11
         9

        10

         2
1 Excludes electrical power supply cost.
Energy and power for low demand is computed as 2 percent  of  the
investment  cost.   For high demands an electric power cost of 2-
1/2 cents per kilowatt hour is assumed.

The capital costs and annualized costs for  the  six  alternative
produced  water treatment systems, for offshore installation, are
contained in Tables 27-31.  Options (a),  (b) , and (c) , as defined
above, reflect equipment costs, installation,  and  the  cost  of
platform space requirements.

Onshore Produced Mater Disposal

The  waste  water treated onshore will result from either onshore
production facilities or offshore produced water  sent  to  shore
for treatment.  The costs for treatment of offshore wastes, which
are  sent  to shore, treated and then discharged will be somewhat
less than the costs quoted aJDOve.  These  lower costs result  from
cheaper  construction costs onshore, no costs for platform space,
lower 0  and  M  costs,  etc.   The  costs  shown  here  are  for
subsurface disposal onshore.

The  typical  system  for  injection  for disposal only is a flow
equalizing or surge tank, high pressure   pumps,  and  a  suitable
well.   Chemicals  may  be  added  to  prevent corrosion or scale
formation.
                              106

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                                                Table 27
Capital Costs

Annualized Costs
   Capital
   Depreciation
   0 & M
   Energy
  Total Annualized Costs
Cost of water disposal
  $/bbl
                                Formation Water Treatment Equipment Costs
                                          Offshore Installations
                                      200 Barrels Per Day Flow Rate
                               EQUIPMENT COSTS (Thousands of 1974 dollars)
Al
59.3
5.93
5.93
2.95
-
14.8
B
69.7
6.97
6.97
4.7
-
18.6
C
87.1
8.7
8.7
6.4
-
23.8
El
348.7
34.9
34.9
28.0
2.4
100.2
                                                                                        E2
                                                    400.5
.20
.25
.33
1.37
 40.0
 40.0
 31.8
  2.0
113.8

  1.55

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                                                              Table 28
o
00
                                              Formation Water Treatment Equipment Costs
                                                        Offshore Installations
                                                   1,000 Barrels Per Day Flow Rate
                                             EQUIPMENT COSTS (Thousands of 1974 dollars)

Capital Costs
Annual i zed Costs
Capital
Depreciation
0 & M
Energy
Total Annual ized Costs
Al
101

10.1
10.1
6.7
-
26.9
B
143

14.3
14.3
11.6
1.5
41.7
C
176.3

17.6
17.6
14.3
1.5
51.0
El
373.3

37.3
37.3
29.7
3.3
107.6
                                                                                                      E2
                                                                                                     432.2
                                                                                                      43.2
                                                                                                      43.2
                                                                                                      38.0
                                                                                                       4.4
                                                                                                     128.8
               Cost  of water disposal
                 $/bbl
.07
.114
.14
.30
.35

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o
vo
                                                     Table 29
                                     Formation Water Treatment Equipment Costs
                                               Offshore Installations
                                           5,000 Barrels Per Day Flow Rate
                                             (Thousands of 1973 dollars)
                                            Al         A2           B         C
E2
Capital Costs
Option (a)
Option (b)
Option (c)
Annuali zed Costs
Capital & Depre-
ci ati on
Option (a)
Option (b)
Operation &
Maintenance
Energy
Total - Option (a)
Option (b)

Option (a)
Option (b)
47
1,452
432
9.4
290.4
4.32
0.94
14.66
295.66
Cost of
0.008
0.16
21
55
43
4.2
11.0
6.51
0.42
11.13
17.93
Water Disposal
0.006
0.0098
88
146
274
17.6
29.2
8.27
1.76
27.63
39.23
- $/bbl
0.015
0.022
131
204
423
26.2
40.8
12.23
2.62
41.05
55.65

0.023
0.031
74
117
157
14.8
23.4
6.96
1.48
23.24
31.84

0.013
.017
451
518
683
90.2
103.6
39.88
9.02
139.1
152.5

0.076
0.084

-------
                                 Table  30
                 Formation  Water Treatment Equipment Costs
                           Offshore Installations
                      10,000  Barrels  Per Day Flow  Rate
                        (Thousands  of 1973 dollars)
                         Al          A2          B          C
E2
Capital Costs
Option (a)
Option (b)
Option (c)
Annual i zed Costs
Capital & Depre-
ciation
Option (a)
Option (b)
Operation &
Maintenance
Energy
Total - Option (a)
Option (b)

Option (a)
Option (b)
60
2,140
a
12
428
5.52
1.20
18.7
434.7
Cost of
0.005
0.117
31
68
66
6.2
13.6
8.28
0.62
15.1
22.5
Water Disposal
0.004
0.006
148
228
488
29.6
45.6
13.91
2.96
46.5
62.5
- $/bbl
0.013
0.017
206
1,626
708
41.2
325.2
19.33
4.12
64.7
348.7

0.018
0.096
108
161 1
259
21.6
32.2
10.12
2.16
33.9
44.5

0.009
0.012
563
,972
979
112.6
394.4
52.14
11.26
176
457.8

0.048
0.125
Not considered to be a viable  alternative  because  of large  space  requirement.

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                                  Table 31
                  Formation Water Treatment Equipment Costs
                            Offshore Installations
                      40,000 Barrels Per Day Flow Rate
                        (Thousands of 1973 dollars)
                         Al         A2          B         C
E2
Capital Costs
Option (a)
Option (b)
Option (c)
Annuali zed Costs
Capital & Depre-
ciation
Option (a)
Option (b)
Operation &
Maintenance
Energy
Total - Option (a)
Option (b)

Option (a)
Option (b)
a 60
a 98
a 102
12
20.4
18.60
1.20
31.8
40.2
Cost of Water Disposal
0.002
0.0028
355
1 ,780 1
880 1
71
356
33.60
7.10
111.7
396.7
- $/bbl
0.0077
0.027
448
,913
,254
89.6
382.6
, 42.04
8.96
140.6
433.6

0.01
0.030
170
230 2
369 1
34
46.0
15.90
3.40
53.3
65.3

0.004
.005
907
,354
,585
181.4
470.8
89.56
18.14
289.1
578.5

0.020
0.040
No estimate made -  method considered to be impractical  because of large space requirements.

-------
When produced water is treated  and  returned  to  the  producing
formation  for  secondary  recovery,   the  costs  should  not  be
considered as a disposal cost, but rather as a necessary cost  in
production of oil.  When produced water cannot fce returned to the
formation for secondary recovery or for water flooding,  the costs
for  treating  it and providing the injection equipment  becomes a
legitimate disposal cost.

Generalized cost  estimates  for  onshore  disposal  of   produced
formation water were developed to include flow equalization tanks
for  1,000,  5,000  and  10,000 tarrels-per-day water production,
pumps sized for these flow rates and 700 pounds per  square  inch
pressure, and disposal wells of 3,000 foot depth.  A maximum well
capacity  of  12,000  fcarrels-per-day  was assumed.  In  addition,
costs for this system include a lined  pond  to  provide  standby
capability  for  continuing  production for seven days while pump
repairs 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  2-1/2  cents  per  kilowatt  hour.
Operation and maintenance costs were computed at 9 percent of the
capital cost based on an industry-sponsored report.  (2)

Other  costs  for  reinjecting produced formation water  have been
developed from field surveys conducted  by  the  EPA  during  the
first  half  of  1976.  The sites surveyed were selected as being
representative of  reinjection  disposal  technology  within  the
various   states.   The  actual  data,  which  can  be  found  in
Supplement B, was taken from data formats submitted  by   industry
for the selected sites and is presented for the most part without
major adjustment.  In two cases, Pennsylvania and Texas/Louisiana
nearshore platforms, field data was not available and engineering
estimates  were  developed.  The values for capital and operating
costs shown in Tables 32 and 33 are from regression  analysis  of
the field data.
                              112

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State
                            TABLE 32
             Capital costs <»> for Onshore Disposal
           by Reinjection of Produced Formation Water
              From Field Surveys in Selected States
                    (Thousands of 1975 Dollars)
Description  f of Sites  Reiniection Capacity, bbl/day
California
Wyoming
Texas and
Louisiana
Land-based
Land-based
Land-based
6
11
14
10 100
74
80
40
1000
146
117
140
10,000
280
300
375
Pennsylvania  Land-based
                Case I
              Land-based
                Case II
Texas


Louisiana
Nearshore
  Platforms

Nearshore
  Platforms
(2),
(3),


CO
CO
CO
(4)
28 5^
15 24
400
400
190
61
500
470
470
110
1600
1680
(1)   Regression analysis data points.
(2)   Production sites without existing reinjection facilities.
(3)   Production sites presently reinjecting fresh water.
(4)   Engineering estimates.
                              113

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                            TABLE 33
        Annual Operating*»> Costs for Onshore Disposal by
                Reinjection of Produced Formation
           Water From Field. Surveys in Selected States
                   (Thousands of 1975 Dollars)
State
California

Wyoming

Texas and
Louisiana
Description


Land-based

Land-based

Land-based
t of Sites  Reinlection Capacityff bbl/day
              10    100    1000    10,000
Pennsylvania  Land-based
                Case I
              Land-based
                Case II
      6

     11

     14



(2) , (4)

(3) ,(4)
                          7.6

                            5
Texas
Louisiana
Nearshore
  Platforms

Nearshore
  Platforms
 5.6

 8.8

12.5



  14

 6.5


  40


  40
15.5

18.5

  25



  46

16.5


  45


  45
 52

 32

 50



100

 32


122


134
(1)   Regression analysis data points excluding capital and
     depreciation charges.
(2)   Production sites without existing reinjection facilities.
(3)   Production sites presently reinjecting fresh water.
(4)   Engineering estimates.


As  an alternative to no discharge - reinjection technology, cost
estimates were developed for discharge to navigable waters.   The
subcategories  of  production  facilities  selected  for separate
estimates  were  those  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 field survey.

Treatment  technology for the stripper well category was selected
as a surge tank followed by chemical  addition  and  ponds.   The
steel  surge  tank has 2-10 day storage.  The three unlined ponds
in series have a 5-foot operating depth and a retention  time  of
100-600  hours,  depending  upon  the  system's capacity.  Annual
costs consist of: operation at 1-3 hours per day, maintenance  at
5*  of  constructed  value,  electrical  power at 4* per kilowatt
hour, chemical costs at  5  mils  per  barrel  and  capital  plus
depreciation  at  2051  of  constructed  value.   The  capital and
                               114

-------
operating costs for stripper well facilities in  the  size  range
10-10,000 bbl/day are shown on Table 34.

Treatment  technology  for beneficial dischargers was selected as
surge tank, skim basin, chemical feed and gas flotation  followed
by ponds.  The surge tank has a 1-2 hour storage capacity and the
skim  basin  is  provided with an automatic skimming device.  The
gas flotation system uses  induced  air  and  the  ponds  have  a
12-hour  retention  time.   A  standby pond of 48 hours retention
time is also provided.  Annual costs  consist  of:  operation  at
6-12  hours  per  day, maintenance at 8* of equipment constructed
value, electrical costs at 40 per kilowatt hour and chemicals  at
3  3/4  mils  per  barrel.   The  capital and operating costs for
beneficial dischargers in the size  range  5,000-100,000  bbl/day
are shown on Table 35.

Treatment  technology for the coastal platforms was selected as a
surge  tank  followed  by  chemical  feed  and   gas   flotation.
Additional platform space was assumed required to accommodate the
treatment  system.   Design  criteria  and  costing  methods were
patterned after the 1975 Brown and Root Report (3).  The  capital
and operating costs so devised for coastal platforms are shown on
Table   36.    Details  of  cost  estimating  procedure  for  all
categories is available in Supplement "B".


                            TABLE 34
            Cost Estimates for Treatment in Ponds and
       Disposal by Discharge for Stripper Well Facilities
                   (Thousands of 1976 Dollars)


              System Capacity Produced Water, Bbl/day

Cost Item     10     50     100   500    1000   5000   10,000

Construction  12     19.6   24    30.1    36     65.7     90

Operation &
Maintenance    5.6    7.5     8.7  13.8    18.8   38.1     53.2
                              115

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                            TABLE 35
          Cost Estimates for Treatment by Gas Flotation
         & Ponds & Discharge for Beneficial Dischargers
                   (Thousands of 1976 Dollars)
Cost Item

Construction

Operation &
Maintenance
System Capacity Produced Water,  Bbl/day
500  1000  5000  10,000  25,000   50,000  100,000
 92


 32
96


37
155


 72
198


 85
289


137
425


220
600


343
                            TABL£ 36
               Cost Estimates for Treatment by Gas
           Flotation 6 Discharge for Coastal Platforms
                    (Thousands of 1976 Dollars)
Cost Item

Construction

Operation &
Maintenance
System Capacity Produced Water,  Bbl/day
100     1000     5000     15,000     25,000
 55


  8
  133


   43
      267


       83
         394


         132
            482


            172
Offshore Sanitary Wastes

Cost  estimates  for  biological  systems  utilized  on  offshore
platforms  are  for  the  aerobic  digestion  process or extended
aeration treatment plants.  The estimates anticipate the use of a
system including a comminuter  to  grind  the  solids  into  fine
particles, an aeration tank with air diffusers, gravity clarifier
return sludge system and a disinfection tank.

Based  on  the  design requirements stated in Table 24 costs were
developed for systems to serve 25 persons  (2,000  gallons),   50
persons   (4,000  gallons)  and 75 persons (6,000 gallons).  These
costs are contained in Table 37.

Energy Requirements for Operating Flotation Systems

Table 38 presents several estimates of horsepower requirements of
flotation systems for the three levels of production.
                              116

-------
Actual  installations   will   probably   comprise   a   mix   of
manufacturers' units and the typical horsepower requirements will
be  some  weighted  average  of  the values in Table 38.   For the
purpose  of   estimating   energy   requirements,   the   average
requirements  are assumed to be 15, 25, and 60 horsepower for the
5,000, 10,000 and 40,000 bbls per day  production  levels.   (The
118  Hp.  figure for the 40,000 bbls per day unit was rejected as
spurious - an incorrect linear extrapolation on a graph.)

Table 39 presents the calculations  that  translate  these  basic
horsepower requirements into total energy requirements.

One  way to evaluate the energy requirements of flotation systems
is to compare their consumption with that of the  oil  production
associated  with  their  use.  Water production rates do not vary
regularly with crude oil production rates.

In some instances, the 5,000 bbl/day of  produced  water  may  be
associated with a crude oil production of only 5,000 bbl/day.  In
other  cases,  crude  production rates may be 50 to 100 times the
rate of water production or vice versa.   Given  these  variation
and the variable products and costs of refining the crude oil, it
would  be  a  meaningless exercise to attempt to estimate the net
BTU equivalent in terms of barrels of  diesel  oil  for  the  oil
production  associated  with  the  typical water flows.  One can,
however, usefully examine a  range  of  possible  levels  of  net
production  to  get  a  general impression of the relative energy
requirements of flotation systems.  For example, it is reasonable
to assume that  the  5,000  bbl/day  water  production  could  be
associated  with  a  net energy production of anywhere from 50 to
50,000 bbl/day of diesel oil.  Sindlarly the  10,000  and  40,000
bbl/day water flows could be associated with ranges of net diesel
oil  equivalent  flows  from  100 and 100,000 and 400 and 400,000
bbl/day, respectively.   Table  40  presents  a  summary  of  tae
flotation  systems'  energy  consumption data as compared to such
associated oil production rates.

It is clear from Table 40 that the energy required for  flotation
relative to the net energy being produced is very small.   Even in
such  a  rare  case as when water production is 100 times that of
crude oil production, the flotation energy requirements amount to
only 1.5 percent of the net energy being produced.

Nonwater-Quality Aspects

Evaluation  of  in-plant  process  control  measures  and   waste
treatment  and  disposal  systems  for  best  practicable control
technology, best available technology, and new source performance
standards indicates that there will be no significant  impact  on
air  quality.   A  minimal impact is expected, however, for solid
waste disposal from offshore  facilities.   The  collection,  and
subsequent  transport to shore of oily sand, silt, and clays from
                              117

-------
the addition of desanding units, where appropriate,  will generate
a possible need for  additional  approved  land  disposal  sites.
There  are  no  Known radioactive substances used in the industry
other than certain instruments such as well-logging   instruments.
Therefore, no radiation problems are expected.   Noise levels will
not  be  increased  other  than  that  which may be  caused by the
possible addition of power generating equipment on some  offshore
facilities.
                               118

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                          TABLE 37

              Estimated Treatment  Plant Costs
         For Sanitary Wastes For Offshore Locations
             Package Extended Aeration Process
                (Thousands of 1973 dollars)

                                   Treatment Plant Capacity
                                   	(gallons/day)	

                                2.000	4.000	6.000

Capital Cost                    18,000      23,000       28,000

Total Annual Costs               6,010       7,660        9,360

    capital                      1,800       2,300        2,800

    depreciation                 1,800       2,300        2,800

    operation & maintenance      2,050       2,600        3,200

    energy and power               360         460          560
                               119

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                                Table  38

                   Estimated Horsepower Requirements
                          for the Operation of
                      Flotation Treatment Systems
                                                   Source
Level of
Production
bbl/day
5,000
10,000
40,000
I/ Brown
2J Wemco
3/ Letter
Brown
& Root I/
(Hp.)
14
25
118
and Root. I 11-11
WEMCO 2/ NATCO 3/ Rheem 4/
(Hp.) (Hp.) (Hp.)
13 6 20
21 13 25
61 47 50
Komi in 5/
Sanderson
Engring Corp.
(Hp.)
17-1/2
-
81-1/2
Data Sheet, F8-D2, dated 4-19-73
dated June 12, 1974
, from National Tank Com. to Mr. R. W.

     Thieme, OTA, EPA, plus telephone communication, Friday, July 19,
     1974, with Mr. E. Cliff Hill, NATCO

kj   Telephone communication with Mr. Ken Sasseen, Rheem-Superior Corp.,
     California.

_5/   Telephone conversation with Mr. Arthur Albohn, Komline, 201-234-1000
     July 24, 1974.
                                      120

-------
                          TABLE 39
                Estimated Incremental Energy
               Requirements Flotation Systems
5,000 bbl/day of water treated;

15 Hp. for 1 yr. = 3.35 x 1()8 BTU/yr.

 1 bbl diesel oil = 6 x 106 BTU

15 Hp. - yr. = 55.8 bbl diesel oil/yr.

Assume 20% conversion efficiency, then 15Hp. - yr = 279 bbl
  diesel oil/yr.

  10,000 bbl/day of water treated;
     464 bbl diesel oil/yr.

  40,000 bbl/day of water treated;
     1115 bbl diesel oil/yr.
                               121

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                                TABLE 40
              Energy Requirements for Flotation Systems as
                   Compared to Net Energy Production
                Associated with the Produced Water Flows
Produces Water
Flow - bbl/day

  5,000

 10,000

 40,000
Assumed Level of Net Energy
Production in Diesel Oil
Equivalents - bbl/day

  50 to 50,000

 100 to 100,000

 400 to 400,000
Energy for Flotation
Units Diesel Oil
Equivalents - bbl/day

   0.76

   1.27

   3.05
                               122

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                          SECTION VIII

                          Bibliography


1.  Offshore Operators Committee, Sheen  Technical  Subcommittee.
    1974.   "Determination of Best Practicable Control Technology
    Currently Available To Remove Oil From  Water  Produced  With
    Oil  and  Gas."   Prepared  by Brown and Root, Inc.,  Houston,
    Texas.

2.  Joint Association Survey of the U.S. Oil  and  Gas  Producing
    Industry.    1973.   "Drilling  Costs  and  Expenditures  for
    Exploration,  Development and Production  -  1972."   American
    Petroleum Institute, Washington, D. C.

3.  Offshore Operators Committee,  Sheen  Technical  Subcommittee
    1975  "Potential  Impact of EPA Guidelines for Produced Water
    Discharges  from  the  Offshore  and  coastal  Oil  and   Gas
    Extraction  Industry,"  Prepared  by  Brown  and  Root, Inc.,
    Hous ton, Texas.
                              123

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                           SECTION IX

                    EFFLUENT LIMITATIONS FOR
               BEST PRACTICABLE CONTROL TECHNOLOGY

Based on the information contained in the  previous  sections  of
this   report,   effluent   limitations  commensurate  with  best
practicable control technology (BPCT)  currently  available  have
been  established  for  each subcategory.  The limitations, which
must be achieved not later than  July  1,  1977,  explicitly  set
numerical   values   for   allowable   pollutant   discharges  of
oil/grease, chlorine residual and floating solids.  BPCT is based
on control measures and end-of-pipe  technology  widely  used  by
industry.

Produced Water Technology

BPCTCA process control measures include the following:

1.  Elimination of raw waste water  discharged  from  free  water
    knockouts or other process equipment.

2.  Supervised operations  and  maintenance  on  oil/water  level
    controls, including sensors and dump valves.

3.  Redirection or treatment of waste  water  or  oil  discharges
    from safety valve and treatment unit by-pass lines.

BPCTCA  end-of-pipe treatment can consists of some, or all of the
following:

1.  Equalization (surge tanks, skimmer tanks) .

2.  Solids removal desanders.

3.  Chemical addition (feed pumps) .

4.  Oil and/or solids removal.

    a.   Flotation.

    b.   Filters.

    6.   Plate coalescers.

    d.   Ponds.

    e.   Gravity Tanks.

5.  Subsurface disposal.
                              125

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Specific treatability studies are required prior  to  application
of a specific treatment system to an individual facility.

Procedure for Development of EPCT Effluent Limitations

The  effluent  guidelines  limitations  for  produced  water were
determined using effluent data for oil and grease.  This data was
provided by the oil and gas producing industry, Department of the
Interior (U.S. Geological Survey), several States,  EPA  regional
offices,  as  well  as  EPA  data  obtained  during  three  field
verification  studies  and  four  field  surveys   of   operating
platforms  in  the  Gulf  Coast;  Cook Inlet, Alaska; and Coastal
California.

The oil-grease effluent data  were  analyzed  to  assess  average
operating   efficiency  and  variability  for  various  types  of
treatment.  The end-of-pipe technologies  assessed  for  offshore
and  coastal  facilities were; flotation units, plate coalescers,
and fibrous media/loose media filters.   For  onshore  facilities
that   discharge  the  end-of-pipe  technologies  assessed  were;
filters, flotation units, and ponds.

Information was also obtained from  the  industry  that  included
schematics, diagrams, and narratives of operation and maintenance
for 25 selected producing facilities.

A  review  of  the effluent data showed a wide range of treatment
efficiencies from facility to facility  with  similar  treatment,
variability  between different treatment methods, and variability
of effluent levels within  an  individual  facility.   Additional
information  was  reviewed in detail to determine the reasons for
these variations.  It was concluded that treatment efficiency  is
affected   by   uncontrollable   factors  related  to  geological
formation and controllable factors related to industry operations
and analytical procedures.  The factors considered uncontrollable
by current technology are:

    1.   Physical and  chemical  properties  of  the  crude  oil,
         including solubility in water.

    2.   Suspended solids concentrations.

    3.   Fluctuations in flow rate.

    4.   Droplet  sizes  of  the  entrained  oil   (some   control
         possible).

    5.   Degree of emulsification  (some control possible).

    6.   Characteristics of the produced water.

The factors considered controllable are:
                               126

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    1.   Opera-tor training.

    2.   Sample collection and analysis methods.

    3.   Process   equipment    malfunction--for    example    in
         heater-treaters  and  their  dump valves, chemical pumps
         and sump pumps.

    4.   lack of  proper  equipment—for  example,  desanders  or
         large tanks.

    5.   Noncompatible operations.

The major objective of the detailed data analysis was  to  reject
inadequate treatment technology and select facilities utilizing a
sound technical rationale.

Offshore  and  Coastal - Initially, 138 treatment systems  (94 off
Louisiana, 36 off Texas, and 8 off Alaska) were  evaluated.   The
treatment  systems  included  gas  flotation,  plate  coalescers,
fibrous  media  filters,  loose  media   filters,   and   gravity
separation.

EPA  survey  data  show  that  the majority of the simple gravity
systems  produced  highly  variable  effluents  and   were   only
minimally  effective  in  removal  of  oil.  The data from the 36
gravity systems  in  Coastal  Texas  were  derived  from  extreme
variations in analytical procedures.  EPA attempts to verify this
data failed and all of this data had to be rejected.

Ten of the 94 treatment systems off Louisiana had 10 or less data
points;  they  were  rejected.   Eata from the 84 remaining units
were analyzed along with the data collected  from  25  facilities
visited in the EPA verification study.  The variance in treatment
efficiencies was reflected in the data for all types of treatment
methods.   Both loose media and fibrous media filters are capable
of  producing  low  average  effluents,  but   because   of   O6M
difficulties the units are being phased out.

The   plate  coalescer  and  gas  flotation  treatment  units  in
Louisiana with greater than 10 data  points  were  analyzed  with
respect  to  O&M reliability.  A comparison was made to determine
the effectiveness of physical separation of oil  and  ability  to
handle  uncontrollable  variation  in  raw waste cnaracteristics.
The treatment efficiencies of plate coalescers were significantly
below those for gas flotation units.  This  is  supported  by  an
analysis of the design parameters for plate coalescers, which are
similar  to  API gravity separators.  A review of O&M records and
findings from EPA field surveys indicate  that  these  units  are
subject  to  plugging from solids, iron, and other produced water
constituents.  When the parallel plate becomes plugged,  frequent
back  washing,  manual  cleaning,  or  replacement  of  plates is
                              127

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required.   The  effluent  data  showed   highly   variable   oil
concentrations   which   indicated  that  both  controllable  and
uncontrollable   factors   significantly    affected    treatment
efficiencies.   Therefore,  plate coalescers were eliminated from
consideration.

The remaining 32 Louisiana treatment  units  were  dissolved  gas
flotation  systems  with chemical treatment.  Historical data and
reports were available on nine of the units.  Each was  evaluated
to  determine  the  acceptability  of  the data and the causes of
significant  effluent  variations.   A  review  of   the   design
parameters  for  the various systems showed that the systems were
designed for the nraximum 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 chemical treatment rates were modified, and when significant
equipment maintenance or other O6M procedures which affect normal
efficiency of the treatment unit was being performed.   Treatment
data  from  some  of the facilities analyzed were highly variable
with no apparent explanation.  In this case, all of the treatment
data  were  accepted  since  it  appeared  highly  unlikely  that
efficiency  could be normalized with better O&M procedures.  More
likely tne varibility seen  is  attributable  to  the  geological
formation.   Units  with  influent data in excess of 200-300 mg/1
were suspect, since historical data indicated that high influents
could be attributed to dump valve  malfunctions  in  the  process
units.  These units were investigated, and if the causes of their
high  concentrations  were  found,  they were rejected; otherwise
they were accepted.  Units without historical data, but which had
variations similar to those which were  rejected  were  evaluated
and  if  the  variations were judged to be caused by controllable
malfunctions, they were eliminated.  Three systems were  rejected
because  of  reported  process  and  treatment  malfunctions, six
months of data were  rejected  from  two  other  systems  due  to
operational  and start-up problems. For the remaining units, data
points were eliminated since a strong  indication  of  errors  in
sample collection and analysis.

Additional  data were obtained for a number of the units from the
oil companies, the Department of the Interior 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 BPCT.  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  nine  of  the  28  selected  gas
flotation  units  off Louisiana.  The results of the field survey
                               128

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supports the rationale used for selection of exemplary technology
and  establishing  the  data  base   for   determining   effluent
limitations.

Upon  completion  of  the  technical  evaluation  of the data and
units, a detailed statistical analysis was conducted to determine
the form of  the  statistical  distribution  and  to  search  for
anomalous  means  or  variances  which  might  indicate a need to
subcategorize based upon flow rates and space  limitations.   The
initial  review  indicated  that  the  selected  units  data were
similar in distribution, and  although  the  observed  means  and
variances  differed  from  unit  to  unit,  no  basis for further
subcategorization was discovered.

The  statistical  analysis  indicated  that  the  data  were  log
normally  distributed  over  most of the data.  The various units
could be separated statistically into three groups: 1) five high;
2) 13 low; and  3)  nine  average.   The  means  and  99  percent
probability  of  occurance  levels  were  calculated for the low,
high, and total groups.  Even though the group  of  27  flotation
units  could  be  broken  down further (into 3 subgroups), it was
felt  that  at  the  current  level  of  experience,  with   this
technology,  the entire industry could not be expected to achieve
the same level of treatment  as  the  very  best  units  are  now
achieving.   Therefore,  data  from  all  27 Louisiana units were
included in determining the effluent limits for oil.

Further analysis of  the  data  base  showed  that  some  of  the
reported  data were composites (4 grab samples taken in a 24 hour
period, analyzed separately and the  results  averaged)   and  the
rest  were  individual  grab samples.  It was determined that the
grab samples had a higher variance than the composites  and  that
the  compositing  technique  would  result in more representative
results.  The compositing would greatly decrease  the  effect  of
sampling   and   analytical   variance,   which   is  potentially
significant in oil and grease monitoring.

The  composited  data  were  than  analyzed  separately  and  two
different  techniques  were  used on the grab samples analysis to
simulate composite sampling.

A maximum monthly average was also calculated from  the  modified
(composite)  data base.  To utilize all of the data, two different
approaches  were used to determine the monthly averages: 1) based
on dates of observed values - this method averages a given number
of samples (N)  which are 30/N days apart, with the analysis being
performed on these averages;  2)   based  on  randomized  observed
values  -  this  method  divides the 2262 data points into 2262/N
groups, each group containing N randomly  selected  points.   The
analysis is performed on the averages of each group.
                              129

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The  first  method is free of assumptions, but is limited in data
base since only 9 of the units had more than 2  data  points  per
month.  The second method is simple and utilizes all of the data,
but  ignores autocorrelation.  Figure 10 is a plot of the results
of these two methods being applied to the data base.  As  can  be
seen the plots begin separating at 4 samples per month because of
the effects of autocorrelation.

The results of the above analyses are as follows:

1.  Long term average (1 year) - 25 mg/1

2.  Maximum monthly average  (weekly sampling)  - 48 mg/1

3.  Maximum day  (composited) - 72 mg/1

The data in Figure 11 represent a cumulative plot of the modified
daily concentrations for the 27 Louisiana flotation  units.   The
plot is essentially linear over the last 90 percent of the range,
and  the  straight line represents a log normal distribution.  Of
the 2,262 samples, 99 percent have oil concentrations  less  than
72 mg/1.

A  statistical  analysis  was  also  conducted  to  determine the
distribution, and variance for the one flotation unit in  Coastal
Alaska which treated produced waters.  The average oil content in
the  effluent  is  approximately  15 mg/1.  The operation of this
unit appears very similar to the low group units for Louisiana.

Beneficial Use - Data for this sutcategory  were  collected  from
nine  facilities  in  Wyoming representing filters, flotation and
ponds as end-of-pipe technology.  These facilities  were  visited
by  the technical contractor and were considered to have well run
and well maintained operations.  An analysis of the data from the
individual units showed no   significant  difference  between  the
three  technologies  used.   In  addition  to this data, 292 data
points which represented  sampling  done  throughout  Wyoming  by
Region 8 were analyzed.

Since  there  is  no apparent difference in the first nine units,
this data  (160 points) were  combined  and  analyzed.   This  data
base  has  a mean of 10.0 and a daily maximum of 45  (both mg/1 of
oil and grease) .

The Region VIII  data base analysis showed a mean  of  7.2  and  a
daily maximum of 45.

An  additional  analysis  was  run  combining  all the above data
points  (452 points) and this data base had a mean of  8.2  and  a
daily maximum of 44.
                               130

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                Figure 10
99th Percentile of Monthly Average Oil and Grease
                  Concentration vs.
         Frequency Of Sampling Each Month
                                » actual
                                *** randomized
       Number of Samples Per Month (Days Betwaen Samples)

                         131

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                      FIGURE  11

      Cumulative  Plot of Effluent Concentrations of All
 Selected Flotation Units  in the Louisiana Gulf Coast Area
a
W
                        10   20  30  40 50 60  70  80    98    95    98   99
              Per of Samples Equal To Or Less Than Ordinate Value
                                132

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Figure 12 represents a cumulative plat of the combined data base.
A   slight  modification  was  made  to  the  analysis  procedure
described for the offshore data.  In order to have the data  form
a  straight line over the entire range, rather than the upper 80-
90% of the range, a constant is added to each data point so  that
log   (X+A) is plotted rather than log X.  Since the affect of the
constant A is more pronounced for smaller values of X the  result
is  a  straight  line fit over the total range of data.  Once the
99th percentile is determined for the  distribution  of  X+A  the
constant is subtracted and the resulting value is the best fit to
the  distribution of X; this method is called the three parameter
log normal analysis.

Sanitary Wastes — Offshore and Coastal Manned Facilities With 10
or More People

BPCT for sanitary wastes from offshore manned facilities with  10
or  more  people is based on end-of-pipe technology consisting of
biological waste  treatment  systems   (extended  aeration).   The
system   may   include   a  comminutor,  aeration  tank,  gravity
clarifier, return sludge system, and disinfection contact chamber
or other equivalent system.  Studies of treatability, operational
performance,  and  flow  fluctuations  are  required   prior   to
application  of  a  specific  treatment  system  to an individual
facility.

The effluent limitations were based on effluent data provided  by
industry  to the U.S. Geological Survey.  Chlorine residual, BOD,
and suspended solids concentrations for the biological  treatment
systems  were  within  the range of values which would meet fecal
coliform requirements.

The only limitation being set on sanitary wastes is for  chlorine
residual.   This requirement is set to control the fecal coliform
level in this effluent.  Limits on BOD or  suspended  solids  for
these  wastes  are not justified since the BOD and TSS content of
the produced waters  are  likely  to  be  several  hundred  times
greater.

The  limit  for  residual chlorine is greater than 1 mg/1,  but as
close to 1 mg/1 as possible.  The facilities for chlorination  on
offshore  platforms  are  much  less  sophisticated  then typical
municipal treatment plants and  the  flows  much  more  variable.
Therefore,  it  is felt that the standard residual chlorine limit
of 1 mg/1 plus or minus 40 % is unrealistic.  There has  been  no
upper limit set because of a lack of valid data to be used to set
such a limit.

BPCT  for  sanitary  wastes  from  small  offshore facilities and
intermittently  manned  facilities  is   based   on   end-of-pipe
technology  currently used by the oil and gas production industry
and by the boating industry.   These  devices  are  physical  and
                              133

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   100
    90
    80
    70
    60

    50

    40

    30
:r   20
z
o
t—I

jj

LU
%
O
o
Ul
10
<.
UJ
a:
to
08
—i
i—i
o
                                                           X

      45     10       20    30   40     50    60    70     «0      90     95

               PERCENT OF SAMPLES EQUAL  TO  OR LESS THAN ORDINATE VALUE

                 Fig.12 - Cumulative  Plot of Effluent Concentrations
                  or All Wyoming Data (values are plotted as %•+ 1.3)
98   99
                                       134

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chemical  systems  which  may include chemical toilets, gas fired
incinerators, electric  incinerators  or  macerator-chlorinators.
None  of  these  systems has proved totally adequate.  Therefore,
the effluent limitations are based on  the  discharge  technology
which  consists  of  a  macerator-chlorinator.   For  coastal and
estuarine areas  where  stringent  water  quality  standards  are
applicable, a higher level of waste treatment may be required.

The  attainable  level  of  treatment  provided  by  BPCT  is the
reduction of waste such that there will be no floating solids.

Domestic Wastes - Offshore and Coastal

Since these wastes contain no  fecal  coliform,  chlorination  is
unnecessary.   Treatment,  such  as  the  use  of  macerators, is
required to guarantee that this discharge will not result in  any
floating solids.

Deck Drainage - Offshore and Coastal

BPCT  for dec* 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  and  oily  wastes
    from  leaks,  drips  and  minor  spillages  to  deck drainage
    collection systems.

3.  Segregation of  deck  washings  from  drilling  and  workover
    operations.

4.  O&M practices to remove all of the wastes possible  prior  to
    deck washings.

BPCT  end-of-pipe treatment technology for deck drainage consists
of treating this water with waste waters associated with oil  and
gas  production.   The  combined systems may include pretreatment
(solids removal and gravity separation) and further  oil  removal
(chemical  feed,  surge tanks, gas flotation).  The system should
be used only to treat polluted waters.  All storm water and  deck
washings from platform members containing no oily waste should be
segregated as it increases the hydraulic loading on the treatment
unit.

The  limits for deck drainage are the same as for produced waters
offshore.
                              135

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Alternate Handling - Offshore and Coastal

Alternate handling of waste water may be necessary when equipment
becomes inoperative or requires maintenance.  Waste  fluids  must
be  controlled  during  these conditions to prevent discharges of
raw wastes into surface waters.  Control practices currently used
in offshore and coastal operations are:

1.  Waste fluids are temporarily stored onboard until  the  waste
    treatment unit returns to operation.

2.  Waste fluids are directed  to  onshore  treatment  facilities
    through a pipeline.

3.  Placing waste  fluids  in  a  barge  for  transfer  to  shore
    treatment.

4.  Waste fluids are piped to a primary treatment  unit  (gravity
    separation)  to  remove  free  oil  and discharged to surface
    waters.

Drilling Muds

BPCT for drilling muds includes control practices widely used  in
both offshore and onshore drilling operations:

1.  Accessory  circulating  equipment   such   as   shaleshakers,
    agitators,  desanders, desilters, mud centrifuges, degassers,
    and mud handling equipment.

2.  Mud saving and housekeeping equipment such as pipe and  kelly
    wipers,  mud  saver  sub,  drill pipe pan, rotary table catch
    pan, and mud saver box.

3.  Recycling of oil based muds.

BPCT end-of-pipe treatment technology is based on existing  waste
treatment  processes  currently  used  by  the  oil  industry  in
drilling operations.

The limitations for offshore and coastal  drilling  muds  are  as
follows:

1.  Water based and natural muds shall contain no free  oil  when
    discharged.

2.  Oil based and  emulsion  muds  shall  not  be  discharged  to
    surface  waters.   These  muds are to be transported to shore
    for reuse or disposal in an approved disposal site.
                               136

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The limitations for onshore drilling muds are as follows:

1.  The muds shall be discharged to surface waters.   These  muds
    are  to  be  transported  to  and  disposed of in an approved
    disposal site.

Drill Cuttings

BPCT for drill  cuttings  is  based  on  existing  treatment  and
disposal methods used by the oil industry.

The limitations for offshore drill cuttings are as follows:

1.  Cuttings in natural or water based muds shall contain no free
    oil when discharged.

2.  Cuttings  in  oil  based  or  emulsion  muds  shall  not   be
    discharged  to  surface waters.  Cuttings should be collected
    and transported to shore for disposal in an approved disposal
    site.

The limitation for onshore drill cuttings areas follows:

1.  No drill cuttings shall  be  discharged  to  surface  waters.
    These drill cuttings are to be transported to and disposed of
    in an approved disposal site.

Well Treatment

Workover  fluids  other than water, or water based muds are to be
recovered and reused.  Materials not  consumed  during  workovers
and  completions  are  to be transported to and disposed of in an
approved site.

The effluent limitations were determined using data  supplied  by
industry   and   service  companies  serving  the  oil  producing
industry.  The limitation for wastes from well treatment offshore
is:  well  treatment  wastes  shall  contain  no  free  oil  when
discharged.
                              137

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                           Section IX

                          Bibliography


1.  Offshore Operators Committee,  Sheen  Technical  Subcommittee.
    1974.   "Determination of Best Practicable Control Technology
    Currently Available to Remove Oil From  Water  Produced  With
    Oil  and  Gas."   Prepared  by Brown and Root, Inc.,  Houston,
    Texas.
                              138

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                            SECTION X

                    EFFLUENT LIMITATIONS FOR
        BEST AVAILABLE TECHNOLOGY ECONOMICALLY ACHIEVABLE

The  application  of  best  available   technology   economically
achievable  is  defined  as  improved  O6M  practices and tighter
control  of  the  treatment  process   for   the   far   offshore
subcategory.    BATEA   for   the   near   offshore  and  coastal
subcategories are defined as  subsurface  disposal  for  produced
waters.   BATEA  for  the  onshore,  beneficial use, and stripper
subcategories are the same as BPTCA.  These effluent  limitations
are to go into effect no later than July 1, 1983.

The  limitations  for all subcategories are the same as BPTCA for
drilling muds, drill cuttings, sanitary and domestic wastes, well
treatment, and produced sands.  Additionally the BATEA limitation
for deck drainage in the near offshore subcategory is the same as
for BPTCA.

Near Off shore and Coastal Su beat egor i es - Produced Water

The BATEA limitations for produced water in the coastal and  near
offshore  subcategories  is no discharge to surface waters.  This
can be accomplished by reinjection or by end-of-pipe technologies
such as, evaporation ponds and  holding  pits   (when -wastes  are
transferred  to shore) or injection to disposal wells.  About H0%
of those producing facilities with no discharge use one of  these
end-of-pipe technologies.

Existing  no  discharge  systems were reviewed to select the best
technology for the purpose of establishing effluent  limitations.
Holding  pits  were  found  to  be the least desirable because of
frequent overflow, dike failure, and infiltration of  salt  water
into  fresh  water aquifiers.  If properly constructed and lined,
evaporation lagoons may result  in  no  discharge  in   arid  and
semiarid  regions.   However, erosion, flooding, and overflow may
•still occur during wet weather.  Disposal well systems which  may
consist  of  skim  tanks, aeration facilities, filtering systems,
backwash holding facilities, clear water accumulators, pumps, and
wells provide the best method for  disposal  of  produced  water.
These  systems  are  equally  applicable  to onshore and offshore
operations and are the primary method used to dispose of produced
water on the California coast and in the inland areas.

Far Offshore Subcategory - Produced Water and Deck Drainage

The BATEA limitations for produced water and deck drainage in the
far offshore  subcategory  are  based  on  the  same  end-of-pipe
technology  as  used for BPTCA.  It is expected that the industry
will have gained sufficient experience in the  reduction  of  raw
waste  loads and operation of end-of-pipe technologies to improve
                              139

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•their operation by 1983.   In  order  to  define  this  level  of
discharge a statistical analysis was carried out on the data from
the 27 flotation units, used to define BPTCA, to determine if any
units  were  significantly  better  in  effluent quality than the
rest.  A group of 10 flotation units were separated on that basis
and their data analyzed.  The resulting BATEA limitations for oil
and grease are, 52 mg/1 daily maximum (composited)   and  30  mg/1
maximum  monthly  average.  Figure 13 is a cumulative plot of the
effluent concentrations of these 10 selected flotation units.

When the BPTCA limitations were derived, it  was  concluded  that
they should be based on what was being achieved by all facilities
using the BPTCA.

This  conclusion was reached on the basis of industry experience.
Since the industry will have, by  1983,  8  additional  years  of
experience . in  waste  abatement,  there should be no significant
problems in attaining effluent qualities now being  met  by  many
facilities.
                              140

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100
 90
 80

 70

 60

 50

 40


 30
 20
                                                  12
 10
  9
  8

  7

  6

  5

  4
X*
          5    10     20   30  40  50  60  70  80     90    95    9"8  99

             PERCENT OF SAMPLES EQUAL TO OR LESS THAN ORDINATE VALUE

                Fig. 13-Cumulative Plot of Effluent Concentrations
                        of Ten Selected Flotation Units in the
                        Louisiana Gulf Coast Area
                                                      99.8

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                           SECTION XI

                NEW SOURCE PERFORMANCE STANDARDS

The effluent, limitations for new source performance standards are
the  same  as  the  6ATEA  limitations for each suJbcategory.  The
facilities defined here will be built, after this regulation is in
affect.  These facilities should therefore,  be  built  with  raw
waste  load  reduction  and  waste  treatability  in  mind.  As a
result,  the  number  and  magnitude  of  t>oth  preventable   and
unpreventable wastes should be minimized.
                              143

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                           SECTION XII

                        ACKNOWLEDGEMENTS

The  initial  draft  report  was  prepared  by  the  special  Oil
Extraction Task Force which EPA Headquarters established 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
Special Materials Control Division (OSMCD),  Co-chairman;  H.  D.
VanCleave,   OSMCD,   Co-chairman;  William  Bye,  OSMCD;  Thomas
Charlton, OSMCD; Harold Snyder, OSMCD; Kenneth Adams, OSMCD; Hans
Crump-Weisner, OSMCD; Arthur Jenke, OSMCD; R. W.  Thieme,  Office
of  Enforcement  and  General  Counsel; Jeffrey Howard, Office of
Enforcement and General Counsel; Charles Cook,  Office  of  Water
Planning   and  Standards;  Martin  Halper,  Effluent  Guidelines
Division; Dennis Tirpak,  Office  of  Research  and  Development;
Thomas Belk, Permit Programs Division; Richard Insinga, Office of
Planning  and  Evaluation;  Stephen Dorrler, Edison Water Quality
Research Laboratory, Edison, N.J.

Martin Halper, Project  Officer,  Effluent  Guidelines  Division,
contributed to the overall supervision of this study and perpared
this  Development  Document.   Allen Cywin, Director; Ernst Hall,
Deputy  Director;  Harold  Coughlin,  Branch  Chief,   and   John
Cunningham,  all  Effluent  Guidelines Division, offered guidance
during this program.

Special appreciation is given to Mary Lou Ameling, Charles  Cook,
Richard Insinga, and Henry Garson for their contributions to this
effort.

In addition to the Headquarters EPA personnel. Regions V, VI, and
X  were  extremely  helpful  in  supporting  this study.  Special
acknowledgement is made to  personnel  of  the  Surveillance  and
Analysis  Division,  Region  VI,  for  their  dedicated effort in
support  of  the  EPA  Field  Verification  Study,  and  to  Russ
Diefenbach  of  Region  V  who assisted with data acquisition for
onshore technology.  Regions IV and VIII assisted in onshore data
acquisition.

Special appreciation is  extended  to  the  EPA  Robert  S.  Kerr
Research  Laboratory  (RSKRL),  Ada,  Oklahoma, for its technical
support.  RSKRL managed and conducted the entire analytical study
phase for field verification in  Coastal  Louisiana,  Texas,  and
California.

Special  recognition  is  due  EPA  Edison Water Quality Research
Laboratory, Edison, New Jersey, for its  participation  in  field
studies   of   oil   and   gas   operations  and  its  review  of

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contractor-operated analytical laboratories  in  the  Gulf  Coast
area.

Acknowledgement is made to Richard Krahl, Robert Evans, and Lloyd
Hamons,  Department  of the Interior, U.S. Geological Survey,  for
their contribution to the EPA Field  Verification  Study  in  the
Coastal Louisiana area.

Many  state  offices  assisted in the study by providing data and
assisting in field studies.  Among those contributing:   Alabama,
Arizona,   Arkansas,  California,  Colorado,  Florida,  Illinois,
Louisiana, Missouri, Nebraska, Nevada, New Mexico, North  Dakota,
Ohio, Pennsylvania, Utah, and Wyoming.

Our  special  thanks  to  Mrs.  Irene  Kiefer  for  her editorial
services.  Appreciation is extended to the secretarial staffs  of
the  Oil  and Special Materials control Division and the Effluent
Guidelines Division for their efforts in typing many  drafts  and
revisions to this report.

Appreciation  is extended to the following trade associations and
corporations for their assistance and cooperation:  American  Oil
Company;   American   Petroleum   Institute,   Onshore  Technical
Committee, Seth Abbott, Chairman;  Ashland  Oil,  Inc.;  Atlantic
Richfield  Company;  Brown  and Root, Inc.; C. E. Natco; Champlin
Petroleum Company; Chevron Oil Company; Continental Oil  Company;
Exxon  Oil Company; Gulf Oil Company; Marathon Oil Company; Mobil
Oil  Company;  Noble   Drilling   company;   Offshore   Operators
Committee,   Sheen  Technical  Subcommittee,  William  M.  Berry,
Chairman; Oil  Operators,  Inc.;  Phillips  Petroleum;  Pollution
control  Engineers;  Rheem  superior;  Shell Oil company; Sun Oil
Company;  Texaco,  Inc.;  Tretolite  Corporation;  United  states
Filters; Union Filter Company; and WEMCO.
                              146

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                          SECTION XIII

                   GLOSSARY AND ABBREVIATIONS

Acidize  -  To  put  acid  in  a  well to dissolve limestone in a
    producing zone, forming passages through which oil or gas can
    enter the well bore.

Air/Gas Lift - Lifting of liquids by  injection  of  air  or  gas
    directly into the well.

Annulus  or  Annular Space - The space between the drill stem and
    the wall of the hole or casing.

API - American Petroleum Institute.

API Gravity - Gravity (weight per unit of volume) of crude oil as
    measured by a system recommended by the API.

Attapulgite Clay - A  colloidial,  viscosity-building  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  -  Barium  sulfate.   An additive used to weight drilling
    mud.

Barite Recovery Unit (Mud Centrifuge) - A means of removing  less
    dense  drilled  solids from weighted drilling mud to conserve
    barite and maintain proper mud weight.

Barrel - 42 United States gallons at 60 degrees Fahrenheit.

Bentonite - An additive used to increase  viscosity  of  drilling
    mud.

Blowcase - A pressure vessel used to propel fluids intermittently
    by pneumatic pressure.

Blowout  -  A  wild and uncontrolled flow of subsurface formation
    fluids to the earth's surface.

Blowout Preventer  (BOP)  - A device to control formation pressures
    in a well by closing the annulus when pipe  is  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.

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Brine - Water saturated with or containing a  high  concentration
    of  common  salt  (sodium  chloride):   also any strong saline
    solution containing such other  salts  as  calcium  chloride,
    zinc chloride, calcium nitrate.

BS&W   -   Bottom  Sediment  and  water  carried  with  the  oil.
    Generally, pipeline regulations limit BS&W to  1  percent  of
    the volume of oil.

Casing  - Large steel pipe used to "seal off" or "shut out" water
    and prevent caving of loose gravel formations when drilling a
    well.  When the casings are set, drilling  continues  through
    and  below the casing with a smaller bit.  The overall length
    of this casing is called the string of casing.  More than one
    string inside the other may 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  discard  solids;.   The  centrifuge  uses high-speed
    mechanical   rotation   to   achieve   this   separation   as
    distinguished  from  the  cyclone-type separator in which the
    fluid energy alone provides the separating force.   Also  see
    "Desander - Cyclone."

Chemical-Electrical   Treater   -   A   vessel   which   utilizes
    surfactants, other chemicals and an electrical field to break
    oil-water emulsions.

Choke - A device with either a fixed or variable aperture used to
    release the flow of well fluids under controlled pressure.

Christmas Tree - Assembly of fittings and valves at  the  top  of
    the  casing of an oil well that controls the flow of oil from
    the well.

Circulate - The movement of fluid from the  suction  pit  through
    pump,  drill  pipe,  bit  annular  space in the hole and back
    again to the suction pit.

Closed-In  -  A  well  capable  of  producing  oil  or  gas,  but
    temporarily not producing.

Coagulation  -  The  combination  or  aggregation  of  semi-solid
    particles such as fats or proteins to form a  clot  or  mass.
    This   can  be  brought  about  by  addition  of  appropriate
    electrolytes.    Mechanical   agitation   and   removal    of
    stabilizing ions, as in dialysis, also cause coagulation.

Coalescence  -  The  union of two or more droplets of a liquid to
    form a  larger  droplet,  brought  about  when  the  droplets
                               148

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    approach  one  another  close-by  enough  to  overcome  their
    individual surface tensions.

Condensate - Hydrocarbons which are in the  gaseous  state  under
    reservoir  conditions  but  which  become  liquid  either  in
    passage up the hole or at the surface.

Connate Water - Water that probably was laid down  and  entrapped
    with  sedimentary  deposits  as  distinguished from migratory
    waters that have flowed into deposits after  they  were  laid
    down.

Crude  Oil  -  A  mixture  of hydrocarbons that existed in liquid
    phase in natural underground reservoirs and remains liquid at
    atmospheric pressure after passing through surface separating
    facilities.

Cut Oil - Oil that contains water, also called wet oil.

Cuttings - Small pieces of formation that are the result  of  the
    chipping and/or crushing action of the bit.

Derrick  and  Substructure  -  Combined  foundation  and overhead
    structure to provide for hoisting and lowering  necessary  to
    drilling.

Desander  -  Cyclong  -  Equipment,  usually  cyclone  type,  for
    removing drilled sand from the drilling mud stream  and  from
    produced fluids.

Desilter  -   Equipment,  normally  cyclone  type,  for  removing
    extremely fine drilled solids from the drilling mud stream.

Development  Well  -  A  well  drilled  for  production  from  an
    established field or reservoir.

Disposal  Well  - A well through which water (usually salt water)
    is returned to subsurface formations.

Drill Pipe - Special pipe designed to withstand the  torsion  and
    tension loads encountered in drilling.

Drilling  Mud  -  A suspension, generally aqueous, used in rotary
    drilling  to  clean   and   condition   the   hole   and   to
    counterbalance   formation   pressure;  consists  of  various
    substances in a finely divided state, among  which  bentonite
    and barite are most common.

Dump  Valve - A mechanically or pneumatically operated valve used
    on separators, treaters, and other vessels for the purpose of
    draining, or "dumping" a batch or oil or water.
                              149

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Emulsion - A substantially permanent heterogenous mixture of  two
    or  more  liquids  which  are  not normally dissolved in each
    other, but which are held in suspension or dispersion, one in
    the other, by mechanical agitation or,  more  frequently,  by
    adding  small  amounts  of  substances  known as emulsifiers.
    Emulsions may be oil-in-water, or water-in-oil.

EPA - United States Environmental Protection Agency.

Field - The area around a group of producing wells.

Flocculation - The combination or aggregation of suspended  solid
    particles  in such a way that they form small clumps or tufts
    resembling wool.

Flowing Vvell - A well which produces oil or gas without any means
    of artificial lift.

Fluid Inlection - Injection of gases or liquids into a  reservoir
    to  force  oil  toward  and  into producing wells.   (See also
    "Water Flooding.11)

Formation - Various subsurface geological strata penetrated by  a
    well bore.

Formation Damage - Damage to the productivity of a well resulting
    from invasion of mud particles into the formation.

Fracturing  - Application of excessive hydrostatic pressure which
    fractures the well bore (causing lost circulation of drilling
    fluids.)

Freewater Knockout - An oil/water separation tank at  atmospheric
    pressure.

Gas Lift - A means of stimulating flow by aerating a fluid column
    with compressed gas.

Gas-Oil  Ratio  -  Number  of  cubic  feet of gas produced with a
    barrel of oil.

Gathering Line - A pipeline, usually of small diameter,  used  in
    gathering  crude  oil from the oil field to a point on a main
    pipeline.

Gun Barr el - An oil-water separation vessel.

Header - A section of pipe into which  several  sources,  of  oil
    such as well streams, are combined.

Heater-Treater  -  A vessel used to break oil water emulsion with
    heat.
                               150

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Hydrogen  Ion  Concent.rat.ion  -  A  measure  of  the  acidity  or
    alkalinity of a solution, nornrally expressed as pH.

Hydrostatic  Head - Pressure which exists in the well bore due to
    the weight of the column  of  drilling  fluid;  expressed  in
    pounds per square inch  (psi).

Inhibitor  -  An  additive  which prevents or retards undesirable
    changes  in  the  product.    Particularly,   oxidation   and
    corrosion; and sometimes paraffin formation.

Invert  Oil  (Emulsion Mud)  - A water-in-oil emulsion where fresh
    or salt water is in dispersed phase  and  diesel,  crude,  or
    some  other oil is the continuous phase.  Water increases the
    viscosity and oil reduces the viscosity.

Kill a Well - To overcome pressure in a well by  use  of  mud  or
    water so that surface pressures are neutralized.

Location  (Drill  Site}  -  Place at which a well is to be or has
    been drilled.

Mud Pit - A steel or earthen tank which is part  of  the  surface
    drilling mud system.

Mud   Pump  -  A  reciprocating,  high  pressure  pump  used  for
    circulating drilling mud.

Multiple Completion  -  A  well  completion  which  provides  for
    simultaneous production from separate zones.

PCS - Outer Continental Shelf.

Offshore - In this context, the submerged lands between shoreline
    and the edge of the continental shelf.

OHM -Oil and Hazardous Material.

Oil  well - A well completed for the production of crude oil from
    at least one oil zone or reservoir.

Onshore - Dry land, inland bodies and bays, and tidal zone.

OSMCD - Oil and Special Materials Control Division.

Paraffin - A heavy hydrocarbon sludge from crude oil.

Permeability - A  measure  of  ability  of  rock  to  transmit  a
    one-phase fluid under condition of laminar flow.
                              151

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Pressure  Maintenance  -  The amount of water or gas injected vs.
    the oil and gas production so that the reservoir pressure  is
    maintained at a desired level.

Pump, Centrifugal - A pump whose propulsive effort is effectuated
    by a rapidly turning impeller.

Rank  Wildcat - An exploratory well drilled in an area far enough
    removed   from   previously   drilled   wells   to   preclude
    extrapolation of expected hole conditions.

Reservoir   -   Each  separate,  unconnected  body  of  producing
    formation.

Rotary Drilling - The method of drilling wells  that  depends  on
    the  rotation  of  a  column  of drill pipe with a bit at the
    bottom.  A fluid is circulated to remove the cuttings.

Sand - A loose granular material, most  often  silica,  resulting
    from the disintegration of rocks.

Separator - A vessel used to separate oil and gas by gravity.

Shale - Fine-grained clay rock with slatelike cleavage, sometimes
    containing an oil-yielding substance.

Shaleshaker  -  Mechanical  vibrating  screen to separate drilled
    formation cuttings carried to the surface with drilling mud.

Shut In - To close valves on a well so that it  stops  producing;
    said of a well on which the valves are closed.

Skimmer  -  A  settling tank in which oil is permitted to rise to
    the top of the water and is then taken off.

Stripper Well (Marginal Welljt - A  well  which  produces  such  a
    small  volume of oil that the gross income therefrom provides
    only a small margin of profit or, in  many  cases,  does  not
    even cover actual cost of production.

Stripping  -  Adding  or  removing  pipe when a well is pressured
    without allowing vertical flow at the top of the well.

Tank - A bolted or welded atmospheric pressure container designed
    for receipt, storage, and discharge of oil or other liquid.

Tank Battery - A group of tanks to which  crude  oil  flows  from
    producing wells.

TDS - Total Disolved Solids.

TOC - Total Organic Carbon.
                              152

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Total Depth (T.D.)  - The greatest depth reached by the drill bit.

Treater - Equipment used to break an oil - water emulsion.

TSS - Total Suspended Solids.

USC6 - United States Coast Guard.

USGS - United States Geological Survey.

Water  Flooding  -  Water  is  injected  under  pressure into the
    formation via injection wells and the oil is displaced toward
    the producing wells.

Well Completion - Jn  a  potentially  productive  formation,  the
    completion of a well in a manner to permit production of oil;
    the  walls  of the hole above the producing layer (and within
    it if necessary) must be supported against collapse  and  the
    entry  into the well of fluids from formations other than the
    producing layer must be prevented.  A  string  of  casing  is
    always run and cemented, at least to the top of the producing
    layer,  for this purpose.  Some geological formations require
    the use of additional techniques to "complete" a well such as
    casing the producing formation and using a  "gun  perforator"
    to  make entry holes, the use of slotted pipes, consolidating
    sand  layers  with  chemical  treatment,  and  the   use   of
    surface-actuated underwater robots for offshore wells.

Well Head - Equipment used at the top of a well, including casing
    head, tubing head, hangers, and the Christmas Tree.

Wildcat  Well  -  A well drilled to test formations nonproductive
    within a 1-mile radius of previously drilled  wells.   It  is
    expected  that  probable  hole conditions can be extrapolated
    from previous drilling  experience  data  from  that  general
    area.

Wiper.  ripe-Kelly - A disc-shaped device with a center hole used
    to wipe off mud, oil or  other  liquid  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 Over Fluid  -  Any  type  of  fluid  used  in  the  workover
    operation of a well.
                              153

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                                    TABLE  41

                                   METRIC:  TABLE

                                 CONVERSION  TABLE

MULTIPLY (ENGLISH UNITS)                   by                TO OBTAIN  (METRIC UNITS)

    ENGLISH UNIT      ABBREVIATION     CONVERSION   ABBREVIATION   METRIC UNIT
acre                    ac
acre - feet             ac ft
British Thermal
  Unit                  BTU
British Thermal
  Unit/pound            BTU/lb
cubic feet/minute       cfm
cubic feet/second       cfs
cubic feet              cu ft
cubic feet              cu ft
cubic inches            cu in
degree Fahrenheit       °F
feet                    ft
gallon                  gal
gallon/minute           gpm
horsepower              hp
i nches                  i n
inches of mercury       in Hg
pounds                  Ib
million gallons/day     mgd
mile                    mi
pound/square
  inch (gauge)          psig
square feet             sq ft
square inches           sq in
ton (short)             ton
yard                    yd
* Actual conversion, not a multiplier
0.405
1233.5
0.252
0.555
0.028
1.7
0.028
28.32
16.39
0.555(°F-32)*
0.3048
3.785
0.0631
0.7457
2.54
0.03342
0.454
3,785
1.609
(0.06805 psig +1)*
0.0929
6.452
0.907
0.9144 .
ha
cu m
kg cal
kg cal/kg
cu m/min
cu m/min
cu m
1
cu cm
°C
m
1
I/sec
kw
cm
atm
kg
cu m/day
km
atm
sq m
sq cm
kkg
m
hectares
cubic meters

kilogram - calories

kilogram calories/kilogram
cubic meters/minute
cubic meters/minute
cubic meters
1i ters
cubic centimeters
degree Centigrade
meters
1i ters
liters/second
killowatts
centimeters
atmospheres
kilograms
cubic meters/day
kilometer

atmospheres (absolute)
square meters
square centimeters
metric ton (1000 kilograms)
meter
                                          154

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