EPA-450/3-74-042
July 1974
            FIELD SURVEILLANCE
       AND ENFORCEMENT GUIDE
   FOR PETROLEUM REFINERIES
     U.S. ENVIRONMENTAL PROTECTION AGENCY
        Office of Air and Waste Management
     Office of Air Quality Planning and Standards
           Triangle Park, North Carolina 27711

-------
                                JEEA-450/3-74-Q42_
      FIELD  SURVEILLANCE

  AND  ENFORCEMENT GUIDE

FOR  PETROLEUM  REFINERIES
                    by

                 Anker V. Sims
                The Ben Holt Co.
              201 South Lake Avenue
            Pasadena, California 91101
             Contract No. 68-02-0645
       EPA Project Officer:  Rayburn M. Morrison
                 Prepared for
           ENVIRONMENTAL PROTECTION AGENCY
         Office of Air and Waste Management
      Office of Air Ojoality Planning and Standards
         Research Triangle Park, N.C. 27711
                  July 1974

-------
This report is issued by the Environmental Protection Agency to report
technical data of interest to a limited number of readers. Copies are
available free of charge to Federal employees, current contractors and
grantees, and nonprofit organizations - as supplies permit - from the Air
Pollution Technical Information Center, Environmental Protection Agency,
Research Triangle Park, North Carolina 27711; or, for a fee, from the
National Technical Information Service, 5285 Port Royal Road, Springfield,
Virginia  22151.
This report was furnished to the Environmental Protection Agency by The
Ben Holt Co. ,  Pasadena, California, in fulfillment of Contract No. 68-02-
0645. The contents of this report are reproduced herein as  received from
The Ben Holt Co. The opinions findings,  and conclusions expressed are
those of the author and not necessarily those of the Environmental Protec-
tion Agency.   Mention of company or product names is not to be considered
as an endorsement by the Environmental Protection Agency.
                  Publication No. EPA-450/3-74-042
                                 11

-------
                             ABSTRACT







      A field surveillance and enforcement guide was prepared for




use by air pollution control officers in petroleum refineries and




natural gas processing plants.  The processing facilities used by the




petroleum and natural gas industries are described and air pollution




sources are identified.  The guide includes methods for estimating




emission  rates and describes instruments for monitoring air




pollution sources.  Procedures for inspection and surveillance of




refineries are presented.  Qualification requirements for the field




enforcement officers are discussed.
                                  111

-------
                             CONTENTS


LIST OF FIGURES                                              xiii

LIST OF TABLES                                               xvi

SUMMARY                                                         1

INTRODUCTION                                                   5

    Purpose                                                       5
    Sources of Information                                         5
    Role of Refineries in the Petroleum Industry                    6

REFERENCES                                                     8

I.   PETROLEUM REFINING AND NATURAL GAS PROCESSING     9

    A.  Introduction                                               9
    B.  Crude Distillation and Desalting                          15

        1.   Crude  Distillation Unit                               15
        2.   Naphtha Stabilizer                                   19
        3.   Crude  Desalter                                      19
        4.   Vacuum Unit                                         21
        5.   Pollution Sources                                    23

    C.  Thermal Cracking                                        24

         1.   Process  Objective                                   24
        2.   Cracking  Furnaces                                   25
        3.   Process  Description                                 25
             a.    Visbreaking                                     25
             b.    Thermal Cracking                               27
        4.   Pollution Sources                                    29

    D.  Coking                                                   30

    E. . Deasphalting                                              36

-------
F.  Catalytic Cracking                                        40

    1.   The Fluid Catalytic Cracking Process                 41
    2.   Catalytic Cracking with Bead Type Catalysts          44
    3.   Control Strategies                                    46

G.  Alkylation                                                46
    1.   The Sulfuric Acid Process                            47
    2.   The Hydrofluoric Acid Process                       49
    3.   Pollution Sources                                     49
H.  Isomerization                                            51
I.   Hydrotreating                                            55

J.  Reforming                                                57

K.  Hydroc racking                                            60

L.  Hydrogen Production                                      66

M.  Sweetening                                                69
N.  Asphalt  Air Blowing                                      73

O.  Acid Gas Treating                                        75
    1.   Acid Gas Absorption Processes                       76
         a.   Absorption in Monoethanolamine (MEA)           76
         b.   Absorption in Diethanolamine (DEA)              78
         c.   Absorption in Hot Carbonate                      78

P.  Sulfur Recovery                                          78

    1.   Process Objective                                    78
    2.   Process Description                                  79
    3.   Instrumentation                                      81
    4.   Pollution Sources                                     82
    5.   Tail-Gas Treatment Processes                       83
         a.   Modified Stretford Process                       83
         b.   Solution Claus Process                           84
         c.   Sulfreen Process                                 84
         d.   Stack-Gas  Treating  Processes                    84

O.  Sour Water Stripping                                      85
     1.   Refluxed Sour Water Steam Strippers                  85
    2.   Nonrefluxed Sour Water  Steam Strippers              87
R.   Natural Gas Processing                                   87

     1.   Gas Dehydration  Using Liquid  Absorbent              88
     2.   Gas Dehydration  Using Solid Adsorbent               89
     3.   Acid Gas Removal                                    92
                              VT.

-------
         4.   LPG and Natural Gasoline Recovery                 93
             by Compression
         5.   LPG and Natural Gasoline Recovery                 95
             by Refrigeration
         6.   LPG and Natural Gasoline Recovery                 97
             by Oil Absorption

     S.   Light Ends Recovery                                    99

     T.   Wastewater Systems and Solids Disposal                102

     U.   Flare and Slowdown System                            105

     V.   Storage                                               106
         1.   Floating  Roof Tanks                               108
         2.   Variable Vapor Space Tanks                        109
         3.   Flares and Incinerators                            110
         4.   Vapor Recovery Systems                           110
         5.   Estimated Hydrocarbon Losses                     111
         6.   Potential Point Sources of Pollutants                119

     W.  Loading and Transfer                                  119

         1.   Loading  Equipment                                120
         2.   Vapor Recovery Systems                           120
             a.  Vapor  Recovery to Fuel Gas                    120
             b.  Vapor  Recovery by Absorption in Gasoline      120
             c.  Vapor  Disposal to Flare                       122
         3.   Loading  Losses                                   122
     X.   Fuel Gas Systems                                      123

     Y.   Steam Generation                                      127
     Z.   Cooling Tower                                         129
   AA.   Electric Power Generation                             132

   BB.   Catalyst Regeneration                                  133

II.   REFINERY EQUIPMENT                                   137

     A.   Introduction                                           137

     B.   Pumps                                                137

         1.   Centrifugal Devices                               138
             a.  Centrifugal Pumps                            138
             b.  Axial Pumps                                  143
             c.  Turbine Pumps                               147
         2.   Positive  Displacement Devices                     147
             a.  Reciprocating Piston Pumps                    149
             b.  Plunger Pumps                               151

                                 vii

-------
              c.   Diaphragm Pumps                              151
              d.   Rotary Vane Pumps                             153
              e.   Rotary Gear Pumps                             153
     C.   Compressors                                           156

          1.   Positive-Displacement Compressors                 156
              a.   Reciprocating Piston Compressors              156
              b.   Rotary Lobe Blowers                           157
              c.   Rotary Sliding Vane  Compressors               159
          2.   Centrifugal and Axial Compressors                  159
     D.   Heat Exchangers                                        163

          1.   Direct Heat Exchangers                             163
          2.   Indirect Heat Exchangers                           163

     E.   Furnaces                                               169

     F.   Jet Ejectors                                            177

     G.   Pipe Valves and Fittings                                 180

          1.   Pipe                                               180
          2.   Valves                                             181
          3.   Flanges                                            181
          4.   Vents and Drains                                   183
     H.   Pressure-Reli.ef Devices                                183

          1.   Spring-Loaded Relief Valve                         184
          2.   Rupture Disc                                       186
          3.   Relief Hatch                                        188

     I.    Flares                                                 188

     J.   Knockout Drums                                        191
     K.   Scrubbers                                              192

     L.   Fractionators                                           195

in.   PROCESS INSTRUMENTATION                              199
     A.   Introduction                                            199

     B.   Identification of Process  Instruments                     199

          1.   Indicators                                          201
          2.   Recorders                                          201
          3.   Transmitters                                       202
          4.   Controllers                                         202
          5.   Control Valves                                      203
                                  Vlll

-------
     C.   Flow Measurement                                     203
          1.   Positive Displacement Meters                       203
          2.   Variable-Area Meters                               203
          3.   Variable-Head Meters                              204

     D.   Temperature Measurement                              204
          1.   Thermocouples                                     205
          2.   Thermometers                                     205
          3.   Radiation  Pyrometers                               205
          4.   Resistance Thermometers                          206

     E.   Pressure Measurement                                 206
          1.   Elastic Elements                                   206
          2.   Gravity-Balance Manometer                        206
          3.   Electrical Pressure Instruments                    207
     F.   Level Measurement                                     207

          1.   Float Devices                                      207
          2.   Displacer Devices                                  208
          3.   Hydrostatic  Methods                                208
     G.   Analytical Instruments                                  208
     H.   Computers                                              209

IV.  MONITORING INSTRUMENTATION                          211
     A.   Source Monitoring                                      211
          1.   Monitoring Systems                                 211
              a.   Approaches                                    211
              b.   System Components                            212
              c.   Monitoring Strategy                            215
          2.   Source Monitoring Interfaces                        216
              a.   Probe and Materials o f Construction            217
              b.   Sample  Conditioning                            218
              c.   Sample  Transport and Flow Measurement       220
          3.   Calibration                                         223
          4.   Source Monitoring Instruments                      224
              a.   Gaseovis Contaminants                          224
              b.   Particulates                                   231
     B.   Perimeter Monitoring                                   2^6
          1.   Continuous Monitoring                              237
          2.   Integrated or Static Monitoring                      239

     C.   Portable Sampling Equipment                            240
          1.   Use of Portable  Sampling Equipment                241
          2.   Types of Portable Sampling Equipment              241

                                  ix

-------
     References                                                 245

 V.   MAINTENANCE OF REFINERY RECORDS FOR USE BY      247
     AIR POLLUTION CONTROL FIELD ENFORCEMENT
     OFFICERS

     A.  Introduction                                            247
         1.  Necessity of Keeping Records                       247
         2.  Availability of Records to the Inspector             248
         3.  How Records  will be  Used                          249
             a.   Permit and Source Registration Identification   249
             b.   Emissions Inventories                          249
             c.   Emergency Action                             251
            • d.   Legal Action                                  251

     B.  Format of  Records                                     251

         1.  Period of Time Covered                            253
         2.  Person Responsible for Keeping the Records        253
         3.  Brief Description of Process or Equipment          253
             for Which the Record is Maintained                 253
         4.  Data                                              254
     C.  Types of Records                                       255
         1.  Permit or License Files                            255
         2.  Maintenance Records                               255
         3.  Shutdown and  Startup                               256
         4.  Ground-Level Perimeter  Monitoring and            257
             Continuous Source Monitoring Records
             a.   Particulates                                   257
             b.   Gases (SO2,  H2S, NH3,  NOX> Amines, RSH)       258
     References                                                 260

VI.   ESTIMATING AND ASSESSING EMISSIONS                   261

     A.  Inspection  and Surveillance Procedures                  261

         1.  Initial  Refinery Survey                             262
             a.   Environmental Observations                    263
             b.   External  Observations of Facility               266
                  (1)  Visible  emissions (plumes)                 266
                  (2)  Evaluation of visible emissions             271
                  !3)  Investigation of odor potentials of          272
                      emission sources
                  (4)  Relating source strength to control         274
                      requirements
                                   x

-------
              c.   Management Interview                          276
              d.   Process and Equipment Inventory               277
          2.   Physical Inspection and On-Site Testing              278
              a.   Preparing for the Plant Visit                    278
                  (1)  Review of records and regulations          278
                  (2)  Review of safety precautions and            297
                      procedures
              b.   In-Plant Inspection and Testing                  300
                  (1)  Sensory observations                       301
                  (2)  Observing process instrumentation          304
                  (3)  On-site testing                             304
                  (4)  Grab  sampling                             308
                  (5)  Source testing                              309
          3.   Resurveys and General Surveillance                 311
              a.   Updating the Process Inventory                  312
              b.   Assessing the Quality of Maintenance            313

     B.   Estimation of Losses                                   314

          1.   Direct Estimation Techniques                       315
              a.   Source Testing and Monitoring                  315
              b.   Direct Observation                             317
          2.   Indirect Estimation Techniques                      318
              a.   Data from Process Instruments                 318
              b.   Equipment Inspection and Operational  Data      320
              c.   Data from Air Sampling  Equipment              323

     References                                                 325

 VII. MAINTENANCE                                             327

     A.   Description of Refinery Maintenance Operations          327

     B.   General Plant Maintenance                              328

     C.   Maintenance of Air Pollution Control Equipment          329
          1.   Flare and Blowdown System                         329
          2.   Particulate Matter Control Equipment               330
          3.   Sulfur Recovery Plants                             331

     D.   Maintenance of Monitoring Equipment                    332

VIII. PERSONNEL                                               333

     A.   Manpower Reqvu'rements                                333

     B.   FEO Functions                                         336

     C.   FEO Personnel Qualifications                           337
                                  XI

-------
    D.  Training                                              340
    References                                                341
GLOSSARY                                                    343
                                 XII

-------
                          LIST OF FIGURES
Figure                                                         Page

   1     Flow Diagram of a Small Oil Refinery                     13
   2     Flow Diagram of an Intermediate Oil Refinery             14
   3     Crude Distillation Unit                                    16
   4     Naphtha Stabilizer                                        18
   5     Crude Desalter                                           20
   6     Vacuum Unit                                             22
   7     Visbreaker                                               26
   8     Thermal Cracking Unit                                   28
   9     Coking Unit                                              33
  10     Propane Deasphalting                                     38
  11     Fluid Catalytic Cracking Unit                             42
  12     Moving Bed Catalytic Cracking Unit                       45
  13     Sulfuric Acid Alkylation Process                          48
  14     HF Alkylation Process                                    50
  15     Butane Isomerization                                     52
  16     Hydrotreating                                            56
  17     Reforming                                               58
  18     Hydrocracking Reaction Section                           62
  19     Hydrocracking Distillation Section                         63
  20     Hydrogen Production by Steam Reforming                  67
  21     Gasoline Sweetening                                      72
  22     Asphalt Air Blowing                                      74
  23     Acid Gas  Treating                                        77
  24     Sulfur Plant                                              80
  25     Sour Water Stripping Process                             86
  26     Glycol Dehydration                                       90
  27     Adsorbent Dehydration                                    91
  28     Amine-Water & Glycol Amine Process Using              94
           Breakdown Turbine
  29     Two-Stage Gas Compressor                               96
  30     Oil Absorption Plant                                      98
  31     Light Ends Recovery                                    101
  32     Wastewater System & Solids Disposal                    103
  33     Flare and Blowdown System                              107
  34     Vapor Recovery for Storage                              112
  35     Vapor Pressures of Gasolines and  Finished               114
           Petroleum Products
  36     Working  Loss of Gasoline  from Fixed-Roof Tanks         1 15
                                 Xlll

-------
Figure                                                         Page

  37     Breathing Loss of Gasoline from Fixed-Roof Tanks       116
  38     Loading Rack Vapor Recovery System                   121
  39     Loading Losses  for Tank Trucks                        125
  40     Loss from Loading Tankers and Barges                  126
  41     Refinery Fuel Gas System                               128
  42     Steam Regeneration                                    130
  43     Cooling Tower                                         131
  44     Centrifugal Pump                                      139
  45     Multiple Stage Centrifugal Pump                        141
  46     Canned  Motor Pump                                    142
  47     Close-Coupled Pump                                   144
  48     Balanced Internal Mechanical Seal                       145
  49     Axial Flow Propeller Pump (Elbow Type)                146
  50     Vertical Turbine Pump                                 148
  51     Reciprocating Piston Pump (Double Acting)              150
  52     Diaphragm Pump                                       152
  53     Rotary  Vane  Pump                                     154
  54     Rotary  Gear  Pump (Two-Impeller)                      155
  55     Reciprocating Compressor (2-Stage)                     158
  56     Rotary  Lobe  Blower (Two Impeller)                     160
  57     Rotary  Compressor (Sliding Vane)                       161
  58     Labyrinth Seal                                         162
  59     Barometric Condenser                                  164
  60     Shell & Tube Heat Exchanger                            166
  61     Double-Pipe  Heat Exchanger with Longitudinal Fins       167
  62     Air-Cooled Heat Exchanger                             168
  63     Vertical Cylindrical Furnace                            170
  64     Horizontal Box Type  Fired Heater                       171
  65     Gas Burner                                            173
  66     Combination  Gas and Oil Burner                        175
  67     Steam Jet Ejector                                      178
  68     Flanges                                               182
  69     Relief Valve                                            185
  70     Typical Rupture Disc Installation                        187
  71     Pressure  Relief Hatch                                  189
  72     Elevated Flare                                         190
  73     Knockout Drum                                         193
  74     Scrubber                                               194
  75     Fractionator                                           196
  76     Typical Stack Monitoring System                        221
  77     Fuel Use/Sulfur  Balance Report                         250
  78     Odor Survey  Form                                     252
  79     Activity Status Report                                  284
                                 xiv

-------
Figure                                                         Page

  80     Process Flow Diagram of a Sour Water                 288
  81     Symbols Used in Petroleum Flow Diagrams              289
  82     Bulk Plant Data Sheet                                  291
  83     Truck Loading Inspection Data Sheet                    292
  84     Oil-Water Separator Inspection Sheet                   293
  85     Tank Inspection Report                                 295
  86     Natural Gasoline, Gas, and Cycle Plant                 296
           Survey Summary
                                 xv

-------
                        LIST OF TABLES
                                                              Page

 1.     Products From Three  Typical Refineries                  11

 2.     Sulfur Content in  Coker Products                          31

 3.     Reactor Products                                         41

 4.     Alkylation Processes Operating Temperatures             47
         and Pres sures

 5.     Sulfur and Nitrogen Distribution in the High                61
         Pressure Separator

 6.     H2S Distribution in the Low-Pressure Separator           65

 7.     Loading Losses:  Motor Gasoline,  Turbine  Fuels,         124
         Aviation  Gasoline

 8.     Instrument Identification Codes                           200

 9.     Approaches to Source Monitoring                         212

10.     System Components  and Operations for Stationary         214
         Source Monitoring

11.     Contaminants that can  be Tested in the  Field              306
         with Portable Devices
                               xvi

-------
                              SUMMARY







      This Field Surveillance and Enforcement Guide was prepared to





familiarize state and local air pollution control officials with the





operation of petroleum refineries and natural gas processing plants





and to aid agency personnel developing surveillance,  inspection,





monitoring, reporting, and enforcement procedures.





      The Guide is divided into eight chapters.  The first three





describe present-day refinery equipment and operation with emphasis




on air pollution sources.  The remaining chapters describe monitoring





equipment,  record-keeping requirements and enforcement programs





and procedures.  A glossary of petroleum industry terms is given at





the end  of the guide.







CHAPTER I  PETROLEUM REFINING AND NATURAL GAS





PROCESSING





      A typical refinery consists of a crude distillation unit and a





variety  of units designed to separate, react, and blend petroleum





fractions.   Several air pollution sources are common to many refinery





process units.  Sour  water  streams  contain dissolved sulfur compounds

-------
and ammonia.  Fuel gases containing hydrogen sulfide are produced





at various locations.   Heaters are widely used and produce combustion





products  such as sulfur oxides, nitrogen oxides,  and particulates.





      Special air pollution problems associated with specific





operations are discussed.  These include sulfur oxide emissions from





sulfur plants, particulates,  carbon monoxide and  sulfur oxides from





catalytic  crackers and catalyst regeneration operations,  hydrocarbon





emissions1 from storage and loading facilities,  and emissions from





flares and blowdown  systems.








CHAPTER II - REFINERY EQUIPMENT





      Individual equipment items  located throughout a refinery have





characteristic air pollution problems.  Each type of process equipment





is described with emphasis on air pollution sources.   In  general,





pumps, compressors,  heat exchangers, valves and fittings emit air





contaminants by leakage.  Furnaces and heaters  are  a source of





combustion pollutants.  Relief valves are designed to release gases





at certain pressures and represent an important  potential source of




air pollution.








 CHAPTER III - INSTRUMENTATION





      Process instrumentation and control equipment, including





devices for measuring pressures, temperature,  liquid levels,  and





flow  rates, are described.  The application of commonly used





process instruments to the detection and measurement of air

-------
pollution is discussed.  A table showing the derivation of the codes for




instruments and controls is included.







CHAPTER IV  MONITORING INSTRUMENTATION




       Equipment and strategy for monitoring air pollution sources are




discussed.  Sampling and source monitoring on a local and continuous




basis is described.  Instruments for determination of sulfur dioxide,




nitrogen oxides, carbon monoxide, hydrocarbons,  and particulates are




commercially available.  Instruments may be required for monitoring




ambient air  quality at locations where widespread leakage occurs, such




as hydrocarbon emissions from valves, pumps,  compressors, etc.  Use




of portable instruments is discussed.







CHAPTER V   MAINTENANCE OF REFINERY RECORDS FOR USE BY




AIR  POLLUTION CONTROL FIELD ENFORCEMENT OFFICERS




       The importance of record keeping in refinery surveillance and




control activities is emphasized.  Records available from the refiner




are described.  Records should be kept on emission rates,  source




registration, permits to operate, complaints, episode histories, and




compliance p]ans.  Programs,  strategics,  and formats for  record




keeping are  described.







CHAPTER VI  ESTIMATING AND ASSESSING EMISSIONS




       The procedures for inspection and surveillance of refineries




include the initial  survey, physical inspection, and follow-up surveys.

-------
The initial survey consists of environmental and external observations





including  visible emissions, odor detection,  and management inter-





views.  The physical inspection includes on-site review of records,





sensory tests, instrument readings, equipment inventories and effluent





sampling. A resurvey is  required  to update inspection data and review




maintenance records.  Techniques  for estimating loss rates  are dis-





cussed.







CHAPTER VII   MAINTENANCE




        Refinery maintenance is an  important element of refinery oper-





ations.  Maintenance operations are a source of air pollution,  and




maintenance  records are a valuable source of information to the control





officer.  Chapter VII describes typical maintenance operations.  Main-




tenance of air pollution equipment and monitoring instruments is dis-




 cussed.







 CHAPTER  VIII   PERSONNEL





        Manpower requirements for state and local air pollution control




 agencies  depend upon the number and complexity of refineries and




 other chemical process related plants in the jurisdiction.  The function





 of the field enforcement officer to survey, inspect,  and investigate is




 defined.  Personnel qualifications and a list of programs for training




 and recruiting are given.

-------
                           INTRODUCTION







PURPOSE




       This Guide was prepared to aid state and local air pollution con-





trol officials in carrying out effective surveillance and control of air





pollution sources in petroleum refineries and  natural gas processing





plants.  The Guide is designed to familiarize control officials and field





enforcement officers with  the operation of petroleum refineries and





natural gas processing plants.  In the description  of refinery equipment





operations, particular  emphasis is given to the  air pollution aspects.





Another important purpose is to provide guidance  to agency personnel




in developing surveillance, inspection,  monitoring,  reporting and en-





forcement procedures.








SOURCES OF INFORMATION





       Private and public  sources were used to prepare the Guide.




Public sources include textbooks and journals which are widely distri-





buted in the petroleum industry.  Some general  references  are listed at





the end of this Introduction. Manufacturers and suppliers were relied





upon for information on equipment and monitoring instrumentation.





Catalogs of air pollution control equipment suppliers are regularly

-------
published by Chemical  Engineering and Environmental Science and





Technology.  The files of The Ben Holt Co. and Pacific Environmental





Services, Inc. were also sources of information.







ROLE OF REFINERIES IN THE PETROLEUM INDUSTRY




        The petroleum  industry is divided into the following functional





operations:  exploration, production, transportation, marketing and





distribution,  and refining.   An oil company may perform only one or a




few or all'of these functions.   Exploration and production companies




 search for  oil and gas  reserves, drill wells, and develop  and  produce




 the resource. Many companies provide only transportation services -





 using pipeline, barge,  rail, tanker, and truck facilities.  Marketing





 and distribution generally  refers to petroleum products only.  This




 function  includes sales,  advertising, and distribution to retail and com-




 mercial  outlets.





        The refining function includes  a broad range of processing and




 manufacturing operations designed to  convert crude oil and natural  gas





 to saleable products.  In the early days of the oil industry, the refining




 function  consisted only of batch distilling of crude oil.  As  the number





 and quality of petroleum products increased,  a myriad of refining pro-





 cesses were developed to effect both chemical and physical changes in





 petroleum.  Today,  there are literally hundreds of these processes





 available.  Each refinery consists of  a combination of them.   The con-




 figuration  of each refinery and natural gas processing plant depends on

-------
the feed stock and product specifications.  Field enforcement officers




should not expect to find all or even a majority of the process equip-




ment and abatement techniques presented (in Chapters I and II).  Many




factors, such as throughput, geography,  and slate and product split,




affect not only the number and types of processes utilized, but also the




abatement controls necessary.  By understanding the function and




operation of each refinery process,  the field enforcement officer will




gain the knowledge  of the refining industry necessary to the effective




performance of  his tasks.

-------
                             REFERENCES
TEXTBOOKS AND HANDBOOKS

Danielson, J. A. Air Pollution Engineering Manual,  2nd Ed. ,
Washington,  D. C. , Air Pollution Control District, County of
Los Angeles,  and Environmental  Protection Agency, 1973.  p. 987.

Guthrie, U. B. Petroleum Products Handbook.  New York, McGraw-
Hill Book Co. ,  1960. p. 837.

Lund,  H. F. Industrial Pollution  Control Handbook.  New York,
McGraw-Hill  Book Co., 1971.  p.  886.

Nelson,  W. L.  Petroleum Refinery Engineering.  New York,
McGraw-Hill Book Co. , 1958.  p.  960.

Perry, J.  H.  (ed.).  Chemical Engineers' Handbook,  4th Ed.
New York, McGraw-Hill Book Co. ,  1962. p.  1884.

Stern, A.  C.  (ed.).  Air Pollution, 2nd Ed. 3 vols.  New York,
Academic  Press, 1968.
 JOURNALS

 Chemical Engineering
 Environmental Science and Technology
 Hydrocarbon Processing
 Journal of the Air Pollution Control Association
 Oil and Gas  Journal

-------
                  I.  PETROLEUM REFINING AND




                     NATURAL GAS PROCESSING







A.     INTRODUCTION




       Crude petroleum is a mixture of hydrocarbons and small





amounts  of sulfur,  nitrogen, oxygen, and various metals.  Crude oils





are classified as being  derived from paraffinic,  naphthenic,  or inter-





mediate  base stocks.  The characteristics  of a given crude can vary





from a clear liquid in the  gasoline range to a pitch that is  so viscous it





must be  heated to be  pumped.  Crudes  from geographically related oil





fields tend to have  similar compositions  and properties.





       Refineries are designed to convert  one or more types of crude





oil into saleable petroleum products.   The types of oil processed and





the products desired  determine the facilities of  a refinery.  Theoreti-





cally, it  is possible to produce any type of product from any crude oil,





but in practice economic considerations usually decide which products




will  be produced.





       The trace elements in petroleum also affect the processing





steps and,  to some extent, the pollutant emissions from the refinery.





A  high sulfur content in the crude oil increases  the corrosive charac-





teristics of the oil  and  its products.  After processing  in the refinery,

-------
sulfur tends to concentrate in the light ends and gases in the form of





hydrogen sulfide and in the heavy ends as complex sulfur compounds.





Generally, the hydrogen sulfide is selectively removed from the process





gas by treating with ethanolamines.  The hydrogen sulfide is regenerated





from the ethanolamines and is usually sent to a sulfur recovery unit.





New air pollution control regulations  will require removal of hydrogen





sulfide  and its conversion to sulfur,  or the use of some  other mechanism





for controlling sulfur emissions.   The residual fuels which contain high





percentages  of sulfur can be treated by hydrotreating or hydrocracking





processes to reduce the sulfur content of the fuel oil to  a level that is





acceptable to local air pollution  control agencies.  The sulfur is con-





verted  to hydrogen sulfide and enters the process gas stream.





         Trace metals such as iron, nickel and vanadium are present in





 crude petroleum and act as a poison to some catalysts.  As  the metal





 accumulates on the catalyst, the  activity of the  catalyst decreases.





 Crudes with high concentrations of metal deposits require more frequent





 catalyst regeneration and replacement.  These  operations generally





 release pollutants to the atmosphere and should be carefully controlled.





         The products from a refinery vary widely with location,





 climate and  time of year.  In winter, there is a high demand for heating





 fuel oils,  and the gasoline products must contain  a high percentage of





 volatile components for cold weather starts.  In summer, the demand





 for fuel oil declines,  the demand for  gasoline increases, and the vola-





 tility of the gasoline must be reduced to minimize vapori?.ation losses






                                  10

-------
and carburetor vapor lock.   Refineries must be  sufficiently flexible to

meet these varying demands..

      Table 1 shows the type of products  that might be prepared at

three typical refineries that differ in size,  location and climate.

      Table 1.  PRODUCTS  FROM THREE TYPICAL REFINERIES
Products
Feed, bbl/day
LPG
Olefins
Gasoline
Jet Fuel
Kerosene
Diesel
Fuel Oil
Heavy Fuel Oil
Naphthenates
Solvents
Asphalt
Lubricating Oils
Greases
Petroleum Coke
a
Refinery 1
10,000
X

X

X

X
X


Refinery 2
80,000
X

X
X
X
X
X
X
X
X

Refinery 3
200,000
X
X
X
X
X
X
X
X
X
X
X
X
X
X
a.  Refinery 1 is assumed to have a crude capacity of 10,000 bbl/day
b.  Refinery 2 is assumed to have a capacity of 80,000 bbl/day.
c.  Refinery 3 is assumed to have a capacity of 200, 000 bbl/day.
      As the size of the refinery increases,  the number of products

increases and the processing operation becomes more flexible.   The

production rate of each of the products shown can be varied signifi-

cantly by making relatively minor changes in refinery processing con-

ditions.  Hydrocarbon fractions can be shifted from one product to

another to' meet product demands.
                                 11

-------
       Figure  1 is a flow diagram of a low-capacity, basic refinery

which contains only the minimum number of  elements to supply a local

area with fuels.  This type of refinery is relatively inflexible and pro-

duces only a limited number  of products.

        Figure 2 is a flow diagram of an intermediate capacity refinery.

This facility has more processing units and  a much wider range of

products.  These diagrams show only the most fundamental processing

operations.  A large, complex refinery would  be about  the same with

the addition of specialty processes.

        Operations such as sweetening,  hydrotreating,  hydrocracking,

 sour-water treatment, and sulfur plants are now needed for pollution

 control in most  refineries.  They are not shown because they do not

 affect the principal product streams, but they  are  essential in modern

 refinery practice and will  be found in every  modern refinery.

         Many refinery products,  for which a special but limited market

 exists,  are manufactured by only a few refineries.  In this category

 are:

               Asphalt                     Petroleum Coke
                Benzene                     Petroleum Solvents
                Cresols                     Phthalic Anhydride
                Detergents                   Tar
                Greases                     Toluene
                Lubricating Oil              White Gasoline
                Naphthenic  Acid             Xylene
               Aliphatic Solvents

  The F£O should expect to  encounter at least a few of them.
                                   12

-------
                                                                            FUEL  GAS
                                                                                  LPG
FELED
                                                                         ictun.oSfc.Mt.
                                                                                    01
                                                                                    OIL.
                        Figure 1. Flow diagram of a small oil refinery.

-------
FiLLO
                        STA&ILIZ
           P'•>"[• I Ll.A"p(OsJ
                                                                      T
 PL.UIC?
CATALYTIC
                                                                              1
                                                                                                  PU£L GAS
                                                                                                          t*
                                                                                                   LPG
                                                                                         T	r




1
1


















•C-ATA t_YT' C-
\~L £- ^-& {T- Nrt Jr. [i.










J







l




- |
T











| 	 ; 	 H
SLPAKATc?f



N
:
1
i 	
^









/
fc







aA;>OL
-------
       Refineries may be divided into on-site facilities and off-site




facilities.  On-site facilities consist of the petroleum processing units.




Off-site units are made up of the support facilities which include waste-




water treatment, power generation,  steam plant,  water treatment,  and




feed and product storage.  Both on-site and off-site  processing units




are discussed in detail in this chapter.  Flow diagrams illustrate the




processing units.  On the diagrams, the point sources of pollution dis-




cussed in the text are indicated by numbered diamonds  -- <£>,  <£>, etc.




The identification codes used in the figures  are explained in Table 8




within Chapter III, Process Instrumentation.







B.     CRUDE DISTILLATION AND DESALTING




1.     Crude Distillation Unit




       The crude distillation unit (Figure 3) is the first refinery unit to




process the crude oil.  The unit separates the incoming crude oil into




light naphtha, heavy naphtha, middle distillates,  and bottoms  residue.




The bottoms  residue  is usually further processed in a vacuum unit to




produce heavy gas oils and a vacuum residuum.




       The crude oil is pumped from tankage, preheated by exchange




with the products  to about 250-300° F,  and then desalted.  Booster




pumps,  downstream of the desalter, pump the crude oil through addi-




tional heat exchange and through a crude furnace.  The temperature of




the oil coming out of the furnace is usually  650 -  700° F.   From the




furnace, the  crude oil passes to the crude distillation column.   Light







                                  15

-------
                                                                                                   TO 6TAe>ii_iZ.e-ri.
N&ATfc-fU
                                         Figure 3.  Crude distillation unit.

-------
naphtha and reflux are condensed in the overhead condenser.  Water




remaining in the crude and entering the tower from the stripping steam




is also condensed overhead.  The foregoing products plus any noncon-




densed gases pass to the overhead accumulator where the phases  are




separated.   Gas may be compressed to the fuel gas  system or for light




hydrocarbon recovery.  In some instances,  it may be vented to the




flare system.  The light naphtha is pumped to the stabilizer.   The




reflux is pumped back to the crude  tower for control of the overhead




temperature.  The water is pumped off plot for treating.




       The  crude tower usually produces three or more sidestreams




which are stripped of their light ends by the use of steam in a side-




stream stripper tower.  Each sidestream (usually heavy  naphtha, kero-




sene, and gas oil) is heat exchanged with crude oil,  cooled in a water or




air-cooled exchanger, and pumped  to storage.




       The  hot residual is steam stripped in the base of the crude




tower and then,  in most refineries, it is pumped directly to a vacuum




unit heater.  Alternatively, the hot residual oil may be cooled by ex-




change with the incoming crude oil and with cooling  water before  being




pumped to storage.




       The  point sources of pollution in the crude distillation  unit are




the crude heater (point 1 on the figure),  the overhead accumulator vent




(point 2), water from the overhead accumulator,  and the  stream




sample  connections.
                                 17

-------
                         I—&
                      (TCV-*-
                                   , '•
                                                     ACCUMULATOR
                                  
-------
2.      Naphtha Stabilizer




        Light naphtha from the crude unit is preheated by exchange with




the stabilized naphtha and sent to the stabilizer (Figure 4).  This is




usually a 20 to 30-tray tower in which only mild fractionation (essen-




tially stripping) takes place.  The light gases are removed overhead in




the tower in order to reduce naphtha vapor pressure.  The naphtha may




then be used as a JP-4 jet fuel or gasoline component.  Reflux is con-




densed overhead and the gas is usually sent directly to fuel gas through




a back pressure controller.  Alternatively some liquid may be produced




overhead in a high-pressure light ends recovery unit.  The stabilizer




bottoms are reboiled by means of a steam heated reboiler.  The stabi-




lized light naphtha is sent to storage after suitable cooling in  an ex-




changer and water cooler.




3.      Crude Desalter




        Desalters are not always required, but when used are the first




unit operation applied to the crude.   The crude oil passes through the




desaltcr to remove salt, silt, sand, water,  and other  crude oil con-




taminants (Figure 5).  Water and sometimes demulsifying chemical




are added to the crude oil stream usually before preheating.  The




mixture is passed through an electrostatic field inside the drum after




preheating by exchange to 250- 300° F.  The desalter can usually be




blocked in, bypassed, and drained during normal operation.  A point




source  of pollution is the desalter water  effluent (point 1 in the figure)




which will contain a mixture of oil,  water and chemicals.





                                  19

-------
Pt- fcM
 CWt.MlC.AL

VALAJfc.

,
r "*"

I
E-f-FLUtUll
                                                                                                           ZOKlfc.
2 50-500*
    IOOP6IQ
                                            Figure 5.  Crude desalter.

-------
       The sour  water effluent from the desalter often must be pro-




cessed in a sour  water stripper or oxidizer for purification.  Some-




times this water  is degassed and then recycled back to the crude oil.




The gas must be  treated for H2S removal and is a possible point source




of pollution.   The desalter is usually equipped with these sampling




connections:   oil-water emulsion (feed), desalted oil, desalter internal




sampler,  and effluent water sampler.




       Sometimes two-stage desalting is employed to further remove




salts, etc. , from the crude oil.  This is merely two desalter drums in




series and the point sources of pollution are the same for both vessels.




4.     Vacuum Unit




       In the  vacuum unit,  hot residual bottoms from the crude unit




enter the vacuum tower by way of a vacuum heater  which heats the oil




to 700 - 750° F (Figure 6).  The process here  again is distillation, but




this time at a reduced pressure (vacuum).   The pressure will usually




be 25 -  100 mm Hg absolute (equivalent to  735  - 660 mm Hg vacuum).




The combination  of higher temperature and lower pressure allows addi-




tional distillation to take  place.




       Any vacuum gas oils are taken off from the  side  of the vacuum




tower, exchanged with feed, cooled in a water-cooled  heat  exchanger




and pumped to storage.  A  small amount of gas oil  plus  any noncondens




ables are taken overhead to the jet ejector system.  Normally three to




five jet  ejectors  are  employed with intercooling, and aftercooling is pro-




vided.  The overhead streams are sent to an accumulator where the





                                  21

-------
                                                                                            STt-AM
                                                                            LT  VACUUM QA5 Pit.
    VACUUM
    HEATER.
RESIDUALS
                                          Figure 6.  Vacuum unit.

-------
phases are separated.  Gas is vented to a heater for burning or to a




gas recovery unit for purification.   The hydrocarbon liquid is usually




sent to a slops tank.  The water phase is sent to a sour water stripper




for purification.  The hot vacuum residual is sent either to storage  via




crude exchange and water cooling or directly to a coking unit.




5.     Pollution  Sources




       The major point sources of air pollution for the crude distilla-




tion unit are shown in Figure 3.  The crude heater is a fired heater and




the stack gas  (point  1) contains pollutants (see ChapterII).  The over-




head accumulator vent (point 2) may contain H2S and hydrocarbons.




Depending  on the amount and composition of the vent gas, the gas may




be flared or sent to the fuel  gas system.




       The naphtha stabilizer is a closed system and should have no




major point sources of air pollution.




       The air pollution point source  for the desalter is shown in




Figure 5.  The water effluent (point 1) may be sour and,  if so, it




should be sent to a sour water stripper.




       Air pollution point sources for the vacuum unit are shown in




Figure 6.  The vacuum heater is a fired  heater and the stack gases




(point 1) will contain pollutants  (see Chapter II).  The overhead accumu-




lator vent (point  2) may contain H2S and hydrocarbons  and should be




vented to a heater for burning or should be sent to a gas recovery unit.
                                  23

-------
C.     THERMAL CRACKING


1.      Process Objective


       Thermal cracking of petroleum is one of the oldest refinery


operations and continues to play an important role in many refineries


today.  Thermal cracking  is the process whereby large hydrocarbon


molecules are converted into smaller molecules through the process


of thermal decomposition.  The  objectives  of the process vary widely


depending oh the feed stock and the severity of  cracking.  Cracking


feed stocks vary from very light materials such as butane to very


heavy vacuum  residual tar.  Cracking of light hydrocarbon gases and


distillates to produce ethylene,  propylene and butylene will not be


considered here.  Olei'in plants are commonly  considered petrochemi-


cal processes  even though olefin generation is  important in the refinery


scheme.  Severe cracking of vacuum tars to produce petroleum coke

                                               •
and cracked distillates will be covered in the "Coking" section.


       Present day cracking operations can be divided into once-


through and recycle plants.  In recycle  plants,  the partially thermally


cracked feed is distilled to separate the uncracked portion.  Part or


all of this uncracked material is then recycled  to the cracking section.


Visbreaking is a once-through cracking process where a heavy residual


fuel oil is mildly cracked to reduce fuel oil viscosity.  Recycle thermal


cracking plants often involve a variety of cracking and distillation steps


to  produce a range of petroleum products.   The most common recycle


cracking plants today feed gas oil and produce  a high yield of  cracked



                                  24

-------
gasoline.  Thermal reformers have been used to convert straight run




naphthas to high octane gasoline.  Today,  however, catalytic reforming




is used for this purpose.  See Section J, Reforming.




2.     Cracking Furnaces




       The cracking operation takes place in a tubestill furnace similar




to other furnaces in the refinery.  Cracking furnaces are designed to




control residence time and temperature.  Unlike other  refinery heaters,




cracking furnaces are  designed to heat the process stream to tempera-




tures in the 800 to 1100°F range.  The furnace consists of radiant and




convection sections.   Burners located near the floor provide radiant




heat to the tubes on furnace walls.  Heat is recovered from the combus-




tion gases in the convection section at the top of the furnace.  The con-




vection section may be used to preheat air, generate  steam, or heat




other process streams.  Coking of tube surfaces is an important design




consideration.  The hot tube surface causes coke to deposit on the




tubes especially in liquid phase  cracking operations.  As coke accumu-




lates, heat transfer is impaired and the tube wall temperature rises.




Regular cleaning of tube surfaces is required to maintain operating




efficiency.




3.     Process Description




       a.     Visbreaking - The process flow  diagram for a typical




       visbreaker is shown in Figure 7.  Vacuum residual tar is  pre-




       heated by heat exchange with visbroken  fuel oil  and fed to the




       visbreaker furnace.   Mild cracking in furnace tubes produces a





                                 25

-------
 VACUUM
RESIDUALS
                                            Figure 7.  Visbreaker.

-------
mixture of residual oil, naphtha and gas.  The reaction products




are quenched with a recycle stream and fractionated in a distil-




lation tower.  In most visbreakers,  no cracked material is re-




cycled to the cracking furnace.  The visbroken fuel oil is




blended with other components to meet viscosity, sulfur and




pour point specifications.  Visbreaker naphtha is taken over-




head and stripped of light ends in the stabilizer.  The naphtha




may be desulfurized and reformed before blending into gasoline.




Light ends containing hydrogen sulfide are taken from the over-




head accumulators on the fractionator and stabilizer.  These




gases may be processed further in a gas recovery plant or fed




directly to the refinery fuel gas system.  A side cut is taken off




the fractionator to provide internal cooling and heat for the




stabilizer reboiler.




b.     Thermal Cracking - The process flow diagram for a




typical thermal cracking process with a single recycle stream




is shown in Figure 8.  The feed stock in most units is a reduced




crude.  The feed is preheated by exchanging with other process




streams and charged to the quench tower.   The feed serves to




quench the furnace discharge to about 800  to 850 °F.  The




quench tower  separates residual fuel oil from distillate petro-




leum.  In this scheme, none of the residual material (black oil)




is' cracked thus  reducing coke buildup in the furnace.  The




quench tower  contains several bubble  trays to ensure an





                          27

-------
00
                                                   Figure 8.  Thermal cracking unit.

-------
       efficient separation of residual oil.   The overhead vapors, con-




       taining straight run and cracked distillate are separated in the




       fractionator.  The  heavy gas oil from the bottom of the frac-




       tionator is fed to the  cracking  furnace which is operated at




       elevated pressure.   The pressure at the furnace outlet is




       dropped sharply to  the quench  tower pressure.  One or more




       side cuts  are taken off the fractionator.  The overhead vapors




       containing naphtha  are separated in a stabilizer similar to the




       one used in a visbreaker.




              Most thermal cracking plants are combination  plants




       containing two or more cracking furnaces.  Side  cuts from the




       main fractionator are recycled to separate furnaces to provide




       selective  cracking  of residual  fuel,  gas oil, and naphtha. In




       some plants, the residual fuel oil from the quench tower is  fed




       to a low-pressure  separator followed by vacuum  distillation.




       Regardless of complexity, the major operations of cracking,




       quenching, and fractionation are present.




4.     Pollution Soxirces




       The major point sources of air pollution are  shown in  Figures 7




and 8.  The cracking  furnaces  (point 1) are fired with fuel oil, natural




gas, or refinery fuel gas.  Stack gas  emissions such as  NOX, SO2, and




particulates will be present.  Cracking furnaces may also emit pollu-




tion during  the maintenance  shutdown period (point 2).  Furnace tubes




are cleaned with steam-air mixtures.  Coke deposits contain sulfur and





                                  29

-------
nitrogen.  Removal of coke by burning will result in SO2, NOX,  CO,





and particulate emissions.  Steam condensate will require stripping to





remove  sour constituents.  Flue gases from cleaning operations may





be routed to a furnace or otherwise incinerated to complete the com-





bustion process.  Mechanical cleaning of furnace tubes will greatly




reduce the air pollution problems, but the refiner is then faced with a





significant solids waste disposal problem.





        Thermal cracking also serves as  a desulfurization process,





with the degree of desulfurization varying from 3% for mild visbreaking





to 80% for severe thermal cracking.  The sulfur is removed in the form




of H2S in the cracked gases  (point 3),  and these gases  should be sent to





an acid gas treating plant before being used for refinery fuel.







D.      COKING





        Coking is  a thermal cracking process in which crude oil residue





and other decanted oils  and tar-pitch  products  are cracked at high





temperature (900 - 1, 080° F) and low pressure  (atmospheric) into lighter





products and petroleum coke.  The objective is to produce gas  oil and




lighter petroleum stocks from the  crude residue. These materials are





further processed and blended with other stocks  to produce premium





products such as gasoline, jet fuels,  and diesel fuels.





       The crude oil residue feed to the coking unit contains most of





the impurities of the crude oil.   It contains most of the heavy metals





(nickel,  vanadium), essentially all the asphaltene, resin,  and ash,  40%





to 60% of the sulfur,  and 80% to 90% of the nitrogen.





                                  30

-------
       .A rough estimate of the distribution of sulfur in coker products

follows in Table 2.


          Table 2.  SULFUR CONTENT IN COKER PRODUCTS
              _   ,  ,                    Percent of Feed Sulfur
              Product                           „
                                             on Products
       Fuel Gas
       Coker Gasoline
       Heavy Oils
       Coke
 12
  3
 25
 60

100
In the coking process, the residue is heated to a cracking temperature

in which the longer hydrocarbon chains in the residue are severed into

smaller more volatile components.  These  components evaporate at

this high temperature and are collected and separated into the desired

products by distillation.   The asphaltene, resin, ash, metals, and

residual carbon precipitate out of the liquid to form the highly cross-

linked polymerized structure of the product coke.  This process con-

tinues until all the volatile components are  removed by vaporization

and all the nonvolatile components have formed coke.

       There are two principal coking processes:  the fluid coking pro

cess and the  delayed  coking process.  The  most widely used is the

delayed coking process and very  few fluid coking units are now in

service.
                                 31

-------
       In the fluid coking process,  the crude residue is fed to the





reactor where it is mixed with recycled hot coke particles.  The





hydrocarbon portion of the liquid feed cracks and evaporates  while





the nonvolatile material is deposited on the suspended (fluidized) coke





particles.   The coke particles thus grow in size, sink to the bottom of





the reactor and flow to the burner.  In the burner,  the particles are





fluidized with air, partially burned and are recycled back into the




reactor.  A portion of the coke produced in the reactor is withdrawn




as product.





       A point source of pollutant emission is the burner.  Emission




control equipment could be  similar to that used with fluid catalytic




cracking units.   Meeting new air pollution regulations may require the





use of electrostatic precipitators and CO boilers.





       In the  delayed coking process  (Figure 9), the charge stock is




fed to the bottom section of  the fractionator where  material lighter




than the  desired end point of the heavy gas oil is flashed off.   The




remaining material combines  with  recycle and is pumped from the





bottom of the  fractionator to the coking heater where it  is rapidly





heated to above 900 ° F.  The liquid-vapor mixture leaving the  coking




heater passes to a coke drum.





       A unit usually has two  drums with one being filled while the





other is  being decoked.   Large units may have four or  even six drums.





The coke drums are most often sized so that each one operates on a





48-hour  cycle,  thus permitting decoking of a drum to be scheduled at





the same time each day on a 24-hour cycle.






                                  32

-------
                                                           rue.u
 rr~~^~i
^ '  } VT£AM ?  T
^JL  OuT   J-.
             Figure 9. Coking unit.

-------
        Under the time-temperature conditions in the drum,  coke is





formed and accximulates in the vessel and the more volatile  compo-





nents former! leave in I he overhead vitpors.   The coke drum overhead





vapors  enter the lower  section of the fractionating  tower for separa-





tion into gas, gasoline,  gas oil.,  and recycle stock.





        After the first coke drum  is filled with coke,  the operation is





shifted to the second drum and the first drum is ready for coke





removal.





        The. initial step  in coke removal is the cooling of the hot drum





with steam.   Live steam is blown into the drum where it absorbs heat,





evaporates .some hydrocarbon material and  ^ntrains  some coke par-





ticles.   After leaving the drum,  the vapors  are cooled to condense the





steam and hydrocarbons.  The cooled stream separates into three





parts :





        1.      Water, with coke particles, that should be added to the





coke  removal system.





        2.      Hydrocarbon liquid that should be added to the slops





system.





        3.      Noncon'iens abl e.s dial normally go to a fired heater or a





flare for disposal.  This stream is primarily fuel gas and usually con-





tains  small amounts of  sulfur compounds.





        The .second  step is cutting the coke.   A high-pressure water  jet,





2,000 psi or more is  used to cut the coke  free  from the drxim.  The coke





particles are washed out with the water and are separated from the






                                   34

-------
water on vibrating screens.  Fines remaining in the water are removed




in a thickener, and the water is recycled for cutting and transporting




the coke.




       Pollution Sources




       Point sources of pollutant emission from this process include:




       1.     The steam  from the steam-out operation, if not




properly condensed and  separated (point  1 in the figure).




       2.     Accumulator fuel gas is normally rich in H2S.  This




stream has to be treated before entering the fuel gas system of the




refinery (point 2).




       3.     Coker gasoline is normally treated for the removal of




H2S (point 3).  (See Section M,  Sweetening. )




       4.     Water drawn from the overhead accumulator contains




H2S and should be routed to a sour water stripper (point 4).




       5.     The fired heater is a source  of pollution; see  Chapter II




(point 5).




       6.     Coking units are in general covered with coke dust.




Unless the units  are cleaned and washed  thoroughly, these fine




particles will blow with  the wind and may create pollution.




       7.     Most delayed coking units use water for  cutting the coke.




The water  is recycled in this operation and  stored in open containers.




Since this water  contains some  sulfur compounds,  it may be the  source




of objectionable odors.
                                  35

-------
E.     DEASP HALTING





       Deasphalting is used to separate oil and asphalt.   The feed




stock is  reduced crude from the crude distillation process.  Reduced




crude is the heavy fraction of the crude from which as much distillate





has been removed as is practical with the existing crude unit.  Deas-





phalting  produces products comparable to those produced by high-




vacuum  distillation, but deasphalting  is generally capable of more





complete oil-removal.  A  variation of the process is  sometimes used





to remove trace amounts of asphalt from lube-oil stocks.





       Asphalt-oil separation is accomplished by selective extraction





(liquid-liquid  extraction) of the  oil by a light hydrocarbon, usually




propane.  A heated mixture of reduced crude and liquid propane settles




into two  liquid phases, an upper phase containing oil  and most of the




propane  and a lower phase containing the asphalt and some propane.





The phases are separated, and  propane is recovered for recycling by





flashing  and steam stripping.




       Liquid-liquid extraction is a unit operation commonly used in





refineries and chemical plants.  In this operation,  a  mixture is sepa-





rated into  two components by means of a selective solvent.  The addi-





tion of the solvent to the feed mixture must  result in  a two-phase





mixture  with an appreciable density difference between the two phases.





The two  phases  will contain different  ratios of the two feed components.





       Although a single step of mixing and settling will produce  some





separation, multiple-step  operations  are frequently used to achieve






                                  36

-------
more complete separation.  Usually counter cur rent extraction is em-




ployed,  with solvent entering near one end of the column and feed at




the other.  The two liquid phases leave the column at the top and bottom.




Mixing and settling within the column can be accomplished in several




ways.  Perforated plates or packing are often used,  as well as mechan-




ical agitators driven by a common  shaft running  through the column.




       A flow diagram for a typical propane deasphalting  process is




shown in Figure 10.  Reduced crude is metered to the process under




flow control and passes through the feed heater where it is brought to




operating temperature by indirect steam heat.  The heated reduced




crude is fed to the center of the extraction column where it is brought




into contact with a rising stream of liquid  propane.  The propane, a




recycle stream, is metered through a flow controller and through the




propane heater into the bottom of the extraction column.   Asphalt,




containing some propane, leaves the bottom of the extractor under




level control.  The remaining propane and the extracted oil  leave  the




top of the extractor.  A steam coil in  the upper section of the column




is used  to heat the rising propane-oil  stream, reducing the solubility




of asphalt in that stream.  In this way, final traces of asphalt are re-




moved from the oil, forming a separate phase that flows downward




through the column.




       The asphalt phase from the column passes through a furnace




and then to a flash drum,  where most of, the propane is removed as a
                                 37

-------
00
               /I    TV bUB-Gt.
               (      1  pnjj M
                       WAJEJL

                   ^\ TO SE-WCA.
                   S. "y
                    r/iopAMt.
                     WtATf-
t)TM
                                              STM

                                              id
               COMPfLE.'ibOR-
                                                  nu
                                               f-LASH
                  OIL.
                                                                   6TM
                                                                                    X
                                                                                     HJJ... J
                                                TO
                                          •6TM.
                                                                                             •6AS OIL
                                                                                             •ASPHALT
Jfc.T
                                     Figure 10.  Propane deasphalting.

-------
vapor.  Since the remaining asphalt still contains a small amount of




propane, this stream is fed to the asphalt stripper.  The remaining




propane is steam stripped from the asphalt, and the asphalt product




leaves the bottom of the stripper under level control.  The stripping




stream and propane  leave the top of the stripper and pass through the




jet condenser to condense the steam.




       The oil-propane phase from the extractor is  fed to a propane




vaporizer, where the bulk of the propane is vaporized by indirect




steam heating.  The  remaining propane is removed from the oil in the




oil stripper by  steam stripping.  Product oil leaves  the stripper under




level control.   The stripping steam and propane join the asphalt




stripper overhead and are sent to the jet condenser.




       Vaporized propane from the flash drum and the propane vapor-




izer are combined and sent  directly to the propane condenser,  where




the propane is condensed to a liquid by cooling with water.  The propane




flows to a surge drum and is pumped  back to the process as  recycle.




Steam and propane vapor entering the jet  condenser  are contacted with




water to condense the steam.  The water  and  condensed steam leave




the bottom of the jet condenser and are sewered.  The propane vapor




leaves the  top of the jet condenser at  a pressure that is lower  than that




in the extraction section,  so a  compressor is used to  send it to the




propane condenser.




       Pollution Sources





       There are two potential sources of air pollution in this process





                                 39

-------
that should be given special attention.  One, point 1 on the flow dia-





gram, is the -water to sewer from the jet condenser.  This  stream will





contain small amounts  of propane and, depending on the character of





the reduced crude feed, may also have an odor.  The other potential




source,  point 2,  is the water to sewer from the propane surge drum.





This  stream is small and may therefore be drained intermittently under





manual control.  The water will contain  a small amount of  dissolved





propane,  but more importantly, relatively large amounts of propane





can be lost if the operator is careless about closing the valve after





manually draining the water.







F.      CATALYTIC  CRACKING




        There are two catalytic cracking processes in use today:  the





fluid  catalytic cracking process which uses a powdered catalyst, and the





Houdriflow or TCC process, no longer in general use,  which uses a bead





catalyst.  Catalytic cracking is a high-temperature, low-pressure




process  which is used to convert gas oil feed stock  into fuel gas,  liquified





petroleum gases  (LPG), high octane gasoline, and  distillate fuel.





        Feed stocks to the catalytic cracking unit may be gas oils from





the crude unit, thermally cracked gas oils, and/or deasphalted oils.





The products from the  reactor  are given in Table 3.  Catalytic cracking





plants are normally operated to produce a maximum amount of gasoline,





but the units are  very flexible and operating conditions can be varied to





produce  other products.







                                 40

-------
                   Table 3.   REACTOR PRODUCTS
              Product
  Wt.  %
       Water
       Gas,  C2 and Lighter
       Coke
       Liquid Hydrocarbons
  1 to 2
  3 to 7
  3 to 8
Remainder
1.     The Fluid Catalytic Cracking Process

       Figure 11 shows a schematic diagram of a typical fluid catalytic

cracking unit.  Gas oil feed is mixed with hot catalyst and introduced  .

into the reactor.  Steam is added at the base of the reactor to fluidize

the catalyst bed and purge the spent catalyst.  The volatile hydrocarbon

products are withdrawn from the top of the reactor and  sent to a frac-

tionator where the product streams are separated.

       The coke and catalyst are withdrawn from the base of  the reactor

and sent to a regenerator.  A controlled amount of air is introduced into

the regenerator with the catalyst to burn  the coke and reheat the cata-

lyst.  The  exhaust gas  flows  through a series of cyclone separators

located inside the regenerator to remove the catalyst dust.  An electro-

static precipitator or a third stage cyclone separator,  located outside

the regenerator,  can be used to remove catalyst fines from the effluent

gas.

       The catalyst is  continuously circulated from  the  reactor to  the

regenerator.  The hot regenerated catalyst is  returned to the reactor

through a separate  line into which the feed to the reactor is introduced.

                                 41

-------
Jk
          pft.OPUC.TS
                                    FLUE GAS
    ^h
  /N A,
   /N

  /\ A
        FUEL GAS
                                         METER
                   TCP BOILER t_-6FW  ppEClPlTATOR
                    '
          STEAM    STEAM
             LlUfe.
Figure 11.  Fluid catalytic cracking unit.
             42

-------
       Fresh catalyst is added to the system to keep up the activity of

the reaction.  Some catalyst is continuously lost to the atmosphere and

constitutes a form of particulate pollution which should be controlled.

       The flue gas from the regenerator contains five to ten percent

carbon monoxide and can be burned to yield a considerable amount

of heat energy.  This gas can be burned in a boiler, with an auxiliary

fuel, to generate steam.  This procedure removes the toxic carbon

monoxide gas from the flue gas and makes it suitable for discharge

to the atmosphere.   The boiler is usually monitored with suitable

instrumentation to assure  that complete  combustion of the  carbon mon-

oxide occurs.

       Pollution Sources

       The catalytic cracking process  converts about half of the sulfur

in the feed stock to hydrogen sulfide.  Part of this material appears  in

the condensate from the fractionator and from the gas plant.  The

wastewater is saturated with the gas and must be treated in a sour

water treating process as  discussed in Section Q,  Sour Water Stripping.

       Some of the sulfur  stays with the coke and  is ultimately burned

to SO? in the regenerator.   The effluent gas from the regenerator

(point 1 on the figure) may contain the following contaminants:

              Aldehydes                    Hydrocarbons
              Ammonia                     Oxides of nitrogen
              Carbon dioxide               Sulfur dioxide
              Carbon monoxide             Sulfur trioxide
              Catalyst fines

The amount of each contaminant will vary with the type of  plant and the

                                  43

-------
effectiveness of pollution controls in the plant.  Aldehydes,  ammonia,





carbon monoxide and hydrocarbons are controlled by combustion in a




CO boiler.   Catalyst fines are controlled by an electrostatic precipi-





tator.  The remaining pollutants are not controlled at present.





2.      Catalytic Cracking with  Bead Type Catalysts




        Figure 12 is a schematic diagram of a typical moving bed cata-





lytic  cracking process.   This type of plant can operate with a  wide




variety of feed stocks to maximize production of either gasoline or





burning fuels.  The process  employs a moving bed of hot catalystbeads





•which flow downward from a surge hopper into a reactor where the




beads contact fresh gas oil feed.  The gas oil  is cracked yielding a





mixture of hydrocarbons known  as synthetic crude.   The descending





bed of catalyst is purged with steam at the base of the reactor.  The





mixture of steam and cracked gases flows from the reactor to a





system of fractionating  columns which separate it into fuel gas,  LPG,





gasoline, gas  oil,  and water. The catalyst drops from the reactor





into the regenerator where air is used to burn off the coke which has





deposited on the beads.





        Pollution Sources





        The flue gas from the regenerator (point 1 in the figure)  is





similar to that from a fluid catalytic cracking unit.   A precipitator or





cyclone separator  can be used to remove catalys-t fines, although  the





problem is not as severe as with fluid units.   The flue gas can be





burned in a waste heat boiler to eliminate the  carbon monoxide.






                                  44

-------
                        FINES
                      SEPARATION
            PR.&.5M
          CATALV5T
Figure 12.  Moving bed catalytic cracking unit.
                              45

-------
       Another possible source of particulate pollution is the catalyst

transfer system.   The catalyst is lifted from the  regenerator outlet to

the catalyst feed hopper with a pneumatic lift.  A disengaging drum at

the top of the lift recovers the catalyst, but some catalyst fines may be

discharged to the atmosphere from this source (point 2) if it is not

controlled.

3.      Control Strategies

       a.      CO  Boiler:

               Excess CO in Flue Gas    -  Increase air  to CO boiler.
               Excess SO2 in Flue Gas       Reduce sulfur in feed stock.

       b.      Electrostatic  Precipitator

               Excess Fines in Flue Gas  -  Inspect and clean fines
               from  Fluid Unit              removal equipment.
                                            Increase fines withdrawal
                                            from the plant at the pre-
                                            cipitator.


G.     ALKYLATION

       Alkylation is  a process in which an olefin hydrocarbon reacts

with an aromatic or  a paraffinic  hydrocarbon.  An acid catalyst is used

to  reduce the temperature and pressure required for the  reaction to

proceed.   Alkylation units are used to produce  high octane gasoline

components and synthetic chemicals such as  cumene  and  ethyl benzene.

       The two principal materials currently being used  as alkylation

catalysts  are sulfuric acid and hydrofluoric (HF) acid.  There are

about 140 alkylation units in operation in the  United States, with the

number of units of each type being about equal.  Both processes  operate


                                  46

-------
at moderate temperatures and pressures as shown in Table 4.

  Table 4.   ALKYLATION PROCESSES OPERATING TEMPERATURES
                          AND  PRESSURES
Process Catalyst
Sulfuric Acid
Hydrofluoric Acid
Temperature
°F
30- 50
75- 105
Pressure
psig
5
125
Both acids are highly corrosive, and the containment systems are
prone to develop leaks.
1.      The Sulfuric Acid Process
        Figure 13 is a  schematic diagram of a typical sulfuric acid
alkylation process.  The feed stream could be a mixture of an olefin
such as butene and a paraffin hydrocarbon such as isobutane.  The two
streams are mixed and introduced into a horizontal staged reactor   A
circulating stream of sulfuric acid and isobutane flows through the
reactor.  The reaction of the hydrocarbons is exothermic, and vapor
is withdrawn and condensed to cool the reactor.  The hydrocarbon
liquid from the reactor is washed with caustic and water and then
fractionated to separate the alky late product from  the isobutane which
is returned to the  reactor.  The process shown uses autorefrigeration.
It is also possible to cool the reaction by indirect cooling.
        The spent acid  (point 1 in the  figure), which may be shipped off-
site for regeneration,  is saturated with volatile  hydrocarbons which
                                 47

-------
00
r
                           I   i
                           I   I    i   i
                                                ~l
                                                                                     (     )       )
                                              Figure 13.  Sulfuric acid alkylation process.

-------
should be contained.  The spent caustic (point 2) and water (point 3)





streams may also entrain some hydrocarbon which will vaporize if the





stream is discharged to the atmosphere.  These sources  should be





confined to prevent atmospheric pollution.





2.       The  Hydrofluoric Acid Process




        Figure  14 is a schematic diagram of a typical HF  acid alkylation




plant.   The  hydrocarbon feed to the plant is mixed with hydrofluoric





acid in a reactor.   The mixture is settled and the hydrocarbon product





fractionated to produce recycle isobutane and product alkylate.   A





small acid stripping column regenerates the catalyst and  gives a by-





product tar  which may be burned  (point 1 on the figure).  A stripping





column is provided to separate an acid rich fraction, which is recycled,




from the LPG product which is washed with caustic and water.  The




caustic waste (point 2) and the sour water (point 3)  should not be vented




to  the atmosphere.





        Hydrofluoric acid is a volatile liquid which is toxic and corro-





sive.  HF lines may be jacketed to contain any possible leakage, and a





water  spray or alkali dump system is usually provided in the event that




a mechanical failure should release any of the acid.





3.       Pollution Sources





        The  principal source of pollution from either type of alkylation




plant during normal operation would result from atmospheric disposal





of  spent caustic and water streams (points 2 and 3 on the  figures) and





these streams  should be confined with vapors vented to flare.





                                  49

-------
f^&e.^
                                            X
                         u*
          1
  HP
stn-ippfca
                                 t
                                 Figure 14.  HF alkylation process.
                                                                                        U/A5H
                                                                                 f

-------
Hydrocarbon and, more particularly, HF leaks are a potential source of





serious air pollution.  Tar from HF alkylation (point 1, Figure 14) is





often disposed of by incineration.  This may be a source of pollution if





the burning is not properly controlled.







H.     ISOMKRI7.ATION




       Isomerization is  used to upgrade normal paraffins  (straight-





chain hydrocarbons) to isoparaffins (branched chain).  The process  is





usually applied to butane or to mixtures of pentane and hexane.   Where





butane is the feed stock, the isobutane  product is normally used as





feed to an alkylation-unit.  Pentane-hexane feeds,  from crude distilla-





tion or catalytic  reforming,  are processed to improve their octane





ratings,  and the product is blended to gasoline.





        Two methods have  been used to bring about the isomerization





reaction in petroleum refining.  The old method used  aluminum





chloride in either vapor or liquid-phase  reactions,  but this practice is





now obsolete.  The new  method employs noble metal catalysts on a





solid catalyst support,  and the feed is  mixed with hydrogen to  suppress





unwanted reactions.





        Figure  15 is a schematic diagram for a butane isomerization





process.  Since the butane feed usually contains a mixture of normal




and  isobutane,  the  mixture is  first separated into its  normal and iso





components by distillation in the deisobutanizer.  The overhead product,





isobutane,  is sent to storage or directly to an alkylation unit.   The






                                  51

-------
r\j
                     7E.ISOIbuTAkll2.fcJL.
                                                     PR.OPUCT
                                                            Jrt ACTOR,
                                             Figure 15.  Butane isomerization.

-------
bottom product, normal butane, is mixed with hydrogen and heated by





indirect heat exchange with reactor effluent.




       The feed stream is further heated in the fired heater and then





passed over the catalyst in the reactor.  Reactor effluent is cooled,




first by exchange with the  feed and then in a water-cooled effluent





condenser.  The condenser is followed by a separator in which the





liquid and gas phases are separated.





       The gas phase from the separator,  primarily hydrogen,  is





recycled to the reactor by means  of the compressor.  The liquid phase





contains dissolved hydrogen and other gases, which are  removed in the





stabilizer.  The stabilizer is a distillation column in which all liquid




reflux is returned to the column.   Gas  from the stabilizer accumulator





is sent to the fuel gas  system.  Stabilizer bottoms is a mixture of iso





and normal butane and is,  therefore, fed to the deisobutanizer for sepa-





ration into isobutane product and normal butane.   Normal butane is





recycled until it is  converted to isobutane.





       The following procedure is used for regeneration in place.   The





unit is shut down,  and the  reactor  is depressurized to the  refinery flare





system.  Inert gas,  supplied by an inert gas generator,  is used to free





the reactor of combustible gas.  The catalyst is brought to temperature




by recycling inert gas through the  heater and reactor, and carbon is





burned off the catalyst by adding a controlled amount of  air to the cir-





culating gas stream.   Since  the gas stream contains products of incom-





plete  combustion,  it is good practice to incinerate  the off gas that is





                                  53

-------
bled from the system to balance the air added.  This off gas can be





incinerated in the fired heater.





       Pollution Sources




       Since the feed to this process must be nearly sulfur free in





order to protect the catalyst,  there is no problem with hydrogen sulfide





contaminated gas streams.  There is, however, a possible potential





source of air pollution in the gas-to-fuel stream (point  1 in the figure).




In some  versions of the isomerization process, particularly with pen-




tane-hexane feed, an organic  chloride is added to the feed to increase





catalyst  activity. This chloride eventually shows up in  the vapor





streams as hydrogen chloride.  Most of the hydrogen chloride is





recycled to the  process,  but some of it is eliminated with the gas-to-





fuel stream.  In such cases,  this  stream should be treated to  remove




the hydrogen chloride before the gas is burned as fuel.  Sometimes a





caustic scrubber is used for this purpose.




       The combustion gases from the reactor feed heater (point 2)





are a source of air pollution (see  Chapter II).





       Another potential source of air pollution is the off gases from





catalyst  regeneration,  not  shown in Figure 15.  The catalyst used in





isomerization is very stable and can be  expected to last for two years





or more before regeneration is  required.  In fact,  some refineries do





not regenerate the catalyst, preferring  to replace  it and return the





spent catalyst to the  manufacturer.







                                   54

-------
I.      HYDROTREATING




       Hydrotreating or hydrodesulfurization processes are used to





remove sulfur from liquid petroleum fractions.  Some nitrogen removal





and saturation of olefin bonds may also occur.  Sulfur  removal is





accomplished by reacting the sulfur containing compounds with hydrogen





in the presence  of a catalyst to form hydrogen sulfide.  The hydrogen





sulfide is separated by simple vapor-liquid separation.




       The processes have been applied to a full range of feeds, from





gasoline  to fuel  oil.  Reaction temperature is normally kept within  the





range of  600  to 750°F,  while pressures are in the range of 300 to 500





psig for  easily treated fractions and from 700 to 1, 000 psig for fractions





requiring more  severe treatment.




       Figure 16 is a diagram of a typical hydrotreating process.   The





hydrocarbon  feed is heated  in an exchanger and mixed with a hydrogen -




rich gas  stream.  The mixed feed is heated in a fired heater and passed





through a catalyst bed, where the hydrogen reacts with sulfur and





nitrogen  compounds.   Reactor effluent is cooled and a small  quantity of





water is  added to absorb ammonia compounds.  The liquids are sepa-





rated from the vapors, and the water  phase is withdrawn.  The hydro-





carbon liquids are fractionated into  separate product streams.




       Pollutioii Sources





       Possible point sources of pollutant emission are:





       The w-ater phase (points  1, 2,  and  3 in the figure) contains
                                 55

-------
                                                                                                        VTAMi.iz.e-tu
            M V PH. & T fZ-fcATl NJ&
01
                                           Figure 16.   Hydrotreating.

-------
ammonia and hydrogen sulfide and should be sent to a sour water treat-





ment plant.





       The gas phase (point 4) contains hydrogen, methane,  and hydro-





gen sulfide and should be treated to remove H2S before being used for





fuel  gas.




       The catalyst loses its activity due to the accumulation of car-




bonaceous deposits and to the deposition of trace  metals.  As the unit





continues to operate the pressure drop across the bed builds up and





eventually the process must be shut down.  The catalyst may be re-





generated by burning off the carbonaceous material (point 5), or it may





be replaced by new catalyst.  With a mild treatment,  regeneration may





be required at yearly intervals, but where treatment  conditions are





severe and with the older type catalysts, regeneration will be required





at more  frequent intervals.  (See  Section B B,  Catalyst Regeneration. )







J.     REFORMING




       Catalytic  reforming is  used by refineries  to economically up-





grade low octane naphthas to produce premium quality motor fuels,





high yields of aromatic hydrocarbons, high quality aviation gasoline





components,  and liquified petroleum gases.  The reactions involved in





reforming normally result in the production of hydrogen which is used





either in other refinery processes or in the plant fuel gas system.





       A typical  reforming process design is  shown in  Figure 17.





Prior to  reforming, the naphtha is hydrotreated for the removal of
                                  57

-------
oo
                                               Figure 17.  Reforming.

-------
essentially all the sulfur in the feed.   (See Section I, Hydrotreating


Processes. )  Sulfur free naphtha charge and hydrogen rich recycle gas


are heated in a furnace to reactor inlet temperature and then passed


through catalyst beds in a series of reactors.  As  the major reactions


are endothermic,  the gas temperature drops across each reactor and


furnaces are required to reheat the gas between the reactors.  The


effluent gas is condensed and separated into a  liquid stream and hydro-


gen rich gas.  The liquid is processed through the stabilizer and with-
                                                •

drawn as finished reformate.  A portion of the gas is recycled and the


remainder used as either a source of hydrogen for other processes or


fuel.


       A number of reforming processes are  currently in use, but the


basic process is  that shown in the figure.   The major differences be-


tween the processes are in the composition of  the  catalyst used in the


reactors and in the methods  for regenerating the catalyst.  Until


recently, catalyst beds were  fixed and were regenerated in  place.


However, continuously regenerated beds  have  now been introduced.


Catalyst regeneration is required because coke is deposited on the


catalyst  surface during normal operation.  This results in reduced


catalyst  activity.  During regeneration,  the coke is burned off the


catalyst  under carefully controlled conditions.


       Pollution ^Sources


       The gases evolved during regeneration may contain air pollu-


tants and should be incinerated  (point 1).  (See  Section BB, Catalyst


Regeneration. )


                                  59

-------
       The fuel gas stream contains hydrogen sulfide and is a potential




source of air pollution  (point  2).  The fuel gas stream is  sent to an





amine unit where hydrogen sulfide is removed.





       Combustion gases from the heater (point 3) are another source




of air pollutant emissions.







K.     HYDROCRACKING




       Hydrocracking is used to convert heavy feed stocks  into lighter,




more valuable products.  In this cracking process,  the feed stock is





converted into shorter  chain  hydrocarbon molecules  in the  presence of





hydrogen and a catalyst.  The feed stock to  the hydrocracking unit is





normally gas oil or middle distillate, and the usual products are  fuel




gas, gasoline,  and jet fuel.  The process is flexible  in that the pro-





duction of either gasoline or  jet fuel can be  maximized as needed.




       Hydrocracking employs high pressure (1, 500 to 3, 000 psi),





high temperatures (500 to 750T),  and a special catalyst.  The reac-





tion section is usually divided into two stages.   The first stage is





used to remove all the  nitrogen and sulfur (see Hydrotreating), while





the second stage is used for cracking.  The first stage is needed  in





most cases because sulfur  and nitrogen are catalyst poisons for the





cracking catalyst used  in the second stage.   However,  a  single-stage





reaction section is sometimes  used where the feed stock is low in





sulfur and nitrogen.  Single-stage catalysts are more sulfur-resistant




than those used in the second stage of a two-stage unit.







                                  60

-------
       Figures 18 and 19 are flow diagrams of a reaction section and

a distillation section of a typical hydrocracking unit.  The feed is pre-

treated and cracked in the reaction section,  and products are recovered

in the distillation section.

       Gas oil and/or distillate feed containing some sulfur and nitrogen

impurities is pumped from the feed drum and heated by exchange with

the first reactor product.  Hydrogen is added to the feed and additional

heat is supplied by a fired heater.  The feed enters the reactor at about

3, 000 psi and 700 °F.   The reaction is exothermic  (heat producing) and

the temperature is maintained by cooling the reactor catalyst beds by

adding cold hydrogen.   The reaction  products are  cooled, water is in-

jected into the product stream and the reaction products and water

stream enter  the high pressure separator.

       At this point all of the sulfur  in the feed has been converted to

H?S and all the nitrogen in the feed to NH3.  The approximate distribu-

tion of sulfur  (H2S) and nitrogen  among the streams leaving the high-

pressure separator is shown in table 5.

    Table  5.   SULFUR AND NITROGEN DISTRIBUTION IN THE HIGH
                      PRESSURE SEPARATOR
Product
Hydrogen rich gas
Hydrocarbon liquid
Water
Total
Wt. % Feed
Sulfur
50
40
10
100
Nitrogen
Nil
5
95
100
                                  61

-------
I ST  6TA6 fe-
ll &.A£.TOn_
                                TO A
                               HEAT fl££0V£A.Y
                                                               I—&
                     Figure 18.  Hydrocracking  reaction section.

-------
      FR-OM  IVT 4-

               -S
      b 6-f*A 11. A TO u. »>
U)
         M;
                                   Figure 19.  Hydrocracking distillation section.

-------
       The hydrocarbon liquid from the first-stage high-pressure





separator is combined with the liquid from the second-stage high-




pressure separator and is  fed to the stabilizer in the distillation section





to separate products from  unreacted feed.  The hydrogen rich gas from





the first-stage high pressure separator is recycled back to the reactor





with the  addition of sufficient makeup hydrogen to replace that con-





sumed by the reaction.  Hydrogen purity is maintained by sending a




bleed stream to a H2S absorber.





       Fractionator bottom liquid from the distillation section is un-





reacted  feed.  This stream is fed to the second reaction stage.  Pro-





cess flows in the second  reaction stage are the same as in the first





reaction stage except that  no sulfur or nitrogen is present in the feed.




Cracking occurs at 1, 500 psi and 600° F.




       The distillation section is similar to those used  in other crack-




ing processes such as  fluid catalytic cracking  and thermal cracking.




The total flow from both high pressure separators is fed to the low





pressure separator in  the  distillation section.  The pressure is




reduced  and fuel gas is flashed out of the hydrocarbon fluid.




       The low-pressure separator liquid is fed to the stabilizer.  In





the stabilizer, all  the light ends and the H?S are  stripped out and are





taken overhead.  Both  the  gas and the  light ends  (overhead) liquid  have





to be treated for the removal of H2S.   The stabilizer bottoms are




separated  into products and fractionator bottoms  in the  fractionator and





the fractionator bottoms are  recycled  to the second reaction  stage.






                                   64

-------
       The approximate distribution of H^S in the streams leaving the




low-pressure separator is as follows:





 Table 6.    H?S DISTRIBUTION IN THE LOW-PRESSURE SEPARATOR
Phase
Liquid
Vapor
Total
Wt. % Feed Sulfur
85
15
100
Pollution Sources
       Point sources for possible pollutant emission in a hydrocracking




unit are:




       1.     Sour water containing H2S and NH3 leaves the first stage




high pressure separator, the low pressure separator,  and the stabilizer




accumulator.  All these streams have to be treated in  a sour water




stripper before being discharged or reused  (point  1 on Figure 18 and




points 1  and 2 on Figure 19).




       2.     The bleed gas from the hydrogen rich gas in the first




reaction stage may contain  as much as 0. 5 vol.  % to 1. 5 vol. % H2S on




Figure 1 8.




       3.     The catalyst is periodically regenerated in situ by




burning off the accumulated coke (points 3 and 4 in Figure 18).  (See




Section BB, Catalyst Regeneration. )




       4.     Fuel gas produced in the distillation section contains H2S







                                  65

-------
and needs to be treated.  Points 3 and 4 on Figure 19.





       5.      Light ends produced in the distillation section contain




some H2S and need to be treated (point 5 on Figure 19).







L.     HYDROGEN PRODUCTION




       Hydrogen is an  intermediate material in refining operations.  It




is used as a reactant in operations such as hydrogenation,  hydrodesul-




furization,  and hydrocracking.  The principal method for producing





hydrogen is steam reforming of some available hydrocarbon like





natural gas, refinery gas, propane, butane, or naphtha.  Hydrogen is





also produced  in the refinery as a by-product  in the reforming process.





       The sequence of processing steps for hydrogen production by




steam reforming is sulfur removal, reforming, shift conversion, car-




bon dioxide absorption  in monoethanolamine (MEA) solution and meth-





anation.   The plant is  in steam balance, that is, high-pressure steam




for reforming  and  low-pressure steam for MEA regeneration and de-





aeration is produced as a by-product.  The flow diagram is shown  on





Figure 20.  The gas feed to  the plant normally contains traces of sulfur





which are removed by adsorption on activated carbon.  Two carbon





beds  are used, normally  operating in  series flow.  During regeneration,





one bed is valved out of the normal flow and returned after  regeneration




to the downstream position in the flow sequence.





       The sulfur-free gas is  mixed with high-pressure steam and





pre-heated in the convection section of the reformer furnace.  The







                                 66

-------
NA7V1AI-
  OH.
ri
 FJ
                  t>T<^
                 HtAPtfl.
>>  t





I
              X
   Me.i»A>-jATg>r>_
              X
              X
    JHIPT
X
' — (
*i-V ' „
?v;
i ' '
i ; '
' : '
1 , 1

1
1

~xy
I
HI&H Ptt£SvVT?\
iTM . PdOr<-| /\by
-N
^3-^
R.£pO/VM6fl.
; fUfX>4ACfc_
@-^-
\

i.
1 Fufci.'
— — , •(
I
auc^cooM-j
j
— L_ C-TFA
H/AVrtMCAT \ — 	
&o't-tn. y , L
                       Figure 20.  Hydrogen production by steam reforming.

-------
mixed gas  flows downward through catalyst-filled tubes where steam




reacts with methane and other hydrocarbons to produce hydrogen,  car-





bon monoxide,  and carbon dioxide.  The high-temperature effluent gas





from the reformer furnace flows through the tubeside of a steam gener-





ator producing high-pressure steam.  Additional high-pressure steam





is generated in the convection section of the furnace.   This steam is





consumed  in the reforming reaction.  More than three-quarters of the





total hydrogen is produced in the reforming reaction.  The remaining





hydrogen is produced by the shift conversion of carbon monoxide to





carbon dioxide.  The catalytic conversion occurs in two stages, one at





high temperature  and the second at low temperature.   The combination




of converters shifts over 98 percent of the total carbon oxides to car-





bon  dioxide and hydrogen.  Reaction heat is removed between the two




stages of shift conversion by generating low pressure  steam.   The gas





temperature between the catalyst beds is also lowered to  give more





.favorable  conditions for the shift reaction.





        The crude hydrogen gas from the shift converter is further





cooled before mixing with MEA solution in an exchanger.   The heat of




reaction between carbon dioxide and MEA is largely removed in this





precontact stage ahead of the amine absorber.   The remaining carbon





dioxide is  removed from the gas stream by reaction in the absorber.





The heat for MEA  regeneration is  supplied partly  from the process





gas  and partly from low pressure steam.   An MEA reclaimer is pro-





vided to maintain  a clean active solution.   Other means of absorbing





                                  68

-------
carbon dioxide may be used instead of MEA; these include Sulfinol and




activated hot carbonate.




       The last traces of carbon monoxide and carbon dioxide are con-




verted to methane by reaction with hydrogen in the methanator.  This




catalytic reaction requires a preheat temperature of about 600° F.  The




residual carbon oxide content of the product hydrogen is less than




10 ppm.




       Pollution Sources




       There are two potential sources of pollution in the steam re-




forming process.  During carbon tower regeneration (point 1 in the




figure), H2S and organic sulfur compounds are removed using steam.




This steam should be condensed and transferred to the sour water




system for processing.




       The periodic replacement of catalyst beds could result in  pollu-




tion if the removed catalyst is allowed to weather in  an open area (point




Z).  The spent catalyst should be put in containers when removed from




process equipment and disposed of in  an acceptable manner.







M.     SWEETENING




       A distillate is said to be sour if it contains noticeable amounts




of sulfur compounds, particularly the odoriferous mercaptans.  A pro-




cess that removes these compounds or converts  them to less objection-





able forms is called  "sweetening".   Hydrotreating,  which could  be




called a sweetening process is discussed in Section I.







                                 69

-------
       Sweetening can be accomplished by removing the mercaptan,





usually by extraction or by converting it to  a disulfide.  Frequently, the





solutions used for extraction are regenerated by converting themercap-





tans in them to disulfides and then  removing the disulfides.   In treating





light distillates or light naphtha, lighter mercaptans can be satisfac-





torily  removed by extraction with caustic solutions containing solubility





promoters.  The  high molecular weight mercaptans associated with the





heavier  distillates, such as'full-range gasoline or kerosene,  are more





difficult to extract and are normally  converted to disulfides and left in




the distillate.





        Doctor sweetening, copper  sweetening,  and hypochlorite sweet-





ening are old processes and are not in general use at this time.  In





doctor sweetening,  the distillate is treated with alkaline sodium plum-





bite solution to oxidize the mercaptan to disulfide.  The lead is reduced





to lead sulfide and is discarded or  regenerated by air blowing.  In





copper sweetening, cupric chloride is  reduced  to cuprous chloride,





followed by regeneration with air to recover the cupric chloride.  In





hypochlorite sweetening,  sodium or calcium hypochlorite is used as





the oxidizing  agent without regeneration.




        There  is  a variety of sweetening processes in  use  today, for





instance, treatment with sulfuric acid  or absorbing mercaptan with





molecular sieves.  However,  the more widely used processes usually





employ sodium hydroxide with added catalysts or promoters.   Most
                                   70

-------
frequently a caustic solution containing the dissolved catalyst or pro-





moter is employed, but a fixed bed of catalyst can also be used.




        Figure 21 is a flow diagram for a gasoline-sweetening process





that employs a sodium hydroxide solution (caustic) containing a dis-





solved catalyst.  Sour gasoline feed is metered into the extractor, where





it is brought into contact with  recycled  regenerated caustic  solution.





Partially treated gasoline, with part of the mercaptan removed, flows





from the top of the extractor and is mixed with recycled caustic solution





and air before entering the bottom of the sweetener.   The remaining





mercaptan is  oxidized to disulfide in the sweetener and  remains in the





treated gasoline stream.  Caustic solution is separated from the treated





gasoline in the solution settler and is recycled to the sweetener. Caustic




solution from the extractor, containing dissolved mercaptan,  is mixed




with air and sent to the oxidizer.  The mercaptan is  oxidized to disulfide





in the oxidizer and then flows  to the air separator.  Excess air is vented





from the air separator, and the caustic solution and  disulfide flow to the





disulfide separator.  The insoluble disulfide layer separates and is





withdrawn from the system, and the regenerated caustic is  recycled to




the extractor.





        Pollution Sources





        There are two points of possible pollutant emission of special





interest in the process.  One is the  disulfide product stream  (point  1 in





the figure).  If the  disulfide cannot be sold, it will normally be disposed





of by burning  as fuel or by incineration.  Since the stream is small,





                                   71

-------
  (W)   •
SOUR,
                                  Aili.
                           CAU5TIC  SOLUTION
                                               -D- - -,
AIR.
                                                r -.
7
o
t-

o


o
£

3

O
                                                                                            7I2.E1AT&-D
           &XTRACTQE.
                                  Figure 21.  Gasoline sweetening.

-------
this may be permissible, but in some cases it may be necessary to use





an incinerator equipped for sulfur dioxide recovery.  Incinerator emis-





sions may be the subject of future control regulations.  The other pol-





lution emission is the excess air from the air separator (point 2).





Since this air will contain disulfide, it may be necessary to incinerate





it.







N.     ASPHALT AIR BLOWING




       Asphalt used for composition roofing and shingles is usually





blown with air to oxidize the material.  The oxidation reaction increases





the hardness and raises the melting point of the asphaltic material and





improves its resistance to weathering.  In some processes a  catalyst





such as ferric chloride or phosphorous pentoxide is added to the asphalt





to produce a product with a very high melting point and hardness.





       Figure 22 is a typical schematic diagram of an air-blowing





asphalt-treating facility.  The feed to the asphalt plant will usually be a





residuum from a vacuum distillation of a topped crude.  The  reaction





is usually carried out in a batch operation.  The feed is preheated  to




400 to 600" F in a fired heater and then-pumped into the reactor.  The





reactor is usually a vertical vessel which is partially filled with feed





stock. Air  is compressed to a pressure high enough to permit dis-




charging it into the residuum through a sparger at the base of the





reactor.   As the  gases rise through the liquid,  an exothermal reaction





takes place  between the  oxygen and the hydrogen in the oil. Simulta-




neous chemical reactions cause polymerization and formation of oxygen



                                 73

-------
                                                  &.
                                                           FUM
_pUfcL.
 AAS
                                       A1/2.
Figure 22.  Asphalt air blowing.

-------
linkages.   The blowing reaction may be continued for periods  of from




one to 24 hours.




       Pollution Sources




       The gases which are vented from  the reactor contain hydrocar-




bon vapors and aerosol particles of oil.  These gases used to  constitute




one of the major forms of air pollution from a refinery.  Now the vent




gases are normally incinerated which eliminates the objectionable




constituents in the vent gas.  However, the incinerator remains a




potential source of air pollution (point  1 on the figure).







O.     ACID GAS  TREATING




       Hydrogen sulfide (H2S) and carbon dioxide (CO2) are  called acid




gases, and a gas stream containing H2S is called sour gas.  Since sour




gas is produced in a number of processes during normal refinery opera-




tion,  untreated refinery fuel gas can be expected to be sour.  It is gen-




erally necessary to treat the gas for H2S  removal before it is  used as




refinery fuel.  This  is done to avoid the air pollution that results  from




the sulfur dioxide  (SOE) formed in burning the H2S.




       Acid gases are removed by absorbing them in an alkaline solu-




tion.  The  alkaline material,  monoethanolamine for  instance,  is chosen




so that the chemical bond formed during  absorption can be broken by




heating.  The acid gas is stripped from the heated solution and the




solution, after cooling,  is  ready for reuse.  Solution containing acid




gas is called "rich"  and the regenerated  solution is called "lean".






                                  75

-------
       Several acid gas treating processes  are available but the differ-





ences are primarily in the choice of alkaline absorbent.  The processes




are similar in that the acid gas is  absorbed in the alkaline solution




under pressure,  and the solution is regenerated by heating at a low




pressure.





1.      Acid Gas^ Absorption Processes





       a.     Absorption in Monoethanolamine (MEA)   The absorbing





       medium is a 10 to 20 weight percent solution of MEA in water.





       Figure 23 shows the process flow for a typical MEA absorption





       system.   Acid gas is removed from the sour gas by contacting





       with the MEA  solution in the absorber.  Sour gas enters the bot-




       tom of the column and cool, lean amine enters at the top.





       Treated gas leaves  the top of the absorber and passes to the re-





       finery fuel gas system.   Rich amine, containing the absorbed





       acid gas,  is used to cool the lean amine and is fed to the top of





       the stripper.   Steam used for stripping the rich amine is gener-




       ated by boiling the stripper bottoms in the reboiler.  Acid  gas





       and steam leave the top of  the column and steam is condensed.




       Condensate and acid gas are separated in the acid gas separator




       and the condensate is pumped to  the stripper as  reflux.  The





       acid gas flows to the sulfur plant for conversion to elemental





       sulfur.  This stream is a potential source of air pollution (point 1





       in the figure).   Hot  lean amine from the stripper reboiler is





       cooled and filtered before returning to  the absorber.






                                  76

-------
                                         -OM*S
                                           v—/ MONITOR
                        SUMP
Figure 23. Acid gas treating.

-------
       b.      Absorption in Diethanolamine (PEA) - The absorbing





       medium is a 20 to 30 weight percent solution of DEA in water.




       The process flow scheme is identical to.that shown for MEA in





       the figure.





       c.      Absorption in Hot Carbonate - The absorbing medium is





       a 15 to 30 weight percent solution of potassium carbonate in





       water.  There are a number of variations to this process em-




       ploying additives to  improve solution performance.  The major




       equipment and process flow are again  similar to the MEA





       process.




       The treated gas (point 2 in  the figure) may be a source of air





pollution if H2S removal is  incomplete.  The H2S content of this  stream




should be checked periodically, if  not monitored continuously.








P.     SULFUR RECOVERY




1.      Process Objective




       The sulfur recovery process,  also  known as the Glaus process,





is  used to convert hydrogen sulfide to  elemental sulfur.   The  feed





stream contains acid gases (CO2 and H?S) obtained from the acid-gas





recovery  plant, but hydrocarbon impurities may also be present.   The





sulfur plant is normally designed to convert 90 to 95% of the H2S to




elemental sulfur,  which requires two or three  reaction stages,  with the





unrecovered sulfur being burned to SO2 and vented to the  atmosphere.





However,  recently implemented pollution regulations have, in some





areas, required higher degrees of recovery.  Tail gas cleanup processes





                                  78

-------
have been developed for this purpose that reduce the SO2 emissions




from the sulfur plants.




2.     Process Description




       Hydrogen sulfide is  converted to elemental sulfur in two steps.




In the first step,  H2S is partially burned to SO2 with air.  The H2S/SO2




mixture is then reacted over a catalyst to produce sulfur and water.




This reaction is known  as the shift conversion and is carried out in




two or three stages with sulfur removal after each  stage.  The design




of a  sulfur recovery plant depends upon the acid gas composition. If




the concentration of H2S in the feed is high,  a "straight-through" pro-




cess is used.   In the  straight-through configuration, all of the acid gas




and air are fed to the burner.  If the H2S concentration  in the feed is




low,  a "split-flow" or "sulfur recycle" process is used.  In the "split-




flow" process, a portion of the feed is burned completely to SO2 and




combined with the remainder of the feed to provide the  proper H2S/SO2




ratio for the shift conversion.  In the "sulfur recycle" process, the




product sulfur is recycled to the burner to  support  combustion.   A




fourth type of sulfur  recovery process uses the  "direct oxidation"




approach.  This configuration, which is for very lean feeds, eliminates




the burner by feeding the acid gas/air mixture  directly to a catalytic




burner.





       Most sulfur plants in refineries are the "straight-through" or




"split-flow'" type.  A flow diagram for a typical refinery sulfur recovery




process is shown in Figure 24.   The acid-gas stream containing H2S,




                                  79

-------
CD
o
                                               Figure 24.  Sulfur Plant.

-------
CO2, water,  and minor amounts of hydrocarbons is fed to an inlet




separator where any entrained liquid is removed.  The  acid gas and




air are fed to the sulfur boiler.  Fuel gas lines are provided to assist




in plant startup.  Boiler feed water is fed to the sulfur  boiler to gener-




ate low-pressure steam.   The sulfur boiler usually contains three tube




passes.  A portion of the gases is  diverted from the boiler after two




passes to provide preheat for the shift converter feeds.  In someplants




an auxiliary burner is provided to furnish preheat to the reactors.




Liquid sulfur is separated from the boiler effluent gases and is sent to




the sulfur pit for storage.  The gases are mixed with the reheat stream




and fed to the first-stage shift converter.  The effluent from the reac-




tor is passed through the condenser.  Sulfur is separated and sent to




the sulfur pit and the gases are fed to the second-stage converter.




Approximately 5% of the sulfur fed remains in the tail gas.   This  sulfur




is converted  to SO2 in the tail-gas incinerator.




       In some sulfur plants,  the sulfur  boiler and condenser are com-




bined into a single unit.   The catalytic converters are often combined




into a single  horizontal or vertical vessel. Combining  the units in this




manner permits many smaller plants to be shop fabricated and skid-




mounted.




3.     Instrumentation




       The acid-gas feed to the sulfur plant is  on pressure control.




The plant-is designed to accept acid-gas  flows as they develop in the




refinery and  a plant may be designed to operate at 25% of capacity to




                                 81

-------
allow for future demand.  The ratio of acid gas to air is controlled by





a special ratio flow controller.  To set the proper ratio,  the acid gas





must be analyzed regularly to determine the H2S concentration.  The





proper H2S/air ratio is  critical to the operation of the plant since the





concentration of  SO2 in the incinerator stack gases will increase if the





improper ratio is set.   Automatic stream analyzers  can be used to set





the proper ratio  on a nearly continuous basis.  The volume of reheat




streams is controlled to set the inlet temperatures to the  shift con-





verters.  If these temperatures are allowed to fall, the  reaction will be





incomplete and sulfur recovery will drop.   Incinerator stack tempera-





ture is controlled by setting fuel consumption and air bypass.  A high





temperature is required to ensure complete combustion of sulfur com-




pounds to SO2  and good  dispersal of gas to the  atmosphere.




4.      Pollution Sources





        The stack gas emissions  (point 1 in the figure) are the major




source of pollution from sulfur plants.  The concentration of SO2 in the





stack gas will depend on the number of stages, feed gas composition,





operating efficiency, amount of dilution air and plant upsets.   In a typical




plant with two reactor stages, the stack gas will contain up to 10% of





the feed sulfur.   The presence of hydrocarbons in the feed will be




detrimental to sulfur recovery and pollutant emissions.   Some of the





hydrocarbons are converted to carbon disulfide and carbonyl  sulfide in




the burner   These compounds are essentially inert and pass through to





the incinerator where they are emitted as SO,.  Hydrocarbons can also





                                  82

-------
foul the shift conversion catalyst and reduce sulfur recovery.




5.      Tail-Gas Treatment Processes




       Tighter air pollution regulations have forced many sulfur plant




operations to consider "hang-on" plants to reduce SO2 emissions.




Numerous processes have been developed to treat sulfur plant tail gas.




The more important tail-gas treating processes are discussed below.




       a.     Modified Stretford Process -  The Stretford Process has




       been used in  Great Britain for  many years to recover hydrogen




       sulfide from  natural gas and convert  it to sulfur.  The feed gas




       is passed through an absorption tower which removes the H2S.




       The absorbent is an organic liquid which also serves to oxidize




       the dissolved H2S to sulfur.   The sulfur is removed from the




       liquid by filtration, and the  solvent is regenerated by air oxida-




       tion.  Very high conversions of H2S to sulfur are  possible with




       this process.




              Since the Stretford Process is not suitable for use with




       feed gases  containing SO2,  two modified versions have been de-




       veloped for use with sulfur plant tail  gas.  The  Beavon Process




       uses a small catalytic  reactor  to hydrogenate the SO2, COS, and




       CS? to H^S before feeding the gas to a Stretford  tower.   The




       Cleanair Process  hydrolyzes the impurities  to H2S and SO2.




       The gas is  then cooled to permit the Claus reaction to take place.




       At low temperatures the conversion of SO2 to sulfur is complete




       and the remaining H2S  is fed to a Stretford Tower.  Adding a




                                 83

-------
Modified Stretford unit can reduce the incinerator stack concen-





tration of SO 2 to 250 pprn.





b.     Solution Glaus Process - The Claus reaction between





H?S and SO2 has a higher sulfur yield at low temperatures.  In





the IFF Process  (developed by the Institut Francais  de Petrole)




H2S and SO2 react in stoichiometric amounts in a liquid-phase





solvent.   The temperature is kept above the melting point of





sulfur so that molten sulfur can be drained from the bottom of





the tower.  The solvent is cooled and recycled to the tower.





Treated  gas is incinerated as in other processes. The IFP




Process can reduce SO2 in the stack gas to 2, 000 ppm.





c.     Sulfreen Process - This process uses a low-tempera-




ture Claus reaction on an activated carbon catalyst.   The sulfur





produced is adsorbed on the carbon and is removed by stripping





with inert gas in a  second step.  Reduction of SO2 in the  stack




gas is comparable  to that of the IFP Process.





d.     Stack-Gas Treating Processes  Another approach to





reducing  stack-gas emissions is to treat the stack gas rather





than the  tail gas.  Several schemes have been proposed to re-





move or recover SO2 from stack gases.  One such process that




has received some attention is the Wellman-SO2 Recovery Pro-





cess.  The stack gases are cooled and fed to a tower where SO2





is absorbed in sodium sulfite solution to form sodium bisulfite.





The sodium bisulfite  is heated to  drive off the SO2 and the sulfite





                           84

-------
       is crystallized,  redissolved, and recycled to the tower.  The




       SO2 is  recycled to the sulfur plant.  Effluent gas concentrations




       may be reduced to 100 ppm SO2.







Q.     SOUR WATER STRIPPING




       Water  containing sulfides is called sour water.   Refinery opera-




tions produce  sour water from processes such as steam stripping and




whenever steam is condensed in the presence of gases  containing hydro-




gen sulfide. Sour water may also contain ammonia and phenols.  Steam




stripping has been used by refineries to reduce the level of contaminants




in sour condensate to allow either further use of this condensate or its




return to public waters.  There are two types of sour water steam




strippers:  refluxed  and nonrefluxed.




1.     Refluxed Sour Water Steam Strippers




       Figure 25 shows the process flow for a typical  refluxed stripper.




Sour water feed may be flashed to release some vapor  and then stored




in a sxirge tank.  The sour water is then pumped through a preheat ex-




changer  and into the top of the stripper column.  Steam is fed into the




bottom of the column.   Sour gas,  containing steam and contaminants,




leaves the top of the stripper and is partially condensed.  Condensate




and sour gas are  separated in the surge tank and the condensate is re-




cycled to the stripper.   The sour gas is disposed of either by conver-




sion to sulfur  in a sulfur plant or by incineration, where air pollution




control regulations allow the emission of the sulfur dioxide  resulting







                                  85

-------
00
                                 Figure 25.  Sour water stripping process.

-------
from incineration.  The stripped water is removed from the bottom of





the column and either is used as a process water stream or flows to the





waste water treatment system.




       The pollution potential of the sour gas stream (point 1 in the





figure) is apparent because of its H2S content.  Further processing of





this  stream is necessary before  emission to the  atmosphere.  The





stripped water (point 2) may be a source of odor problems  if traces of





dissolved H2S remain and the stream flows to an open waste water





treatment system.




2.     Nonrefluxed Sour Water Steam Strippers




       In these systems there  is no overhead condensing system and





the column overhead goes directly to either flare or  incineration. This





stream has proved hard to dispose of because of the  large volume of





steam and is a potential source of pollution.







R.     NATURAL GAS PROCESSING





       Natural gas processing refers  to processes used to remove




impurities and to recover heavier hydrocarbons  from natural gas.





       Natural gas is a mixture  of methane and ethane that occurs in





nature as deposits trapped in geologic structxires.  The gas may occur





in combination with crude oil or  alone and at pressures varying  from





hundreds of pounds per square inch to substantial vacuums. Usually





water or brine is produced along with the gas,  and the gas  can be ex-





pected to contain nonhydrocarbon impurities and heavier hydrocarbons.







                                 87

-------
       Water,  brine,  and crude oil where present are usually sepa-





rated from the gas at the production location.   The field separators or





gas traps, used for this purpose,  are simple physical separation de-





vices.  The separated gas can be  expected to be saturated with water




vapor and will frequently contain heavier hydrocarbon vapors,  carbon




dioxide and hydrogen sulfide.





       Mixtures of water vapor and natural gas,  at elevated pressures





and low temperatures,  can form gas hydrates.   These icelike solids





plug lines and otherwise  interfere with transport and storage equip-





ment. Water vapor,  carbon dioxide,  and hydrogen sulfide are corro-





sive and hydrogen  sulfide is a potential air pollutant.  For these





reasons  it is frequently desirable to remove such impurities from




natural gas.





        The heavier hydrocarbon vapors are often separated to recover




LPG  and  natural gasoline which are valuable products.   LPG is pro-




pane, butane, or mixtures of both.  Natural gasoline is a component of





motor gasoline  consisting of mixtures of butanes, pentanes, hexanes,





and lesser amounts of still heavier hydrocarbons.





1.      Gas Dehydration Using Liquid Absorbent




       Natural gas is  dehydrated by using either absorption in a hygro-





scopic liquid or adsorption on a solid desiccant.  In processes employ-




ing liquid absorbents,  the liquid is  continuously regenerated and





recycled.  Solid adsorbents are usually regenerated periodically, with





two or more  vessels used to provide continuous operation.





                                  88

-------
       Diethylene glycol, triethyiene glycol,  and calcium chloride





brine are commonly used liquid absorbents. The glycol dehydration





process which is typical of the processes using absorbents is shown in





Figure 26.  Gas is brought into the system through an inlet scrubber




to remove any entrained liquid water or hydrocarbon.  The gas is then





dried by countercurrent contact with the absorbent in the absorber.




Dehydrated gas leaves the system from the top of the absorber and  the





absorbent containing water leaves from the bottom.  Since the absorber





is normally operated at pressures of several hundred pounds per





square inch,  some gas will be dissolved in the absorbent.  This gas is





separated in a flash vessel at reduced pressure and delivered to the





fuel gas system.   The absorption liquid is then fed to a distillation





column, or still, for regeneration.  Water is distilled overhead,  along





with a minor amount of gas which is sent to the flare.  The regenerated





absorbent is  recycled to the absorber after cooling by exchange with





the feed stream and cooling water.





       Water from the inlet scrubber (point 1  in the  figure) and the




still overhead (point 2) may contain sulfides.   If so,  these  streams





should be routed to a sour water stripping system.   Flash  tank gas




(point 3) may contain hydrogen sulfide and may require treatment





before being used for fuel.





2.     Gas Dehydration  Using Solid Adsorbent





       Alumina,  silica gel, and molecular sieves are three commonly





used solid adsorbents.  Figure27is a flow sheet for atypical adsorbent





                                 89

-------
                                              OVERHEAD
                                              ACCUMULATOR
Figure 26.  Glycol dehydration.

-------
iHLtT
^

Vk/AT1^!-
            _
             I
                            i,
                             r-7
                         n
                                  n
                                              L Al

                                                     r*
                                                         i
                     Figure 27. Adsorbent dehydration.
                                                           •«•

-------
dehydration process.  Since the adsorbent is regenerated in place, two





dehydration vessels are provided to permit continuous operation.  One





vessel is in service while the other is being regenerated. In the follow-




ing description, it is assumed that one desiccant tower is in service




while the other tower is being  regenerated.  Gas is brought  into the





system through an inlet scrubber to remove any entrained liquid water.




The main flow, to the # 1 desiccant tower, is controlled by a flow-





control valve taking its signal  from, a flow sensor in the bypass used





for regeneration.  Gas flows downward through the tower and dehydra-





ted gas leaves the process from the bottom of the tower.





        The rr 2 desiccant tower is regenerated while the # 1 tower is on




stream.  A bypass  stream from the main gas flow is heated and then





passed through the # 2 tower.   Gas and water vapor from the tower are





cooled to condense the  water.  The water is separated from the gas in





the condensate separator and the gas is returned to the main gas





stream. After regeneration,  the desiccant bed is  cooled by bypassing





the heater  and passing  cool gas through the tower.





        Depending on the pressure  of operation and on the amount of




hydrogen sulfide  in the gas, it may be desirable to treat  the water re-




moved from the process to  control dissolved hydrocarbon and sulfide





emissions  (points 1  and 2).





3.     Acid Gas  Removal




        The processes applied  to natural gas are essentially the same





as those covered under Section O,  Acid Gas Treating. There are,





                                  92

-------
however,  some differences attributable to the usually much higher




pressures of the gas to be treated.




       Glycol is often added  to the amine in an amine process to pro-




vide simultaneous dehydration and acid gas removal.




       In amine plants, a flash tank and reabsorber are normally added




to the rich amine circuit between the absorber and the stripper. This




arrangement is shown in Figure 28.  Natural gas absorbed at the high




absorber pressures is released at a lower pressure in the flash tank.




Since the flashed gas  is sour, a small reabsorber column is mounted




on the flash tank.  A slip  stream of lean amine is  fed to  the reabsorber




to remove the acid gas from  the flashed gas before the gas is sent  to




the fuel gas system.




       Since the absorber pressure is much higher than the  stripper




pressure, a large amount of  power is required to  pump  lean treating




solution from the stripper to the absorber.  Some  of this power can be




supplied by utilizing the pressure difference available in the rich solu-




tion circuit.  A pressure  breakdown turbine is inserted  in the rich




solution circuit and the turbine is used to drive the lean solution pump.




A motor or steam turbine is  used to supply the balance of the power




required.




4.     LPG and Natural Gasoline Recovery by Compression




       Natural gas is often transported through high pressure pipelines




as a matter of economy.  Where the gas is produced at low pressure,




the gas  must first be  compressed. Although natural gas is seldom




                                 93

-------
                                                                  on.
Figure 28.  Amine-water and glycol amine process using breakdown turbine.

-------
compressed solely for the purpose of LPG or natural gasoline recovery,





significant amounts of these products are recovered from compressor




stations.  Under pressure, the heavy hydrocarbons are condensed and




separated from the natural gas.  Since the increase  in pressure per




stage,  expressed as  the ratio of outlet to inlet pressure, is limited by




practical considerations,  several stages of compression may be needed




to reach the required pressure.




       Figure 29 is  a flow sheet for a typical two-stage compressor




station.  Gas enters  through  an inlet scrubber or knock out drum to




remove entrained liquid.  The  gas is  compressed in the first stage




cylinder,  cooled by a cooling water exchanger and sent to the first stage




accumulator.  Water and hydrocarbon are separated from the gas under




liquid level and interface level control.  The hydrocarbon is sent to a




distillation unit for recovery of LPG and natural gasoline (see Section S,




Light Ends Recovery).  The gas is then compressed in the second




stage in a similar manner.  The  first and second stage cylinders are




usually driven by a single engine or motor.




       The water  streams (points 1,  2, and 3 in the figure) may contain




sulfides and hydrocarbons.  If so, they should be routed to separators




and a sour water stripper.




5.     LPG and Natural Gasoline Recovery by Refrigeration




       The amount of heavy hydrocarbon vapor  that can be held at satu-




ration by natural gas decreases with  decreasing temperature or increas-




ing pressure.  Increased recovery of LPG and natural gasoline can be




                                 95

-------
Figure 29.  Two-stage gas compressor.

-------
achieved in a compressor plant if refrigeration is used in place of




cooling water  in the compressed  gas coolers.




6.      LPG and Natural Gasoline Recovery by Oil Absorption




        The absorption process for recovery of LPG and natural gaso-




line is more complex and generally more expensive than the compres-





sion and refrigeration process, but it  is also more  efficient.   An




absorption oil, usually in the kerosene range, is used to absorb the




heavy hydrocarbon vapor under pressure.   The hydrocarbon product is




recovered from the absorption oil by distillation.




        Figure 30 is a flow diagram for a typical oil absorption process.




Gas is fed to the bottom  of the  main absorber where it is brought into




countercurrent  contact at relatively high pressure with cold lean




absorption oil.  Treated gas leaves the system from the top of the




main absorber and rich absorption oil flows from the bottom to a flash




tank.   Enough product vapor is flashed along with the dissolved natural




gas to  warrant the use of a reabsorber column.  Flashed gas and gas




from the still  are combined and fed to the reabsorber where they are




brought into contact with a slip stream of lean absorption oil at low




pressure.  Overhead gas from the reabsorber goes to fuel.  Rich oil




from the reabsorber and the flash tank are  combined and heated by




exchange with still bottoms. The combined  stream is heated by ex-




change with steam or hot gas oil  and is sent to the still for regeneration




by distillation. A small amount of steam is injected directly into the




still to help strip the lean  absorption oil.  Most of the resulting




                                 97

-------
oo
           TREATED
               OUT
                                          Figure 30.  Oil absorption plant.

-------
condensate is removed from the top trays of the still by the use of a




draw off tray.  Product hydrocarbon from, the  reflux accumulator is




sent to a fractionater for distillation into LPG and natural gasoline.




Hot lean absorption oil from the bottom of the  still is  cooled by feed-




bottoms exchange and  by cooling water exchange and is recycled to the




absorbers.




       Water entering the process in the feed  gas and stripping steam




is condensed in the system and leaves in  streams (points 1-5 in the




figure).  These streams may contain sulfides.   If so,  they  should be




routed to a sour water stripper.   Gas from the reabsorber (point 6)




may contain hydrogen  sulfide and  may therefore require treatment




before using  as fuel.




       Some absorption  plants are operated at high pressure, on the




order of 1, 000 psig.  In  such cases,  it may be desirable to  employ two




stills for absorption oil stripping.  One  still is  operated at high pressure




and one at low pressure.   The advantage  of this procedure  is that better




recoveries of product  and  cleaner separations  are possible.







S.     LIGHT ENDS RECOVERY




       Refinery light ends are usually  hydrocarbon compounds having




four or  less carbon atoms, including methane, ethane, propane, butane,




and isobutane. The objective of a light ends recoveryunit is to separate




these components into  saleable products and fuel gas.  In small refin-




eries,  or in refineries where little or no cracking processes take place,







                                 99

-------
light end recovery units may not be economical and most of the light





ends are used as fuel.  Larger refineries, on the other hand,  may have





more than one light ends recovery system, perhaps located in different




sections of the refinery.





        Normally, the ethane and methane go into the fuel gas system.




Propane is separated as a product because of its value as a feed stock





in the petrochemical industry.  The butanes are either added to the




gasoline pool, or separated to isobutane and normal butane andused as





feed for other units in the refinery (see Section G, Alkylation Process).





The process configuration and recovery of light ends will vary with the





particular needs of the refinery.  A typical unit is presented in Figure 31.





        The feed  to the  recovery unit is unstabilized naphtha (a gasoline




cut containing dissolved light ends) and a gas stream rich with propane





and butanes. The naphtha feed is stabilized in the stabilizer by removing





a portion of the light ends.   Some  butanes are left in the stabilizer bot-





toms product for maintaining the proper naphtha vapor pressure.  The





stabilizer overhead product is combined with other refinery gases and





fed to a deethanizer.  Methane and ethane are removed as fuel gas from




the deethanizer accumulator and the deethanizer bottom product, essen-




tially propane and butanes,  is fed  to the depropanizer for separation





into the two products.





        Pollution Sources




        Possible  point sources of pollutant emission are sour water





from the deethanizer accumulator  (points 1 and 2 in the figure).  This





                                  100

-------
L^-2^1
          Figure 31. Light ends recovery.

-------
stream should be sent to a sour water stripper.  Fuel gas (point 3)





from the unit may contain H2S,  in which case it should be treated for




H2S removal before being used as fuel.







T.      WASTEWATER SYSTEMS AND SOLIDS DISPOSAL





        Refineries generate a significant amount of process water, which





has been in contact with oil and chemicals.  This wastewater  stream





requires extensive treatment before discharge into a body of  water.  In





addition, large quantities of runoff  from refinery process and storage




areas during rainy periods require treatment before discharge.  Fig-





ure 32 shows a relatively complex system for handling these  water




streams.   The unit  operations involved vary from refinery to refinery





depending on local requirements.  All refineries can be expected to





have  an API separator.   Dissolved air flocculators are common,  many




units having been installed in the past few years.  Biological  oxidation





units are less common, and there are only one  or two carbon units in





service.   For more detail refer to Air Pollution Engineering Manual.





        During dry weather operation, the process water streams are





collected and flow to an API s eparator.  The oil skimmings are pumped




to a  storage tank to await treatment.   The sludge that settles  in the





separator may be either pumped to an incinerator or removed by tank





truck for disposal.  The pH of the water leaving the separator is  con-





trolled  at 7. 0 to  7. 5 by the addition of either acid or caustic.





        This water  is frequently pumped to a biological oxidation system







                                 102

-------
                                                          ro LX t LtcTn.0 tyrt.
o
UJ
                                                                                            A
                                                                                          \*4CiMg.rLATog.
                                                                                                  iua&*.
                                                                                                  TAWK.
                       EppUUC-WT
                        5UMP
r


•



L
r
t
CAIUOU
t,to
\

h
1
r
i
CAfcBnJ
bU7
t

h
i
r
i
CAAA
6*1
*
L^
                                                                                              I   i>e.*Je.B,
                                                                                               /
                                                                                    (Lft-^c-fuvoin.
                               32.  Waste water system and solids disposal.

-------
to reduce the biological oxygen demand (BOD).  Further removal of





suspended solids and oil from the water is effected by chemical floc-





culation,  using a combination of alum and a polyelectrolyte flocculent,





followed by air flotation.  Sludge from biological oxidation and the





skimmings from air flotation may be either pumped to  anincinerator




or removed by tank truck  for disposal.   The water has now been





treated sufficiently to be pximped to a surge tank and then to a muni-




cipal sewer if one  is available.





        Further treatment may be required before the water can be





discharged to a natural water body.  The wastewater is  collected in a





reservoir,  and the final or tertiary treatment for the removal of dis-





solved organics is effected by passage through activated  granulated





carbon beds.  The water is then chlorinated and flows  to a retention




sump before being discharged from the plant.




        The carbon beds are  reactivated by backwashing with treated




water.   Removed contaminants flow back to the wastewater-reservoir.





When the carbon is spent, it  is removed from the beds in slurry form





and  placed in storage tanks.   The carbon is  regenerated by  educting





from the tank to a dewatering screw and feeding to a multiple hearth





furnace.   Contaminants are burned off  as the carbon drops through the





furnace.   The carbon falls into a quench tank and is  educted to a stor-





age  tank ready for reuse.   Flue gases from the furnace are quenched





and  then scruhbed before venting.
                                  104

-------
       During periods of rain, the process waters, mixed with rain




water, continue to be processed through the normal treating facilities.





The maximum rate through this system is limited by the capacity of




the biological oxidation and air flotation units.  Water runoff in excess




of the capacity of the system is pumped to the reservoir.   Oil skim-




ming facilities  should be provided in the reservoir for surface oil




removal.   This water can then be pumped and processed through the




activated carbon adsorption plant before being discharged from the




plant.




       Pollution Sources




       Tanks that are open to the atmosphere are potential sources of




pollutants, thus the API separator  (point 1) should be designed with a




cover where required to comply with pollution control standards  for




oil-effluent water  separation equipment.




       Another source  (point 2) is  the stack gas from the incinerator.




This equipment should also be designed to comply with local pollution




control standards.





       A third potential source of emission (point 3) is the  vent gas




from the carbon regeneration system.







U.     FLARE AND SLOWDOWN SYSTEM




       During refinery processing plant upsets and plant emergency




conditions,  such as power failures, higher than normal pressure may




be generated in certain equipment.  To protect this equipment from







                                 105

-------
damage, pressure relief devices are installed and set to open at a





pressure below the design pressure of the equipment.  Process  mate-





rials released when these valves open are collected and burned  by a




flare (see Figure 33).  Process waste gas is  sometimes  also flared.





        Under normal operating conditions, when no systems are




relieving to the flare  header,  a small purge of fuel gas is used to keep





a positive pressure in the line and the flare flame  alight.  During





emergency conditions  the relieved process fluids  flow through the flare





header to the knockout drum,  where any entrained liquid is separated.





The vapors from this drum flow through a liquid seal to  the flare and





are burned.   The liquid is pumped to a slop tank.





        Pollution Sources





        The only potential source of air pollution from th'is system is





the  stream containing the products of combustion  of the flare (point  1





on  the figure).  Any of the  refinery processing plants could relieve to





the  flare, including those containing H2S and  other pollutants; but air





pollution regulations  do  not usually cover  emergency situations. A





continuing emission problem  could occur if relief  valves do not reseat





properly, leaking  process  fluids to the flare  system.  Preventing such




leakage is a matter <>t proper maintenance.   Additional information  on





flares is presented in Chapter II.








V.      STORAGE




        Normal refinery operation requires the storage of  large vol-





umes of crude oil, intermediates,  and finished products.  Many of





                                  106

-------
       T  TL
1—*r  ****•
PUC.L
              FLANI
AiR-
                              FUAO.ES.
                                       LIOUlP
                                       SBAL,
/A
                                         T
                  Figure 33.  Flare and blowdown system.

-------
these materials are volatile and, unless properly controlled,  storage





can be a major source of hydrocarbon pollutants.





       Hydrocarbon emissions from volatile fuel storage can be  con-





trolled by not allowing space for vapor formation,  confining the vapors





within the storage  system, collecting and burning the vapors, and by





collecting the vapors and recovering the hydrocarbon portion.  Although





adequate  control can be achieved for any storage facility by any of





these methods,  the best method to use  depends on the characteristics





of the storage facility and fuel to be stored.





1.     Floating Roof Tanks





       The principle used in floating roof  tanks is the elimination of





vapor spaces.  This is accomplished by floating a rigid deck or roof




on the surface of the stored liquid.  The roof then rises and falls





according to the depth of stored liquid.  The roof is  equipped with a





sliding seal at the  tank wall so that the liquid is completely covered.





No additional roof  is required; however, many tanks are equipped with





a standard  fixed roof that covers the floating  roof.  Floating roof tanks





are  suitable for volatile fuel storage where the fuel is stored below its





boiling point.  That is,  the vapor pressure of  the fuel must be below





atmospheric pressure at storage conditions.




       Sliding seals are an  important feature  of all floating roofs.   The





ideal seal will be vapor tight, long lasting, and require little mainte-





nance.  Seals are required at the rim of the roof,  at support columns,
                                  108

-------
and at all points where tank appurtenances pass through the roof.  Two





basic types of seals are in  common use today,  the metallic and the





nonmetallic seal.   The metallic  seal consists of a sheet metal shoe held





against the tank wall by springs  or counter weights.  The space  between





the roof and the shoe is covered by a flexible fabric membrane.   The





fabric is often protected by a metal cover.





        The nonmetallic seal is usually made of a  hollow  flexible plastic





tube filled with plastic foam,  liquid,  or compressed air.  Column and





guide cable seals are usually close-fitting,  flexible plastic sheets.  The





sheets cover holes cut in the  floating roof and are sealed at the edges  of





the holes  by resting on plastic or metal rims fitted around the holes.





The sheet  is sometimes allowed to slide horizontally on the rim to





provide for vertical misalignment of the column.




        Floating roofs are taken  as the standard of effective emission




control for storage tanks.  Their effectiveness depends on the material





stored and other factors, but their use results in  about a 90% reduction





of emissions.





2.      Variable  Vapor Space Tanks





        There are two general types of variable vapor space, or conser-





vation,  tanks that have been used in volatile  fuel storage systems.




Lifter roof tanks have a movable roof  that rises or falls  as the volume





of vapor changes.  Flexible diaphragm tanks have a diaphragm installed





within the  tank and attached to the wall so as to provide a variable
                                  109

-------
vapor space in the'lower half of the tank,  with the diaphragm protected





by the upper half of the tank.





        It would be possible to provide enough vapor space within a




system to prevent  the escape of vapor during both loading  and normal




breathing, but the  volume required would be almost equal  to the liquid





storage volume. Such a system would be too expensive to be practical.





In the past, lifter roof tanks have been used to  prevent tank breathing





losses.  No attempt to prevent loading losses was made,  the excess





volume being vented to the atmosphere.  Since  the degree  of control





provided by such systems will not meet current pollution control re-





quirements, the use of variable vapor space tanks as primary control





devices has been discontinued.  They are, however,  still used to pro-





vide surge volume in systems employing absorber units  and the like.




(See Section W, Loading and Transfer. )





3 .      Flares and Incinerators





        Hydrocarbon emissions from storage systems can  be controlled





by piping the  vapors to a flare or incinerator for burning.  Since the





hydrocarbons are destroyed in the process, this procedure results in




an economic loss.   The procedure is  sometimes justified for isolated





tankage, but most  refineries employ floating roof tanks and/or vapor





recovery systems.





4.      Vapor Recovery Systems





        Occasionally vapor recovery systems of the type described in





Section W,  Loading and Transfer,  are used for  control of  storage






                                 110

-------
systems (or tank farms).  A more generally used system,  however, is





one in which the storage tanks are blanketed with natural gas. (That is,





the tanks are manifolded together and a slight positive pressure of





natural  gas is maintained in the manifold. ) When vapor is generated in





this system,  the  excess is compressed and sent to the refinery fviel




system.  In larger systems, where the cost of the additional equipment





is justified, light ends recovery may be employed (see Section S).




       Figure 34 is a schematic diagram for a typical refinery storage





vapor recovery system.  Standard cone roof tanks are interconnected





with a piping manifold.  Since the tanks can withstand a pressure or





vacuum of only a few inches of water in the vapor space, the tanks are





equipped with combination pressure-vacuum relief valves.  The  system





should be designed so that these valves remain closed.  The proper





pressure is maintained by admitting  natural gas to the manifold when





the pressure falls, and by removing  vapor  by means of the compressor




when  pressure rises.   Normally, the compressor is run continuously so





as to  maintain a vacuum in the surge tank at the compressor inlet.  The





fuel gas stream may contain sulfur compounds (point 1 in figure).





5.     Estimated Hydrocarbon Losses





       Annual fuel losses  can be estimated by a method given in a




manual  prepared by the American Petroleum Institute,  API Publication





No. 4080, Recommended Procedures for Estimating Evaporation and





Handling Losses  of Volatile Petroleum Products in Marketing Operations,





July 1971.   The appropriate nomographs from this publication are
                                 111

-------
                                                ScMXC.6.
                                                 fAKlK.
Figure 34.  Vapor recovery for storage.

-------
shown in Figures 35, 36 and 37.  The factors affecting hydrocarbon

loss include:

                       Daily temperature change
                       Fuel volatility
                       Loading frequency
                       Paint
                       Storage temperature
                       Tank diameter
                       Tank outage

       Fuel volatility is normally expressed in terms of vapor pres-

sure.  Reid Vapor Pressure is commonly used.  It is the vapor pres-

sure at 100°F as determined by a test method that employs a specified

apparatus.  Because of the apparatus  used, Reid  Vapor Pressure is

not a true vapor pressure.  If the true vapor pressure is required, it

is usually found by using an experimentally developed correlation.

       Vapor pressure is a measure of the pressure developed by a

liquid, at a given temperature, in the vapor space over the liquid.  It

applies to a closed container containing only the liquid and vapor from

the liquid.  The vapor pressure depends only on the composition of the

liquid and on the temperature.  If the  vapor pressure  is equal to atmo-

spheric pressure, the liquid is at its boiling point.  Materials such as

gasoline are  normally stored at temperatures below their boiling

points.   The  vapor space of the tanks, therefore,  contains mixtures of

hydrocarbon  and air.  For practical purposes,  the volume percent of

hydrocarbon  in the mixture at equilibrium is equal to  the  ratio ofliquid

vapor pressure to total system pressure, expressed as percent.  The
                                 113

-------
         0.20
      —  O.3O







Ul
t-
0
m
CD
<
x
o
z
w
<
^J
e»
<0
c
Ul
0.
O
z
D
O
a.
z
" *
Ul
ff
3
«0
40
ec.
a.
K
0
a.

>
Ul
D
t-














— 0.40
— O.50

— O.60
— 0.7O
— o.eo
— O.9O
— I.OO




— 1.50

-
— 2.0O
-
_^
— 2.50

-
±- 3.00
^- 3.50
—
— 4.00
—
_
M
— 5.0O
~
-
~ 6.00
—
^
^- 7.00
—
^
— 8.00
-
— 9.00

— IO.O
— 1 1.0

— 12.0
— 13.0
— 14. 0
— I5.O
— 1 6.O
— 17.0
— 18.0
— 1 9.O
— 20.0
— 21.0
— 22.0
— 23.0
<=- 24. 0


S
,1 0
43
nil 1

iim •
IT



1 ,
\

1
\
n
1

L
V



1-4" 2

M «
3
\\ 3 «
Vc 4 8
nt
1 Jf S
ixi p
6^
<

ffln 8 i
iM/t 10 *
/









AH/f

' T/V
<1V> 14
. y% 16
• MA**

'w/x20

'W
v






120-:
^
I 1 0 ^~
'.
~
1 00 "™"
1
~
90-^
;
^
«
I
80-^
;
;
70-^
"
-
"3
™
60-^
•^
™
50-^
™
.1
~
I
40* i
f
•™
-
30-:

i
^
;
20 -f

S a SLOPE OF THE ASTM DISTILLATION CURVE AT I
10 PER CENT EVAPORATED » ~
DEG F AT 15 PER CENT MINUS
1 0
1 W
DEG F AT 5 PER CENT 10 —
;
^
IN THE ABSENCE OF DISTILLATION DATA THE FOLLOW- o :









^>
u
X
z
Ul
(C
X.
"•
Ul
Ul
oe
o
S
Z
Ul

-------
EXAMPlEi
   MOM Barral Tank
   Huovghpvl=5oOOOO tarrcb p«f To«
   Turnover* =10
   Tr«« Vapor >rouvro= 5.B p»ia
   Working UH    =  975 e«rr.li P«r r«or
                                                                               JO-
                                                                               IS
                                                                   10 -
                                                                                    20
                                                                                  - IS
1000 n
1500 -
2000-
3000-



4000 -


5000-

6000

7000

8000
9000
10000
       I
       I
10.0-
 9.0T-;
 1.0-

 7.0-

 6.0-.

 5.0-


 4.0-
 J.O-
 1.3-
                                          Pivol
e
* « —
o- .5 •
•= ? 5

1*1
E • j
•• o **
 Note: The throughput is divided by a number (1, 10, 100,  1,000) to bring it
 Into the range of  the scale.  The  working loss, read from the scale,  must
                 then be multiplied  by the same number.
                                                                          (API PUBL. NO. 4060)


- U

- 1.0
- 0.9
- 0.8
- 0.7
- 0.6
•
-04
- 0.4
i
J- OJ
0.2-^

:;
0.15




0.10
0.09
•- 0.2
• '
'

. -0.15
:-
0.0« 3"
^- 0.10
0.07-J. Q0o
0.06 "T" 0.08
V 0.07





















u.
&
c
^
J
e>
c
^
o
*
•
c

1
£





        Figure  36.   Working loss of gasoline from fixed-roof tanks.
                                             115

-------
(API PUBL. NO. 4060)
T - U*r
I, - 1.11
H - 31 rm
D - 100 rY.1
I, - I150*orr*li »«' y.«»




10





r
X





15



S
s






\





\



s
s






\





\



\
s





s
\


20
X







X






\


\




\




^ i
\

X
25
N,

\


\



X






s
10 >
\




\



\
\






Tonh Color
tool
•nil*
wMta
•|«*IM« (ipocvlor)
•Iwin.x Mill.-)
fighl gray
•wditia gray
ih.ll
whita
wfcito
•IwHllNtim (lp*Cvl«f)
OfwM[MW«(tp«i>>.» IdWuu)
Kokt gray
M«diwM gray

Po«» factor, F,
Point in Good Condition
1.00
1.04
1.1*
1JO
1.10
1-1?
1JO
143
1*1
Point In Poor Condition
1.15
1.11
1.24
1.2*
l.M
1.44
1.4*

u
1.4
\
1Jv
IJ,
'•'v
LO
^
30*

b
N
sx
23'



X
s

1
20
Average AtmotpKork
Temperature Chang*
in DvgiMi Fohranh
15 .
\
\

N



\




s



\




j
> « r 1 1 ! i i ii — i
40
x
s
\





\



s
s



x
\
x
s
\
\




\



s



50
\
x
\
\
\
\

\


\



s
X

40
\
^
s
x
\
\
\

\


\



x
X,
.70 (0 M 100 125
Xl X X X X J _X
\
\
s
X
s
\
\
\

\


\



s
X
x
S
\
s
\
\
\
\

\


N



\
x
S
\
s
\
s
s

\

X


\


. X
\
X
s
X
ss
\
s
s
s
\
s.
\
v

\


N

X
s
X
S
x
s
\
\
s
\
s
V
\
\

N


\

s^X
S
\
v
S
V
\
\
\
S.
X
\
\

N


150 175 200
x. rv r\


X\
X
S
\
V
S
\
\_
sv
S
\
X

\

\
k

s\
\
\
X
v
S
s
\
\
\
s
\
\

S
\
\
\

s^\
x,s
N
V
\

\
s
S
v,
S
s

k


S
\
\
\


N\
N
\
N

S
S
\
\
S
v
V
^
S
\
10 15 20
f 	 £— « 	 1 	 1 	 »• fill 	 1 	 1— f-1 	 1— « 	 1 	 1

k
\
s
\
s
\
\


^v
\v

\
\
N
V
K
S
\


^
S
\
\
\

\\
v
s'

\
\
IS
s
N
\



\%
X,
s
s
s.
S
\
y
s^
x^
\
s
s
\
s
s
s



s^
s,
s
\
v
S
\
s

sj"
\jv
Njv
^

s!





**^
xS
s
\
\
s

\
>s
s
s
\





K>
X
s
V
S
\


X
N
N
s
s






'0
S,
v
s
s
~N
\
y
\\
\s

s








s
v
s
S
\
s
\s
V
x,
SI









s
s
x,
S
\
^
v\
x










s
s
\
S
\
y
s\


v


s
x
X
i
•it.











s
V
s
V
s
N
\



\
x^
X
X
V



^

ss
X
;''N












s
S
X
s
S
\













\
V
s
V
\




—
x
x
X
X
s
10 '














N_




—


/
/

^
i

>
i
4
7

'*
10 ,






200
175




--
/
/
r
/
'

\
s
\
\
s
\v
X
s\
\
\










/
/
/
/ 1
/
y
'


\
\
s
V
\
k \
\
s\
s
N







/
/
/


//
/
' k
I
f i

,.
/ ' " '

'/
(I
f
/
/
//
A
/ /



^
X
\
\
\
V

s\
x
S





-t
*r
X
\
s,
\v


X
\
\




//
/
/
H
/

'/ f
f j
I


*

\
\
\
\
\
v



\



/
//
//
{/
i
$
'•/
7
V
",
1
1
1
1
N
N
^
V
iv

\

\
s
S


//
//
//
/t
§
/






^
\
\
\v
\


s\
s


r/
//
/*
V
• f
v










* *<

\
\

V

^

s

9

r










»


s
^
x
^
\
v
v
25 101540 50 M 70 10 »0 100 125 150
•"I It >-l 	 tl 1 > 1 II t 	 1 	 1 1 M 1 	 »— OooooVw
Figure 37.  Breathing loss of gasoline from fixed-roof tanks.

-------
amount of hydrocarbon lost in a given volume of vapor displaced from a





tank is thus a direct function of the vapor pressure of the stored liquid.





       Loading frequency is a measure of the  number of times a tank





is filled and emptied in a given period of time.   It is usually expressed





as "turnovers per year". When liquid is loaded into a lank,  an essen-





tially equal volume of  vapor is displaced.  The amount of hydrocarbon





lost  is a function of other factors  as well bul is strongly dependent on





the total volume of vapor displaced and, therefore, on the  turnovers





per year.




       The temperature at  which  a given fuel is stored determines the





vapor pressure and hence the equilibrium vapor composition.  The





higher the  temperatxire, the higher the hydrocarbon content of the vapor




and the greater the loss per volume of vapor.   In vapor loss correla-





tions,  the Reid Vapor  Pressure and the storage temperature arc used to





specify vapor composition,  and the composition itself may not  ever be





determined explicitly.





       Daily temperature change  causes  a cyclical change in the tem-





perature of the stored liquid and of the vapor space above  the liquid.





Increasing liquid temperature  results in increasing liquid  vapor pres-





sure, and some of the liquid is vaporized.  At  constant pressure, not





only is the percent of hydrocarbon in the vapor increased,  but  vapor is





displaced  from the tank.  Another effect of increasing temperature is





that  the vapor in  the vapor  space  expand's.  I'nless the tank pressure is





increased, vapor  is  displaced  from the tank.  When temperature drops,





                                  1 17

-------
the reverse occurs and air is drawn into the tank vapor space.





        Breathing losses  are  a function of vapor space volume (or tank




outage); the greater the volume, the greater the loss.  Losses from





tanks that are nearly empty will be greater than losses  from tanks  that





are full.  For a tank of a given diameter,  the vapor volume can be




specified by stating the height from the top of the tank to the liquid





surface. This  height is called outage.  When calculating breathing





losses,  it is common practice to assume that the tanks  are half full;





that is,  outage is taken as equal to one-half of the total  tank height.





        If the liquid and vapor in a tank were always in equilibrium,




tank diameter would only be  a means of stating volume.  In actual field





testing,  however, it has  been found that the tank vapors  are not always




saturated and that vapor  losses are somewhat  less than would be other-




wise  expected.  Smaller  tanks were found  to have lower  losses, but the





difference  is not significant for tank diameters of 30 feet or more.





        The color and condition of the paint on  a tank have been found to





have  an  important effect  on breathing losses.  Using white paint in good





condition as a standard,  white paint in poor condition may  lead to a 15%





increase in loss.  A medium grey paint may lead to a 46%  increase.





        All of these factors are included in the nomographs.  The nomo-





graph in Figure 35 can be used to obtain the true  vapor  pressure from





the more commonly available Reid vapor pressure.  That in Figure 36





can be used to estimate working loss,  that is,  the loss due to loading
                                  118

-------
operations and the nomograph in Figure 37 can be used to estimate





breathing loss, that is the loss due to daily temperature changes.





6.     Potential Point Sources of Pollutants




       Vents on uncontrolled cone roof tanks storing volatile hydrocar-





bons are a source of pollutants and should be controlled.




       Sliding  seals and gage-opening covers on floating roof tanks





must be properly maintained or they will leak.





       Conservation valves on tanks connected to a vapor recovery





system may leak.   The leakage may be due to a system pressure thai





is higher  than the  set pressure of the valve or to an improperly main-





tained valve seal.







W.    LOADING AND TRANSFER




       Gasoline and other petroleum products require distribution





from the refinery  to the consumer.   This is achieved by pumping from





refinery storage tanks to a loading terminal where the products are





loaded into tank cars,  barges,  and tank trucks by means of loading





racks.  Products are also loaded into ocean-going tankers at bulk




marine terminals  by pumping from  storage.  Marine terminals may





have facilities  for unloading  crude oil from tankers into storage tanks.





During all these loading and  transfer operations large amounts of air





containing hydrocarbon vapors are generated. If not controlled,  these





vapors can be  an important source of air pollution.
                                 119

-------
1.      Loading Equipment





       Loading racks are structures  containing the platforms, piping,





vapor collection devices,  control devices,  and loading arm assemblies





required for transferring the product from storage to the transport





vehicle.   Bottom loading normally requires simpler equipment than





overhead  loading.  The method used for loading marine  tankers is





similar to the bottom-loading operation.   Liquid is delivered to the




bottom of a compartment while vapors are vented through a manifold.




       To avoid atmospheric pollution the produced vapors are col-





lected at the tank vehicle hatch using  specially designed closure  de-





vices.  For overhead loading these are plug-shaped devices that have





a central  channel for the liquid to flow into the tank and  an annular





space for the vapor to flow out  of the  tank into a pipe connected to a




vapor disposal system.   For bottom loading a vapor take-off line is





connected between  the vapor space of the tank and a vapor disposal





system.





2.      Vapor Recovery Systems





       a.      Vapor Recovery to Fuel Gas    When a suitable fuel gas





       system is available,  the vapors can be used for fuel.   The





       loading system is gas blanketed to avoid explosive mixtures,





       and the vapors are collected in a  vapor holder.   The vapors are





       fed to a compressor and discharged to the fuel gas system.




       b.       Vapor Recovery by Absorption in Gasoline   Figure 38





       presents a typical system for the absorption of hydrocarbons in





                                 120

-------
      gasoline.  Explosive mixtures cannot be permitted in this unit





      so the amount of hydrocarbon in the air is raised substantially





      above combustible limits by saturating with gasoline.  This is





      accomplished by countercurrent contact of the air with gasoline





      in the saturator prior to storage in the gas holder.   The vapors





      are compressed,  cooled and introduced into an absorption column





      where absorption of the hydrocarbon in gasoline  takes place.





      The air  is vented to the atmosphere through a  back pressure





      control valve.  The gasoline is returned to storage after the





      dissolved air is removed in the two-stage flash separator.





      Although the design recovery of hydrocarbon vapor by this





      system can be in excess of 90 percent, the vented air (point 1





      in the figure) may  be a potential source of pollution and may





      require  checking.  If the hatch closure (point  2) is  not operating





      properly, air pollution may occur.





      c.     Vapor Disposal to Flare   The vapors can be satisfactorily





      disposed of by burning in a smokeless flare.





3.     Loading Losses





      Loading losses are influenced by many variables.  The volume





of  vapors produced during  loading is influenced by the  mode of loading





employed.   The modes in general use in  refinery operations  are





overhead loading  and bottom loading.  Overhead loading is sub-





divided into two types, splash filling and submerged filling.  In





splash filling, the outlet of the delivery  tube is normally above the





                                 122

-------
Figure 38.  Loading rack vapor recovery system.

-------
liquid level, while in submerged filling the outlet is below the liquid





level.  The former generates more hydrocarbon vapors.





       To calculate loading losses,  the total throughput information is





recorded on a form such as that shown in Table 7.   The true vapor





pressure (TVP) is determined from the nomograph in Figure 35 for





each product.   The curves in Figure 39 can be used to calculate the





evaporation as volume percent of load for splash loading and sub-





merged loading in tank cars  and tank trucks.  The  correlation curve in





Figure 40 can be used to determine marine evaporation losses.  A





detailed discussion of these calculations can be found in API Publication





No. 4080 (July 1971).







X.     FUEL  GAS SYSTEMS





       Operators would like to maintain a fuel gas balance in  their





refineries to produce enough fuel gas to  supply the heat required in the





refining processes.   However, production and use  of fuel gas  depend on





the refinery processes, the crude processed, and  economics.  In





general,  additional fuel gas must be purchased.  The crude unit and all





of the cracking process units produce  fuel gas.   In most cases these




gases contain  sulfur compounds and have to be treated before  entering




the fuel gas system.





       The fuel gas system is the storage and piping network by which





the refinery stores, blends and distributes  the gas internally in the





refinery.   The input  to  the  fuel gas system  is in general from two








                                 123

-------
Table 11.   LOADING LOSSES:  MOTOR GASOLINE, TU RBINE FUELS, AVIATION GASOLINE

Plant	 Company	

                                            State                                         Year
Location:  City
Product















Total
Thruput
M Gallons















Total Deliveries
M Gallons
Tank Car or Tank Truck
Marine















Splash (1)

.








.




Sub-
Surface (2)















Product
Temp.
°F















Vapor Pressure
RVP
PSI

•













TVP
PSIA (3)















Losses
Bbls/Yr.
(3)















 (1)  Splash Loading - free fall of product during loading.  (2)  Subsurface Loading - product delivered to bottom
 of compartment without splashing.  Direct bottom delivery or top loading thru long spout achieves this effect.
 (3)  To be calculated.

-------
DURING  SPLASH LOADING CAM
         EVAPORATION LOSS BY
     OP rHR£E FOLD
l/APOR.
                             6    789

                              (TVP)iPS/A
 Figure 39.  Loading losses for tank trucks.
                  125

-------
    0. 10
Tl
ri
    0.08
"o   0.06
W
CO
O
c
o
.^H
-1-1
ri

O
    0.04
S*  0.02
W
          0        2       4        6        8       10
                  True Vapor Pressure (TVP) psia
      Figure 40.  Loss from loading tankers and barges.
                                 \26

-------
sources; from the treating unit where the sour gases produced in the


refinery are treated for the removal of sulfur and from the gas


purchased outside.


       A diagram of such a system is presented in Figure 41.  A knock-


out drum is provided to collect any liquid that may condense from the


gas stream and to provide minimal storage for averaging high and low


demands by the refinery.   The fuel gas  produced by the refinery flows


into the system on a back-pressure control from the higher pressure


level in the treating unit.  When the demand exceeds the supply of gas


produced within the refinery,  the pressure in the knockout drum de-

                                         «
clines and purchased gas is allowed into the system. When the supply


of refinery gas exceeds the demand of the refinery,  the excess gas is


flared.   The system in general is well contained, with minimum emis-


sion sources.   However, fuel gas produced in the  refinery should be


checked  to see that it is free of sulfur compounds  (point 1 in the figure)


and any excess gas should be flared (point 2).



Y.     STEAM GENERATION


       Steam  is used as a heating medium in various refinery opera-


tions and as a process fluid in others suchas  hydrogen production and


steam stripping.


       Plant steam systems are normally closed cycles in which the

steam generated yields  its heat to process streams in heat exchangers


by condensation.   The condensate is returned to the steam generators


                                 127

-------
00
                                   Figure 41.  Refinery fuel gas system.

-------
to be vaporized again.  A relatively small make-up water stream is





required to  replace losses and blowdown from the system.  The  pro-





cess flow sheet is shown on Figure 42.





       Utility water is  normally used as make-up water to the system.




This water is  treated by either softening or  deionization. Air dissolved





in the treated  water  is removed by steam stripping in the deaerator





after which  it  is mixed  with the recycle condensate.  The water is





pumped from the deaerator to the steam drum for conversion into





steam.





       The  boiler may  be fired by either fuel gas, fuel oil,  or coal.





Whichever fuel is used, the stack gases may be a source of atmo-





spheric pollutants (point 1  in the figure).  The deaerator vent could




emit pollutants to the atmosphere if there is leakage of hydrocarbons





from the process side into the steam side of a heat exchanger.  This





stream (point  2) should be  checked regularly for  hydrocarbon contami-





nation.







Z.     COOLING TOWER





       Water  is used as the medium for removing heat from various




refinery streams.  Plant cooling water systems are normally closed





cycle (see Figure 43).  Water from the cooling tower picks up heat





from process  heat exchangers and is returned to  the cooling tower.





The heated water flows to the top of a tower, which is open to the atmo-





sphere, and is allowed to flow down the tower over packing. Atmospheric






                                 129

-------
                                           pH^SRH Alt-
                                            is),
Figure 42.  Steam generation.

-------
n
          a
         w»—
8
 ^
                                 r~*T»
                                                  UTILITY
                                                                                   ACID
»       f
                                          •—   (PI
                          Figure 43.  Cooling tower.

-------
air is either forced or flows by natural convection up the tower and the





water is cooled by partial vaporization into the air flow.   The cooled




water is collected in the cooling tower basin prior to being pumped





back to the  process users.  Utility water is added as make-up to the





basin to replace water lost by evaporation in the tower, entrainment,




and to blowdown.  Chemicals, such as  sulfuric acid, are added to





maintain water quality.





        The cooling tower (point 1 in the figure) could be the source of





atmospheric pollutants if there is leakage of either hydrocarbons or





other pollutants from the process side  into the water  side of a heat





exchanger.   Evaporation and entrainment losses can result in the





release of significant quantities of pollutants into the  atmosphere.  A





periodic check of the cooling tower basin for odor and visual surface





contamination would indicate the presence of this type of leak.







AA.    ELECTRIC POWER GENERATION




        Each operation and process in an integrated refinery adds to the





overall power requirement of the refinery.  Requirements of the indi-





vidual processes can vary from 0. 3 to  5. 0 kw of electrical power per





daily barrel of throughput.  Maintenance of adequate and reliable sup-





plies of electrical power is a major concern.





        Most refineries now use purchased electric power for normal





operation.  Commercial sources of power are reliable and power can





be obtained at a reasonable cost.  Refineries,  however, frequently have







                                  132

-------
emergency shutdown procedures that must be followed to prevent a





major loss of product or damage to equipment in the event of a local





power failure.  Some pumps or blowers must continue to operate, and





some instruments and alarms must be available to warn if a hazard




exists.  Normally, a refinery will have an emergency power generation




system to meet this need.   Emergency power generation equipment





may be driven  by  steam turbine or by gasoline or diesel engine.





       Remotely located refineries may not have access to a commer-





cial source of power and may,  therefore, generate their own power.





The motive source to drive the main refinery generators may be a





steam or gas turbine or a gas engine.  The air pollution resulting from





operation of gas turbines or gas engines is  usually not excessive if low





sulfur fuel gas is used.  The air pollution characteristics of steam





boilers are the same as those of other fired heaters (see Chapter II,




Refinery Equipment).







BB.   CATALYST REGENERATION





       The catalyst in most of the refinery catalytic processes needs





to be regenerated  periodically.  Whenever hydrocarbon feed stock is





cracked, reformed, isomerized,  or hydrotreated,  some coke deposit




will be formed on  the catalyst and thus deactivate the catalyst.  In most





cases as soon as the catalyst gets partially deactivated, the yields




decline and higher cracking or reforming severity is  needed to achieve




the desirable product characteristics.  Higher severity in  most cases







                                 133

-------
means higher operating pressure and temperature which in turn de-





posits more coke on the catalyst.  So at some point, the process has to





stop and the catalyst has  to be rejuvenated.   The frequency of catalyst





regeneration will depend upon the type of process,  the feed stock and





the severity of the  operation.  Regeneration frequency can vary be-





tween once every two or  three years to once  a week.  In some pro-





cesses,  the catalyst bed  may be removed,  replaced with freshcatalyst





and the deactivated bed shipped to be regenerated elsewhere.  Most




catalysts,  however, are  regenerated in place either continuously or





periodically.   For  continuous  catalyst regeneration, see the process




description of catalytic cracking, especially  fluid catalytic cracking.





        Periodic in situ catalyst regeneration procedures  are similar





for most processing units.  The only way coke can be removed without




disturbing the catalyst bed is by burning it with air. Some processes





may use steam and air to burn the coke while others can use inert gas




(mainly nitrogen) and air when the catalyst is sensitive to  water.  The





decoking operation will normally proceed as  follows:





        1.      Purge and depressurize the reactor.





        2.      Inert gas or steam circulation.





        3.      Coke burning.




        4,      Inert gas and combustion products purge.





        5.      Gas purge and repressure.




        The initial step is to cut off the feed to  the reactor and purge





the unit  into the relief header  and to the flare.   At  this  stage, steam or





                                  134

-------
inert gas  (less than 0. 1% O2) may be added to the system and the purge





will continue until all the volatile combustible materials are out of the





system.   Pockets of combustible material in the system could cause an





explosion during the coke burning step.  When the gas purge is clear of





hydrocarbons or other combustible gases,  the inert gas or steam is





recirculated through a compressor and a heater to bring up the temper-





ature of the catalyst bed to the coke ignition level.  Some of the coke




will break loose at this stage and flow out of the system with some





catalyst dust.  Both coke and dust have to be removed,  for instance, by





wet scrubbing.  Also,  if steam is used,  some CO2, CO  and H2 will be





formed and some of the circulating gas needs to be continuously purged.





At the preset temperature (500-700 °F) air is allowed into the  circu-




lating inert stream,  and the coke burn begins.  Excess  gases  are con-




tinuously  purged,  and coke particles and dust are  scrubbed out of the





recirculatmg stream.   The circulating gas temperature is allowed to





go to about l,000°Fby regulating the  amount of  air allowed into the





system.   The "hot spot" where the coke burns slowly proceeds down





the catalyst bed until all the coke deposit is consumed.  At this point,





the circulating gas is purged to  the flare with fresh inert gas.  This





purge continues until the oxygen  level in the system is reduced and the




ash and dust are removed.  The  inert gas is then circulated to reheat





the system to operating temperature and feed is introduced while the




inert gas  is purged to the flare.
                                 135

-------
       Gaseous air pollutants are formed throughout the regeneration





operation by the reaction of steam air and coke,  and mechanical action





forms dust.  If sulfur is present in the coke,  SO2 will be formed as a




part of the coke combustion products.   Coke dust,  ash,  and catalyst




dust also are present throughout this operation and have to be removed




before the combustion gases are discharged to the  atmosphere.  Wet




scrubbing of the purged gases with a caustic wash  may be used in some





cases to reduce the SO2 and the dust in the combustion gases.   How-




ever,  this scheme is not in general use and  cannot be used where





water is a catalyst poison.
                                 136

-------
                    II.   REFINERY EQUIPMENT







A.     INTRODUCTION




       In the same way that individual chemical processes have charac-




teristic kinds of pollutant  emission, the pieces of equipment used in




these processes have characteristic points of pollutant emission.




       This chapter contains a summary of the major types of process




equipment and their performance characteristics.  The internal mech-




anisms of each are illustrated. Emphasis is directed toward the mech-




anisms by which each item of equipment might release material .to the




atmosphere under normal and abnormal operating conditions.




       The objective of this chapter is to provide sufficient information




about process equipment  so that the  FEO will recognize the equipment,




understand its function, and be sufficiently knowledgeable regarding its




operation to decide whether the unit  is being operated properly.  If im-




proper operation is  evident, he should be able to recommend changes to




the system that would reduce pollutant emissions to the point where the




facility can comply with environmental pollution standards.






B.     PUMPS




       A  refinery uses many different types of pumps to move fluids.





                                 137

-------
Pumps vary in capacity up to  100, 000 gallons per minute and in pres-





sure differential up to 30, 000 pounds per square inch.  A pump is de-





signed to perform a specific function, and it is limited  to a rather




narrow range of operation above and below the design condition.  For





this reason, hundreds of pumps of different styles and modes of opera-




tion are used.   The types most often used in refineries fall into two




categories: centrifugal  and positive displacement devices.  Centrifugal





devices  are centrifugal, axial and turbine pumps.  Positive displace-





ment devices are reciprocating piston, plunger, diaphragm, rotary





vane, and gear pumps.  Other specialty pumps are available for unusual




applications,  but this list covers the types that will be encountered most




often..





1.      Centrifugal Devices





        a.      Centrifugal Pumps   A centrifugal pump consists of a





        rotating element,  called an impeller, and a casing which sur-





        rounds the impeller.  Liquid enters the pump and flows to the




        eye of the impeller.  As the impeller rotates, it throws the





        liquid outward by centrifugal force.  The casing  collects the




        liquid that is discharged from the impeller converting a part  of




       the  kinetic energy in the liquid into fluid pressure.   The centri-





       fugal pump is a  flow device which continuously imparts energy





       to a flowing  fluid.   Figure 44 is a cutaway view  of a centrifugal





       pump.



               The amount of  energy imparted to the  fluid is a  function





       of the top  speed  of the pump impeller.   The discharge pressure





                                   138

-------
                          PUMP
u>
             rfcE.6.
                                            Figure 44.   Centrifugal pump.

-------
of the pump increases with the diameter of the impeller and




the speed of the pump.  Low-pressure electrical pumps nor-





mally operate at 1, 750 rpm,  and higher head pumps will rotate





at ?, 500 rpm.   Even higher pressures are available if a tur-





bine drive is used to increase the impeller speed.  Many differ-





ent types of centrifugal pumps are used in the refinery. Figure




44 is typical of a single-stage,  horizontal centrifugal  pump.




Where a high head is  required, multiple impellers can be





mounted on the same  shaft as shown in Figure 45.  The same




type of pump is sometimes mounted in a vertical position to





conserve space.




        Figure 46 shows a sealed rotor, or canned motor,




single-stage pump in  which the rotor is exposed to the process





liquid.   The pump motor case is  fully enclosed and therefore




no seals are required for the pump.  This pump is frequently




used where the fluid pumped is particularly  corrosive or toxic.





        The centrifugal pump is a variable capacity pump.  The





liquid  capacity of the  pump can be regulated by adjustment of a





valve on the discharge of the pump liquid. Closing the valve




increases the head that  the pump must provide, and the liquid




capacity of the pump  is  reduced to  meet the  new requirement.




As the valve is closed,  the horsepower  requirement of the




pump is minimized.   However,  if the  flow of fluid is stopped,





the fluid in the pump will overheat  and the pump could be





damaged.





                           140

-------
Figure 45.  Multiple stage centrifugal pump.

-------
Figure 46.  Canned motor pump.
              142

-------
       The centrifugal pump shown in Figure 47 has three





points where leakage might be expected to occur:  at the inlet





flange (point 1  in the figure), at the outlet flange (point 2), and





at the shaft seal (point 3).  If the  system is  properly constructed,




the flanges will not leak and the principal spot where leakage





will occur is at the shaft seal.  The shaft seal may be a simple





packed stuffing box which must be replaced  periodically when





leakage becomes excessive, or it may be a  mechanical seal




(see Figure 48).  Mechanical seals work very satisfactorily and





allow only minimum leakage with clean fluids, but deteriorate





rapidly if the fluid contains abrasive particles.





       Pump leakage is readily visible if the  products do not





vaporize.  Where the liquid pumped has a high vapor pressure,





vaporization will occur as soon as the product is released.





Evidence of leakage may appear as an accumulation of conden-





sate or frost around the point of leakage.





b.     Axial Pumps - The axial pump uses  both mechanical





impulse and centrifugal force to pump large quantities of fluid




where the head requirements are  low. Figure 49 shows a sec-





tion of a  typical axial pump.  The rotating element  is a pro-





pellor, which is sometimes followed by stator blades to assist





in recovery of the fluid energy.





       Axial pumps are normally used for recirculation of





fluids where the head requirement is  low.  One application  is






                          143

-------
               (OUTLET)
( INJLET)
                Figure 47.  Close-coupled pump.
                          1 A A

-------
Stationary
Seal Ring
                                       Rotating Seal Ring
Static Seals
                                           Shaft
  Shaft
                     Internal Mechanical Seal
                                            Packing
                           Packed Seal
                           Figure 48.  Seals
                                    145

-------
      Pi 5CMA£.<££.
                                    /NJJ-B.T
Figure 49. Axial flow propeller pump.
             (elbow type)
                  146

-------
       in the circulation of large tanks of stocks such as gasoline.





       Side-entering mixers which are a type of axial pump are fre-




       quently used to obtain uniform blends of mixed stocks.  If the





       discharge of an axial pump  is throttled, the horsepower in-





       creases and the pump efficiency decreases.  Normally these




       pumps are operated for maximum capacity with minimum





       regulation.





               Hydrocarbon emission from axial pumps can occur at





       the. points where the pump is  connected into the  system (point 1





       in the figure) and at the shaft seal (point  2).  Leakage at the





       shaft seal is most common.   The discussion of the problem





       under the heading  Centrifugal Pumps is also applicable here.





       c.      Turbine Pumps  -  Turbine pumps  combine the character-





       istics of centrifugal and axial pumps.  The impeller of a. turbine




       pump,  as shown in Figure 50, causes the liquid to move axially




       and radially as it passes  the impeller.   These pumps may have





       several stages in series  and are frequently mounted vertically.





       They are often immersed in fluid to  be pumped  - for  example,





       when they are xised in wells.





2.     Positive Displacement Devices




       There  are many pumps that move liquids by mechanical dis-





placement of the liquid from a  fixed chamber.   These pumps are





usually low-volume, high-differential pressure pumps.  The capacity





of the pump may be variable but  is limited by  the mechanical volumetric





                                 147

-------
Figure 50.  Vertical turbine pump.
                148

-------
displacement of the pump.




       A positive displacement pump produces a discharge pressure




that meets the head requirements of the system.  The maximum head




obtainable with the pump is fixed by the power limitations of the drive




mechanism and  it is not possible to throttle the discharge of the pump




to adjust the fluid capacity.  Instead, the rate of displacement of the




pump must be adjusted.




       a.     Reciprocating Pistoji Pumps - The reciprocating piston




       pump is  one of the oldest types  of pumps in refinery service.




       Figure 51 shows a motor-driven piston pump which could be




       used to pump fluids in a high-pressure process system.




              Each displacement stroke of a piston pump produces  a




       flow pulsation.  Some pumps are double acting, i. e., each




       movement of the piston causes fluid displacement to produce a




       more continuous flow.  To smooth the flow even more,  two  or




       more pistons may be coordinated so that the flow pulsations




       are alternated.  By these measures, the flow pulsations can be




       minimized until the flow is  essentially continuous.  Piston




       pumps are most susceptible to leakage through the packing on




       the pump shaft. This packing must slide along the  shaft for  the




       full stroke of the pump and is continuously subject to wear.   To




       prevent excessive leakage,  this packing should be regularly




       adjusted and maintained.
                                149

-------
Figure 51.  Reciprocating piston pump.
             (double acting)

-------
       Piston pumps have check valves on the suction and dis-





charge sides of each cylinder.  These valves are subject to




wear and must be serviced periodically.  The valves are im-





mersed in the fluid that is pumped and, to service the valves,





this  fluid must be removed.  Removing it can release a signifi-





cant amount of hydrocarbon to the atmosphere.





b.     Plunger Pumps -   Plunger pumps are similar to piston





pumps in function, but instead of a piston they use a plunger





which moves in and out of a fluid-filled chamber.  A packed





seal is used to prevent leakage around  the plunger. The plunger




punp is prone to leak through the packed seal in the same way





that  a piston pump leaks  around the  pump shaft.   The valves of




this  type of pump must also be maintained regularly, and this





operation could result in air pollution if not  carefully performed.





c.     Diaphragm Pumps  -  A diaphragm pump uses the move-





ment of a flexible diaphragm to displace the fluid that is being





pumped.   Check valves on the  inlet  and outlet of the pump pre-




vent the liquid from flowing backward.  A typical diaphragm




pump is illustrated in Figure 52.





       The use of a diaphragm eliminates the need for a shaft





or plunger packing to contain the fluid being pumped.  However,





the diaphragm itself is subject to  failure and must be watched





carefully.  A leak in the pump diaphragm would allow the pro-





cess fluid to escape to the atmosphere  through the mechanism





                          151

-------
Figure 52.  Diaphragm purnp.
             153

-------
that is used to move the diaphragm.





d.      Rotary Vane Pumps  -   Rotary vane pumps  are frequently




used at moderate pressures and temperatures  to pump fluids.





Figure 53 shows a cutaway drawing of a typical rotary vane





pump.  As the rotor turns counterclockwise, liquid is carried





from left to right by the vanes which slide in and out of the





.slots in the rotor to maintain constant contact with the wall.




The cylinder space is circular  but it is offset from the axis of





the rotor. Each revolution  of the rotor moves a positive volume





of liquid through the pump.  The flow through the pump is non-





pulsating, and the  pump can handle fluids and gas without devel-




oping a vapor lock.




        The shaft of this type of pump is the principal point of





external leakage.   However, effective shaft seals are available




so that, with a well maintained pump,  leakage  should not be a




problem.





e.      Rotary Gear Pumps  - Rotary gear pumps are used for





low-head, low-capacity services with clean fluids.   Figure 54 is




a cutaway section of a dual-shaft, two-gear pump.   As this




pump rotates,  the  gear teeth carry fluid from one side of the




pump to the other.  The meshing teeth prevent the  liquid  from




flowing backward.





        The principal point of leakage with a gear occurs  where





the shafts penetrate the pump case. With a regular maintenance





program,  leakage at this point  should be negligible.




                          153

-------
Figure 53.  Rotary vane pump.
               154

-------
Figure 54. Rotary gear pump.
              (two-impeller)
            155

-------
G.     COMPRESSORS





       Mechanical devices used to compress gases also fall into posi-




tive-displacement and centrifugal categories.  Positive-displacement




category includes piston,  rotary-vane, and rotation-lobe compressors.




The centrifugal category includes centrifugal and axial  compressors.




       The mechanism, used to drive the compressors, can sometimes




become a secondary source  bf air pollution.  Therefore the type of




drive used with each compressor is also discussed briefly.




       In addition to these devices, there are a number of hydraulic




systems for compressing gas,  but they are seldom found in refinery




service and, therefore, are not discussed.




       A unique type of gas-compression device which  is described is




the jet ejector,  a simple device that uses the dynamic energy of one




fluid to compress another.




1.     Positive-Pis placement Compressors




       a.      Reciprocating Piston Comprejsors   The reciprocating




       piston compressor is the most common type of gas compression




       device in use.   It is used for pressure differentials from five to




       several thousand psi and for capacities from a fraction of a




       cubic feet per minute (cfm) up to  the maximum capacity of a




       system.  In refineries,  reciprocating piston compressors are




       likely to be found in  service compressing natural gas,  hydrogen,




       or liquified petroleum gas (propane and butane).
                                  156

-------
       Where pressure differentials are high,  several stages of




compression may be required to achieve a desired processing




pressure.  For high capacity gas compression requirements,




several cylinders can be designed to operate in parallel.  In




many instances,  a single multicylinder compressor may be used




to compress  two  or more stages of several different gases.




       For high-pressure systems most pistons are single-




acting, two-stage devices as shown in Figure 55.  At low pres-




sure, the usual practice is to use double-acting pistons with a




packed seal on each end of the piston rod.  The cylinder is often




supported by a sleeve or distance-piece and the crankcase is a




second low-pressure packing designed to prevent loss of crank-




case oil.  Any gas which escapes from the cylinder  is vented




into the distance-piece, and in  some cases, where the gas being




compressed is toxic or flammable, the distance-piece is  en-




closed and a  pressure  vent to the flare is  provided.




       Large reciprocating  gas compressors may be driven by




electric motor or by gas or  diesel-powered engine.  Where a




reciprocating combustion device is used to drive  the compressor,




the device could become a major source of pollution.  The




exhaust gas from such engines  should be monitored  as a part of




the complete  refinery inspection.




b.     Rotary Lobe Blowers -  Rotary lobe blowers  are used for




high  capacity, low-differential  pressure systems.  A section of




                         157

-------
                          «  /VAU/es
Figure 55.  Reciprocating compressor.
               (2-stage)
               158

-------
       such a blower is shown in Figure 56.  Leakage occurs primarily




       at points where the shafts come through the case.




       c.     Rotary Sliding Vane Compressors - The  rotary sliding




       vane compressor operates at relatively low pressures and capa-




       cities.  As shown in Figure 57,  a single rotor with sliding vanes




       turns in an eccentric cylinder, compressing the  gas as it moves




       through the unit.  As with the  rotary lob£ blower, leakage occurs




       primarily where the shaft comes through the case of the blower.




2.     Centrifugal and^ Axial Compressors




       Centrifugal and axial compressors may be used in various pro-




cesses in the refinery.  The centrifugal compressor is effective in




compressing the relatively high molecular weight hydrocarbon gases.




It is frequently used to compress the  mixed gases from  a catalytic




cracking unit.




       Axial compressors are suitable for high-capacity gas  require-




ments, but they are  not as versatile as the centrifugal compressor and




have not been used extensively in refineries.




       Figure 58 shows a centrifugal compressor shaft  with a labyrinth




seal used to prevent loss of gas.  The seal consists of a number of re-




strictions and openings through which the escaping gas must flow.  If




this seal is not properly maintained,  it can be a major source of loss of




the process fluid.  The labyrinth seal is normally vented at some mid-




point and bled back to a lower pressure stage or to the compressor
                                159

-------
Figure 56.  Rotary lobe blower.
             (two impeller)
                160

-------
Figure 57.
Rotary compressor.
  (sliding vane)
 161

-------
Figure 58.  Labyrinth seal.
             162

-------
suction.  When loss of gas must be restricted, an inert gas or liquid





can be injected into the seal at the midpoint of the labyrinth.




       Centrifugal and axial compressors may be driven by an electric




motor, a steam turbine, or a gas turbine.  If a gas turbine is used, it




could be a secondary source of pollution and, therefore,  the exhaust




gas from the turbine should be monitored.







D.     HEAT EXCHANGERS




       The  exchanging of heat between refinery fluids is  one of the




methods by  which heat is  added or removed from refinery streams.




       There are two  types of mechanisms for effecting this exchange:




the direct and indirect heat exchangers.




1.     Direct_He_at Exchangers




       The  single most important direct heat exchanger  is the baro-




metric condenser (Figure  59) used mainly for the condensation of steam




in vacuum systems.   Heat is exchanged by contacting the incoming




steam directly with cooling water.   The steam condenses and is pumped




out of the system with the  coolant.   Noncondensables in this system are




removed with a steam jet  or a compressor.




       Any  pollutants  in the steam will be distributed between the con-




densed steam and the noncondensables based on the degree of their solu-




bility in water (point  1  in  the figure).  In most cases, however, the




steam is relatively free of pollutants.




2.     Indirect Heat Exchangers




       Indirect heat exchangers  are more common. In these units, the




                                 163

-------
                     WATER.    STEAM
            STEAM
 SUCTION
HOT  WELL
NONCONDEN^/ABLES
FUME   INCINERATOR
                                                       TO
                              CONDENSER   TAIL  PIPE
             figure 59.  Barometric condenser.
                            164

-------
two fluids exchange heat through a surface plate or a tube that separates





them.  This group of exchangers includes: the shell and tube,  the





double pipe,  and the air-cooled.





       Shell and rube heat exchangers (Figure 60) consist of a tubular





shell 12 to 40 inches in diameter and 10 to 24 feet long with 3/4 or





1-inch in diameter tubes inside.  One fluid thus  flows in the  shell and





the other through the tubes.





       A double-pipe exchanger (Figure 61) consists of two concentric





pipes, one inside the other.  The outer pipe may be 2 to 3 inches in





diameter.  The inner pipe is usually about 1  inch in diameter.   The two





fluids flow countercurrently through the two pipes, exchanging heat





through the walls of the pipes.





       Air-cooled heat exchanger  (Figure 62) uses ambient air as  the





cooling medium.  The fluid to be cooled passes through the  inside of




the tubes and  a fan induces or forces a flow  of air to the outside sur-





faces of the tubes.  The fluid is cooled by transferring some of its heat





through the walls of the tubes to the air.   These units are relatively





large, varying between 10 and  20 feet wide and 10 to 40 feet long.  Often





these units are stacked on top of and along the pipeway in the refinery.





       Miscellaneous  exchangers include  plate coils, steam coils,  tank





heaters,  and box coolers.   Most of these exchangers are in steam heat-





ing,  water cooling, or emergency services and are of little importance




from the pollulant emission standpoint.
                                165

-------
OUfLfc-T
   Figure 60.  Shell and tube heat exchanger.

-------
cr-
-vl
                                            x^*=
                                                                             t
                                                                             t
                         Figure 61.  Double-pipe heat exchanger with longitudinal fins.

-------
AXIAL
(2.1 U<£
                 Figure 62.  Air-cooled heat exchanger.
                                 168

-------
       Heat exchangers normally do not emit pollutants.   However,
because  of the corrosion of the tubes or leakage between the shell and
the tubes,  it is possible to contaminate the lower pressure fluid with

the higher pressure fluid.  When the lower pressure fluid  is cooling
water, the hydrocarbon contamination  will be released in the cooling
tower  (see Section Z,  Cooling Water System in Chapter I).  If steam
condensate gets contaminated with hydrocarbons,  these contaminants
will be released to the atmosphere with the noncondensables in the
deaerator.  By checking the composition of the effluent gas leaving  the
deaerator  and the vapor leaving the cooling tower,  leakage into the
steam and cooling exchange  systems can be detected.   In some cases,

leakage to the cooling water system can be detected by observing an oil
film on the water in the cooling-tower  basin.

E.     FURNACES
       Furnaces are used for heating  refinery fluids.  These units  are
also known as "fired heaters",  "tube stills",  or "pipe stills".   In
general,  refinery proces s streams are heated by exchanging heat with
other hot streams up to 400°F.  When  a process  requires  a higher
temperature level or when other hot  streams  are not available,  the
direct-fired furnace will be  used.
       Refinery furnaces have  many shapes and forms and varying
firing and tube arrang ements.  Two of the more common units,  the
vertical  cylinder and thr horizontal box are illustrated in Figures 63
and 64.
                                 169

-------
               x\
Figure 63.  Vertical cylindrical furnace.
                    170

-------
Figure 64.  Horizontal box type fired heater.
                     171

-------
        Most furnaces have two main sections: the convection section





and the radiant section.





        In the convection section, heat is exchanged between the hot




combustion gases on the outside of the convection tubes and the process




stream inside the tubes.  Often additional tubes will be added in this





section of the heater for superheating  steam.  The recovery  of heat in





this section greatly influences  the total heater efficiency and reduces





the stack flue-gas temperature.  Flue gas temperatures in the stack





vary between 500-700° F in an  efficient heater and 900-1300°F in an





inefficient furnace with reasonable amounts of excess air.





        In the radiant section, heat is transferred to the tubes mainly by





radiation.  The refractory walls of the heater get red hot and emit heat.




The tubes absorb this heat and transfer it to the process streams inside.




The temperature of the walls in this section will vary from 1000 to 2000°F.





        Fuel is  delivered to the furnace through the burners.  The





•function of the burners  is to  mix the fuel and the air, maintain  a  flame





of  proper shape,  size,  and stability,  and ensure complete  combustion.





There are some 20 basic burner designs and many variations of each





basic design.




        A typical gas burner  is shown in Figure 65. Natural  gas  or




refinery gas is delivered to the burner at 3 to 20 psig.   The fuel  gas is





mixed with the  primary air,  and the mixture is injected into  the fire





box of the furnace; the secondary air is drafted or forced through the





air registers into the fire box  where the combustion takes place.  The





                                   172

-------
AlR.
           Figure 65.  Gas burner.
                        173

-------
fire box is maintained at a. low vacuum (up to 0. 5 inches of water) and




thus any flow of air is inward with little danger of the flame burning




outside the firebox.





        When heavy fuel oil is used for firing the furnace,  the oil must




be atomized,  either by mechanical means or by steam.  The combina-





tion oil-gas burner shown in  Figure  66 is a steam-atomized fuel oil




burner.   The steam and fuel  oil are  fed simultaneously to  the oil gun at





about 100 psig.   They form an emulsion like mixture in the oil gun,  mix




with the primary air, and are injected into  the fire box much like the




mixture in the natural gas burner.





        The combustion product  leaves the furnace through the stack.




Stacks are designed to induce draft (low-level  vacuum) in  the fire box,





dispose of the hot gases high enough above ground so that  the fire dan-




ger is minimized,  and reduce the ground-level concentrations of the




combustion products.  Both the  burners  and the stack create noise and





may require mufflers.





        Coke will deposit on the  inside of the tubes when the furnace





processes hydrocarbons.  These deposits may be removed from the





tubes either by mechanical cleaning  (turbining) or by steam air de-





coking.  The steam air  decoking process is divided into two portions.





First the tubes are heated by partial firing  of the  furnace  to about 300°F




and steam is allowed to flow  through the tubes. The external heating of




the tubes  produces shrinking and cracking of the coke (spalling) inside





the tubes  and the steam blows the loose coke out of the tube.





                                  174

-------
                                  TILE
Figure 66.  Combination gas and oil burner.
                     175

-------
       Some of the steam will react with the coke to form CO2,  CO,




and H2.  Coke particles,  steam, and gases come out of the tube and





into a concrete pit or drum; the decoking  effluent is then  cooled with




water.  All of the gases and most of the steam with some coke particles





are discharged from the decoking drum into the  atmosphere.  When the





spalling  stops, compressed air is  slowly added to the steam,  and the




coke deposits inside the tube start burning.   The reaction of coke and





oxygen produce CO2 and CO.  At this point,  if any sulfur is  present in





the coke, SO2 is formed.  Current practice  is to discharge the decoking





effluents into the atmosphere.  This may not be  a severe  problem if the





furnace has to be  decoked infrequently. Otherwise,  flaring the effluents,




or incineration of the gases in another furnace,  may be required.




       The emission of pollutants  from furnaces is dependent on the




fuel used for firing, the proper operation of the  furnace, and - to a





lesser degree -the design of the fire box and burners.  Natural gas or





refinery gas is the least polluting fuel if it is properly treated  for the




removal of all the sulfur components.  All of the sulfur in the fuel  oil




or the fuel gas will be converted to SO2 or SO3 in the process of com-





bustion.





       Noncombustible residue in  fuel oil,  such as  ash and  metals, will





be discharged into the atmosphere as  soot and ash.   Improper  atomiza-





tion of the fuel oil in the  burner will produce unburned  carbon  in the





flue gas.  Refinery furnaces, in general,  operate with high  excess  air
                                  176

-------
(15-25% excess air when gas fired  and 30-50% excess air when oil fired).





High excess air produces complete burning, reduces flame temperature,





and minimizes the amount of carbon monoxide in the flue gas.  However,





high excess air reduces furnace efficiency.  NOX compounds are pro-





duced in the furnace from both the  nitrogen in the air and the nitrogen





compounds in the fuel.  Only a very small portion of "the nitrogen in air





is reacted, while the generally accepted opinion la that most of the fuel





nitrogen is converted to NO .  Recent research on the formation of NOX





compounds, in furnaces  indicates that a reduced flame temperature can





reduce the rate of formation of NO .   Redesign of burners and fire





boxes may be required  in the future to reduce the flame temperature





and with it the formation of NOX.








F.     JET EJECTORS





       A jet  ejector is  a gas compressor that vises the  dynamic energy





of one fluid to compress another.   The unit shown in Figure 67 consists





of a nozzle, a vacuum chamber, and  a diffuser tube.  A high-pressxire





gas (normally steam) is expanded in the nozzle.   It passes through the





vacuum chamber  at high velocity,  entraining  the surrounding vapor.





The mixed pases  then enter the diffuser where the kinetic energy in the





gas is recovered  as  the gas decelerates,  leaving the ejector at a pres-





sure significantly higher than the pressure in the vacuum chamber.





       A jet  ejector can be used to move large amounts of gas from a





low-pressure system to a higher pressure with a very low investment






                                177

-------
Figure 67.  Steam jet ejector.
              178

-------
in equipment.  Consequently, ejectors  are widely used in refineries in





such services as tank evacuation, batch distillation, drying,  and re-





moval of inert gases  from condensing operations.




       The effluent gas from a steam-jet  ejector consists  of a mixture





of process gas  and steam.  Frequently, these gases are discharged





directly to the atmosphere (point 1 in the figure).  If these gases con-





tain significant amounts of hydrocarbon or sulfurous gases, this dis-





charge could amount  to significant pollutant  emissions.





       In many systems,  the discharge from the jet ejector is cooled





to condense the steam. The  condensate removes some of the hydrocar-




bons and some  of the acid gases such as H2S.  The  condensate  should be




checked for sulfides and hydrocarbons  and routed to the appropriate





treating facility if they arc present.  The  efflxient gas from such a con-





denser should consist primarily of inert gases,  but the  vent gas  should





be analyzed to assure that the gases  are being effectively scrubbed.





       To obtain a high vacuum,  two (or more) electors are  sometimes





connected in series.  In some cases, an interstage condenser may be





used to reduce  the volume of gas to the second-stage ejector.  The inter'




stage condenser will  operate at a reduced pressure and, therefore, will





not be effective in absorbing acid gases and  light hydrocarbons.  Where




these materials are present  in the process gas,  a  condenser on the




effluent of the second-stage  ejector would be beneficial  in  reducing





pollutant emission.
                                179

-------
G.     PIPE VALVES AND FITTINGS


1.     Pipe


       The pipe used in refineries in hydrocarbon service is primar-


ily carbon and alloy steel.  Carbon steel is used in ambient to moder-


ate temperature service, and alloy steel is used in high-temperature


service.  In general  practice, threaded connections are used for the


smaller sizes  (1-1/2 inches and under) and flanged connections are


used for piping that is 2 inches and larger.  Wherever possible,


welded joints are used to connect  sections of pipe to minimize leakage.


       Specifications for pipe and fittings  for refinery service are nor-


mally  very conservative.  It  is reasonable to assume  that if the pipe is


in good condition,  it  will perform satisfactorily and will not contribute

                                       o
to atmospheric pollution.  However, if the piping is allowed to  corrode


on either the interior or e.xterior  surface, a significant  reduction of


wall thickness can occur with resultant leakage of the process fluid.


       Threaded connections, when first assembled,  can be made leak


tight.  However,  if a threaded connection is assembled and disassem-


bled many times, the threads become  deformed and leakage becomes


a probability.


       Piping  that is designed to hold  very hot or very cold fluids must


be  capable of expansion or  contraction.  In some cases an expansion


joint is installed in the line,  but in most cases the line is designed with


sufficient flexibility to absorb the  change in  length. Such lines  are  in-


clined  to leak either at the  expansion joint or at a terminal point in the


line that is highly stressed by the  pipe expansion.


                                  180

-------
2.     Valves




       A  refinery uses many types of valves.   Gate or ball valves are





used where complete shutoff is  required.  Globe or plug valves are





used where the valve is used  for throttling or process control.  Check




valves are used in a flow line to prevent backflow.  Control valves are




used to regulate process  flow.




       All of these valves tend  to leak through  the  valve seat when





handling low viscosity fluids and/or when  the pressure differential





across the valve is large.  Where a single valve is used to separate a





material that is considered a pollutant from the environment, the outlet





of the valve should be closed  with a blind flange,  a blind, or a plug, to





assure that the material does not escape.




       The second major source of valve  leakage is the  packing that is





used to .seal  I ho valve stem.  This packed joint must  slide along the




valve stem as the valve is opened and closed.   A regular program of





inspection should be scheduled to ensure that valve stem packings are





properly maintained to prevent  leakage to the atmosphere.





3.     Flanges





       Flanges  provide a removable connection between pipe and ves-




sels or other items of equipment.  Flanges are specified by pres sure




rating  and by facing.   Pressure  ratings used are:   150,  300, 400,  600,





900, 1500, and 2500 psi.   The most common flange facings, shown in





Figure 68, are flat face,  raised face,  tongue and groove,  and ring





joint.  It is important that two opposing flanges have  the same rating





                                 181

-------
00
                         Kg
  m
                                   /)
m
                                                        MALE.
                                                      PLAT
                               Figure 68. Flanges.

-------
and facing.  If mismatched flanges are connected together, there is a





good possibility that the joint will warp and leak.





4.     Vents  and Drains





       Most process piping is installed with vents on the high points of





the lines and with drains at the low points of the line.  These connec-




tions  facilitate startup and shutdown procedures.   They also constitute





a prime candidate for leakage  of the process fluid.   Vent and drain con-




nections on lines containing volatile hydrocarbons should be closed and





sealed with a  pipe plug  or blind flange to  assure that no leakage will





occur at those points.





       Many vessels containing hydrocarbons  are equipped with manual





drain valves which can  be used to separate water from the hydrocarbon





that is in the vessel.  In this operation,  an operator is supposed to





visually observe when the water flow stops and the hydrocarbon flow




starts.  At this  time  the valve should be  shut to minimize loss of hydro-





carbon.  Unfortunately,  such manual separation operations are fre-





quently left unattended,  with the result that large quantities of hydro-




carbon are dispersed into the environment.







H.     PRESSURE-RELIEF DEVICES




       All vessels,  tanks, heat exchangers, and other equipment





capable of being pressurized should be equipped with pressure-relief





devices that will protect them  from too much pressure.  Many different





types of pressure-relief devices are used for this purpose.  The







                                 183

-------
principal types of relief devices that may be encountered in a refinery





are the spring-loaded relief valve,  the rupture disc, and the relief





hatch.  Each device has different operating characteristics and failure





modes.  Knowledge of these characteristics will permit the FEO to





determine if a given device is performing effectively.




        Relief devices may be installed for relief of gaseous or liquid




pressure.  The liquid relief devices are normally installed to relieve





thermal expansion and are less  inclined to leak than vapor relief





devices.  Vapor relief devices are emphasized in this discussion





because they are the primary source of pollutant emissions.




1.      Spring-Loaded Relief Valve^





        A typical spring-loaded  relief  valve is shown in  Figure 69.




Fluid pressure is maintained in the throat of the valve.   If the operating




pressure exceeds the valve set  pressure,  the valve will open and relieve





the system pressure.




        Relief valves may discharge into a closed flare system or di-





rectly to the atmosphere depending on local air pollution regulations.





If the discharge  from the  valve  goes to a flare system,  then leakage





through the valve does not constitute pollutant emission.  However,  if





the relief valve discharges to the atmosphere, significant amounts of





material could be dispersed.




        Relief valves, as delivered from the manufacturer,  arenormally





gas-tight.  However,  after the valve has  been actuated one or more





times,  it is possible that  the valve may leak.  In an effective refinery





                                   184

-------
Figure 69.  Relief valve.
                    185

-------
maintenance program,  all relief valves would be removed and checked




for performance and leakage at least once a year.





       Most relief valves achieve a seal by forcing a metal plate




against a metal seat.  These seats are durable but tend to leak.  A





more effective seal can be achieved by use of an "0" ring or plastic





seat where process conditions permit their use.





        Relief valves are normally set to activate at  a pressure that is





10% or 25 psi above the normal operating pressure of a vessel.   If the




operating pressure is too close to the set pressure,  the valve will tend





to lift off the seat during normal operating cycles with resultant dis-





charge of material through the valve and possible damage to the valve




seat.  The set pressure of each valve should be reviewed in relation to




the operating pressure of the system to assure that the two pressures




are separated sufficiently to prevent loss of material.




2.      Rupture Disc





        The rupture disc or  burst diaphragm is a metal diaphragm




which is designed to rupture at a predetermined pressure.   Figure  70





shows a typical rupture disc assembly.  The rupture disc is used to




protect systems which might experience a sudden pressure rise or





which must vent large quantities of gas in a short time.





        In  continuous processes, use of the rupture disc is limited be-




cause the  entire system must be depressurized to replace the disc.





Rxipture discs  are  usually used on batch systems which can be readily





shut down.





                                  186

-------
Figure 70.  Typical rupture disc installation.
                          187

-------
       Rupture discs can provide a vapor-tight seal when initially in-





stalled.  However, it is possible for the disc to develop a pinhole leak





due to atmospheric or internal corrosion.  If such a leak should develop,





significant amounts  of material could be lost before the leak is dis-




covered.





       The effluent from a rupture disc may be vented directly to the




atmosphere or it may be discharged into a flare system. Rupture





discs which discharge directly into the atmosphere should be checked





frequently for  leakage.





3.     Relief Hatch





       The relief hatch is designed to provide a large emergency relief





opening for handling large volumes of vapor at low pressure or in case




of internal explosion.  Figure 71 is a typical section of such a device.




       These relief devices normally discharge directly to the atmos-




phere.  If the device becomes warped or if the gasket surface deterio-





rates, significant quantities of material may escape to the  atmosphere.







I.     FLARES




       The primary purpose of a flare is the safe disposal of waste





gases by combustion.   Except during rare emergencies, it should be





possible to  accomplish the complete combustion of the waste gases





without producing smoke or noise.




       The flare shown in Figure  72 is representative of one of a num-





ber of acceptable designs.  It is an elevated flare with a smokeless tip.






                                  188

-------
                                VACUUM
Figure 71.  Pressure relief hatch.
                     189

-------
                                         PILOT BURNER
    FLARE   TIP
         STE/4M  LINE
P/L07





IGNITER
                                                          SUPPLY
L/N£
^3 f* ^J ^\ i M
^^ ^^ /\ ^x^^y















ELECTRIC
IC,MITtOM
SOX
T— G^IS
>« / a


X DPX\IN


                  Figure 72.  Elevated flare.
                                190

-------
The flare consists of a vertical pipe extending to an elevation suffi-




ciently higher than surrounding equipment and the ground so that the





heat given off by the flame will not harm personnel or equipment.  A





pilot burner and ignition  system is provided to insure that a flame  is





maintained during venting.  The flare burner tip is equipped with a





series of steam jets so placed that turbulence is produced in the flame,




which leads to  smokeless combustion. Smaller flares sometimes use





air provided by a blower in place of the steam,  but larger flares gen-





erally employ steam.  To conserve steam,  a control valve in the steam





line is activated by a flow sensor in the flare line.





       Another type of flare frequently encountered in refineries is the





burning pit.  They are generally reserved for very large  gas flows





during major emergencies and are connected to the blowdown system





through a deep liquid seal that only opens when the elevated flare is




overwhelmed.  A simple burning pit may consist of a circular area




enclosed by a wall, with  inward-facing burners piercing the wall at




intervals.





       For additional  information  refer to "Air Pollution  Engineering





Manual" (Second Edition), John A.  Daniels en, available from the





Government Printing Office as EP4. 9:40-2.







J.     KNOCKOUT DRUMS





       A knockout drum  is a device for separating entrained liquid




from a vapor stream.   The separation is  accomplished by increasing







                                 191

-------
the area of the cross section available to the flowing stream,  thus re-





ducing the flow velocity and allowing the entrained liquid droplets to





settle by gravity.   In some knockout drums,  the separation is improved





by adding a mist eliminator in the upper section of the drum just ahead




of the vapor outlet. The mist eliminator can take the form of a knitted





wire pad that  separates fine liquid droplets from the vapor by impinge-




ment.   Figure 73  is a sketch of a typical vertical knockout drum.




Horizontal knockout drums are also very commonly used.   The level





control shown on  the figure is not a required feature and may be omitted





where the volume of liquid to be separated is small.







K.      SCRUBBERS





        Scrubbers are devices for contacting a  vapor with  a liquid for





the purpose of removing a contaminant from the vapor.  For instance,




a hydrocarbon gas stream containing H7S can be scrubbed with a sodiurn





hydroxide solution (caustic solution) to remove the H2S.  Another





example would be the scrubbing of a gas stream with water to remove





dust carried by the gas.




        Figure 74 is a sketch of one of the many possible scrubber de-




signs.  In the sketch, ceramic saddle packing  is used to promote inti-





mate mixing of vapor and liquid.   Other forms of packing  and various





types of trays can be used,  or the vessel can be left empty with vapor-





liquid contact being achieved by spraying the liquid into  the vapor.  The





scrubber shown uses closed liquid circulation, implying that the liquid







                                  192

-------
                                  VAPOR

                                 OUTLET
 INLET
VAPOR
LIQUID
                                  MIST  5L/M/NM70R
                                  P/P£
                           LEVEL
                           VALVE
                                             LIQUID
CONTROL   OUTLET
              Figure 73.  Knockout drum.
                           193

-------
                 OUTLET  VAPOR
  LIQUID
  DISTRIBUTOR
CERAMIC
SADDLE
PACKING,
/=>n/P    U—
      VAPOR
             ^   /'N   X'N
   SCRU&&IN&
   LIQUID
                          fl-
                                   -tx-
                  CIRC UL ATION
                        PUMP

                Figure 74.  Scrubber.
                     194

-------
will be replaced periodically.  Other systems might employ once-





through liquid circulation.







L.     FRACTIONATORS




       Fractionators are sometimes called fractionating towers, or





distillation columns,  or stills.  They are liquid-vapor contacting de-





vices that achieve a separation of feed components based on the differ-





ence in boiling points of the components.  When a mixture of hydrocar-




bons is boiled the vapors produced are richer in the lighter, or lower -





boiling-point components.  If the vapors are condensed and the process-





repeated further  enrichment of the lighter components will be obtained





in the vapor.  Similarly, if the liquid from the first step is boiled,  the





remaining liquid  will contain a still higher concentration of heavy com-





ponents.   The fractionator shown in Figure  75  is a device to accomplish





these steps  in a continuous fashion.





       Feed is introduced near the middle of the column onto the feed





tray.  Vapor rising from the tray below condenses in the liquid on the





tray,  vaporizing  some of the liquid which travels up to the next tray.





In this way, vapor originally formed by the  reboiler at the bottom of





the column supplies a vapor  stream that passes up through the column,





leaving as overhead vapor.   The overhead vapor is condensed to liquid




in the condenser.   Part  of this liquid is overhead,  or light, product





and the remainder is returned to the column as reflux to provide a




source of liquid to the trays.







                                195

-------
OVERFLOW
WEIR
t\
                    J

Q
                                                 COND&NSBR
                                                   REFLUX

                                                   ACCUMULATOR
                                  •*—S
                                        REFLUX
                                        PUMP
                                 TRAY
                                                  35£ C K
                                                           T/?/W
                                     REROILER
                                        RE&OILtK
                                                                VALVE
                                                                X^>
                                                          BnnB^
                                              BOTTOMS
                                                        KISEIZ
                                                          SLOT
                BOTTOMS PUMP
                               Figure 75.  Fractionator.
                                          196

-------
       The figure shows a fractionator that uses trays as vapor-liquid




contacting  devices.  Details  are shown for both valve trays  and bubble




cap trays,  which are two of many types of trays.  The combination of




downcomer and overflow weir shown is used to maintain a liquid level




on the tray and a vapor seal  so  that the vapor is forced to flow through




the valves  or caps.  It is also possible to  use shaped solids such as




Raschig rings,  Intalox saddles or Pall rings as contacting material.




The column is filled with the rings or saddles  and is called  a packed




column.
                                197

-------
                  III.   PROCESS INSTRUMENTATION







A.     INTRODUCTION




       Process instruments are widely used in refineries  to indicate,





record, and control the operating conditions and plant performance.





Early processing plants contained only indicating instruments to assist





the operator to control the plant operation manually.  Modern refin-





eries are highly automated with instruments which control process





flows,  temperatures,  and pressures.  Some refineries  have computers




which process operating data and recommend or execute changes in




operating conditions.







B.     IDENTIFICATION OF PROCESS INSTRUMENTS





       Process instruments can be classified according to the variable





being processed and its function.   The variety of instrument types is





best illustrated by the Instrument Society of America (ISA) code system.





This code system is used on all flow sheets in this manual.  A two or




three-letter symbol is used for each instrument.  A summary of the





commonly used code letters  is presented in Table 8.  The  symbol





"FRC", for example,  indicates an instrument which records and con-




trols the flow  rate.  Other symbols are used to indicate whether the




                                199

-------
        Table 8.  INSTRUMENT IDENTIFICATION CODES
Letter
A
C
D
E
F
G
H
I
L
M
0
pH
P
R
S
T
U
V
W
Process Function (s)
(First Position) (Second and Third Position)
Alarm
Conductivity Controller
Density
Electric variable Element
Flow
Glass or gage
Hand or manual
activation
Indicator
Level Logging, scanning
Moisture
Orifice, restriction
Acidity
Pressure
Recorder
Speed Safety
Temperature
Unit
Viscosity Valve
Weight Well

Example:  PSV = Pressure Safety Valve
                            200

-------
instrument is board mounted in the control room or locally mounted





within the plant.




       A process instrumentation and control system consists of sen-





sors that measure the process variable,  transducers that convert the




signal to electrical or mechanical form,  gages,  recording devices,





transmitters that relay the signal to receiving instruments, control





valves,  and other instruments that affect the process stream behavior.





Each of the major instrument categories is discussed below.





1.      Indicators





       An indicator shows the immediate condition of the process





stream.  It might be a thermometer gage,  level glass, or manometer.




In  most refineries,  operators take readings of various indicators in the





plant at regular intervals.  These data are generally recorded on oper-





ating sheets and filed for a limited time.




2.      Recorders





       A recorder takes an electric or pneumatic  signal from  a remote





sensor and records  it on a moving  chart.  Some recorders use circular





charts that rotate as a pen traces the process signal.  The normal time





coverage of these charts is 24 hours.   This type of recorder is widely




used, but the current trend is to use strip charts which trace  a process





signal on a roll of paper as it moves from one roll to another.  A strip-





chart instrument will accumulate data from several days' operation on





a single roll,  which makes it easier to review and analyze the  process





operation over an extended period.





                                201

-------
       Care must be exercised in reading instrument charts.  The





charts are frequently graduated in units from one to ten or from one to





one-hundred.  The proper instrument value is obtained by multiplying





the chart reading by a factor which is unique to that instrument system.





These factors may be written on the instrument face or recorded in the





instrument log book.  The field engineer should check with the oper-





ating foreman to confirm that the correct factors are being used.




       Care is  also  required in  reading pulsating or cycling signals.





An average of the high and low signals can be used to estimate the





average  value.   The maximum reading can be used to estimate the





instantaneous peak value.





3.     Transmitters




       Transmitters are devices used within the plant  to relay signals




from the measuring  point  to  the  receiving device.  Transmitters are





generally the electric or pneumatic type.   The pneumatic  transmitter




in conjunction with force-balance measuring devices is  in wide use





today.




       This system operates on a low-pressure  instrument  air system





with signals transmitted through small-bore tubing.





4.     Controllers




       A controller  is an instrument that receives a signal from the





sensing  element or  transmitter,  compares the signal to a predeter-




mined value or set point, computes the action required to  align the pro-





cess  variable,  and executes  the  corrective action.  Controllers operate






                                  Z02

-------
on electrical, mechanical,  hydraulic,  and pneumatic signals.   The





pneumatic system is the most common type found in refineries.





5.     Control Valves




       The control valve is the final device in a control system.   The





valve opening is varied according to the pneumatic signal received.





The valve position is adjusted through a diaphragm or bellows which





responds  to pressure changes.  Control valves are discussed in more





detail in Chapter II,  Refinery Equipment.







C.     FLOW MEASUREMENT




       Flow metering devices fall into three categories:  positive dis-




placement,  variable-area,  and variable-head meters .





1.     Positive Displacement Meters




       The nutating piston  or nutating disk meter is the most commonly





used positive displacement meter.  This meter is used primarily for





liquids.   The lobed rotor meter contains two lobed impellers and is




used chiefly for high volume  gas flow metering.  Other types include the





rotary vane meter (gases and liquids)  and the liquid-sealed gas meters.





       Velocity meters are based on the turbine principle.  The velocity




of the fluid  actuates an impeller whose speed varies with flow rate.  The





turbine meter is the  inost frequently used type of velocity meter.




2.     Variable-Area Meters





       The piston meter and rotometer are based on the variable-flow





area principle.  A rotometer is a vertical tapered tube  containing a






                                 203

-------
float.  The level of the float is determined by the balance between the





weight of float and the force of the fluid passing between the float and





the tube wall.  The float level is read directly on a scale on the trans-





parent tube.





        The piston meter contains a piston which rises as the flow in-





creases. As the piston rises additional orifice area is exposed.   The





level of the piston provides a direct indication of flow rate.




3.      Variable-Head Meters





        The most frequently encountered variable-head meters measure




the pressure drop across  a constriction in the line.  An orifice plate or





flow nozzle is often used to create the pressure loss.   Streamlined





restriction tubes, known as venturi tubes, are also used.  A pitot tube




measures the local fluid velocity in the line.  A tube is placed in the





flowing fluid facing upstream.  The velocity pressure is converted  to




static-head reading.   Pitot tubes can be used as portable instruments





to measure gas flow rates from vents and ducts.




        Weirs and flumes  are used to measure flow rates in open





channels. A weir is a dam with a notched opening.  The height of the





level in the notch indicates the flow  rate.  A flume is a narrow throat





in the open channel.  The level of the quiet fluid upstream of the  flume





indicates the flow rate.







D.      TEMPERATURE MEASUREMENT




        Temperature measurements in refineries are made with thermo-





couples,  thermometers, and radiation pyrometers.




                                  204

-------
1.     Thermocouples




       Thermocouples are widely used in refineries to measure the





temperature of process streams.  When two dissimilar metals are con-





nected in a circuit, an electric  current will flow if a temperature differ-




ence exists between the two junctions.  The thermocouple is placed in





a protective tube or thermowell.  Voltage signals  from thermocouples





are used to operate controllers, recorders, and multiple readout sta-





tions in control  rooms.





2.     Thermometers




       The common liquid-in-glass thermometer  is used as a tempera-





ture indicator in refineries.   More common,  however,  is the bimetallic




thermometer or temperature gauge.   When two  dissimilar metal strips





are attached,  a  temperature change will cause unequal changes  in





length  in the strips resulting  in a deflection.   Temperature gauges are




placed in the plant to obtain local readings. Often only a thermowell is





provided requiring the operator to  insert a thermometer to obtain a




reading.





3.     Radiation Pyrometers





       Radiation pyrometers are generally used where temperatures




are extremely high or where  other devices cannot be used in  direct





contact with the heat  source.  Radiation pyrometers measure the in-





tensity of radiation from a hot source. A photocell or other detector





converts the radiation to electrical current.  Optical pyrometers com-





pare the  radiation intensity from the object in question to another hot





                                205

-------
source of known temperature such as a tungsten filament.





4.      Resistance Thermometers





       The resistance thermometer and filled-system thermometers





are also used in refinery applications.  The resistance thermometer is




based on the change in electrical resistivity of metals with temperature.





The element is placed in a protective tube similar to a thermowell.





The filled-system thermometer measures the pressure change of an




enclosed volume of gas or  liquid.







E.     PRESSURE MEASUREMENT





       Pressure  measuring instruments  can  be classified as elastic





elements,  gravity-balance manometers,  and  electrical pressure in-




struments.




1.      Elastic Elements




       Pressure  indicating gauges commonly found throughout refin-




eries operate on  elastic elements,  such as bellows,  diaphragms, or





bourdon tubes.  When the elastic element is strained, a deflection indi-




cates the pressure level.   Sealing fluids  are often used to protect the





element from the process  fluid.




2.      Gravity-Balance Manometer




        A U-tube  or well filled with a liquid column will register a level





differential under pressure.   One side of the  manometer is connected to




the unknownpressure source and theother side is connected to  atmo-




sphere,  vacuum,  or  other  known pressure. A manometer can also be




used to directly measure differential pressures on flow elements such  as




an orifice plate.




                                  206

-------
3.     Electrical Pressure Instruments
       The strain gauge operates on the principle of change in electric




resistivity of a wire under strain or deformation.   The strain gauge is




used as a transducer to convert pressure  signals to electric signals.




High-vacuum pressures are also measured using electric or electronic




principles.   Resistance elements in a vacuum can be used to measure




pressure indirectly by measuring gas thermal conductivity.   The




Knudsen gauge is a complex device for measuring vacuum pressures by




measuring, the deflection of molecules off  heated vanes.  Other types




are based on the principle of gas ionization.







F.     LEVEL MEASUREMENT




       The measurement of liquid levels and liquid-liquid interface




levels is widely practiced in refineries  to control process  operations.




The simplest method of level measurement is direct observation.  This




can be done with a manually operated gauge tape or an externally




mounted sight glass.  Indirect methods  of level determination arebased




on the location of an internal float, differences in physicalproperties of




the two phases,  or static head.  Each of these is discussed brieflybelow:




1.      Float Devices




       The simple  ball-float mechanism is widely used in refinery ser-




vice to control liquid levels.  A rod, attached to the ball float, is used




to  operate a level indicator,  inlet valve, or pilot relay which, in turn,




operates a pneumatic control system.  In  some cases, the float is
                                 207

-------
located in a float cage connected to the vessel.  Magnetic floats are also





used to indicate levels.





2.      Displacer Devices





        The displacer type of liquid-level indicator has largely replaced




the ball float.  The  displacer is a tube lighter than the liquid whose




level is being measured.  As the  liquid level rises the displacer under-




goes  a buoyant force.  This force is translated  to torque in a rod or to





pressure in a bellows located externally.  The  rod rotation or the bel-




lows  pressure is used to indicate level or transmit signals  to a control





system.





3.      Hydrostatic  Methods




        Numerous hydrostatic methods are used to measure the static




head of the liquid in a vessel.  One method connects the liquid under





static pressure to a diaphragm box.  The diaphragm pressure is then




metered to determine level.   Mercury manometers and other differen-





•tial pressure instruments are also used to measure static head.







 G.     ANALYTICAL INSTRUMENTS




        A variety of special instruments  is  used to monitor product




 quality and control  refinery operations.   Some  of these instruments are




unique to the petroleum industry.  Each  refinery has a laboratory for




 quality control testing.   In large refineries, the laboratory may contain




 sophisticated analytical equipment and perform limited research func-





 tions.  In most refineries, the laboratory performs only  routine tests.







                                   Z08

-------
These tests include determination of gravity,  boiling point, flashpoint,




viscosity,  and sulfur and metals content.  Gas chromatographs are




occasionally used to analyze the composition of light hydrocarbon




streams.




       In most cases, refinery laboratory data can provide only clues




to possible emission  sources.   Routine data on chemical and physical




properties of process streams are useful in determining the normal




plant operating charactistics.  Deviation from normal operation indi-




cates a possible plant upset which could result in temporary emission




of pollutants.







H.     COMPUTERS




       Digital computers find widespread use in modern refineries and




are often  applied in process  control.  Shortly after computers became




generally available, many people felt that within a few years entire




refineries would be under the direct control of on-line computers. This




did not come to pass,  and at this  time direct computer  control is usu-




ally limited to sections of a processing unit or to a single piece of




equipment.   Computers are, however, very widely used to collect and




display data  and to provide information used in making  process control




decisions.




       Where  computers are used for on-line control,  electric rather




than pneumatic sensors and controllers are usually used.  Signals from




primary sensing elements are converted to low voltage electric signals






                                209

-------
that are in turn converted to binary codes acceptable to the computer.




The computer is programmed to produce process  control decisions




which are converted from binary code to low voltage signals for trans-




mission.  The low voltage signal is used to control electric motors




that position valves,  etc.
                                   210

-------
               IV.   MONITORING INSTRUMENTATION







A.     SOURCE MONITORING





1.      Monitoring Systems





       a.     Approaches - Today source emissions are still mea-





       sured manually.  A sample is extracted from a point or series





       of points in a stack or duct and are analyzed in  the laboratory





       or at some other remote site.  The result of the analysis repre-





       sents an integrated average of the emission parameter measured





       over the length of time the sample was  collected.





              While the field enforcement officer may request that




       such tests  be made and may observe  or even participate in





       the conduct of these tests,  his principal concern will be in  data





       that are immediately available and that can be correlated with





       physical observations  made during an inspection or investiga-





       tion.  Greater use is now being made of newer measurement




       methods that permit immediate determination of some measure-




       ment variables related to emissions and that also can be used





       in the continuous monitoring mode.





              Nader  has  categorized these newer methods according






                                211

-------
to three criteria:  (l)Is measurement made in situ (at the point

of extraction)or on extracted sample; (2) Is a point measure-

ment made or is the measurement integrated across a path;

and (3) Is sensing  on-site or remote?  Since all extractive

monitoring inherently involves point sampling, only in situ or

remote sensing can involve the integrated sample mode.

Table 9 lists those approaches that are at present in use or that

seem feasible, considering the above criteria.  Specific exam-

ples of these techniques will be given later.
      Table 9.   APPROACHES TO SOURCE MONITORING
       Approach
                                 Example
 1.  'Extractive monitoring
2.  In situ point monitoring
3.  Integrated in situ
      monitoring


4.  Integrated off-site
      monitoring
                          Continuous analyzer on stack
                          gas sample extracted from
                          point or series of points in
                          stack
                          Sensor placed directly in
                          stack at single point or
                          series  of points

                          Spectrometric or optical
                          measurement made across
                          stack
                          Remote sensing Spectrometric
                          or optical technique.  May
                          have active source or use
                          solar energy
b.
System Components - A source monitoring system con-
sists of far more than the sensor or analysis  device used.  In

the same reference,  six component or component/operation

                           212

-------
combinations are given as parts of a source monitoring system.




These are reproduced in Table 10.




       A major problem may be encountered in satisfying the




requirements of the site  selection criteria as applied to source




monitoring.  In conventional extractive source testing where




samples are removed for subsequent off-site analysis the New




Source Performance Standards of the Environmental Protection




Agency  call for a minimum of twelve  sample traverse points in




a stack if the sample location is eight stack or duct diameters




downstream and two duct diameters upstream from any flow




disturbance such as a bend,  expansion, contraction or visible




flame.  If these location  criteria cannot be met, additional




traverse points are  called for.




       In the case of a continuous point source extractive moni-




tor or an in situ point source monitoring device which is  used in




a permanent fixed installation,  there will be only one sample




point.  This point should be relatable in terms of contaminant




concentration to the true mean concentration established  by




traverse prior  to the fixed installation.  This  relation cannot be




expected to remain constant unless process and stack  conditions




(e. g. , temperature and flow rate) continue to be the same as




when  the  relation was originally established.  Therefore,  the




field enforcement officer should determine, when observing such




monitoring equipment, the precautions which have been taken to




                          213

-------
         Table 10.  SYSTEM COMPONENTS AND OPERATIONS
                    FOR STATIONARY SOURCE MONITORING
Component /Ope ration
            Requirement
1.   Sample  site selection
    and execution
    Sample transport
    (when applicable)
    Sample treatment
    (when applicable)
4.  Sample analysis
5.  Data reduction and
    display
6.  Data interpretation
Representative sampling,  consistent
with intended interpretation of
measurement

Transporting sample extract  with
minimum and/or known effects on
sample integrity

Physical and/or chemical conditioning
of sample consistent with  analytical
operation with  controlled and/or
known effects on sample integrity

Generation of qualitative and quanti
tative  data on pollutant or parameter
of interest

Calibrating and processing analog
data and display of final data in
format consistent with measurement
objectives

Relating the  measurement data to the
source environment within the
limitations of the  sampling and
analytical operations
                                 Z14

-------
assure that the relation between the contaminant concentration





as determined by the fixed monitor and the true concentration





can be reasonably established.   This problem is much less





severe with an integrating or across the  stack monitor,  but still





cannot be neglected.




       A  variety of other problems may  be related to sample





point or sample point environment.  For example,  in the case of





an extractive monitor for sulfur dioxide in the tail gases from a





sulfur  recovery unit, any residual hydrogen sulfide may con-





tinue to react forming sulfur which may  cause erroneous ana-





zer readings or plug the sample line.  The American Petroleum





Institute  has suggested that the following environmental in-





fluences be considered when locating process or source moni-




toring  analyzers:  radian heat,  mechanical shock and vibration,





vulnerability to  damage, electrical hazards, and weather.





Further,  analyzer  installation points should have safe access





for calibration,  servicing and maintenance.





c.     Monitoring  Strategy - In addition to the  sometimes




severe environmental problems associated with source moni-





toring,  e.g.,  high  temperatures, excessive moisture,  and




presence  of high contaminant concentrations, a  major problem





exists  in obtaining  representative test  data.  This is  a result of





the time variation in  the process* and distributional variation





across stack or duct  and fluctuations in contaminant loading.





                         215

-------
              The' strategy approach in source monitoring should be to




       (1) examine the process and equipment for likelihood of these




       variations,  (2) to pick a sampling point at which the variations




       will be at a minimum,  and (3) to select a monitoring approach




       which, within available options, is best able to compensate for




       the variations.




              One of the primary arguments in favor of source moni-




       toring,  of course,  is the potential for obtaining a continuous




       record of contaminant  concentrations,  thus enabling a more




       accurate determination of the true emission rate.  This is




       particularly true for gaseous  contaminants.  In the case of




       particulate extractive monitors where time variations are




       accompanied by flow rate changes, there should be an ability to




       vary the sampling  rate to maintain isokinetic sampling condi-




       tions.




              In the case of distributional variation,  nonextractive




       across-the-stack integrating monitoring devices are much




       better able to minimize the effect of such variation.




2.     Source Monitoring Interfaces




       To present a source sample to a monitoring device in a form




that will ensure a correct analysis and to ensure that the monitoring




device will be able to function continuously and reliably, some acces-




sory items are usually required.  These are commonly classified as








                                  216

-------
interfacing equipment.  This  equipment is designed (at least in the case





of extractive monitors) to remove the sample from the stack; to trans-





port it; to clean it; to alter temperature, water content, and possibly





pressure; and to measure,  and if necessary,  to control its flow rate.





The selection and design  of this interfacing  equipment in many  cases is





as important as the selection and design of the actual analytical device.





It often costs as much or more to acquire and install the interfacing





equipment as it does for the monitor itself.   For example,  in the case





of an electrochemical type extractive monitor for sulfur dioxide, the





purchase price of the analyzer is approximately $1, 100 and the total





installation cost typically ranges from $6,000 to $8, 000.  In the case of





an extractive photometric analyzer  costing approximately  $12,000,  with





installation charges ranging from $6, 000 to $8, 000 the total installed





cost can be $18, 000 to $20, 000.   The important categories of inter-




facing equipment are discussed briefly below:




       a.      Probe and Materials of Construction -  A probe is a  de-





       vice that is placed in the stack of an extractive  monitor.  Under





       clean, dry conditions,  it may be  a simple tube curved at the end





       to face the exhaust flow, or  it may have an integral particulate





       filter as a preliminary clean-up device.  These filters are  -





       usually of ceramic or sintered metal design to withstand tem-





       perature and to minimize adsorption effects for reactive gas





       sampling.   Further,  the probe may require heating to prevent








                                 217

-------
moisture condensation or may incorporate internal static pres-


sure taps to determine isokinetic sampling conditions in the

                             4
case of particulate monitors.


        Materials of construction should be such as to reduce to


a minimum wall losses through reaction,  adsorption, or other


depositions.   Smooth, clean, nonreactive tubing such as boro-


silicate glass, Vycor, or stainless steel are preferred  mate-


rials.   If copper is used, it should be refrigeration grade.  All


probes and tubing should be cleaned thoroughly prior to instal-


lation.  All valves,  fittings,  and  seals should be compatible


with the system  and must be leak-proof,


b.      Sample Conditioning - Sample conditioning is one  of the


major problems in source monitoring.  This operation can


include temperature reduction, moisture removal, particulate
                                         »                   *

removal, and pressure reduction - all to be accomplished with


a minimal or known effect on the component of interest.


        Temperature reduction and moisture removal may both


be done by cooling.   In turn, the  cooling may be accomplished


directly by refrigeration or indirectly by dilution,  although  the


latter  step requires additional flow measurement and control.


Unfortunately, the removal  of moisture by cooling  leaves  a


condensate which must be purged from the system.   This  is


done by a trap - a device permitting discharge of water without


loss of the gas sample.   In the case of soluble gases such as


                           218

-------
sulfur dioxide, the moisture removal process by condensation




will also result in the removal of some SO2.  Considerable




effort has been expended by manufacturers" of commercial equip-




ment  to alleviate this problem.   One approach is to pass the gas




through condensing systems  as rapidly as possible with the trap




located away from the main gas flow path.  This reduces  expo-




sure of the gas stream to the condensate.   Nevertheless,  the




probable loss of SO2 should be evaluated, preferably by in-place




sample spiking or by calibration.




       Unwanted particulate matter which may clog lines  or




interfere with the measurement process is usually removed by




filtration.  Depending upon the loading and  the operating sched-




ule, a built-in inert gas back-flush system may be required to




periodically remove accumulated particulate  matter which in-




creases back pressure and may cause increased sample losses.




The filter media  itself should be nonreactive,  strong,  resistant




to moisture and corrosion, and nonadsorptive.




       Recently,  reverse  permeation devices have  been studied




which will permit a gaseous  contaminant of interest to pass




from  the sample  stream through a semipermeable membrane




barrier into a nonreactive carrier gas which  then flows to the




detector.  The unwanted contaminating moisture and particu-




lates  are retained on the sample*-gas side of the barrier.




Because the permeation of the gas of interest is not quantitative





                          219

-------
but is a function of partial pressure (concentration) in the orig-




inal stream, a careful calibration is required to translate the




apparent analyzer concentration to the true concentration.




These devices have not as yet been used extensively, but if




successful could become an attractive solution to sample




clean-up problems.




       Pressure reduction may sometimes be necessary.  If




so, those making the installation should be cautious about




effects of .possible  freezing, ice deposit, or hydrate formation.




Figure 76 illustrates a typical sample system for an extractive




monitoring  device  showing major interface components.




c.     Sample Transport and Flow Measurement - In the case




of extractive  soxirce monitors, a sample gas stream, must be




made to flow  through the interfacing equipment to the actual




sensor.  This is accomplished by a vacuum-pro due ing device,




usually a  pump,  but sometimes an air or steam jet ejector.




The latter require  auxiliary services which are usually avail-




able in a refinery,  but they are quite  reliable and less subject




to wear than are mechanical pumps.




       In the  case  of concentration measuring sensors,  flow




rate does not  directly affect results unless pressure limits are




exceeded  or unless pressure conditions inside the detector are




changed from those at calibration.  Where an indirect measure




of mass is made, the  sample flow rate enters directly into the




                           220

-------
ts>
                               SPAM  GAS
                                  1
                             Z.ERO GAS
                                _L
                STACK WALL
         PROBE/
         PRIMARY
         FILTER
      * INCLUDES
      PARTI C.LE FILTER,
      PUMP; 4 SLOWDOWN
      CONTROLS
                        SAMPLER/BLOWDOWN
                             UNIT*
                                                                      SAFE DISCHARGE
                                              ANALYZER  RECORDER
                                          FLOWMS.TER.

                                          NEEDLE  VALVE
                       DRYER
                                                                 TRAP
COMPRESSED
   A\ R
                                                                          AUTOMATIC
                                                                            DRAIN
                               Figure 76.  Typical stack monitoring system.

-------
final calculation of emission rate.  In any case, flow should be



at a rate to minimize wall losses and to avoid unusually long



response times which are not consistent with possible rate-of-



concentration variation.



       Sample flow rates may be measured by a variety of



measuring devices including calibrated nozzles and orifices and



rotameters.  The latter are probably the most commonly used.



They are indirectly sensitive to temperature by its  effect on



carrier gas viscosity and are subject to wear of float and tube



which also affects  calibration.   They should be used with care.



       As  earlier  mentioned,  isokinetic flow conditions must



be maintained when sampling particulates where particle diam-



eter exceeds  about 3 /jm.  If sampling velocity in the probe is



higher than that in the stack, a disproportionate number of



smaller particles will be present in the sample.  If probe ve-



locity is lower than stack velocity,  a higher proportion of



larger particles will be present in the sample  stream.   It may



be desirable to have a sample flow  rate controller which is



actuated by a stack flow  rate sensing device.



       If mass emission rates  are  to be obtained,  total exhaust



flow must be  measured  regardless  of whether  extractive or



nonextractive monitoring equipment is used.  Although pitot


                                                         4
tubes may be used as  in  conventional batch  source testing,   an



instrumental  approach using a transducer which produces an



                           222

-------
       electrical signal may be useful for permanent installations or




       those used to control sample flow  rate.  Recently, a heated




       thermopile velocity sensor has been marketed in which fluidic




       control of an inert gas  flow over the thermopile is utilized




       instead of the stack gas itself.  This permits operation in con-




       taminated conditions without  the necessity of cleaning the gas




       stream to be measured.




3.     Calibration




       Calibration requires relating the readout of the source monitor




to the true concentration of the contaminant in the source being mea-




sured.  A full-scale calibration involving the  in-place introduction of a




known concentration of the contaminant to the analyzer under stack




conditions would be  desirable, but to date, this has  been difficult to do
                                                                "e 1" 
-------
devices, the zero transmittance point can be obtained by blocking the





light path,  but a true 100% transmittance can only be obtained during




shutdown conditions.





4.      Source Monitoring Instruments





        In recent years, many firms have been working on the develop-




ment of continuous source monitoring instruments.  Relatively few of





the devices have reached full commercial status.   The field enforce-





ment officer should be generally familiar with the types of continuous





monitoring systems  in use or soon to be available.  The principal types





for the major air pollutants and their principal points of application are





described  here.





        a.      Gaseous contaminants




        (1)     Sulfur dioxide - The potential for sulfur dioxide emission




        exists in any combustion operation in which sulfur-containing




        fuel is burned - sulfur recovery plants, catalyst regeneration





        and other decoking operations,  and some treating units.





               Most  source monitors available for sulfur dioxide de-





        termination are based upon the extractive monitoring concept.





        The two having the widest  application involve the nondispersive





        infrared  (NDIR) principle and an electrochemical approach.  The





        nondispersive infrared technique involves the absorption of





        infrared  energy by  sample gas in  a cell.   Instead of using dis-





        persive optical elements to obtain  specificity,  the infrared





        absorbing properties of the gas of  interest are used.   This is





                                   224

-------
done by using the gas of interest either in a sensitizing cell or




in a detector cell.  In the first case, a differential thermopile




is used for detection and, in the second, a capacitor micro-




phone is used.   The thermopile type is less sensitive but is also




less sensitive to vibration and shock.  In any case,  the NDIR




method is quite specific. It requires moisture and particulate




removal to keep optical surfaces  clean.  The measurement is




not highly sensitive to flow rate,  but cell pressure must be




maintained at the same level as during calibration.




       The electrochemical sensor operates by producing an




electric  signal through electrooxidation of  sulfur dioxide.   In




this particular class of electrometric  instruments,  the bulk gas




flow does not pass  through an electrolyte,  but rather the  gas  of




interest passes through a semipermeable membrane to the cell.




As  in the case  of the nondispersive infrared analyzer, the in-




strument is not directly sensitive to flow rate but must be




operated at constant pressure.  Moisture and particulates must




be removed and temperature is normally limited to 1 10° F.




       Water removal  systems for all sulfur dioxide monitors




should be designed so as to minimize contact time  between the




gas stream and condensate  to reduce the possibility of sulfur




dioxide adsorption.  The dilution  approach to cooling and hu-




midity reduction might be particularly attractive in sulfur




dioxide analysis systems.




                         225

-------
       At least one commercial in situ sulfur dioxide analyzer





is available.  It is  based upon the principle of ultraviolet corre-





lation spectrometry.  Although it  is a dispersive technique,





specificity is obtained by comparing the spectrum obtained




with a correlation  mask instead of selecting a particular wave-





length interval as representative of the compound of interest.





Physically, a tubular slotted probe is inserted in the stack so





that flue gas continuously passes through the slot.   Ultraviolet





light shines through the flowing sample and is reflected by a





mirror at the end of the  slot back to the spectrometer head.





An electrical signal proportional to the sulfur dioxide concen-




tration results which is processed and displayed.  Compensa-




tion for particulate accumulation on the optics is provided by





automatic adjustment of  the gain on the photomultiplier in the




detector to  reflect overall  light intensity.  Obviously,  this





accumulation cannot be permitted to continue indefinitely.  Very





little practical experience  is available with this analyzer.





(2)     Carbon monoxide -  The principal source of carbonmon-





oxide emissions from refinery operations  is the regenerator of





a fluid catalytic  cracking unit.   Carbon on the catalyst is burned





off with less than the  stoichiometric quantity of air.   This




results in appreciable carbon monoxide formation instead of





total conversion of the carbon to carbon dioxide.  In most





cases there will be an afterburner, commonly called a  "CO




                           226

-------
boiler" in which the carbon monoxide is burned.  While there


are other possible  sources  such as other types of decokers,


fluid cokers, engines, and incinerators,  the most likely point


of application for carbon monoxide monitoring is in connection


with the fluid catalytic cracking  regenerator.


        The most frequently used technique for carbon monoxide


monitoring is the extractive nondispersive infrared method.


Fundamentally,  the same type of sample conditioning equipment


and analyzer is used as previously described for sulfur dioxide.


The sensitizing cell would,  of course,  be filled with a carbon

                                  *
monoxide mixture instead of sulfur dioxide.


        Electrochemical sensors used in  conjunction with extrac-


tive monitoring techniques are also available, but there  is much


less  experience with this method available to date.


       It is entirely possible  that in  situ open path infrared


spectrophotometric procedures will come into use, but they  are


still in the research and prototype stages.


(3)     Nitrogen oxides - In refineries,  almost all emissions of


nitrogen oxides are from combustion processes  and are  pre-


dominantly in the form of nitric oxide (NO).  Therefore, heaters,


boilers, catalyst regenerators, furnaces,  engines, flares,  and


other miscellaneous combustion processes may be considered


as potential candidates for monitoring.  It  is  likely,  though,  that


only the larger sources, even in the  future, will have monitoring



                        227

-------
equipment installed.




       There are many techniques for monitoring nitrogen




oxides.  These include both extractive, in situ,  and remote




sensing.  These techniques are for the most part specific for




either nitric oxide or nitrogen dioxide. Thus  in the case of the




extractive monitoring approach, where this is the case, con-




version of NO to NO2 to NO may have to be employed.  Obviously




this is not practicable in the case of in situ open-path  or remote




sensing techniques.




       The extractive monitoring techniques available include:




       •       Electrochemical sensors - Fundamentally,  these




       use the same general principle as similar devices  for




       sulfur dioxide and carbon monoxide.  The semipermeable




       membrane and electrolyte are optimized to give the




       necessary specificity.   The commercially available sen-




       sors  respond to both nitric oxide and nitrogen  dioxide,




       although the relative response to nitric oxide is usually




       greater.   Where the ratio of  nitric oxide to nitrogen di-




       oxide is known and constant,  this is not a serious




       deficiency.




       •       Chemiluminescence -  These analyzers  operate




       on the principle of light emission resulting from the




       reaction between  nitric oxide  and ozone.  The  analyzer




       incorporates a built-in ozonizer which provides a





                           228

-------
stream of ozonized air to react with the sample stream.




If nitrogen.dioxide is to be determined,  the sample




stream must first pass through a catalytic decomposi-




tion section.  Both particulate contamination and water




must be removed.  Special care must be taken or opera-




tion must be at reduced pressure if SO2 or CO2 are pre-




sent in significant quantities, as both compounds act to




quench the chemiluminescent reaction.  Several manu-




facturers offer commercial instruments.  All must be




operated, calibrated,  and serviced  with considerable




care.




        Ultraviolet-visible spectrometry - At least one




manufacturer offers a split-beam filter photometer of




this type for analysis of NO2.  If NO is to be determined,




it must first be oxidized to NO2.  One approach used is




to oxidize the NO with O2 at approximately five atmo-




spheres pressure.  As is the case with most extractive




gas monitors, particulates and water must be removed.




Calibration is usually accomplished with a standard




optical filter, but the zeroing operation uses a  zero gas




supply.





        In situ open  path or remote sensing  is possible




for  nitrogen dioxide with the use of  ultraviolet correla-




tion spectrometry.   The same general approach is used





                 229

-------
       as when the technique is applied for sulfur dioxide.




       Because nitric oxide is not detected, the application is




       limited.




(4)     Hydrocarbons - The major potential hydrocarbon losses




in a refinery are from storage and product transfer.  In most




cases, source monitoring is not applicable.  There are many




other smaller sources such as blow down  systems,  vacuum jets,




barometric condensers, air blowers,  emergency vents, and




fume  incinerators where monitoring conceivably could be




applied.   So far,  little effort has been made in this  direction.




       Three extractive monitoring techniques are  applicable




to hydrocarbons.  One is the nondispersive infrared method




previously discussed.  The  second is hydrogen flame ionization




detection in which the presence of hydrocarbons in  a sample




stream flowing through a hydrogen flame increases the ion flow




between two electrodes thus producing a signal proportional to




the hydrocarbon concentration.  The selective combustion ana-




lyzer technique is a third.   Particulates and most water should




be removed from, the sample although the  flame ionization




method is not so  sensitive to the presence  of water  as the other




techniques.




(5)     Miscellaneous gaseous contaminants - Hydrogen sulfide,




mercaptans, ammonia, phenols,  and other organic  compounds




may be discharged from catalyst  regenerators,  treating units,





                          230

-------
air blowers, hydrogen sulfide recovery systems,  and fume




incinerators.   One of the techniques previously mentioned for




other contaminants can also be applied to most of these com-




pounds.  Monitoring  for hydrogen sulfide is a more common




practice than is monitoring for the  contaminants of lesser im-




portance.  Again, most of the techniques applicable would be




based upon  extractive monitoring.




b.     Particulates - The term particulates, here,  covers




smoke, dusts and fumes, and liquid phase aerosols.  It is




obvious that a great variety of sizes, particles, densities,




shapes, optical properties, rigidity,  and surface  characteristics




may be covered by this definition.   In a refinery,  we shall




mainly be concerned with smoke, catalyst dust, coke breeze,




and liquid aerosols.  Because of the high reliability of combus-




tion control now available, the major particulate problem from




refineries is catalyst fines lost from fluid catalytic cracking




unit regenerators.




(1)     Optical - A variety of devices may be included  in this




category such as single-particle, light-scattering  instruments,




nephelometers, and opacity meters.  The  latter is the one  in




current use for source monitoring and includes the long avail-




able smoke  meters.  Using the earlier mentioned classification




system,  opacity instruments  would be listed under the in situ




open path class.





                         231

-------
       In recent times,  considerable effort has been devoted to


the adaptation of opacity instruments so as to enable the deter-


mination of mass concentration from light transmittance read-


ings.  Ensor and Pilat  have recently described in some detail


the theory and assumptions necessary to make such calcula-


tions.  In their  expression,  mass concentration is a function of


particle density, optical path length, optical density (In —V  and
                                                    \ Io/

a "K"  factor.  In turn, this  "K" factor is a constant which is


dependent upon particle diameter, wavelength of source light,


refractive index of the particle,  size frequency distribution,


and scattering efficiency based upon particle  shape.  It is quite


obvious that the "K" developed for any given particulate emis-


sion is quite unique.  Any change in the several parameters


listed  above can affect the validity of the  relation between light


transmittance and mass concentration.


       A number of installation and operational problems affect


the reliability of opacity measurements in addition to those


related to fundamental design.   In large part, these are related


to source and receiver alignment, cleaning of optical surfaces


exposed to the stack gases,  and to problems of calibration and


zeroing.  A variety of techniques has  been used  to facilitate


maintaining cleanliness of optical surfaces.   They include using


recessed mounts with partial isolation  of surfaces by purge  air


to cleaning technique based  upon air blast and water jets. Even



                           232

-------
with the best of these, some manual cleaning is necessary at




varying intervals.




       Both infrared and visible light sources are used for




instruments now  available commercially.   While most systems




have the transmitted light sensing unit mounted opposite the




light source, at least one now offers a dual beam unit with a




corner cube reflector making possible the  mounting of the




source and receiver in the same housing.




       It is important that the field enforcement officer under-




stand the exact nature of any opacity device used for mass-load-




ing determination,  its limitations,  and its  operating require-




ments .




(2)    Particle mass sensors - At least two devices are now




available which are stated to be direct mass sensing devices .




Both are in fairly early  stages of development as far as source




monitoring applications  are  concerned.  The  first described




uses the principle of beta radiation attenuation.  In this approach,




an extractive sampling system dilutes and  moves a sample




stream of stack gas to a sequential filter tape mechanism where




an integrated filter sample is obtained over some pre-set time




period. Following this,  the  tape is  advanced so as to be exposed




to a beta radiation  source.   On  the other side of the tape  a




sensing device measures the attenuation of the beta radiation.




This attenuation has been found to be almost directly proportional





                         233

-------
to the mass between the source and detector.   The procedure




does not give a truly continuous measurement but rather a




series of integrated values over finite time periods.  As is the




case with an extractive sampling procedure for particulates,




provision should be made for isokinetic sampling.  Also care




must be taken to maintain the  integrity of the  sample.  Systems




presently available have  three major components  as follows:




(1) sampling probe and diluter, (2) collector unit containing




pump, filter tape system, and beta radiation gage, and




(3) control and readout units in which computation of mass




concentration is  made from mass, and flow data.  The collector




unit should be near the source while the  control and readout




unit may be  located remotely.




        Another type of mass sensor involves  the use of the




piezoelectric principle.  Here particles  in a sample  stream are




deposited by electrical precipitation on a piezoelectric quartz




crystal oscillating at its  resonant frequency.   Since the reson-




ant frequency is  mass dependent,  the rate of change of this




frequency can be measured by an  appropriate detector circuit




and related to the increase of mass on the crystal caused by




the particulate deposit.   At higher concentrations, dilution




may be required.  Also the effective particle  size range of




one instrument is stated  to be limited to . 01 to 20;um. Among




the operational problems that have to be considered are the




                          234

-------
requirement for periodic cleaning of the crystal and ensuring




that liquid water is not deposited and cause spurious readings.




(3)     Electrical  -  One type of particulate monitoring device




is an  extractive monitor which utilizes the charge transfer




principle.  In this instrument,  particles in the sampled gas




stream pass by a sensor without being collected but result in an




electrical disturbance changing the current flow in the detector




with a logarithmic dependence  upon particle mass flow.  Rela-




tively little  experience is available with this type of analyzer.




Calibration  is obviously a problem as is sample handling.




(4)     Costs  - A brief word is in order about present day costs




of source monitoring instruments and installations keeping in




mind  that such figures may become dated  rapidly.  One of the




lower cost sensors is the electrochemical sensor.  For the




sensor only, costs for a single parameter instrument are in the




range of $1, 000 to $1, 500.  Total installed cost including site




work,  sample handling system, and recorder may easily  reach




$6,  000 to $8, 000.  At the higher end  of the range, a completely




installed spectrophotometric system  may  reach $18,000 to




$20, 000,  based upon an analyzer cost of $14, 000.  The installed




cost of one of the more expensive opacity  instruments,  including




purge air systems,  isolation shutters, and other accessories




can reach $6, 000 to $7, 000. Other types  of particle monitoring




devices including the mass  sensors may have installed costs




                        235

-------
       ranging up to $20, 000.  It seems obvious that even for a large





       company the installation of continuous monitoring devices can-





       not be considered a trivial expense, particularly when the con-





       tinuing costs for servicing,  calibration, repair and data





       processing are considered.







B.     PERIMETER MONITORING





       Contaminant monitoring as applied to the field surveillance  of





petroleum refineries can be more broadly interpreted than direct




source monitoring alone.   For one thing, not all sources of air con-




taminants are easily subject to direct source testing or monitoring.





Such sources would include pump seals, valves, fittings,  storage tanks,




barometric condensers, oil water separators, pressure relief systems,





most emergency flares, and other relatively minor sources.  Further,




it will be some time in the future before even most potentially major





sources  will be equipped with fully effective direct source monitoring





instruments.  To fill these gaps, the concept of perimeter or source





oriented ambient air monitoring may be applied.





       Source,  meteorological, and receptor oriented criteria are all





important in designing and establishing a perimeter air monitoring





effort.   The source oriented information would include an emission





inventory for normal operation including points of emission and de-





tailed information  on potential major point  sources of emission includ-





ing stack location, stack height and maximum expected  emission rate





in  the event of control  equipment failure.




                                  236

-------
       The meteorological data required involves wind speed and




direction and atmospheric stability.  If available, a wind rose and




stability wind rose are most useful.  A wind rose gives the frequency




of occurrence for each wind  direction (usually 16 points) and wind




speed class (nine classes in  standard Weather Bureau use) for the




period under consideration.  A stability wind rose gives the same type




of information for each stability class.  For maximum utility both




seasonal and annual wind roses should be obtained.




       The source and climatological data thus developed  may be




applied through the use of a diffusion model to predict points of maxi-




mum expected concentration and concentration isopleths for various




averaging times and seasons.  Turner has prepared a workbook on




the practical application of these models while Stern  has  reported on




the current status of a variety of modelling techniques.




       Receptor  and effects  oriented information are also useful in




planning  a  perimeter monitoring procedure.  Should significant informa-




tion be available  relating to locations of odor complaints and materials




or vegetation damage that clearly is  related to past refinery operations,




it  should be used to modify or  support monitoring planning based upon




emission and meteorological data.




1.     Continuous  Monitoring




       This approach involves the use of automatic, continuous,  re-




cording air sampling instruments.  Such instruments are normally




located in specially prepared fixed sampling sites or in mobile




                                237

-------
equipment.  A significant investment is usually required and special


precautions are necessary to ensure proper calibration, operation, and


maintenance.   Descriptions of such monitoring networks have been pre-

               Q
pared by Bryan  and the Office of Air Programs  of the Environmental

                  9
Protection Agency .


        Both fixed and mobile sites have advantages.  In some cases the


criterion will be availability of land  or  shelter where the optimum site


locations have been determined through diffusion modelling process.


Because the modelling process can only approximate expected condi-


tions,  the additional flexibility of a mobile station may be advantageous.


On the other hand, a mobile station is generally more costly than


equipping a permanent site and can require more manpower.  It is


particularly important in the case of perimeter or source oriented


ambient monitoring systems to obtain wind speed and direction data


concurrently with the contaminant data.


        As a general principle, perimeter monitoring is most effective


at points reasonably close to the probable source of expected contami-


nants.  As distances increase, the contribution from a single source to


the total ambient air loading of a given contaminant  is reduced  and a


point will be reached where this contribution is nearly indistinguishable


by ordinary monitoring means.  Obviously, the contribution from a


large point  source in a remote area  having no other point  or area


sources could be distinguished at greater distances  than could the same


source in the  midst of  similar sources.



                                  238

-------
       At the other extreme, contaminants discharged from elevated




point sources will not reach the surface of the ground closer than some




finite distance from the source.  Even under unstable plume looping




conditions  this distance may be several stack heights.  Even though




these latter conditions  give rise to high concentrations at point of im-




pact, the values can be expected to fluctuate rapidly due to vertical and




lateral plume eddying movements.  Thus some compromise must be




reached  in station siting so as to satisfy two conditions:  (1) the sites




must be  close enough so that the contribution from the source  involved




can be clearly distinguished,  and (2) the sampling or monitoring net-




work must be dense enough at the given distance from the source that




the emissions will be detected.




2.     Integrated or Static Monitoring




       Integrated monitoring systems may be either  active or passive.




That is they may involve the active sampling of air by means  of a




powered device moving air through or over a collection or  sampling




device, such as a bubbler  train or a  filter,  or they may involve use of




effects packages which are merely exposed to the normal free passage




of ambient air.  This latter group would include sticky paper,  greased




glass slides,  sulfation  plates, fabrics, metal plates, etc.  In general,




a much denser network of  intermittent or  static sampling sites is prac-




tical as compared to continuous monitoring.   This results from the




lower cost, lesser demands for space and power, and lower level of




manpower  skills  required.





                                239

-------
       The resolution of data obtained from intermittent or static





monitoring equipment takes longer than that from continuous monitor-





ing so it is less suitable for episodic sampling.  On the other hand, in





preplanned situations such as might be the case with the application of





an intermittent control strategy sufficient notice should be available to




make the use of intermittent air sampling devices practicable and





us eful.







C.     PORTABLE SAMPLING EQUIPMENT





       The field enforcement officer may find it advantageous to use





special portable  sampling and analysis equipment during some phases





of refinery inspection or in the investigation of complaints. For one





thing not all potential sources of air pollution in .refineries are well-




defined stacks serving a major process or operation.  Such miscel-





laneous  sources  would include  leaks from pumps, fittings, and relief




valves either into air or into cooling water  later passed through cooling




towers;  oil-water separators; sumps;  wastewater handling andstorage;





low-level minor  process vents; storage tanks; low-level flares and




spillage.





       In many of these  sources,  general housekeeping and mainten-





ance is closely related to the degree of contaminant loss.   Further,





the character of  contaminants likely to be lost from these miscellaneous





sources  includes mahy of those of significant nuisance potential because





of odor.   These include hydrogen sulfide,  mercaptans, aromatic hydro-




carbons,  amines, and other nitrogen bases  to mention but a few.




                                  240

-------
1.      Use of Portable Sampling Equipment


       The field enforcement officer should be very careful in the use


and interpretation of data collected by portable equipment.  First of all,


by very nature of the sources involved,  many of these losses may be


concentrated but very small in volumetric or mass flow.  The  actual


ambient concentration, particularly near the source, will be highly


variable and  greatly affected by atmospheric or meteorological condi-


tions.  Thus  the  inspector should record over a period of time the


values of a particular  measurement made in any given area of  the re-


finery or close proximity to establish a range of normal or expected

 *                   •
values.  In some cases, it will be more satisfactory to collect an inte-


grated sample using nonreactive flexible bags or miniaturized  integrated


sampling devices, such as impingers, to obtain a more representative


value. Of  course, if one is  leak tracing, a fast response system is


desirable.


       The field enforcement officer may also  use portable sampling


equipment  during investigation of complaints.   This  equipment is oper-


ated at the  point  of the  complaints or in a systematic perimeter check


of  the suspected  source.  Some knowledge of wind  speed and direction


and atmospheric stability will be needed to interpret such data.


2.      Types of  Portable Sampling Equipment


       A variety of  sampling and analysis equipment is available


ranging from manually operated devices to portable, continuous,


direct-reading analyzers.


                                241

-------
       One of the commonest portable devices is that based upon the





use of indicator tubes.   These tubes are sealed ampules containing a





reagent on a solid substrate which are inserted into an air sampling




device immediately following the breaking of the two sealed ends.   A





known amount of air is drawn through the tube by a squeeze bulb,  hand





pump, or a battery-driven air pump.  Following exposure, the tube is





compared against a standard by use of a length of  stain measurement





or degree of coloration  to determine the concentration of the contami-





nant in the air sampled.  A great variety of indicator tubes is avail-





able, some of which have been tested by the Bureau of Mines or other




groups concerned with occupational health.  The accuracy and sensi-




tivity are, of course,  generally poorer than instrumental methods of





analysis.  In some situations, it may be the only practicable approach.




       As earlier mentioned,  the field operation may be limited to





sampling only with analyses to be performed in the laboratory.  Com-




monly this approach involves the use of sampling bags,  liquid im-





pingers,  filters, and perhaps precipitators or impactor devices.  This





type of collection should be performed as directed by a competent





chemist  or other air sampling specialist.





       Finally,  there are a substantial number of portable continuous





analyzers.   Generally,  they are equipped with a direct-reading meter





and only occasionally used with a miniature recorder.  Perhaps the





most common  such instrument is the combustible gas analyzer.  In





this  instrument an air sample is drawn over a heated element connected





                                 242

-------
in an electric bridge circuit.  Any combustibles present are oxidized





over the surface of the element causing a temperature rise and conse-





quent change in resistance of the element.  By appropriate circuitry




this resistance change  causes a meter displacement proportional to




concentration.  However, the concentration shown is only  relative and




the instrument must be calibrated  in terms of the material of interest.





Other combustible gases or vapors will cause a response but the con-





centration indicated will not be  correct.





       Combustible gas analyzers have also been long available for





carbon monoxide.  In this analyzer, the resistance element is in a





special  catalyst and held at a temperature so that only carbon monoxide





will be oxidized and thus cause  a response.  There can be some inter-




ference from large concentrations of the more easily oxidized hydro-





carbons,  such as ethylene.





       Portable sampling instruments are available for hydrogen sul-





fide and  sulfur dioxide.  One  for sulfur dioxide is based upon the con-





ductivity principle and  uses a plunger pump to draw the  sample.  Other





instruments for hydrogen sulfide use the bromocoulometric or titri-




metric approach.





       In recent years there  has been  considerable  development of the




electrochemical cell type of instrument which is essentially the same





in principle as those used for fixed source or  ambient air  monitoring.




Analyzers based upon this principle are'available for H2S,  NO2,  NO,





C12, HCN, COC12, SO2, and CO.  Specificity is obtained by the use of





                                Z43

-------
selective prefilters,  semipermeable membranes, electrolyte material,




electronic  circuitry»  or a combination of one or more of these




approaches.
                                   244

-------
                           REFERENCES
1.  Nader,  J.  S.   Developments in Sampling and Analysis Instru-
    mentation  for Stationary Sources.   (Presented at the 65th Annual
    Meeting of the Air Pollution Control Association.   Miami Beach.
    June 18-22,  1972.) Paper 72-39.

2.  Standards  of Performance for New Stationary Sources.  Federal
    Register.  3^:24876-24895,  December 23, 1971.

3.  Manual on Installation of Refinery Instruments and Control
    Systems, Part II-Process Stream Analyzers,  2nd  Ed.  American
    Petroleum Institute,  Division of Refining,  Washington, D.C.
    Publication Number API RP 550.  May 1965.

4.  Morrow,  N.  L. , R. S. Brief, and R.  R.  Bertrand.  Sampling and
    Analyzing  Air Pollution Sources.  Chemical Engineering. 79:84-98,
    January 24,  1972.

5.  Ensor,  D. S.,  and M.  J.  Pilat.  Calculation of Smoke Plume
    Opacity from Particulate Air Pollutant Properties.  Journal of the
    Air Pollution Control Association.  21:496-550, August 1971.

6.  Txirner, D. B. Workbook  of Atmospheric Dispersion Estimates.
    Department of Health,  Education and Welfare, Public Health
    Service, National Air Pollution Control Agency, Washington, D.C.,
    Publication Number 999-AP-26.  Rev.  1969.

7.  Stern,  A.  C.  (ed. ).  Proceedings of Symposium on Multiple
    Source  Urban Diffusion Models.  Environmental Protection  Agency,
    Air Pollution Control Office, Research Triangle Park, N.  C.
    Publication Number AP-86.  1970.

8.  Bryan,  R. J.  Air Quality Monitoring. In: Air Pollution, Vol.  II,
    Stern,  A.  C.  (ed. ).  New  York, Academic Press,  1968.

9.  Field Operation Guide for Automatic Air Monitoring Equipment.
    Environmental Protection Agency,  Research  Triangle  Park, N.C.,
    Publication Number APTD-0736.  November  1971.
                                 245

-------
           V.  MAINTENANCE OF REFINERY RECORDS
               FOR USE BY AIR POLLUTION CONTROL
                 FIELD ENFORCEMENT OFFICERS
A.     INTRODUCTION

1.     Necessity of Keeping Records

       The recording and filing of operational data is a requisite for

efficient and economical plant operation in refineries and most other

industries.  Much of this information is related to throughput,  turn-

arounds, upsets, emergency  venting, maintenance,  source

monitoring, and ambient air monitoring and is, therefore,  valuable

in the effective enforcement of air pollution control  rules and

regulations.  Field enforcement personnel, in addition to making

observations for violations of visible emission standards, perform

other duties which,  in part,  depend upon information from  refinery

records.  These other duties include:

       •  Emissions Inventories   cataloging point sources according

          to type and quantity of air contaminants emitted;

       •  Source Registration Monitoring  - determining  that all

          sources covered by the ag'ency's regulations have been

          duly registered with the agency;
                                247

-------
       •  Permit Compliance Investigations - checking to ensure that




          permits have been granted for all applicable processes and





          equipment and their modifications.





       •  Complaint Investigation -  determining cause of complaint,





          recording pertinent data,  issuing violation notices if





          appropriate, and ascertaining adequacy of plans for pre-




          vention of future incidents;





       •  Episode Management - periodically reviewing emergency





          procedure plans; checking that all shutdown procedures are





          being implemented during periods of process curtailment;




          coordinating with other agencies  participating in pollution




          reduction effort;





       •  Compliance  Plan Status Inspection - checking to see that





          engineering, procurement, installation,  and testing of





          equipment is proceeding according to the approved plan.





       •  Source Compliance Monitoring -  determining that all




          sources are in compliance with applicable emission





          standards  (particularly important where the agency does





          not have a permit system).





2.     Availability of Records to the Inspector





       To conserve time and effort, data files should be  kept in a





specified location preferably where the enforcement officer meets the





individual designated to accompany him on inspections.  Refinery man-





agement personnel must also be aware of the location and content of





                                  248

-------
these files so that in the event the primary contact is not available,  an





alternate can be assigned.  Files kept at the home office, if not on the





refinery premises, are of little immediate value.  The unavailability of





data may result in time delays that reduce the field enforcement offi-





cer's effectiveness and waste the time of plant personnel.





3.      How Records will be Used




       Data contained in these records will have four primary uses.





       a.      Permit and Source Registration Identification -  Flow





       charts, engineering drawings, and equipment description will be





       used to designate the exact location,  capacity and configuration





       of  a system or permit unit.   This descriptive information is





       necessary to preclude modifications without agency concurrence,





       to  estimate increases of emissions due to process or feed





       changes,  and to determine the location of monitoring systems





       (see Chapter IV).





       b.      Emissions Inventories - Data usable for estimating




       emissions are  contained in special reports such as sxilfur




       balances in fuel gases (Figure 77) and estimates of losses from




       pumps, valves, emergency flaring, tanks, and transfer pro-





       cesses.  Additional direct data can be found in logged values





       from  source monitors, air monitoring devices,  plant operations





       reports, analyzers, sulfur and hydrocarbon balance forms,  and





       odor surveys.
                                249

-------
                            REFINERY DAILY FUEL, USE REPORT
 Company Name
 Add res a
Zip
Tel. No.
Day
of
Month
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
Ga^
Cur-
tailed































Total
Fuel Use Data
Fuel
Oil
Barrels
































Weight
%
Sulfur
































Gravity
API
































Natural
Gaa
MCF
































Refine ry
G*.
MCF


•
















•












SOj
Refinery
Gas, Tons
































Remarks



















*












Signature of Company Representative_
              Title
                         Figure 77. Fuel use/sulfur balance report
                                           Z50

-------
       c.     Emergency Action - Plans and procedures for emer-





       gency action are among the documents which will be duplicated





       in the enforcement agency's  files.  These records will serve as





       a checklist for the field enforcement officer during periods of





       curtailment of operations and during dry runs to"simulate





       emergency operations.  These plans must be updated periodi-





       cally to account for process  changes, procedural modifications,





       and errors detected during practice runs.




       d.     Legal Action - Incident and complaint investigations,





       court actions,  and variance board activity will require data





       from all of the records described above.  For example,  the





       point of emission of excessive odors may be traced from an





       incident described in an operator's log or from an inplant odor




       survey record (Figure 78).





              Some of the information retained for agency use will be





       sensitive  if not classified in  the military sense.  The field en-





       forcement officer must respect the confidentiality of any infor-





       mation so designated by the refinery management. Any process,





       control,  or cost  data that the company feels is proprietarymust





       be treated as  such by  the air pollution control agency represen-




       tative.







B.     FORMAT OF RECORDS




       Data management and records control procedures may be dif-




ferent at each refinery.   It is necessary, therefore, to arrange with





                               251

-------
Date
              12-8   8-4  4-12
Time
Wind
Direction






                                                      4

                                                 /
                                   L
                                                 N
                                                      M St.
  Remarks
             12-8
8-4
4-12
  Odor Complaints
    F rom:	
    Time:
    Investigation^
                                 Figure 78 - Odor survey form
                                          252

-------
refinery management for the maintenance of data in the format most




useful for air pollution control field personnel.  In general, written




files should contain the following information:




1.     Period of Time Covered




       Continuous records, such as daily logs,  are usually prepared by




shift, i. e. ,  12 to 8,  8 to 4, and 4 to 12 for specified dates.  Incident




records must accurately pinpoint the time of day, duration of theoccur-




rence, and date.  Weekly, monthly, quarterly, and annual records or




data summaries must  note the time span from start date to end date,




2.     Person Responsible for Keeping the Records




       Most refineries have designated a member of management to be




contacted by the field enforcement officer and to serve as the coordina-




tor for all environmental control functions.  Generally, this individual




will also be responsible for keeping the records. Since there is  the




potential for inspections at off-hours and over weekends,  supernumer-




aries who are familiar with the environmental files should be assigned




to be  contacted during these times.




3.     Brief Description of Process or Equipment for Which the




       Record is Maintained




       There are two  basic methods for describing the processes or




equipment for which data are  recorded.  The first is to use commonly




accepted nomenclature accompanied by a location indicator such as




"Fluid Catalytic Cracking  Unit No. 1.  "  The second appropriate




approach to process identification  is a numbering system.  Some of the




                                253

-------
options available include air pollution control agency permit numbers,




source registration number or an "Emission Point Number".  These




designators may be assigned to each point within a refinery capable of




emitting air contaminants. A numbering system starting with 001 and




continuing until all points are numbered is acceptable.   When a num-




bering  system is employed, the  descriptive details of the equipment




and location must be kept in a master file.




4.      Data




        Recorded information will generally be presented as a narrative




or in tables.  Typed data are always preferred but carefully written or




printed details are acceptable.  Each chart or table should have an




appropriate heading to describe  the data, i. e. ,  "Hydrocarbon Losses




from Tanks",  "Semiannual Sulfur Emission Balance",  or "S<52 Losses




from Emergency Flaring".  Column headings for tabular information




should be precise, clearly defined  units (such as Bbl/day,  Tons/hr,




etc. ), allow space for remarks  and identify totals and  subtotals where




applicable.




        A significant quantity of  information is stored in computer data




banks.  Printouts of these data may  use abbreviations to conserve  file




space.   These abbreviations  may not be easily understood by the  field




enforcement officer so  it is advisable that descriptions of the abbre-




viations and symbols  be kept with the hard copies.
                                  254

-------
C.     TYPES OF RECORDS




1.     Permit or License Files




       The field enforcement officer will probably use the permit




records more than any other single file.  During routine inspections,




he observes refinery operations for compliance with permit conditions




and looks for equipment or process modifications.  Permit certificates




may only partially describe a given unit, but additional details are




necessary for an efficient inspection.   "As built" drawings  and flow




charts will provide the necessary details to show the field enforcement




officer if unregistered modifications have been performed.   Each per-




mit unit description should provide operating data  which includes




throughput, sulfur content of processed crude,  fuel usage,  or  rated




capacity.




2.     Maintenance Records




       Maintenance procedures and schedules including preventive




maintenance are essential for a sincere air pollution control effort.




Maintenance is not only the repair or  replacement of valves, flanges,




compressors,  etc.,  after failure;  it is a planned, co-ordinated effort




to prevent breakdowns which will affect pollutant emission  rates.  Since




maintenance in most refineries is  a planning function based upon inputs




from the operating departments, replacement,  repair and modification




schedules will  be kept in the planning  department files.  The field




enforcement officer should determine where these records are kept,




and who is responsible for the data.  Periodically, he should discuss




                               255

-------
the maintenance and replacement schedules with designated personnel.




Often the maintenance plans also include modifications or  system




alterations for which new permits  will be required.  A thorough review




of all such proposed modifications may preclude legal action at some




future date for noncompliance.




       Another group of maintenance records which is of concern to




field personnel is monitoring instrument repair and replacement.




Chapter  IV contains a detailed discussion of in-stack and peripheral




monitoring systems.  Maintenance responsibility for these instruments




may reside with the planning department of the refinery, a special




instrument repair shop,  or the environmental control office.   The field




enforcement officer must determine where  the records are maintained




and institute a regular evaluation of the plans for repair, installation,




or modification of the instruments.




3 .     Shutdown and Startup




       Reports of equipment malfunctions,  upsets, and overload con-




ditions reported by operating personnel should be compiled,  recorded




and maintained in the environmental control office.  As an example, if




sulfur recovery facilities are unable to receive the sulfur bearing gases,




the gases must be flared causing the release of significant quantities of




SO2.  The record  of this event will contain the  quantity of sulfur burned




(usually  in tons),  the duration of the procedure, time of day and date.




       Emergency plans and procedures also come under this category




of data.  Shutdown procedures for refinery  operations call for very




                                  256

-------
stringent safety precautions for both personnel and equipment which




are the overriding consideration in the suspension of operations.  This




coupled with the possibility of secondary effects  of greatly increasing




emissions demands that curtailment plans be very specific regarding




operations and time.   The plan is a narrative with accompanying sched-




ules,  designated responsible personnel and special safety precautions.




The plan must be periodically reviewed by management and agency




field officers to assure the workability of the procedure.




4.     Ground-Level Perimeter Monitoring and  Continuous Source




       Monitoring Records




       The design and placement of ground-level perimeter and con-




tinuous monitoring systems are discussed in Chapter IV.  Measure-




ments are  recorded in analog form on strip  or circular charts,  in




digital form on punched or magnetic tape, or are hand logged from dials




and gages.  Contaminants  monitored are aerosols and gases that are




reported in the following manner.




       a.     Particulates - The ambient measurement reporting units




       depend upon the sampling or monitoring methods.   In the case  of




       a high  volume sampler,  the units are usually mass concentra-




       tion units such as  mg/m  .  In the case of sequential filter tape




       samplers,  the  reporting parameters normally are in reflection




       or transmittance units such as RUDS (Reflective Units of Dirt




       Shade) or COH  (Coefficient of Haze). These units are  arbi-




       trary and cannot be translated  directly into mass units unless  a





                                257

-------
consistent conversion factor has been determined.  It is not





likely that LJDAR or nephelometers will be encountered, but





such instruments essentially look at numbers of particles,  and




reporting units are usually in terms of visibility.





       In the case of a source monitoring  instrument,  the re-





cording is actually a fraction  or percentage of the full-scale





range of the instrument.   Only if the instrument has been cali-





brated and a scale attached to the instrument can a  meaningful




reporting parameter be observed.  Further,  most monitoring




devices measure concentration so that  stack exhaust flow must





be known before  mass per unit time such as Ibs/hr  can be





derived.  The most common  particulate monitoring device that





will be encountered will be an opacity meter.  These instru-




ments are usually calibrated to give  a direct readout in terms





of opacity.   In some cases, they may be calibrated  in terms of





mass concentration units  such as gr/ft ,  mg/m , etc.  The new





beta gage-filter  tape samplers are calibrated to read out





directly in mass concentration units.





b.     Gases (SO,.  H,S.  NH^.  NOX.  Amines, RSH)  -Monitoring





for gases almost uniformly results in the  reporting units being




produced in  volumetric concentration  units.  Depending upon





the concentration these units may be percent by volume, parts





per million (ppm), or even parts per billion (ppb).  Most instru-




ments would be calibrated to permit  the use of a direct-reading





                           258

-------
scale.  In some cases where a multirange instrument is used,




the scale would be only in percent of full scale.
                         259

-------
                       REFERENCES
1.   Administration  of the Permit System.  County of Los Angeles,
    Air Pollution Control District,  Los Angeles,  Calif. Internal
    Document.  January 1968.  pp.  1-12.

2.   Enforcement Management System Users Guide.  Environmental
    Protection Agency,  Research Triangle Park,  N. C.  Publication
    Number APTD-1237.  September  1972. pp. 3.4-3.5.

3.   Stein,  A.  Guide to Engineering Permit Processing, Environ-
    mental Protection Agency, Research Triangle Park, N. C.
    Publication Number APTD-1164.  July  1972.  pp.  5.8  -  5.9.
                               260

-------
          VI.  ESTIMATING AND ASSESSING EMISSIONS







A.     INSPECTION AND SURVEILLANCE PROCEDURES




       An air pollution inspection consists of entering a refinery to




determine if the equipment or processes meet the standard and




comply with the rules  and regulations of the air pollution control




agency.




       Some inspections,  especially initial ones, are comprehensive




and designed to gather information on all equipment and processes of the




refinery. Others  are  conducted for specific purposes,  such asr




       • obtaining  information for source registration;




       • gathering evidence relating to violations;




       • checking permit or compliance plan status of equipment;




       • investigating complaints;




       • following  up on a previous inspection;




       • obtaining  emissions  information by source testing.




       Field surveillance is a  field operations activity that provides




for the systematic detection and observation of emission  sources.




Observations are  made of surrounding areas and the exteriors of




facilities for visible emissions,  odors,  contaminant damage, new






                               261

-------
construction or expansion, and other visual or sensory manifestations




of air pollution or changes in emission potentials.




       Surveillance is conducted mostly by vehicle patrol.  However,




aircraft,  television,  ambient air-sampling devices,  and pollutant -




detection instruments can be used.





       An initial refinery inspection lays the groundwork for evalu-




ating potential emissions of pollutants from a facility and for assessing




the relative magnitude of pollution control problems  requiring correc-




tion,  reinspection, or further attention.





       The initial inspection has two phases: a refinery survey and




a physical inspection of the equipment and processes.  After this




inspection is  complete,  routine surveillance continues. Periodic




reinspections are scheduled and occasional special-purpose inspec-




tions (unscheduled) may be  required.




1.     Initial Refinery Survey




       The elements of a refinery survey include:




       •   Environmental Observations - the examination  of possible




           effects of  emissions on property,  persons, and vegetation




           adjacent to the source; include  the collection of samples




           or  specimens that exhibit possible pollution-related




           damage.




       •   External Observations of  Facility - observation of all




           possible points  of emission,  all visible emissions, odors,




           and pollution-related activities.





                                  262

-------
•  Management Interview - interview with refinery managers





   and equipment operators establishes corporate identity,




   ownership of the organization,  operations, and air pollu-




   tion control performance.




•  Process and Equipment .Inventory - the inventory consists of




   obtaining complete descriptions and records of all processes




   equipment capable of emitting air contaminants. The inventory




   inspection can also  serve to initiate a  source registration




   system as a method for rigorously accounting for equipment




   and processes capable of air pollution or confirm the infor-




   mation provided in permit applications.







a.     Environmental  Observations - The surroundings of any




refinery or petroleum  operation should be surveyed for odors




and for damage to vegetation and materials.  Findings should be




confirmed by questioning residents in the neighboring communi-




ties.  Soiling of surfaces of automobiles,  residences, and other




structures should be noted and,  where found to be severe, should




be investigated.   Any pattern of increasing intensity of soiling or




staining of materials in the immediate vicinity may be a clue to




previously unrecognized emissions and should be studied.




       Hydrocarbon vapors and gases are likely to  be particu-




larly prevalent near petroleum production and refining facilities.




When the odors are intense, they  indicate the occurrence of high







                        263

-------
emission le-vels since odor thresholds for these compounds are




relatively high and their quality not especially offensive.




       Sulfur compounds associated with crude  oil production




and with some refinery operations are readily detectable by




odor.   Sulfur dioxide may be produced by  combustion of fuels




or waste gases  (for example in boilers,  catalyst regenerators,




incinerators, and flares).  This gas has an acrid,  suffocating




odor with a threshold at one part per million  (1  ppm).  Reduced




sulfur compo-unds, including hydrogen sulfide, various mer-




captans, and other sulfur-bearing organics, have characteris-




tically very  offensive odors and very low threshold levels,




which have been estimated at less than one part per billion




(1 ppb).2




        In reporting on occurrences of odors allegedly causedby




petroleum facilities, the inspector should note wind conditions




(speed, as well as direction) at the time of his observations,




and he  should develop systematic procedures for patrolling and




characterizing odors.




        Odors may be described on an intensity  scale in terms  of




subjective evaluation, or a procedure using a scentometer or




other comparison devices may be adopted.  A  community odor




panel can help to establish the  significance of day-to-day




variations in odor intensity and quality of the ambient atmo-




sphere,  as well as to alert the field enforcement officer to the





                           264

-------
occurrence of unusual conditions.


       Sulfur compounds, particularly hydrogen sulfide,  can


discolor and damage lead-based paints often used in residential


areas.  They also accelerate tarnishing of silver and copper


surfaces.


       Sulfur dioxide and trioxide may be responsible for


causing damage to vegetation, such as evidenced by yellow to


brown blotchy spots on many varieties;  sulfuric acid mist


formed from the trioxide occasionally causes a  sort of pock-


marking injury to plants.  Diagnosis of plant damage due  to air


pollutants is difficult, however,  and should be confirmed  by


consultation with someone experienced in  the field.


       Data relevant to determining the speed and direction  of


dispersion of contaminants in the atmosphere include tempera-


ture,  humidity,  wind speed, and wind direction  measurements.


These data are continuously provided at weather observing


stations, but they may be required at other locations during


special investigations.


       Equipment suitable for such purposes includes thermo-


meters,  psychrometers,  especially the "sling"  variety and


anemometers or wind gages. Such equipment is discussed in

                 4
detail by Hewson.    For measuring surface wind speeds,  rota-


tion anemometers are most  satisfactory;  a particularly con-


venient type is the totalizing cup anemometer, which counts  and


                         265

-------
records each tenth, sixtieth, or whole mile of wind past the




instrument.




b.     External Observations of Facility -  A fundamental in-




spection technique consists  of identifying,  describing,  and




evaluating air pollution emissions and the factors contributing




to their formation.




       The field enforcement officer must demonstrate that his




observations prove the presence of an air contaminant (that is,




an effluent that is not water vapor or a natural constituent of




the atmosphere) and that the emission violates a standard.  He




must also determine what factors caused the emission to violate




the standard.  He should be prepared to describe the events




occurring in each stage or element of the air pollution problem.




(1)    Visible  emissions (plumes) - The air contaminant of




primary interest is the plume.  It is the "discharge" or "emis-




sion" regulated or prohibited in most statutes or rules.




       Since all substances become liquid, solids, and gases at




certain temperatures, the plume may consist of a variety of




contaminants in various states of matter.  Smoke, for instance,




contains visible aerosols -  carbon particles and solid or liquid




particles of partially burned fuels - gases such as sulfur di-




oxide, oxides of nitrogen, and unburned vapors.




       The  identity ascribed to the plume is  usually made in




terms of its outstanding visible characteristic.   For example,





                           266

-------
even though sulfur dioxide may be the most significant of the





pollutants emitted from a given stack,  the  effluent in which it is





contained is frequently described as smoke due to the visible





soot,  carbon particles, and fly ash contained in the plume.





       The mere observation of  a plume, however,  does not





result in its conclusive identification.  Knowledge of the specific




conditions which caused the contaminants is required.  The dis-





tinction between smoke and fumes cannot be made unless the





processes by which they are generated are known.  Effluent





plumes may be smoke, dusts,  mists, gases or vapors.





       •      Smoke is the visible  effluent resulting from in-




complete combustion.   It consists mostly of soot,  fly ash, and





other particles less  than one micrometer in diameter.  Depend-





ing upon the composition of the fuel or materials being burned





and the efficiency of combustion,  various volatilized gases  and





organics such as aldehydes,  various acids, sulfur oxides, nitro-





gen oxides and ammonia may also be emitted.  Because  of the





low vapor pressures and slow  settling properties of the parti-





cles,  the smoke may be carried  considerable distances from




the source and many submicron particles will be permanently




dispersed in the atmosphere.





              Smoke will vary in color but will be generally





observed as grey, blue, black, brown,  white, or yellow,





depending upon types of fuel or material and the conditions under





                         267

-------
which they are burned. ' The color of smoke is generally a good




indication of the type of combustion problem encountered.





               Grey or black smoke may indicate that material is




being burned with insufficient air or inadequate mixing of fuel





and air.  This, for example, will occur during the flaring of





waste gases when steam injection is not functioning properly.




        •      Dxtsts are minute solid particles released in  the





air by natural forces or by mechanical processes such as crush-





ing,  grinding, melting, drilling, demolishing,  shoveling,





sweeping, and sanding.  Dust particles are  larger and less  con-





centrated than those in colloidal systems, such as smoke and




fumes,  and will settle  fairly quickly on surfaces.  A dust





effluent may also contain many submicroscopic particles.





               Catalyst regenerators are a major source of dust





emissions in  refineries.  High efficiency collection systems





such as electrostatic precipitators in  series with cyclones or




multiple cyclones in series are generally used to control this




pollutant.  Bag filters  are not  generally used in petroleum re-




fineries though baghouses may be required  to meet stringent





air pollution control regulations.





        •      Mists consist of liquid  particulates or droplets





smaller than  raindrops,  such as fog,  and are  formed by con-





densation of a vapor or atomization of a liquid by mechanical





spraying.  Mist droplets may contain contaminant material in




solution or suspension.





                            268

-------
               In large oil-burning installations, sulfur trioxide





is formed as a gas and, after  contact with sufficient moisture in





the air, forms as a white-to-blue  plume several feet above  the





stack (detached plume).  After further contact with moistxire in





the air, the sulfur trioxide is  transformed to a sulfuric acid





mist.




       •       Gases    A gas  is a fluid of freely moving mole-





cules tending to expand infinitely and to diffuse and mix readily





with other gases.   Gas pollutants include a large variety of  in-





organic and organic compounds which may have noxious, mal-





odorous, toxic or corrosive effects or may have an effective





smog-producing potential.  These  include  carbon monoxide  (CO),




ozone (O3),  oxides of nitrogen  (NO, NO2),  sulfur dioxide (SO2),





hydrogen sulfide (H2S), hydrocarbons and their oxidation products,





halogens (chlorine, bromine,  fluorine, iodine) and  their deriva-





tives such as hydrogen fluoride (HF), and  vario\is  chlorinated





solvents such as those used in industrial degreasing and dry





cleaning.  Other important toxicants include ammonia  (XH-J,





arsine (AsH3),  fluorine (F,)( hydrogen chloride (HC1),  phosgene





COC12) and hydrogen  cyanide (HCN).




               Gases that commonly occur in refinery  air pollu-




tion problems as a. result of direct emission are sulfur dioxide,




hydrogen sulfide,  and mercaptans.





       •       Sulfur dioxide is a common stack gas produced





                          269

-------
from the combustion of sulfur-containing fuels such as coal and





fuel oil,  the burning off of residue on catalyst in oil refining





operations, the burning of tail gases from  the recovery of sulfur





from refinery waste gases,  and various  other chemical and





metallurgical processes.  A major source of sulfur dioxide is





the burning of fuel oil by refineries.  Fuel oil may have a sulfur





content from less than 1 percent sulfur to  5 percent in some of




the heavier fuels.  SO2 has a noticeable odor at comparatively





low concentration and will damage certain  species of vegetation





at 0. 25 ppm.  Sulfur dioxide gases and sulfuric acid mists can




hasten the corrosion of wires,  metals, and other materials.





               Cracking processes in oil refining operations




convert the sulfur contained in the crude oil into hydrogen sulfide





and mercaptans.  When hydrogen sulfide is released to the atmo-




sphere as  a gas,  it manifests a characteristic rotten egg odor.




From  relatively small gas  concentrations,  mercaptans also





exhibit'strong unpleasant odors such as garlic,  decayed garbage,





skunk, or  onions.  Hydrogen sulfide is detectable at 0. 12 ppm





and mercaptans at 0. 001 to  0, 041 ppm.  Under humid conditions,





H2S will also discolor some surfaces  painted with lead pigments.





       •       Vapors  -  A vapor is the gaseous phase of a sub-





stance which at normal temperature and pressure is a liquid or





solid.




               The most important vapor problem results from





                           270

-------
the evaporation of petroleum products,  such as the unburned





gasoline vapors in automobile  exhaust.  Gasoline vapors also





originate from processes in which volatile products are main-




tained in storage tanks and from the operation of pumps, com-





pressors, and blowers required for moving liquid and gas





streams.





(2)     Evaluation of visible emissions    Once a plume is identi-





fied as an air contaminant, it must be measured against  some





standard to determine whether a violation of the law has





occurred or it must be evaluated to determine the size or





severity of the pollution.





       Compliance with applicable  emission standards is





determined by visual evaluation of visible emissions and by




source testing of emissions which  are invisible or near the





threshold of vision.





       Visual observation of plumes by field personnel can be





an effective and economical method of determining compliance





with air pollution regulations,  provided the regulations are





based on the  visible aspect of plumes or on other properties





that can be shown to be directly  related to the visible aspect.




       The benefits of basing smoke statutes on opacity or





density are quite evident,  even though equipment and fuel regu-





lations have increasingly assumed precedence in control legis-





lation.  When the visual standard is specific with reference  to a






                           271

-------
cut-off point and time interval, it is simply and directly en-





forced.   To cite a violator for excessive smoke, enforcement





officers need only observe an emission of an opacity or density





beyond that allowed for a specific period of time.  Although the




visual standard is limited to estimations of particulate pollution




which obscures vision, its application simultaneously tends to




reduce grain loading and gaseous contaminants.  (As the grain





loading in the plume increases,  the light transmission decreases





exponentially. )  To  comply with the opacity standard,  more




efficient combustion or equipment operation is necessary.   The





Ringelmarm  standard can be applied not only to smoke,  but to





fumes,  dusts, and mists arising from a variety of problems and,





therefore, is most versatile in identifying and controlling atmo-





spheric pollutant emissions in a community.




        However, while large reductions  can be anticipated, they





cannot always be precisely predicted or evaluated.  Determina-





tion of opacity and shade of any  emission alone gives no specific





measurement of the qxiantities of contaminants being emitted.





       A complete description of the theory and use of the




Ringelmann  chart is discussed in a Bureau of Mines Information




Circular  and in EPA Field Operations Manual .




(3)     Investigation of odor potentials  of emission  sources





       •       Plant Inspection   - On suspicion of odor nuisance





emissions,  an inspection may be undertaken supplemented by





                           272

-------
source testing for evaluation of the odor potential.  As soon as





practical after identifying the suspected source of odor emis-





sions, the field officer should enter the refinery: (1) to gather





the evidence needed to prove that the violation has occurred, for





example, that someone discharged into the atmosphere,  a con-





taminant in greater  amount or density than allowed  and for mo re





than the  specified time; (2) to determine the  cause:  and (3) to





ascertain the necessary corrective measures.





               By proper interrogation,  the field officer  should





establish the circumstances leading to the emission violation.





He should be alert for observations he can make to  verify the




accuracy of the statements made to him.





               Next,  if not already a part of  the plant record,




the equipment data are obtained.  These  should include the make,





type,  size,  and capacity of all equipmenfor  processes involved.





General  conditions bearing on the air pollution potential of the





equipment should be noted.  Observations  should be made of





gapes and monitoring  instruments,  particularly temperature





charts on incinerators, and load charts on boiler instrument





panels.   Information on operating failures which lead  to exces-





sive emissions is being published in the technical literature.





Much can be learned from process  studies which identify





operating conditions that  cause high pollution discharge.
                         273

-------
       •      Evaluating Odor Concentrations -  If the odor



being investigated has been identified as caused by a known



odorant, its concentration should be measured by chemical or



physical means  in the laboratory.   This is especially true when



the known odorant also has toxic or irritant potential,  as in the



case of hydrogen sulfide,  sulfur dioxide,  ammonia, chlorine,



and various aldehydes.  In many such cases,  the criteria for



acceptable concentrations in ambient air are already estaUished



in terms of mass concentrations which  are lower than odor



thresholds, so that evaluation in terms  of odor units is super-



fluous .



              However,  when the odor  nuisance  is the only



suspected effect, or  the identity of the odorant is in doubt, or



more specific methods of measurement are unavailable, the



samples collected at the  source should  be evaluated by an odor


                               8
panel using dilution techniques.



(4)     Relating source strength to control requirements -  The



contaminants  responsible for an odor should be controlled so that



threshold levels are  never reached in the outdoors. Some indus-



tries assume  that they have no odor problems, because  they con-



sider discharges from their processes  to be unobjectionable or



even pleasant.  However,  the  presence  of any odor which per-



sists and is not  normally associated with the daily  routine of



living will  be  a  source of annoyance to the neighborhood.



                           274

-------
       The odor evaluations of source samples provide esti-





mates  of odor concentrations in terms of odor units per unit





volume.  These estimates can serve as guidelines  in the  devel-





ment of control methods.  Thus, if a stack effluent is normally





diluted by a factor of 1, 000 before it arrives at a breathing level





in the  surrounding neighborhood,  an odor  concentration of 1, 000





odor units per  standard  cubic foot  could be considered to be on





the verge of acceptability, while an odor concentration of 10, 000





would  require at least 90% control.





       This sort of guideline can be refined by calculating an




odor emission  rate in odor units per minute.  This is equal to





the product of the odor concentration and the volume rate of the





stack exhaust,  in standard cubic feet per minute.





       Dilution factors required for positive control can  be





estimated either by surveying ambient air in the vicinity  to de-




termine the maximum odor concentrations observable or by-




standard engineering design  procedures based on plume dilution





equations or  community experience.  It should be  remembered





that dilution of odorous gas to the median  odor threshold  level





can be expected to render it  undetectable by only about half of





the people  in the community; therefore the use of an additional





safety  factor in design for positive control is advisable.   Also,





dilution factors work better  near the source and tend to break





down with distance.






                         275

-------
       An application of odor measurement in improving neigh-


borhood odors would be to survey all the operations in a plant


and determine the odor emission rate from each.   Listing such


emissions together with estimates of costs for control can help


management pick out the  largest odor sources  (rather than the


largest stacks or largest volume discharges) and concentrate


effort initially on those which are likely to provide the greatest

                                       Q
improvement per dollar of expenditure.



c.     Management Interview - The purpose of the management


interview is to obtain from management and supervisory per-


sonnel the identification of processes and equipment as possible


sources of pollutant emissions,  preparatory to making the de-


tailed equipment inventory.


       In particular,  the field enforcement officer should obtain:


       •  business and ownership data, including former


          owners,  .and responsible management personnel


       •  plot plans  showing disposition of all major units of


          the facility


       •  flow charts for each major processing unit, indicating


          purpose,  operating  conditions,  and normal processing



          capacity.


The FEO  should  determine what procedures are employed to


control or eliminate  the discharge to atmosphere of noxious or



malodorous emissions through the purging or depressurizing of



                           276

-------
tanks or vessels.   These procedures may include the instal-





lation of special instrumentation, high-level or high-pressure





alarms,  liquid knock-out drums on fuel gas systems, pressure





relief or manually  controlled discharge from process equipment





to blowdown vessels of either variable or fixed capacity which





are served by vapor recovery compressors,  flare systems, or





both,  and fixed roof tankage tie-in to properly sized vapor





recovery or fume disposal systems.





d.     Process and Equipment  Inventory - The  initial





process and equipment inventory may be developed from




information acquired through administration of a permit





system or a source registration system or from  direct inter-





views and conferences with management personnel.  It  consists





of complete records of all equipment and processes  capable





of emitting air contaminants that are located at all facilities





within  the jur i sdictional area.





       Inventory of equipment is called an  equipment list.





This list enumerates al] items capable of emitting air





contaminants that are located at a  given  refinery and thf





status  of that equipment with respect to compliance with the





permit system and  the  rules and regulations.





       In preparing equipment lists, the agency  should





consider using the  format of procedures devised  by the
                          277

-------
       Environmental Protection Agency for the National Emissions


       Data System (NEDS).  Equipment and process classifications


       readily usable for an automated data processing system have


       been enumerated which may also serve as an aid in preparing


       equipment lists.   Complete details  of this system are con-


       tained in the EPA Guide for Compiling a Comprehensive


       Emission Inventory.


2.      Physical Inspection and On-Site Testing


       a.      Preparing for the Plant Visit  -  The objectives of


       the field enforcement officer are not only to determine which


       elements  of the operation are governed by rules and regu-


       lations, but to determine as well the degree of  compliance to


       them.   His inspection procedures are adapted to the specific


       air pollution regulations  that apply to the type of unit being


       inspected.  All refineries have standard safety procedures for


       employees and visitors.   These procedures also concern the
             • "%,

       field enforcement officers.


       (1)     Review of records and regulations  -  Prior to the


       physical inspection,  the field enforcement officer should review


       and organize the records  contained in the field  file.  He should


       determine what specific rules and regulations apply to the


       operations of the facility to be inspected and he should be
                                  278

-------
prepared  to furnish appropriate copies or extracts of these





regulations to the management of the facility.





       On the occasion of the  initial physical inspection,  the




field file for the facility should contain the equipment list, plot




plans,  flow charts and auxiliary information furnished by





management in the interview phase of the inspection.   At this





stage,  the file will probably be incomplete, and a major objec-





tive of the physical inspection is to fill in the gaps and pin-point





problem areas.   The visit will also be the subject of an Activity





Status  Report on findings and recommendations.





       Because of the operational complexity of petroleum re-





fineries,  and allied activities,  a degree of specialization,  and





training and experience  is required to make an effective FEO.




It is  necessary to write  technical reports of processes and to




prepare graphic presentations  to describe the  air pollution po-




tentials of the process units being inspected.





       Separate inventory forms for  each type of equipment,





operation, process, and plant are helpful at inspections  to





ensure coverage of specific  points.   Coverage is  complicated





becaus e:





       •  Similar process vessels arc used in various source





          activities and are grouped  interdependently. Attempts





          to itemize individual pieces of equipment often lead to




          confusion and disorientation.





                          279

-------
       •  Air pollution potential can be better determined from




          an inventory of functions of process vessels than





          from itemization of equipment units. Process inven-





          tories may also require field surveys of product




          flows, throughput capacities, and emission factors.




       •  Refinery and chemical plant inventories thus cate-




          gorize, itemize, and present such data as will





          directly determine compliance not only with permit





          regulations but also with equipment regulations.




       To make these data readily available, a special inven-





tory system should be adapted for each refinery.   To cover each





of the multiple operations of a refinery adequately, the plant





area is subdivided into process units-.  (Units with the gfeat'S-st





air pollution potential are subsequently assigned more frequent




inspections. )





       Plant ownership data is recorded  separately on a Plant





Card.  It is most important to know who the responsible officials





are and how they can be quickly contacted.   Where accurate





field data exist  in the inventory  files, it is  possible to make a




preliminary investigation of refinery problems by telephone.




       The  inventory records for each refinery consist of a




group of file folders,  each  folder dealing with a single process





unit.  The folders are numbered  and filed sequentially.  As one





or more process units may constitute a source activity, an index





                           280

-------
of source activities cross referenced by folder number is main-





tained at the head of the file.





       A  source activity folder contains:





       •       A general description of the process and an





       analysis of its purpose and function in the processing





       sequence.   Generally,  the analysis traces the flo\v of





       materials  from introduction through various sidestrearns





       to final effluents.




       •       A list of pieces of equipment contained in the





       process unit and their function.




       •       A discussion of the air pollution potential of





       the process or equipment including an analysis of any





       important  problems and,  if possible, estimates of the





       contaminants emitted and their chemical designations,





       odor quality and  intensity, opacities, or physiological





       effects,  as well as the  potential hazards of the stocks





       or products released should equipment failure occur.




       •       Estimates of throughput of volatile materials





       and of emissions from  known sources.   This may be




       determined from results of "material balances", e.g.,





       estimates  of sulfur  derivatives lost as  calculated from





       the differences between input and final  output.





       •       Results of any tests or analyses of effluents,





       fuels or other materials.





                         281

-------
       •      A process flow chart and plot plan, which can be




       used for reference and verification on follow-up inspec-





       tions.  These give the flow rates,  pressures,  tempera-





       tures,  etc.,  in process  vessels and lines, where neces-





       sary to estimate air pollution potential and to  locate




       points  of emission.





       Flow diagrams and plot plans are of particular impor-





tance in accounting for all equipment in a  production  sequence





which otherwise might be overlooked.  They are  of value in





showing the potential of an existing production system for





growth or change.  They also show the capacity for such systems





to accomodate increased production.  Comparison of the flow





chart and plot plans with conditions existing at a  later inventory




reinspection will show  exactly how the process may have




changed.




       Flow charts  and plot plans are drawn according to con-




ventional  engineering rules.  Pertinent liquid or  gas  feed lines





are shown and gas or liquid  effluents indicated.   Overhead dis-





charge and drainage from columns or vessels are generally





shown by  vectors indicating  method of disposal.  Features not





essential  to the understanding of the air pollution problem are





omitted.




       The flow lines are clearly labeled  and vectored as to





direction  and  content, for example:  "Refinery Gas In",  "To





                            282

-------
Fuel Gas System", and "To Oil-Water Separator".  The process





lines indicate whether the flow originated in, or entered at the





top,  side, or bottom of columns or equipment.  Functions of





equipment and columns should be clearly labeled, unless they




can be depicted  by symbols (such as heat exchangers ,  and con-





densers, and by plant number).  It is of utmost importance in a





flow diagram to illustrate clearly all sources of air pollution,





including stacks,  flares,  and pressure relief valves, and to





identify the  problem areas and the contaminants which may be




emitted. Process vessel and line  operating  conditions  recorded





on pressure  and temperature gages, manometers,  continuous





recorders,  and  relief valve pressure settings should be





indicated wherever pertinent.





       A sample of an Activity Status Report covering a sour





water treatment and disposal plant and accompanying flowcharts





are shown in Figures  79 and 80.  The symbols used in chart





preparation are shown in Figure 81.





       Some sources  are so routine that standard inventory




forms are used  to .report them.  These in chide bulk plants,




truck loading facilities,  oil-effluent water separators,  tanks,





and natural  gasoline plants.   Examples of these forms and the





Activity Status Report arc those used by the Los Angeles County Air




Pollution Control  District.
                         283

-------
                     ACTIVITY STATUS REPORT     M.R.No.
Firm Name:  Sunrise Oil Company,  Inc. , Unit II	Sector:  1 3

Address of Premises:  1325 Court Street	 City:	
Responsible Person Contacted:  J.  R. Hicks	Title: Plant Engineer

Nature of Business:   Petroleum refining	

  Assigned Inspection        New Activity      Change of Status

Description   General Usage   Name of Equipment - System or Process

Inspected:   Sour water oxidizing unit - Unit II	



Field Enforcement Officer;    J. R. Hardy	Date:  10-15-59

FEO's Conclusions and Recommendations:  The odors detected at this

time were not great enough  to result in a public nuisance.  This unit

remains, however,  one of the greatest potential sources of odor prob-

lems in this refinery  since it comprises the processing area for sour

waste  water containing malodorous components formed during the

cracking operation.

      Modifications made for compliance with Rule  62  have reduced the

possibility of excessive SO2 emissions from the vacuum heater.  Since

the materials processed are both highly  malodorous and corrosive,

the present inspection frequency of three times per year should be

continued to insure adequate maintenance.

Figure 79 .   Activity Status  Report from an Inspection  Made of a Sour
             Water Oxidizing Unit at an Oil Refinery (from Los Angeles
             County Air Pollution Control District).


                                  284

-------
FEO's Findings:  The purpose of this unit is to deodorize the  sour





water pumped from the accumulators at the crude,  thermal, and





catalytic cracking units.  This consists of the following equipment:





      (1) a 10, 000 barrel cone-roof tank, (2)  a neutralizing column





tower, (3) a waste-water stripper,  (4)  an aeration column,  (5) a waste-





water cooler, (6) a sour water degasifier drum, and (7) necessary





pumps,  piping, and instrumentation.  These are shown in the attached





flow diagram.





      The sour water is pumped from the accumulators to the degasi-





fier drum.  The gas removed from this drum flows through a back





pressure regulator valve to a low pressure H2S removal  plant.





      The sour water and waste caustic are collected in the 10, 000 bbl.




capacity tank venting to the vapor recovery system.





      The sour water is pumped from the tank to the neutralizing





column where it contacts 98% sulfuric acid.  The mercaptans released





from the water by the sulfuric acid, along with other waste gases in





the overhead line from the caustic  regeneration unit,  are condensed





and fed into the cracking unit for conversion to H2S  and recovery.





This accounts for the disposal of most  of the  mercaptans in the  system.




      The neutralized water  is then pumped to the waste-water





stripper,  and live steam is introduced  in the  column to strip out H2S




and mercaptans.  Sweet gas  with 7 or less  grains of H2S  per 100 CF







Figure 79 (continued)  Page 2 of 4.







                                 285

-------
from the secondary scrubber at the H2S removal plant is introduced




into the bottom of the stripper at the rate of 350, 000 to 500, 000 CF/D




to sweep the released gases from the water.  This sour gas from the*




stripper goes to  the H2S absorption plant.  A pressure relief valve on




the stripper vents to the flare.




      The  stripped water then flows to an aeration column where it is




contacted counter-currently with an air stream and caustic and is




oxidized to non-odorous thiosulfate.  The resulting foul  air from this




vessel is sent  to the  firebox of the vacuum unit heater for deodorizing.




The water flows  from the bottom of the serator through  a cooler to




the covered waste-water separator.




      Prior to the introduction of the  air pollution  control program,




the principle sources of air pollution  at this unit resulted from the




introduction of (1) mercaptans from the neutralizing tank to the burners




of the vacuum  unit heater,  and (2) the H2S from the waste-water




stripper column  to the refinery fuel gas system.  The APCD test




team determined that previously 0. 5 ton/day of H2S was contributed by




this unit to the refinery fuel gas system.  This is equivalent to a loss




of 2, 000 Ibs/day of SO2 to the atmosphere.  After studying  data




disclosed by extensive physical inspection, testing, and industrial




cooperation on waste gas streams throughout the refinery,  Rule 62 was




introduced to control those  waste gas streams to be incinerated and







Figure 79  (continued) Page 3 of 4.







                                 286

-------
containing significant quantities of sulfur derivatives.  To comply





with this rule, this refinery adopted the  following solutions to meet





the problems  resulting from its particular operating methods:





      a.  Enlarged its H2S absorption facility.





      b.  Made provision for introduction of condensable mercaptans





          into the cracking plant for  conversion of H2S and its





          eventual recovery.





      The waste gas stream now burned  in the  vacuum unit heater was





found to comply with Rule 62 during  a test  conducted by  the APCD test





team on 10-13-59.





      Negligible mercaptan odors were noted in the  vicinity of equip-





ment at this time.  Equipment was in good condition and operating





under permit  conditions and requirements.  No visible emissions





were observed at this time from the  vacuum heater. A  sample of





treated water taken from the cooler  (after  oxidation) was free of





noxious odors.
Figure 79 (continued)  Page 4 of 4.
                                 287

-------
              PMBUM
              VACl'W VAlVf
                                                                                      , VAfO« UlCOVtin
                      lUTt
                      H.O 1MK
                      ROM
                       ew. i
                                  ,»
                                  1
                                  1
                10UH NjO
              IIUI OF KOI
              xmoultccuu
    TO
    lit "CAM All
    oisrosAi
    UNIT.
:•   PVVPH.

iTf
MTJOI ---J
r
yy
«v

OiTOVr«>M
II
1
ir nines
TO* Ait
J_
«
T>
H..UA.

 >luin
 C-IV
           f(«»f

           Lf Hj!
                                                       TDCRACXMO
                                                      » WIT

                                                      » ru«
                                                      » i.r.n^

                                                       VAC HIATM
                                                               TOW WO
                                                               Wt
                                                                      U . rUkHTAJH
                                                                                          TOCOVCMD
                                                                                          • Hit MICH
                                                                                          HPMATM
                             tun IATK
                             SIHIPPH
                             r.nx
                                                                                   COOK*
                               roiuwc-ut
*-* "S
FLOW DIAGRAM
..urnrtrri-nt Sunrl" ou ^3^^, Inc. tm,in IV5 C«,rt .t«.l


r.i, ,«pirnn 10, l>/\9 KEO J-*- "'"'J'
-

REVISIONS
VJA0 ojd?7



Figure  80.   Process  flow diagram of a  sour water oxidizing unit (page 4  of the

                Activity Status  Report).
                                                     288

-------
    SYMBOLS USED IN PETROLEUM FLOW DIAGRAM*
    XJ
I (S»
 ©
vV

©
©
TYPES OF FLOATING ROOFS
Chart Number Two
                                              10
                                              1L
                                                 ftr
                                                 ft>
                                                                      cjl
                                                                             DOVBK 0(CK
                                                                            POMOV. 1ITHOU1
                                                                            CfMHPCmOOH
                                 i 0!C<
                                 MOCi «iih
                                 Mt< 4(lC«T
                                                                            |l>'l .ili .UT
                                                                            CI'.HH PU11COK
                               vf.iiutio
                               PO »
                               MllUttO
                               PI'. >MH
        Figure  81.  Symbols used in petroleum flow  diagrams.
                                        289

-------
       •      Bulk Plant Data   This inventory form (Figure 82)





is used to record data obtained from inspection of loading racks,





storage tanks, pumps, vapor controls, and associated equipment





located at bulk plants.  Bulk plants are used to store and distri-





bute various petroleum products and may be found at airport





facilities,  distributing centers, marine terminals,  etc.  The





form is used to emphasize degree of compliance in equipment





and operation with the applicable rules.   This  Bulk Plant Data





Sheet presents a master inventory for each bulk plant.





       •       Truck Loading Inspection Data Sheet -  An





inspection sheet (Figure 83) is  made for each trxick loading





facility.  It lists the  number of racks and spouts, the permit





status of  each  rack,  and throughputs of tank truck loading racks.





               From this form,  the total losses of hydrocarbons





are  determined using the following emission factors:





           »    Emission of hydrocarbons in gallons from



               uncontrolled equipment - Approximately 1/10



               of 1 percent of the average gallon throughput



               per day.





           •    Emission of hydrocarbons in gallons from



               controlled equipment   8  percent of the



               above.





        •       Oil-Effluent Water Separator Inspection  The





example shown in Figure 84 is  of a single refinery  oil-effluent





water separator which derives  its influent from treating vessels,







                           290

-------
                         BULK PLANT DATA

Name   Sunrise Oil Company	Date   12-1-56
Address  1325 Court Street	Conversation with    H. Smith
No.  of Storage Tanks   6	No. Storing Gasoline    3	
Reid V. P.  of Gasoline 11  IDS. Av. Gal/Day   49, OOP
Max. Gal/Day   58, 500	 Plant Throughput  980, OOP  Gal/Mo.
Units Loaded/Mo.     150	 No.  of Loading Racks     2	
Length of Racks    20 ft.	
Loading Schedule     12	Hrs/Day	5	Days/Wk.
Peak Operation Hours: 	6-11 A.M.	
No. of Filler Spouts:	2
Method of Filling (% splash and/or bottom fill) Through vapor closures
Rate of Filling	250	Gal/Min.
Vapor Recovery on Loading:  Yes (x) No( ): If Yes,  Type  Vapor	
	absorption system	
Possible Sources of Vapor Loss;  Filling and breathing of storage tanks


No. of Tanks Under Rule 56   3   No. of A. P. Controls Floating roof.
Fill out tank data summary forms on these tanks.
Remarks:	Used for blending stocks.	

No. of Sumps	1	No.  of Slop Tanks	1	
No. of Separators None	No. Under Rule 59	None
Fill out Separator Inspection Forms on All of Above.
Remarks:
Actual Loading Rack Total Hydrocarbon Losses    20	Lbs/Day
                               FEO       <2-  A? /
                                                      J
              Figure  82.   Bulk plant  data sheet.


                                291

-------
            TRUCK LOADING INSPECTION DATA SHEET
CO* ANY
Sunrise Oi 1
Conp any
•'
'•
••
-^^V_
LOCATION
1325 Court St.
Onyx, Calif.
"
'•
••
^^J
RACK
NO. OR
NAME
1
2
1
2
	 --'
GAL/DAY GASOLINE
TO TRUCKS
AVERAGE
23,000
26.000
24,500
26.000
^V.
MAXIMjM
28 , SOO
30,000
47.000
30,000
— 	 	
SPOUTS
TOTAL
s
6
S
7
^•\
OVER
4«
RVP
2
2
2
2
	 J
UNDER
40
RVP
3
4
3
S
^- — »».
RULE
61
S
2
2
2
\
PERMIT
STATUS
A-7432
A- 473 3
A- 473 2
P.R.
^^
RECHECK


7-8-59
7-8-S9
^- 	
DATE
CONTROLS
FIRST
USED
12- 1- 56
t t


^^
INSPECTED
BY
J.R.H.
J.R.H.
J.R.H.
J.R.H.
_. 	 ^
Figure 83.  Truck loading inspection data sheet.
                            292

-------
             OIL-EFFLUENT WATER SEPARATION INSPECTION

 Company   Sunrise Oil Company	Date  12-1-59
 Address   I 325 Court St. f Onyxp Ca.   Conversation with   H. Smith

 Designation of separator  Oil-effluent water separator	
 Description  A reinforced concrete basin consisting of one primary
 and three subsequent compartments separated by wooden curtain walls
 with primary compartment  covered by floating roof.	
 Method of  skimming  4 -  2" swing pipes manifolded to 4" suction line

 Size of inlet & outlet  12" dia. inlet and outlet	
 Location of separator   At  #3 treater area in south area	
 Size:  Length  47'11"	Width 2Q'-10"      Depth    10'	
Description of A. P. controls  Floating roof on primary compartments
Primary compartments, No. & Size   11' x 20' x 0'
Subsequent compartments. No.  & Size   Three 11' x 20' - 10" _

Oil on surface   3" _ Temperature   90" _ Odor  Moderate
Quantity & disposition of oil  300 bbls/day to oil  recovery facility

Disposition of water & estimate of quantity  15,000 bbls/day to _
_ drainage  system _
Sources of oil & water  From treating shells at FCCTCCU south
 tank farm -t-2243 and alkylalion plants _
Quantity of oil & water from each source  Major  source: _
  cracking area _
Oil sample
                                    .E.O.   JjL Vp.
    Figure  84.   Oil-water separator inspection sheet.
                                293

-------
south tank farm, thermal and catalytic  cracking units, and





alkylation plants in the general cracking area of the refinery.





The  influent wastewater is  traced on the flow diagram by the




inspector.  The dcsc ription of the controls,  (i.e., "floating roof





on primary compartments") and other information indicates





whether the equipment is in compliance with pertinent rules.





        •      Tank Inspection Report - This inventory form





(Figure 85) records the type of tank,  vapor control,  function,





dimensions,  products stores, Reid vapor pressure,  storage





temperature, etc. ,  of each tank to determine compliance with





rules.




        •      Data Sheet for Natural Gasoline, Gas,  and





               Cycle Plants -  This form (Figure 86) is used to





inventory plants located  away from refinery facilities but near





crude oil production facilities.  Information to be recorded in-





cludes  the status of tanks and separators subject  to emission





control regulations.




        Another aid to the field enforcement officer is the infor-




mation incorporated in applications to operate the equipment.





The permit status  of equipment should  be  routinely checked to





detect  any changes in equipment  or process that might invalidate





an existing permit or conflict with variance conditions.





        The factors affecting the  permit status are (1) change  of





ownership, (2)  change of address,  (3)  new construction of





                            294

-------
NO
                                                                             AREA  GRID NO.   8 TRJ
                                                                                                          M.R.NO. _fii
u
FIRM NAME l/ii Aniylrs tYlrolfim, Gsrpany (
AonRFSs OF PRFMISFS 12W, s. Oil iioj.i
NATIJRF OF flllSINF•
30'
12'
30'
sr
IS' 1
Si'
Dia.
30'
30'
CO1
40'
HO1
11'
401
Type
c
c
c
c
F
11. P
F
Gen.
Cond.
G
G
G
G
G
G
G
Product
Stored
G-isoline
Sieve Oil
..
\vialion Gnso.
(in^ol inc
n-'litane
Dl.icl
RVP
(lb.)
9
t^ftt.

6
9
50
nrrl.
Prod.
Stg.
Temp.
Mbient
1 1

airhirnt
..
..
•'
Service
*tor*R«
i«
..
%i nrm*?
..
..
'•
Vapor
Control
vn
N
N
V»
F (SS)
PVV-W
F (SS)
Permit
Status
IVIr 13
U.Ic ll-K-5
n.,ic )3
n-,u 13
«10002
• 104AJ
Uil- ll-h-3
/tl^l-K-S
Rules
Affected
RuU 10. S6
None
Non-
nil <• 10 V.
It.l* 10. V,
None
IV fe 10
Remarks

No. off
Vnoor llrrnvrrv
Tc«^wr»rily
nil nf vr
-------
            NATURAL GASOLINE, GAS, AND CYCLE PLANT
                         SURVEY SUMMARY

Company  Sunrise Oil Co. of Calif.. Inc. + 3   Date   3r28-56
Address  1400 Bliss St.	City  Onyx, Calif.	
                                   Phone RA 6-3251
Information by  L.  M. Black	 Title Production Engineer	
Type of Plant:  natural gasoline (x): Absorption (  ), Booster (  ),
Other  ( )      Specify:   Gasoline plant	
Source of material  process Wet gas from oil wells	
Total No. of wells	
Throughput:  Wet gas   20    mm SCFD:  Dry    2	mm SCFD
  Natural gasoline  (bbl)475/day  Propane (bbl)    0	
  N-butane(bbl)  0	Butane-propane mixture  (bbl)	0	
  Isobutane(bbl)	
Boilers: Number   5   , Type hrt   Heaters: Number  2   Type steam
         Type fuel  Plant gas	Source   Plant  residue	
         Quantity of fuel used   400 MCF/day	
Is flow diagram available^	Can it be obtained?	
Storage & handling:
          Tanks                 Oil-Effluent Water Separators
  No.  of Tanks    8	    No. of separators	1	
   Vapor recovery   3	    No. questionable	None
   No. under rule 56 None     Type of control	None
   Pressure •    4	    Floating roof   None
   Other (specify) 1  cone	   No. under rule 59   None
   No. controlled 1            No. controlled under rule 59  None
                              Totally enclosed   None
                              Vapor recovery system   None
   Other (specify)   None
 FEO's remarks re equipment & plant conditions:   No leakages.
 _ No losses noted.
FEO
                                         >Li  K-
                                        u
 Figure 86.  Natural gasoline, gas, and cycle plant survey summary.
                                  296

-------
equipment,  and (4) alteration of equipment.  The equipment list





is constructed to provide reference data which will enable en-





forcement officers on inventory reinspections  to determine





whether the permit status has changed.  Any untested equipment





found in the plant,  capable of air pollution will require a permit.





        Similarly, alteration of equipment is frequently detected





by discrepancies in the  equipment description  or on the flow-





chart or by changes noted on engineering applications in the




permit file.





(2)      Review of safety precautions and procedures -  The FEO





is accompanied to the unit or units to be inspected by the  air





pollution representative within the plant or by  such other  in-





formed refinery personnel as he might indicate.




        Personal protection  is necessary in many of the indus-





trial locations that an enforcement officer may be required to





visit.  Safety equipment such as hat,  goggles,  steel-toed  shoes,





ear plugs,  heavy gloves, gas masks or respirators, and safety





flashlights should be available.   The field  enforcement officer




must never  enter a plant without the proper safety equipment.





        The  following is  a list of do's  and don'ts for field enforce-




ment officers to adhere  to during refinery inspections.



        1.  When entering a  plant to make an investigation, do





ENTER and leave by the MAIN GATE or GUARD POINT set up





by company regulations.  Comply with company SECURIT Y RULES






                        297

-------
by registering and wearing  a BADGE OF IDENTIFICATION if





requested to do  so.





       2.  Do wear a head  covering while in a plant,  preferably





a HARD SAFETY HAT.





       3.  Do wear RUBBER GLOVES, when necessary,  such





as when  sampling strong acids and alkalies,  a RESPIRATOR in





an atmosphere of heavy dust or gases, GOGGLES to protect the





eyes from caustic solutions, flying particles of steel, sand, and




hot oil.





       4.  In areas containing noxious gases, such as hydrogen





sulfide or  hydrogen fluoride,  a respirator should be worn unless




the gas previously has  been tested by an MSA DETECTOR and





has been found to be below the toxic  limit.




        5.  In the event of FIRE in the  area of your inspection,




do immediately LEAVE, and remain outside the area until the




 "ALL OUT" signal is sounded.




        6.  When inspecting an area where inflammable liquids





are being processed, do make certain that there is an avenue of




escape before starting  the  assignment.  Look around.  If the





area  appears to be unsafe,  leave it until you are assured of its




safety by someone in control of the area.





        7.  When working in an area where strong acid or caustic





solutions are handled,  do note the location of the nearest water




shower for quickly washing off a person accidentally sprayed






                           298

-------
with these chemicals.





       8.  If your clothing becomes sprayed with light oil such





as kerosene or gasoline,  do change clothing as soon as possible





to prevent damage to skin from contact with the oil and to elimi-





nate the hazard of the clothing catching on fire.




       9.  Do use the buddy system when taking a sample or





gauging a tank of volatile or gaseous hydrocarbons.  The Field





Enforcement Officer should be accompanied by another person





and the two persons should  remain together until the job is





completed.





       10.  If about to  sample a tank, do make certain that all





equipment is in workable order before leaving the ground.   The





uncertain perch atop of a high tank is no place to untangle a line





or to force a stubborn bottle in or out of a sampler.





       11.  Do not smoke or carry "strike anywhere matches "or





cigarette  lighters which ignite when dropped within an oil re-





finery.  Most plants allow smoking in the main office and certain





approved  areas with permission of management.





       12.  Do not open or close VALVES, or start or tamper




with any  equipment.





       13.  Do not enter a tank or other confined area where





gases may be present unless equipped with  a GAS MASK and an





ASSISTANT is in attendance outside.  Make use of  the EXPLOSI-





METER to determine the quantity of hydrocarbons present.






                        299

-------
      14.   Do not ascend to the ROOF OF A TANK or other





large vessel in the course of an inspection unless accompanied





by a company representative,  except when you have his permis-





sion to proceed  alone.  Do not step or  walk on the roof of a tank





unless planks have been laid to distribute the weight of the body,





except advised otherwise by the company engineer.





      15.   Do not poke a flashlight into an open tank hatch or





confined area and snap it on.  The light may be defective and an





explosion might result.  It is better to turn the light on away





from the hatch and bring it no closer than necessary.  Only





approved  safety flashlights will be used in oil refineries.





      16.   Do not place the  face close to a  tank hatch and peer





inside to get a better view unless someone is close by to offer





assistance in case the gas happens to be toxic.





      17.   Do not watch a welding torch in  action.   Failure to





observe this precaution could  result in painful eye  burns.





      .18.   Do not use petroleum distillate or benzol to remove





grease from any part of the  body unless  the action  is followed





by a thorough rinse with plenty of  soap and  water.  This pre-





caution may  prevent a serious case of dermatitis.





      19.   Do not enter into the immediate area of a flare which





might go off  at any moment  and scorch everything within reach.





b.    In-Plant Inspection and Testing - After the preparatory





review and paper work have been completed,  the FEO undertakes





the m-plant inspections.



                          300

-------
      For gathering evidence in the field, it is useful to include





in an inspection kit:  binoculars,  camera, stop watch, flashlight,





maps, compass, smoke tube, and the required forms and regu-





lations.





      Cameras are used primarily to photograph excessive





emissions from stacks and vehicles and to photograph equipment





and  operating personnel for identification purposes.  Cameras





which permit rapid development of photographs at the site of an





investigation are especially useful.   Moving picture cameras





may be desirable for special investigations.





      Stopwatches should be of the accumulative type for use in





recording total time of excessive  emissions within a given period





of observations.




      The actual techniques which may be used in any given




inspection depend xipon the  specific information to be gathered.





For  a complex facility such as a refinery, completing the initial





inspection may require a number  of visits.  To optimize the





efficiency of the total inspection,  individual trip objectives





should be planned in advance.  Among the inspection techniques





which may be  useful are:





(1)    Sensory observations - Sensory evidence, such as visible





discharge and odors disclosed by  thorough physical inspection,





may be sufficient to determine noncompliance or equipment





breakdown in the cases of Ringelmann number readings or excess





                           301

-------
hydrocarbon vapor discharge from vapor controlled tankage,





for example.  However, in other situations,  sensory evidence





may only be a preliminary or corroborating  step to a broader





investigation, either because the regulations affected call for





evidence not obtainable in this manner (e. g. , percentage sulfur





in the fuel oil,  t^ S grain loading in gaseous  products burned





and  its Btxi value, weight of particulate discharge,  concentration





of SO2 in discharge of flue gas) or because the control  equipment





does not discharge a waste effluent directly to the  atmosphere.





In such cases,  the inspector must either rely on data indicating





temperature, density,  pressure,  vacuum or throughput recorded





on gages,  continuous recorders, high level or density  alarms,





voltmeters and  ammeters, or he must provide for special





testing.





        Emissions caused by leakage  are primarily recognized





by sensory evidence.   Their detection depends on  the ability of





the  field enforcement officer to recognize odors and trace  them





to their points of origin.  Probable points of origin within  refin-





eries include pres sure-relief valves, storage vessels, bulk-





loading facilities,  pump glands, pipeline valves, flanges and





blinds, and cooling towers.





        The t'EO must  also note any visible air turbulence





caused by light hydrocarbon leakage,  frosting of valves or





pump glands caused by light hydrocarbon evaporation,  liquid





                           30Z

-------
leakage, local area discolorations caused by vapor condensate,





visible emissions or changes in flow (surging)  of an emission,





extinguished flare pilot lights or detection of audible gas leaks.





These may disclose a violation or a potentially critical  situation





that  should be corrected quickly.




      Visible plumes must be noted and their apparent causes





recorded for further investigation. Plumes may be caused by





incomplete combustion of waste gases  in flares,  by dust from





catalyst  regeneration operations,  or by breakdowns in various





process  unit operations.





      The field enforcement officer inspecting  refineries should





thoroughly survey the vapor recovery systems and the facilities




for gathering and processing (sour water, wastewater,  sour gas,




spent caustic, and acid sludge). Even though in a modern





refinery most of these streams are treated, their extremely




noxious and malodorous characteristics make even the most





isolated  uncontrolled stream a potential air pollution problem.





      Wherever possible, the inspector should point out condi-





tions having  a high pollution potential  so that the  refinery's tech-





nical staff may have the opportunity to assess the problem and




solve it.   More  effective use of existing control equipment may




be achieved by extending its service to as many uncontrolled




sources  as is possible without overloading its capacity.
                          303

-------
      The inspector may find





      •  isolated streams  of sour gas fuel untreated for H2S





         removal and recovery





      •  sour water discharged to open drains with live steam





         which has not been first deodorised by processing in





         sour water oxidation or H2S stripping facilities





      •  odors and hydrocarbons emitted to the atmosphere





         from oil-water separators





      •  malodorous or  noxious acid slxidge stored in





         uncontrolled tanks, which release fumes  and odors





         due to breathing and filling losses,  or loaded  into





         tank cars and trxicks with similar results.





(2)     Observing process instrumentation   The process flow





charts obtained from plant management in the preparatory phase





of the survey should be annotated with operational information





relevant  to emission evaluation.  Operating conditions may be





indicated on pressure and temperature gages,  manometers,





continuous  recorders, and other devices.  Recording the pres-





sure settings for relief valves can be useful.





(>)     On-site testing    At times,  the enforcement officer will





be called upon to make quick and sometimes crucial, estimates





of air pollution problems in any environment.  While he cannot





make accurate determinations of concentration on the basis of





sense perceptions only,  he may be able to identify  pollutants,






                           304

-------
allow for hazardous concentrations,  and trace them to a logical





source.  To eliminate guesswork and to establish identity and





concentration within a reasonable degree of accuracy, some




field sampling equipment is  required.   Such equipment,  to be





of use in enforcement,  must be portable, require a minimum





amount of bench and field preparation,  be of a direct-reading




type,  yet be sxibstantially accurate.  Table 11 lists  a variety of





contaminants  that can be detected or measured by means of





simple portable equipment.





       Noxious gases,  odors,  vapors and phenomena  for which





tests  can be made in  the field and which require no collection of




samples for laboratory analysis are aldehydes,  ammonia, aro-





matic hydrocarbons (benzene,  toluene,  slyrene, xylene) atomic





radiation, carbon dioxide, carbon monoxide,  chlorine, com-




bustible gases and  vapors, organic halides, humidity, hydrogen





cyanide, hydrogen  sulfide, mercaptans, oxygen (deficiency),  and




sulfxir dioxide.





       Certain types of  sensitized papers will change  color in





the presence of physiologically significant concentrations of




certain noxious gases,  fumes,  and dusts.  These can be vised to




test for or to  verify the  existence of certain suspected contami-




nants such as  ammonia, hydrogen sulfide and phosgene.   For





example,  ammonia reacts with litmus to produce a red to  blue-





color change.   Concentrations  of ammonia from 0 to 1,000 ppn>





                         305

-------
T.ble II.   CONTAMINANTS THAT CAN BE TESTED IN THE FIELD WITH PORTABLE DEVICES
Contaminant
Aldehyde*
Ammonia
A romalic
Hydrocarbons
1. Benzene
2. Toluene
S. Xvlene
4. St\rene
A r sine
Ca rbon
Dioxide
Carbon
Monox' -if
Chlorine
Combustible
Gates
Hydrocyanic
Acid Gas
H> drogen
Fluoride
HvJropen
Sull.de
Dioxide
0:one
O r ! ; c i r n C V
rh^s^ne
Phosphmr
Sulfur
Dioxide
Reason for
Source Te»t
Eye
Irritation
Complaints
Odor com-
plaint!
Plating
Operations
E xhaust
Compla mt s
E xhaust
Compla mts
Cylinder
Loading fa
Bleach Mfg.
Venting
Storage
Tanks Odor
Complaints
Plating

Phosphate
Rock
Odor Com-
plaints
R efmene s
^. Chemical
r rocesaes

; r o m Air

Room
T herR-.al D.--
t. ompof ition
.-f Organic
MfS. of
Aretylene
Equipment Used
Absorption in
Sodium Bi*ulfite
M.S. A. Midget
Impinger
Red Litmus L Stop
Watch
M. S. A. Aromatic
Hydrocarbon
Detector
M. S. A. Arsine
Detector
Fynle CO.
Analyter
M.S. A. CO
Detector
O. Tolidine in the
M.S. A. Midget
Impinger
M.S. A. Model 40
Indicator
M.S. A. Hydro-
Detector
M.S. A. Hydro-
cyanic Fluoride-in-
air Detector
M.S. A. H.S.
Detector


F\ r . :e Ox v &;<• n

I rented Filter
Pipen
Treated Granules
M.S. \ SO detector
Treated Granules
Reic h' • Ir *t
T 'J r*' e : I f T
». Prrparation in Minutes
Time
Treatment or Required
Jodometnc Titration
10 5 10
Color Change to Blue 1 1 0
Colors. Treated
Granule*. Stain Length
Measured 10 2 0
10 2 0
10 2 0
10 2 0
Change Color 10 2 1
Absorption in Caustic
b Measure Vol. 1 3 0
Change
Colors. Treated
Granules • Color 122
Change
Color Intensity Com-
pared to Standard* 10 S 2
Direct Reading

Treated Granule*
Change Color 10 2 0
Treated Filter Papers
Change Color 550
Treated Granule*
Change Color 1 2 0
Color Change
Time Interval of
Cracking Measured ' 10 20 2
Absorption Measure
Volun.e Change 550
Color Change Com-
pared to Standards 5 S )
Color Stain Length 552
Measured
Length of Bleaching
Action Measured 1020
Gas Titration 10 10 5
Gas Titration 10 10 S
o. Test or Sampling
Concentration
0-1000 ppm
10- 100 ppm
0- 100 ppm
0- 400 ppm
0- 400 ppm
Qualitative
0- 100 ppm
0-20%
0-1000 ppm
0- 70 ppm
0-20 x LEL
0- SO ppm
.5- 5 ppm
0- 50 ppm
0- 10 ppm
u- 100 ppm
„.„«
1 - 100 ppm
1- 10 ppm
1- ISO ppm
0- 1000 ppm
50 Grams/ft3
c. Calculation
Eight-Hour
Threshold
. 5 to 5. 0 ppm
100 ppm
25 ppm
200 ppm
200 ppm
100 ppm
0. OS ppm
5000 ppm
100 ppm
1 ppm
...
10 ppm
3 ppm
20 ppm
?• ppm
10 pphm
18-21'.
1 ppm
5 pphm
5 ppm
and Interpret*!
Sufficient
Warning Without
Te.ling
Ye*. Eye
Irritation
Ye*. Odor
Ye*. Odor
Yes, Odor
Yes, Odor
Ye*. Odor
No
No
No
Ye*. Odor for
Immediately
Dangerous level*.
No. for Low Cone.
Some Yes, Odor
Ye*. Odor.
by Trained
Personnel
Ye*. Odor for
Immediately
No. for Low Cone.
No, Odor is
not reliable
Not reliable
No
No
No
No
Yes. Odor
ion
                                  306

-------
can be detected by this method.  Similarly, hydrogen sulfide





may be detected with lead acetate, phosgene with diphenylamine,





etc.




       Another detection system,  useful for various contami-




nants including  aromatic hydrocarbons, carbon monoxide,





hydrogen cyanide,  hydrogen sulfide, and sxilfur dioxide uses





glass tube ampules containing treated granules which change




color when exposed to contaminated  air.  Air is  aspirated





through the tubes  by rubber squeeze-bulbs, and the length of





the discoloration produced  is proportional  to the concentration





of the contaminant.





       Combustible gas meters, also called explosimeters,




may  be used  in  testing for high concentrations  of hydrocarbon




gases, vapors,  and other combustible gases including carbon




monoxide.





       More accurate measurements may  be made, usually less





conveniently,  with portable kits for  specific chemical tests.





Among these are gas-liquid reaction systems such as Tutweilers





apparatus (for H,S, SO2,  NH3, and CO2), Reich's test  ;for SO,





by reaction with iodine),  and Fyrite  analyzers  (for CO, and O,).




       Midget impingers incorporate a  hand-cranked  pump to




bubble air through impingcr tubes  for collection of particulate




matter or for absorption of soluble gases.   For some contami-





nants,  they offer a convenient means of gas-liquid titration, but





                         307

-------
for other contaminants it is necessary to return the samples to





a laboratory for analysis.  Fritted glass bubblers may be used





in a similar manner,  except that insoluble particulates are not





conveniently manageable with  these devices.





(4)    Grab sampling  Where on-site testing is inconvenient  or





the necessary apparatus for filtering and absorption is unavail-





able,  a simple expedient is to obtain samples for later analysis





in the laboratory.  "Grab samples" are often obtained by filling





gas sampling tubes or inert plastic bags with air by means of





motor or hand-powered pumps.  The collected air  sample is





analyzed in the laboratory.  For sampling of liquid fuels,  as





may be required to enforce fuel composition regulations,





special containers for flammable liquids are required.  Fuel





oils of low volatility can be collected in quart  or half-gallon





tins.





        Systems used for the collection of particulate contami-





nants include sedimentation and settling devices, such as fall-





out jars and gummed paper stands, miniature cyclone collectors,





blower and filter  systems,  impingers and impactors,  electro-





 static samplers and  thermal precipitalo rs .  It is becoming





more important to obtain size -discriminating  samplers  in place





of total mass samplers.





        The sampling of gaseous contaminants involves sepa-





 rating them from the air in which they are entrained.  Such





                           308

-------
techniques are adapted either to the  sampling of specific Caseous





compounds or to the determination of gross  total concentrations





of gaseous contaminants.  Specific methods are available-  for





sampling many  inorganic gases and some reactive organic com-




pounds.  Inmost cases, these methods involve   absorption by





bubbling the  air through a reactive liquid agent.  Mixed gases





are usually trapped by adsorption or freeze-out techniques.  In





any event, an appropriate sampling train must be devised,





usually augmented  by  a suction pump and a wet or dry gas meter.





(5)    Source testing  Source tests may be re-quired for  a




variety of reasons.  Among the most critical  is the establish-





ment of compliance or noncompliance of the equipment in  ques-





tion with emission  standards.  Where qualitative estimates are





nonconclusive,  the field enforcement officer will be the initiator





of the test request.  The efficiency of the testing operation may




depend largely upon the field enforcement officer's adcptness at





preparing the test request and his presence during the test to





observe the operation of the system under scrutiny.  This is





especially important  in regard to operating parameters  that





must be maintained as specified during the test.




       The request for analysis must state in detail the- operat-




ing condition of  the suspect equipment  during  the source test.




This is  necessary so that the  appropriate test procedures  may





be prepared.    Basic instructions for the test should include





                        309

-------
the points to be tested, anticipated contaminants for which the





test is run, accessibility of test points (scaffolding),  and avail-




ability of electric power near the test point.  Provisions  should





be made for portable hoods,  or other specialty items where the





equipment to be tested does not have an exhaust system.  In





summary,  sufficient data should  be made available to the team





to avoid surprises during the test.  Operating conditions  must





be defined for  the basic system and for  the air pollution control





system.





        •  Basic equipment




               Description of the type, quantity, and rate of





               material to be processed by the equipment




               during the  test




               Type, quantity, and rate of usage of fuel




               Phase of operation during which the source




               test  is to be  conducted if the process is not




               continuous




        •  Air pollution control system




               Pressure drop across the control device




                For  scrubbers  water rate




                For  electrostatic  precipitators   current and





               voltage reading, rapping frequency, operating





               temperature, gas velocity




                For  baghouses   shaking frequency





                            310

-------
                      Duration and frequency of control device





                      down-time,  if any,  during the test





               The air pollution control system must be in operation





       during the test.  If it is desirable,  samples may be taken at the





       inlet to the air pollution control device as well as the outlet to





       confirm collection efficiencies.




3.     Resurvcys and General Surveillance




       Because of the complexity of the petroleum industry,  unit pro-





cesses must be inspected systematically and regularly.   The frequency





of reinspection of any process is based upon the findings during  the





initial inspection and the recommendations of the FEO and his super-





visor.  The schedules are printed  monthly for each area or  special





assignment and forwarded to the FEO and his supervisor.  The reinspec^





tions  are scheduled  so that they can be completed within a month.  The




number of  reinspections assigned per area is based on the estimate





that all  required inspections can be completed within one year.




       The enforcement officer may have occasion to inspect plants





out of schedule because of complaints or violations.  In  these cases,





he does not make a formal inventory reinspection,  but uses the copy of





the previous inventory record  (equipment  list), from his files as a





check on status of the permit,  compliance, or other situation.  When a





specific air pollution problem  is involved,  it is best to concentrate  on





that problem rather than on the inventory  of the entire plant.   The




equipment  list  can thus be updated  during  unscheduled inspections.






                                  31 1

-------
      Vehicle patrol is the principal surveillance method.  Field





enforcement officers drive  their vehicles throughout a defined area -





such as a zone,  sector,  or  district - and major traffic arteries to





observe evidence of emissions and to detect possible violations  of the





rules and regulations.  The patrol route is  laid out to bring the  greatest





area under view over the shortest distance.





      As the enforcement officer becomes familiar with his area, he





concentrates on sources requiring the greatest attention and on areas





of high source density.   He may employ a check list of facilities that





are currently involved in permit cases,  hearing board actions,





recurrent violations, and complaints.





      a.    Updating the Process Inventory -  The process  inventory





       can be used as a tool in gathering  evidence.  This is especially





       true in public nuisance cases where it is desirable to eliminate





       from suspicion all processes or equipment that do not contribute





       to the nuisance.  In such instances, the equipment list serves as





       a check list.





            On an assigned inspection,  the enforcement officer  must





       check all equipment units  in the plant against those on the equip-





       ment list.  He is careful to note not only that all equipment





       listed is identical  in  important respects,  but that they have not





       been  replaced, since a replacement can affect permit regulations.





       This  is usually determined by comparing manufacturer's





       serial numbers.  He  also'checks  for new equipment, alteration





                                  312

-------
of equipment, posting of permits,  operation contrary to condi-





tions of permit, etc.  Any discrepancies noted are recorded in





detail on an inspection report.




       Information from the process  inventory is input to the





permit system data  base whenever an enforcement officer pre-




pares or updates an equipment list.   The data management





system then outputs data from the permit system to schedule





inventory inspections  and, while doing so,  prints out the  exact





permit descriptions of the equipment.





b.     Assessing  the  Quality of Maintenance - The effective




operation of various control systems  in a refinery is of basic





importance to efficient air pollution control.





       Reinspcctions  and surveillance afford the opportunity to




observe changes in the condition and performance of control





equipment and to detect any development of, or increase  in,




sources of leakage within a refinery.





       Cyclones,  electrostatic precipitators and vapor recovery-




plants are subject to corrosion and other destructive forces




which reduce efficiency.  In addition,  a change in process feed





or feed rates due to altered product requirements may also




result in overloading or otherwise upset operating conditions in




the air pollution control system.




       In a vapor  recovery system serving tankage, peak loads





develop in the morning hours when the heat of the sun produces





                         313

-------
       maximum volumes of hydrocarbon vapors in the space above





       the liquid.  Uneven loading schedules at tank truck loading





       facilities tend to create a similar situation.





              Since a gradual reduction in control efficiency does not





       always alter  the effective operation of the process unit,  it may





       not be noted by  operating personnel until a major breakdown




       occurs accompanied by a serious air pollution situation  consti-




       tuting a public nuisance.  It is therefore essential for adequate




       air pollution  control that such areas be inspected regularly





       and frequently.





              Proper design and maintenance of this equipment, to-





       gether with adequate housekeeping, are required for the effi-




       cient control of emissions from refineries and other petroleum





       industry operations.   It is field enforcement officers' responsi-




       bility to  observe and report,  from the physical evidence, the




       managements' degree of  success or failure in this  endeavor.







B.     ESTIMATION OF LOSSES





       Most air pollution control enforcement activity involves investi-





gating compliance with statutory regulations and abatement orders.




Regulations include  emission prohibitions and performance standards.





These standards require that the losses or discharge to the atmosphere




of specific  contaminants be determined.  Inspection of equipment for




general emission inventory purposes or for support of permit system







                                  314

-------
activities may also require that losses be estimated.





       A variety of direct and indirect techniques, having different





levels of accuracy and precision,  may be used to estimate losses in





petroleum refinery operations.  Some direct techniques are source




testing and monitoring and physical observation.   Indirect techniques





employ material balance,  related process variables, perimeter moni-





toring, and emission factors.





1.      Direct Estimation Techniques





       a.     Source Testing and Monitoring  - When performance or





       emission standards are given in allowable mass rates of dis-





       charge or concentrations,  source testing or monitoring  is





       normally used to achieve the accuracy required for enforcement.





       This does not mean that a reasonable estimate of losses cannot





       be made for a specific source when a previous correlation has




       been developed between an observation and actual test data.




              Source testing differs from source monitoring in that the




       former is limited in scope to a  specified amount of time while





       the latter is continuous.  Also,  samples extracted for source





       testing are examined or  analyzed elsewhere while samples  ex-




       tracted for source monitoring are examined in situ.   The field




       enforcement officer in a large diversified control agency nor-





       mally would not participate in source testing except as an ob-





       server of the process or of visual emissions.  In a smaller





       organization,  and depending upon his qualifications,  the  FEO





                                315

-------
     may also participate in the actual test operations.  In both



     situations, the field enforcement officer will be expected to



     initiate requests for source testing when he has reason to



     believe that a violation of a regulation exists.



             Readings from source monitoring instruments which the



     field enforcement officer may take during  on-site inspections



     can  be used to estimate losses  although nomograms or further



     calculations may be  required to convert the instrument readings



     to useful emission terms.  Most of the source monitoring instru-



     ments normally used in a refinery (see Chapter IV) measure



     concentrations of contaminants.  If performance standards are



     given in terms of mass  flow rates, the FEO must be able to



     estimate the loss rate in those terms.  Suppose, for example,



     that the emission standard was given in terms of pounds  of



     particulate matter lost per pound  of material processed,  and



     the  analyzer was calibrated in  terms of Ibs. /ft.  (at stack condi-



     tions),  then
                                 TT-   ^^

                                   = ^
     where                            ^


                    _      .         Ib.  contaminant
                    E.  = emissions,.
                                  'Ib. process weight


                                       Ib. contaminant*
                    C = concentration, —7^1	;	
                                        ft.   stack gas
                    Q = stack gas flow  rate, —-
                                         Ib.
                    Wp= process weight, ~~~
Both C and Q at the same  stack conditions or corrected to standard

temperature and pressure.



                                 316

-------
If an instrument does not measure in the units required,  then a




calibration chart will be needed to convert to the proper units.




b.      Direct Observation - The field enforcement officer uses




his powers of direct  observation of an effluent stream to esti-




mate losses at many points.  The most common example  is in




determining the Ringelmann Number of black smoke or the




equivalent opacity of any visible plume.  Also included would be




observation of liquid hydrocarbon leaks from pump seals,




flanges, and relief valves and from blind changing.  It could




include estimation of losses from flare operation, from condi-




tions in oil-water separators,  from odor intensity inside plant




boundaries,  and from fugitive  dust  (that is, dust from open




storage of bulk materials,  from uncovered materials-handling




equipment, and from unpaved roads and exposed soil).




        Training  is the key to achieving an  acceptable level of




proficiency in using observational estimation techniques.  This




requires the repetitive making of estimates which are verified




by an objective measurement procedure at the time of observa-




tion.  Opacity observations, for example,  are accepted in court.




When carried out by  a trained  observer under correct conditions,




procedures for making visual opacity determinations are to be




found in the Field Operations and Enforcement Manual for Air



                 14
Pollution  Control  and in the  EPA  Standards of Performance



        o   •      o        15
for new Stationary Sources.




                           317

-------
2.     Indirect Estimation Techniques




       a.      Data from Process Instruments - Process instruments





       are used to secure efficient and safe operation of the various





       process units in a refinery.  Where the parameter being mea-





       sured is closely related to the potential for effluent losses or to





       the efficiency of control equipment, the process instrument is a




       useful tool in the estimation of losses.




               Most process instruments are used to measure flow,





       pressure, and temperature.  Normally, a measurement per se





       may  not permit the estimation of losses.  However,  any evi-





        dence of unstable or off-limits operation may give an indication




        that  excessive demands are being placed upon control equipment





        and that losses may increase as a  result.




               There are many situations  in which pressure, flow, or





        pressure/vacuum measurements may aid in the estimation of





        losses or potential for losses.  First,  the temperature and flow





        rate of gas  entering a carbon monoxide afterburner (CO boiler)




        serving a fluid catalytic cracker catalyst regenerator unit will




        indicate whether there is sufficient residence  time and  a high





        enough temperature for the complete conversion of carbon




        monoxide to carbon dioxide to take place.  Minimum tempera-




        ture and residence times may be specified by permit conditions





        and  are provided for in the new source performance regulations





        of the  EPA for fluid catalytic cracking units in petroleum





        refineries .



                                   318

-------
       Though not routine,  flow rate monitoring for waste gas





or emergency flares will yield data that may be used to estimate





losses if the composition of flare gases is known.





       Vacuum recording at vapor recovery systems can give





an indication of the adequacy of compressor and recovery sys-





tem capacity.  Where insufficient capacity results in other types





of venting or flaring,  estimates of the losses can be made.





       Voltage measurements  on electrical precipitators can be





used to estimate some of the performance characteristics of





such control equipment although specific knowledge of the design




specifications of the equipment would be necessary to interpret




this data.





       Pressure drop measurements across  cloth filter units




are valuable in estimating the degree of bleed-through,  whether





capacity  is being exceeded,  whether the cleaning cycle is ade-





quate,  and in some cases, whether bags are ruptured.   Again,





specific knowledge of the design pressure drop is necessary to





interpret these findings.





       Absorber solution circulation rates and indications of





strength  such as pH are process measurements that may be use-




ful in estimating effluent losses in  acid gas scrubbers or ab-




sorbers.   Because of the high dependence of scrubber perfor-





mance on these parameters, very good estimates may be





possible.





                         319

-------
       The collection efficiency of almost all air pollution





control equipment decreases with an increase in the effluent




gas flow rate.  A possible exception is the centrifugal collector





class, but increased flow in these devices results in such high





pressure drops that capacity is somewhat self-limiting .  There-





fore,  as a general  case, effluent gas flow rates in  excess of





design capacity can be expected to increase losses both by




virtue of the increased flow and the loss in collection efficiency




as well.





       A very special case  of process monitoring involves  the





analysis of fuel oil and fuel  gases for sulfur  content.  This  is





particularly  applicable to the sulfur content of refinery "make




gases".   These ar-e gases-that  res-ult from refinery operations.





They have a  reasonably high heating value and are  used as  sup-




plementary fuel for heaters rather  than being further processed.





Sulfur content information so obtained,  together with usage





rates, -can be used directly  to calculate sulfur losses to atmo-




spheres.





b.     Equipment Inspection and Operational Data    Estimates




of contaminant losses may sometimes be made by observation of





operating techniques, by inspection of equipment condition, by




determining  level and adequacy of maintenance, and by evaluation




of process data not  determined analytically.




       Hydrocarbon losses  from storage tanks vary with color





                            320

-------
and condition of paint,  with product throughput, with vapor pres-

sure of product and,  in the case of floating  roof tanks, with the

condition of seals and interior surface.  Specific calculation

procedures for determining losses from storage tanks have been
                   o
reported elsewhere   and are not  normally applied in the field.

However, the field enforcement officer should be aware of the

influence of these factors  so that estimates can be made  of the

potential influence of changes in them.  The conditions andproper


functioning of floating  roof seals is, for example, very important

in maintaining losses  at the expected  levels.

        The field enforcement officer  must learn the kind and

frequency of maintenance necessary to keep control equipment

in effective operating  condition. For example,  fluid catalytic

cracker dust is  sufficiently abrasive to wear through the 'high

efficiency cyclones generally used as collection equipment in

front of an electrostatic precipitator.  If excessive wear results

in high dust loadings  to the precipitator,  losses to atmosphere

will increase.

        Losses would also be  expected to increase  as a result of

inadequate maintenance of relief valves and pump seals although in

these situations visible emissions  may also increase.  Electro-

static precipitators,  cloth filters,  and mist eliminators also

require regular maintenance.   The principal maintenance  prob-

lems with electrostatic precipitators  are related to the power


                         321

-------
supply,  particularly voltage level and regulation.  Broken




electrodes must be replaced, collection plates and tubes must





be kept in the proper condition, alignment must be maintained,




and rapping mechanisms must operate properly.




        Fabric filters  require regular inspection and replace-





ment of bags.  Based  upon the fabric used,  the  severity of




service, and the cleaning procedure, an estimation  can be made





of expected bag life.   Bags must, of course, be mounted prop-





erly to  avoid overstressing the fabric and to preclude leaks at





points of fastening.  The bag cleaning mechanism whether in-





volving shaking,  rapping, or reverse flow must be maintained.




Timers, solenoid valves, and mechanisms,  all require main-





tenance and are subject to failure.




        Mist eliminators,  such as those used on sulfuric acid




plants and on the discharge of some absorption  columns,  are





passive devices and somewhat less subject  to failure than the




other equipment.  In some cases,  however,  depending upon the




materials  used and the severity of service,  corrosion or clog-




ging may occur which will disrupt design flow patterns or reduce




collection  efficiency.  Sagging or compression of  the eliminator





media (usually metal  or glass fiber mesh) may  also result in




loss of efficiency.





        Operational data that does not appear on process instru-





ments may also give an indication of possible emission losses.





                           322

-------
Examples would include catalyst make-up rates, change in





nature of materials being processed,  and operator comments in





shift logs.




c.     Data from Air Sampling Equipment - Information avail-





able to the field enforcement officer from ambient sampling





which might be of use in assessing losses will for the most part





be obtained by the use of portable or hand-held sampling equip-





ment or  by perimeter monitoring equipment.  The portable or





hand-held devices are most likely to be useful inside or close to





the plant boundary, although under unusual conditions they may




be used to verify outside complaints.  Sampling would be con-





ducted regularly at a series  of points within and near the




refinery boundary.  These points would be selected on the basis





of past experience, proximity to known  sources, and subjective





criteria  such as location where certain  odors  have been or are




detected.





       Sampling  devices or indicator tubes are  available to mea-





sure hydrogen sulfide,  sulfur dioxide,  carbon monoxide, ammo-




nia,  mercaptans,  phenols, and hydrocarbons.  These measure-




ments are useful mainly in a qualitative sense because of




limitations in  accuracy, specificity,  and knowledge of the amount




of dilution of the  contaminants  after discharge from the source.




That is to say they are most useful in identifying unusual loss





or emission conditions which may be related to  leaks or





                        323

-------
operational malfunctions.




       Perimeter monitoring as use,d here means formalized




monitoring at sites established outside the refinery boundaries.




Contaminants monitored at these sites would most likely be




those identified as being of major importance, either because of




actual or potential volume of release, toxicity,  or impact on




meeting air quality-standards.  Expected values for the contami-




nants monitored,  based upon known  release rates and meteoro-




logical conditions, through use of diffusion modeling should be




determined.  Then a normal pattern  should be established,




which the  field enforcement officer should be able to use to




estimate changes in source  strength  through observation of the




recorded contaminant concentrations.
                            324

-------
                           REFERENCES
1.  Weisburd, M.  I.  Air Pollution Control  Field Operations  Manual,
    A Guide for Inspection and Enforcement.  Department of Health,
    Education and  Welfare,  Public Health Service,  Division of Air
    Pollution, Washington,  D.C.  Publication Number 93 7.  1962.
    p. 285.

2.  Douglass, I. B.  The Chemistry of Pollutant Formation in Kraft
    Pulping.  Department of Health, Education and Welfare,  Public
    Health Service, National Council for Stream Improvement.
    In: Proceedings of the International Conference on Atmospheric
    Emissions from Sulfate Pulping, Hendrickson,  E.  R. (ed. ).
    Gainesville,  Fla. ,  April 28,  1966.

3.  Brandt,  C.  S., and W.  W. Heck,  Effects of Air Pollutants on
    Vegetation.  In:  Air Pollution,  Vol. I, Stern,  A. C.  (ed.  ).
    New York, Academic Press,  1968.  pp.  401-443.

4.  Hewson,  E.  W. Meteorological Measurements.  In:  Air Pollution,
    Vol. II,  Stern  A. C. (ed. ),  New York, Academic Press,  1968.
    pp. 329-391.

5.  Kudlich,  R.  Ringelmann Smoke Chart.   Department of the Interior,
    Bureau of Mines,  Washington,  D.  C.   Information Circulars
    Numbers 77 1 8 and  8333 (revised).  May  1967.

6.  Weisburd, op.  cit. p. 65.

7.  Gruber, C. W. Source Inspection,  Registration and Approval.
    In: Air Pollution,  Vol.  II, Stern,  A.  C.  (ed. ).  New York,
    Academic Press,  1968.  pp.  561-595.

8.  Danielson, John A.  Air Pollution Engineering Manual,  Second
    Edition, A. P.  - 40.
                               325

-------
 9.   Byrd,  J. F.,  and A.  H. Phelps, Jr. Odor and Its Measurement.
     In:  Air Pollution, Vol. II, Stern, A. C.  (ed. ).   New York,
     Academic Press,  1968.  pp. 305-327.

10.   Guide  for Compiling a Comprehensive Emission Control Inventory
     (revised).  Environmental Protection Agency, Research Triangle
     Park,  N. C.  Publication Number APTD-1135.   March 1973.
     pp. 1-1  -  1-2.

11.   Weisburd,  op. cit.  pp.  260-265.

12.   Weisburd,  M. I., and P. Roberts.  Inspector's  Manual.  County
     of Los Angeles, Air Pollution  Control District,  Enforcement
     Division, Los Angeles, Calif.   Internal Document.   May 1957.
     pp. 95-97.

13.   Stein,  A.  Guide to Engineering Permit Processing.  Environ-
     mental Protection Agency,  Research Traingle Park, N. C.
     Publication Number APTD-1164. July 1972. pp. 7.12-7.13.

14.   Weisburd,  M. I.  Field Operations and Enforcement Manual for
     Air Pollution Control,  Vol. I.   Environmental Protection Agency.
     Research Triangle Park, N. C. Publication Number APTD-1100.
     August 1972.  pp. 4.16-4.36.

15.   Standards of Performance for  New Stationary Sources.  Federal
     Register.  36^24876-24895, December 23,  1971.
                                  326

-------
                       VII.  MAINTENANCE







A.     DESCRIPTION OF REFINERY'MAINTENANCE OPERATIONS





       Maintenance is a major activity at all refineries.  A large





portion of the work force is assigned to maintenance operations.





These operations can be categorized as routine or emergency.





Emergency maintenance is required to clean and repair facilities





damaged by accident.  Emergencies such as ruptured lines, fires,





and explosions must be considered from  the safety standpoint first




and from the pollution standpoint second.  Other emergencies, such





as a broken compressor shaft,  can  be handled with more attention to




pollution control.





       Routine maintenance can be  categorized as minor or major.





Minor maintenance includes the day-to-day upkeep of individual





equipment items.  Major maintenance involves the shutdown and





repair of entire processing units or even the entire refinery. These





"major turnarounds" are performed on a regular basis, usually at





intervals of two or  three years.  Routine maintenance is carefully




scheduled and planned whether it is  minor servicing  of equipment or




a major refinery turnaround.







                               327

-------
       Record keeping is an essential part of a refinery maintenance





program.  Maintenance records are kept primarily to facilitate





planning and work schedules.  In some large refineries, electronic





data processing equipment is used to improve the efficiency of main-





tenance operations.   Maintenance records are useful to determine the





state of repair of individual  pieces  of equipment.  These records can,





therefore, be used to review the  maintenance history of equipment





items known to be pollution  sources.  Emission control equipment





with histories  of frequent upsets  and malfunctions can often be detec-





ted easily by reviewing the maintenance records  before beginning the




field inspection.







B.      GENERAL PLANT MAINTENANCE




        Routine maintenance operations within the refinery may con-





tribute to air pollution. Major turnarounds are often handled by




contractors  who specialize in refinery maintenance.  The  procedure





in a major shutdown will vary widely depending on the individual





refiner's practices.   In most cases,  all liquid  material is pumped to




product and  intermediate storage or slops tanks.  As the plant is





depressurized, gases are delivered to the blowdown system.




        If acid gases are present, these can be delivered to the  fuel-




gas system or the acid-gas  recovery unit.   Tanks and vessels are




steamed  out to remove toxic and flammable.gases.  Generally,  the




steam vapors  are vented to  the atmosphere and pollutants  escape.







                                 328

-------
The vapors can,  however, be vented through a condenser to a flare





where such an arrangement is justified.  The shutdown procedure





followed in each  case will greatly affect the quantity of air pollutants





emitted.  At present,  complete recovery of air pollutants during





shutdown is not practiced.  Ventilation of vessels and tanks is




required for safety reasons during repair.   Noticeable odors are





generally unavoidable  at these locations.




       The repair and cleanup operations represent a source of air





pollution during both major turnarounds and day-to-day operations.





Tanks,  vessels,  and towers  require  sandblasting and painting.  Sand-





blasting can be the  source of particulate air pollution resulting  in





property damage or health hazard.  In some cases, protective





tarpaulins or wet blasting can be used to reduce dust  emissions.





Smaller items can be removed to  remote sandblast facilities




equipped with dust collectors.  The use of steel shot or grit can also





be used in place  of  sand.  Paint spraying results in particulate  and




hydrocarbon emissions.   Nonreactive paints and solvents should be




used.  Outdoor paint spraying is illegal in some areas.  Solvent





cleaning may also be a source  of air  pollution. Nonreactive solvents





should be used.







C.     MAINTENANCE OF AIR POLLUTION CONTROL EQUIPMENT




1.     Flare and Slowdown System





       A blowdown system consists of relief valves,  blowdown







                              329

-------
piping,  liquid knock-out drum,  and flare stack.  The operation of a





blowdown system is discussed in Chapter I, Section U.  Relief valves





are discussed in Chapter II, Section H.  The blowdown system is





designed primarily as an emergency shutdown system.  The proper





operation of the system,  however,  is essential to the  reduction of air




pollution from relief valves and flare stacks.





        Relief valves are normally  removed from service and  are





shop  repaired on  a regular basis.  Relief valves should be tested for




correct operation at  regular intervals.  If this is not possible, spare





valves  should be installed to permit removal and servicing.  Service





records can be  reviewed to determine the inspection frequency. It is





essential that the valves  be clearly marked and replaced in the proper





location.   Tank vents and flame arresters also require regular




inspection to assure  proper operation.





        The flare  stack is designed to operate under a wide range of




conditions.  Since materials of wide ranging properties are processed





by the blowdown system, plugging of lines is a possibility.  Blowdown





lines and knock-out vessels should be  regularly  inspected to maintain




them free and clear.  Control systems on the liquid knock-out drum





must operate properly to prevent flooding of the  flare stack.   The gas





pilot  equipment and purge gas lines must be in good operating condi-





tion if the blowdown material is to  be combusted completely.




2.      Participate Matter  Control  Equipment




        Particulate matter  is controlled in refineries through the use





                                  330

-------
of cyclone separators, electrostatic precipitators, and  to a lesser





extent - baghouses.  Cyclone separators can plug at  the dust outlet





if viscous material is introduced.   Pressure buildup should be moni-





tored to determine if the cyclone is operating as designed.





        Electrostatic precipitators are used to recover catalyst fines





in some refineries.  These units can malfunction if tars or other





materials foul the  collection plates.  Regular inspection and cleaning




is required.   Ionizer wires will corrode and require  replacement.





Electrical control  systems require checking to assure the  proper





voltage and rapping frequency and  intensity.  Operating conditions





may have to be adjusted if particulate properties vary with time.





        Baghouse filters require regular maintenance to ensure





efficient operation.  This includes regular removal of the collected





dust, inspection of the bags, and lubrication of the moving  parts.  If





required, the bags should be replaced.  Precoating of bags after each




cleaning cycle with dust is recommended to improve  collection





efficiency, but may not be required in all cases.





3.     Sulfur Recovery  Plants





       Sulfur recovery plants  are  an important source of sulfur




dioxide pollution in refineries.  An upset can result in sharply





increased emission rates.  The operation of sulfur plants is





discussed in detail in Chapter  I, Section P.  A sulfur plant generally





requires little attention.  Proper operation  of the inlet mixture con-
                               331

-------
trol valves is essential to complete conversion of sulfur compounds





to elemental sulfur.  Sudden surges in feed rate or composition can





also upset the performance  of the plant.  Frequent inspection is





required to determine catalyst activity.  The tail-gas incinerator





must be inspected for corrosion.  Air/fuel mixture control instru-





ments should be inspected.  Since a sulfur recovery plant is pro-




cessing a poisonous gas, alarm systems are provided to announce





plant upsets.







D.      MAINTENANCE OF  MONITORING EQUIPMENT




        A  wide variety of monitoring equipment is available.  Sam-





pling devices and analytical instruments are commercially available.





Manufacturers' instructions  should be carefully followed for use and




maintenance of monitoring equipment.  Portable instruments can be




easily damaged in transit.   Instruments located outdoors can be





damaged by the elements.  Attempts to use equipment under condi-




tions other than those intended by the manufacturer may also cause





damage.  Titrating  solutions should be sealed tightly when not in use.




Fresh solutions should be used and frequently checked for concen-




tration.  Regular calibration and inspection of instruments is essen-





tial.  A maintenance record should be maintained on each monitoring





device.
                                  332

-------
                         VIII.  PERSONNEL







A.     MANPOWER REQUIREMENTS





       Of the field and enforcement functions performed by air pollution





control agencies,  those relating to  petroleum refineries  and to the





petrochemical and chemical industries are probably the most  special-





ized.  Since these industries are likely to constitute large point sources




of pollution,  as well as the cause of public complaints, an organizational





component within the agency (or at  the very least,  special assignments)




should be dedicated to the surveillance of these industries.  The man-





power and the degree of specialization required will depend on the





number and types  of such installations located within the jurisdiction of




the air pollution control agency.





       Few air quality control  regions contain a sufficient number of





petroleum refineries to justify  a special  operating  unit.  In most cases,





petroleum refineries are grouped with other plants  requiring chemical





engineering expertise and with  activities related to  the petroleum




economy of the area.  '    These include:





              Asphalt  manufacturing  plants
                                 333

-------
              Chemical plants,  including manufacturers





                 of sulfuric acid,  vinyl chloride, paint





                 and varnish, and fertilizer





              Gasoline absorption plants




              Natural  gas processing plants




              Oil reclaiming plants





              Petrochemical plants





              Petroleum marketing and consumption





              Petroleum marketing stations, service




                 stations,  bulk  plants,  marine terminals





              Soap and detergent manufacturing plants




              Sulfur recovery plants





              Tank farms





       With a few exceptions (such as power plants and ships), these




industries are organized from unit processes - those involving a




chemical change in one or more reactants (e.g.,  nitration,  polymer-




ization,  hydrogenation)  and unit operations - those involving physical





changes  only (e.g., distillation, absorption).  Both unit processes





and operations may be  defined in terms of the process  unit, that is,




the equipment or process vessels  interrelated by flow  systems in




which materials are progressively transformed towards  a desired end.





       Surveillance work levels tend to be related to the number of





process  units with significant air pollution potentials rather than to
                                  334

-------
the number of industrial plant address-locations.  On the average,  a





process  unit in this  industry may require three hours of surveillance





and inspection time.  This includes surveillance,  equipment inspection,





plant personnel interviews, and  report write-up,  exclusive of detailed





engineering evaluation, permit processing,  and coxirt and hearing




board activities.   At an inspection frequency of four times per year,




1Z man-hoxirs of  field time per year per process unit would be  re-




quired.   Thus about 160 process units is equivalent to one man-year





of surveillance for the industry.   This would be equivalent to eight





petroleum refineries each averaging 20 process units that are signi-





ficant from an air pollution standpoint.




       Of course, these averages will vary among agencies,  depending





on the personnel  available and delegation of responsibilities.  Field





personnel who are also responsible for  permit evaluation (as opposed





to a separate permit processing  unit) or for source testing will require




significantly more man-hours  per process unit.   Ideally, for maxi





mum  efficiency,  permit and source testing operations should be sepa-





rated from surveillance operations.  A  grouping of installations in





terms of process/work units and in terms of the types of surveillance




and enforcement  functions required will help to determine the




manpower,  organizational structure,  and support  services that will




be needed.
                                 335

-------
B.     FEO FUNCTIONS





       The functions of the field enforcement officer to be performed





in connection  with petroleum refineries are discussed  in Chapter V,





"Maintenance of Refinery Records" and Chapter VI,  "Estimating and





Assessing Emissions".  To summarize,  these functions are:





1.     Maintain surveillances  of all process,  equipment, and activi-





ties associated with assigned petroleum,  petrochemical,  or chemical





installations,  by means of vehicle patrol  or other exterior proce-





dures.  The purpose of this surveillance  is to detect visible emis-





sions, odors,  new construction, or other obvious changes in plant





conditions which may affect emission  rates or permit  status.





2.     Conduct surveys and inspections of all processes, equipment,




and activities that have air pollution potential to establish,  at each





and every definable source of pollution,  compliance  or noncompliance





with all  rules and regulations.





3.     Investigate all  citizen complaints  made in connection with





these installations.





       To perform  these  duties, certain  capabilities are required





of the air pollution control agency, the enforcement  operation, and





the individual officers.





       The aii- pollution control agency and, desirably,  the field





enforcement operation should have personnel with baccalaureate





degrees  in chemical engineering and previous  work experience in the





industrv.  Even with such training and experience, personnel should





                                 336

-------
receive as much as  100 hours of formal on-the-job training.





Training should include courses in petroleum technology, and air





pollution engineering and enforcement.  Courses may be available





from a nearby university or from the EPA or they may be created





and implemented by the air pollution control  agency itself.





       The specialized personnel should be available to perform such





functions as permit  evaluation,  plan review, engineering super-





vision,  supervision  of specialized enforcement activities,  technical





services,  and general agency planning and evaluation.   In any event,





the field enforcement operation should either be supervised by,  or





have access to,  these personnel.  In larger agencies,  particularly





agencies responsible for large petroleum,  petrochemical, and





chemical plant complexes,  highly trained and experienced personnel





should occupy senior field enforcement positions.







C.     FEO PERSONNEL QUALIFICATIONS





       If the expertise described above  is directly available to the





enforcement operation, then it is not necessary for FEOs to possess





degrees and previous experience in chemical engineering.  Using





such personnel in the field may be  inefficient, since not all of the





engineering capabilities of such persons  would  be  needed in the field





operations program.





       The qualifications of field enforcement personnel  should be





looked upon,  primarily,  in terms of aptitude, including ability to






                               337

-------
receive special-purpose training and, secondarily, in terms of



general education and previous work experience.   With respect to



aptitudes,  FEOs should be able to:



1.     Assimilate and comprehend (1) engineering information
                                            _\


related to chemical and physical processes and (2) legal and adminis-



trative information related to enforcement activities;



2.     Recognize equipment, process configurations, and operating



conditions  or parameters (particularly pressure and temperature)



that affect  air pollution emissions;



3.     Relate equipment,  processes and conditions to specific pro-



cessing functions (unit processes or operations) and to the specific



substances (input and output) involved in such operations;



4.     Identify abnormal operating conditions,  e.g.,  process



upsets, overloads, breakdowns, equipment failures;



5.     Become familiar with the chemicals  and materials employed,



particularly  hazardous substances, and understand the technology



and terminology of the industry;



6.     Evaluate  visible and nonvisible emissions, including odors,



and materials-damaging substances;



7.     Prepare and interpret process flow data and make preliminary



estimates of  material losses; and



8.     Prepare concise,  accurate, and  complete reports which



effectively communicate the technical information necessary to
                                 338

-------
establish compliance or noncompliance of specific sources with the





rules and regulations.





        These personnel aptitudes or capabilities can be determined





from:





1.      General intelligence tests.  Candidates should have high





verbal and arithmetical scores,  including reading comprehension and





vocabulary  skills.





2.      Scholastic records and courses pursued in high school,  junior





college, college, and technical institutes with  respect to exposure





and performance in technical and scientific  courses.





3.      Previous work and military experience, especially in tech-




nical areas  and responsibility and level of contact with public





(e.g. engineering sales activities).





4.      Special aptitude tests.  These can be developed and used to




identify and select  potential FEO candidates.  Skills and aptitudes





that  can be evaluated include interpretation  of flow charts, compre-





hension of technical information  with  respect to chemistry, heat





transfer,  principles of conservation of energy  and mass and fluid





flow. Personality  tests can be used to help assess judgment,





emotional stability, ethics,  and  responsibility.





5.      The  degree of motivation.  Motivation is a very important




factor,  since FEOs generally operate in the field under minimal





supervision and are responsible  for planning and scheduling much of





their own work.  In effect,  they  are responsible for the installations





                               339

-------
they are assigned to,  and it is up to them to conduct all necessary





research and collect all information they may need to understand the





operations of these  installations.





6.     Approach and  appearance.   Neatness, maturity, objectivity,





and  responsibility are essential qualities in relating to operating





personnel at all levels.







D.     TRAINING





       Personnel meeting these qualifications should receive at least





100  hours of classroom and on-the-job training.  They also must work





vinder supervision of  experienced field personnel prior to entering and





inspecting petroleum  refineries on their own.  Courses should include:





               Air Pollution Control Technology





               Care and Use of Inspection Equipment




               Drivers Training





               Field Orientation




               Legal  Authority





               Monitoring Instrumentation





               On-the-Spot  Field Testing





               Petroleum and Petrochemical Technology





               Report and Notice Writing





               Smoke School





               Supervised Field Training
                                  340

-------
                           REFERENCES
1.    Weisburcl,  M. I.  Air Pollution Control Field Operations
      Manual, A   Guide for Inspection and Enforcement.  Depart-
      ment of Health, Education and Welfare, Public Health
      Service. Division of Air Pollution, Washington,  D. C.
      Publication Number  PUS 937.  1962.  pp.  98-99.

2.    Weisburd,  M. I.,  and  P. Roberts.  Inspector's Manual.
      County of .Los Angeles, Air Pollution Control District, Enforce
      ment Division, Los Angeles,  Calif.  Internal Document.
      May 1957.  pp. 84-97.

3.    Weisburd,  M. I.  Field Operations and Enforcement Manual
      for Air  Pollution  Control,  Vol.  I.  Environmental Protection
      Agency, Office of Air Programs, Research Triangle Park,
      N. C.  Publication Number APTD-1100.  August 1972.
      pp.  1.49-1.52.
                                   341

-------
                           GLOSSARY
ABSORPTION: A process whereby a liquid dissolves a gas, such as
       oil which absorbs  light hydrocarbons from natural gas.

ABSORPTION GASOLINE: Gasoline which is obtained from natural
       gas by absorption  in oil.

ACCUMULATOR:  A vessel which serves as a surge tank and holds
       intermediate product,  usually overhead distillate.

ACID GAS:  A gas consisting mostly of hydrogen sulfidc and carbon
       dioxide.

ACID TREATING: A process in which petroleum products  are
       contacted with sulfuric acid.

ACTIVATED CARBON:  A form of carbon or charcoal which has a
       high adsorptive capacity for gases, vapors or solids.

ADDITIVES: Chemicals added to petroleum products to improve
       performance or  obtain needed product characteristics.

ADSORPTION: A process in which a gas or vapor physically adheres
       to the surface of a  solid such as activated carbon.

AEROSOL:  A continuous  dispersion of solids and liquids in a gas,
       usually air, such as a haze  or fog.

AIR BLOWING:  A process in which hot asphalt is oxidized by passing
       air through it.

ALIPHATIC HYDROCARBONS:  Open chain hydrocarbons  such as
       paraffins and olefins.
                              343

-------
ALKYLATION:   A process for combining isoparaffins and olefins such
       as isobutane and butylene,  to form alkylate,  a gasoline
       component.

AMINE UNIT:   A process in which acid gases are removed from
       hydrocarbon gases by absorption in amine solution.

ANILINE POINT:  An index for measuring the solvent  capacity or
       aromatic content of hydrocarbons.

ANTI-KNOCK COMPOUNDS:  An additive in gasoline,  such as tetra-
       ethyl lead,  for improving combustion characteristics in internal
       combustion engines.

API:   American Petroleum Institute.

API GRAVITY:   An index for measuring the  density of  petroleum.

API SEPARATOR:  A device for separating oil from water by gravity.

AROMATIC HYDROCARBONS:   Hydrocarbons with an unsaturated
        closed ring structure,  such as benzene,  toluene and xylene.

ASH:  A nonvolative, incombustible component of fuels which remains
       after combustion.

ASPHALT:   A high,  boiling, semi-solid hydrocarbon refined from
        crude oil.  A component of asphaltic-base crude oils.

ASTM:  American Society for Testing Materials.

AVIATION GASOLINE:  A grade of gasoline  for  reciprocating aircraft
        engines.
AZEOTROPIC DISTILLATION:  A process for separating hydro-
        carbons of the same boiling point.
                                   B

BARREL:   A volume unit used in the petroleum industry consisting of
        42 U. S.  standard gallons.

BENZENE:  An aromatic hydrocarbon present  in some  crude oils.

BFW:   Boiler feed water.
                                  344

-------
BITUMEN:  See Asphalt.

BLACK OIL:  Petroleum containing residual crude oil.

SLOWDOWN: Material purged from the refining process during
       startups, shutdowns, and pressure relieving.  The blowdown
       system collects and disposes of the waste material.

BS&cW:  Bottom  settlings and water material found in tank bottoms.

BTU:  British thermal unit - used  to define  heating value of fuels.
       The heat required to raise  one  pound of water one degree
       Fahrenheit.

BUNKER FUEL OIL: A heavy residual fuel oil.

BURNING OIL:  See Kerosene.
CALCINED COKE: See Coke.

CASINGHEAD GASOLINE:  See Natural Gasoline.

CATALYST: A  substance used to accelerate chemical reactions.

CAUSTIC:  A term used for solutions of sodium hydroxide used in
       treating  processes.

CETANE:  A paraffin used as a standard for diesel fuel quality.

CLAUS PROCESS:  A process  in which hydrogen sulfide is converted
       to elemental sulfur.
    •
COKE:  Solid carbonaceous residue obtained from coking  residual
       crude oil.   Calcined coke is coke that has been heat treated
       to remove volatile materials.

COKING:  A process in which crude oil is destructively distilled to
       produce  petroleum coke.

CONDENSATE:  A  liquified hydrocarbon gas such as obtained from
       natural gas wells.

CONVERTER:  See Shift Converter.
                              345

-------
CRACKED GASOLINE:  Gasoline obtained by cracking heavier
       petroleum fractions.

CRACKING: A process in which large hydrocarbon molecules are
       divided into  smaller molecules.  Process may be catalytic
       or thermal cracking.

CUTBACK:  Petroleum fractions used to reduce viscosity of fuel oils
       and asphalt.

CYCLE STOCK:  Intermediate refinery product which is recycled to
       other process units.
                                 D

 DEA:  Diethanolamine, an absorbent used to remove acid gases for
        sour gas streams.

 DEAERATOR:  A device  used to remove dissolved oxygens from
        boiler feed water.

 DEASPHALTING:  A process in which asphalt is  removed from
        reduced crude.

 DEBUTANIZER:  See De-ethanizer.

 DE-ETHANIZER:  A distillation column which removes ethane and
        lighter hydrocarbons  from propane and heavier hydrocarbons
        The terms depropanizer and debutanizer are also used for
        similar operations.

 DEHYDRATING:  A process in which  water is removed from hydro-
        carbon gases and liquids.

 DEPROPANIZER: See De-ethanizer.

 DESALTING: A process in which salts  are removed from crude oil.

• DEWAXING:  A process in which wax is removed from lubricating
        oils.

 DIESEL FUEL:  A petroleum product used as fuel in diesel engines
        consisting of gas  oils.

 DISTILLATE:  The light  material taken overhead in a distillation
        column and condensed.

                                  346

-------
DISTILLATION:  A process in which a hydrocarbon feed is separated
       in two or  more components of different boiling points.

DOCTOR TEST:  A test used to determine the mercaptan content or
       odors of petroleum products. Odor-free products are termed
       "Doctor Sweet".

DRUM: A container which holds 55  gallons.  Also, a vessel used in
       the refinery process for storage or separation.

DRY GAS:  A hydrocarbon gas, usually natural gas, which does not
       condense  easily.   Usually contains mostly light hydrocarbons,
       such as methane and ethane.
ENTRAINMENT: Liquid droplets or mist contained in vapors
       leaving a boiling liquid.

EXTRACTIVE DISTILLATION:  A distillation process in which hydro-
       carbons with similar boiling points are separated by selective
       absorption in a solvent.
FLARE:  A device used for burning waste gases.  See Blowdown.

FLASH DRUM: A vessel used to separate vapors and liquids after a
       pressure  reduction.

FLASH POINT:  The minimum temperature at which vapors above a
       petroleum fraction or product will ignite in the presence of a
       flame.

FLOATING ROOF:  A roof which floats on surface of liquid in a
       storage tank and reduces  evaporation losses.

FRACTIONATOR:  See Distillation.

FUEL  GAS:  Light hydrocarbon gases generated in the refinery
       process used for firing process heaters and furnace.

FURFURAL:  An organic compound used as a solvent in refining
       lube oils.
                              347

-------
FURNACE OIL:  Distillate fuel oils used for residential and
       commercial heating.
GAS OIL:  A fraction obtained in the distillation of petroleum
       generally used in distillate fuel oil.

GASOLINE:  Refined petroleum naphtha used in internal combustion
       reciprocating engines.

GRAVITY:  See API Gravity.
                                 H

HEATING OILS:  See Furnace Oils.

HOT CARBONATE: A  potassium carbonate solution used to absorb
        acid gases from light hydrocarbon streams.

HYDRODESULFURIZING: A process in which sulfur is removed
        from petroleum in the presence of a catalyst  by combining
        the sulfur with  hydrogen.

HYDROTREATING: A  process in which petroleum is reacted with
        hydrogen in the presence of a catalyst to remove sulfur or to
        hydrogenate unsaturated compounds.
ILLUMINATING OIL:  See Kerosene.

ISOMERIZATION:  A process in which normal hydrocarbons are
        converted to isomers by rearranging the molecular
        structure.  A typical isomerization is the conversion of
        butane to isobutane.
JET FUEL:  A kerosene based fuel for use in gas turbine powered
       aircraft.  JP-4 and JP-5 are common grades of jet fuel.
                                 348

-------
                                 K

KEROSENE: A petroleum distillate boiling between naphtha and gas
       oil.  Used in jet fuels and heating oils.

KNOCK: A  property  of gasoline related to octane  rating and engine
       knocking.

KNOCKOUT DRUM:  A process vessel used to remove entrained
       liquid from gases.
LPG:  Liquified petroleum gas.  A petroleum product containing
       propane and butane.

LAMP OIL:  See Kerosene.

LEAD:  Refers normally to lead additives in gasoline, such as
       tetraethyl lead.

LEAN OIL: An absorption oil which contains no dissolved light
       hydrocarbons.

LIGHT: A relative term applied to petroleum fractions to denote the
       lower boiling material,  such as light naphtha,  light gas oil.

LIGHT ENDS:  Light liquid hydrocarbons,   typically ethane, propane
       and butane.

LOADING RACK: A structure used to load petroleum products  into
       tank trucks,  rail tank cars or barges.

LONG RESID:  Residual oil obtained from crude distillation
       containing neutral oils.

LUBE OILS: A petroleum fraction,  generally heavy gas oils, vacuum
       gas oils and neutral oils used for lubricating purposes.
                                 M

MEA:  Monoethanolamine, an absorbent used to remove acid gases
       from sour gas streams.
                               349

-------
MERCAPTAN: An organic compound present in "sour" crude oil.
       Mercaptan compounds contain sulfur and have a strong odor.

METHANATION:  A process in which carbon monoxide is converted
       to methane by  reaction with hydrogen.

MOTOR OILS: See Lube Oils.

MOTOR SPIRIT:  See  Gasoline.


                                 N

NAPHTHA: A petroleum fraction boiling in the gasoline range.

NAPHTHENES: A group of hydrocarbons having a saturated ring •
       structure such as cyclohexane found in naphthenic crude oils.

NAPHTHENIC ACID:  A corrosive organic  acid found in some
       naphthenic crude oils.

NATURAL GAS:  Light hydrocarbon gases naturally formed in the
       earth.  May also refer to the finished product or pipeline gas.

NATURAL GASOLINE: A mixture of light hydrocarbons boiling in
       the gasoline range recovered from natural gas.

NEUTRAL OILS:  Distillate petroleum fractions, generally heavy gas
       oils,  having specific viscosity properties and used in lube oils.
                                 O

OCTANE NUMBER:  An index used to measure the anti-knock
       properties of gasoline.  Research,  Motor and Road Octane
       Numbers are three different octane ratings.

ODORANT: A material added to fuel gas to impart a distinctive
       odor and permit human detection.

OLEFINS: A  class of paraffin hydrocarbons which are "unsaturated1
       or deficient in hydrogen,  such as ethylene, butylene.

ON STREAM:  A term to  denote that a refinery or process unit is in
       normal operation.
                                 350

-------
OVERHEAD:  The vapors which are boiled off the top of a distillation
       tower  or the lightest product  obtained in the distillation
                                                         *
       process.
PALE OIL: A distillate lube oil,  yellow in color.

PARAFFIN:  A series of linear and branched hydrocarbons fully
       saturated in hydrogen,  such as methane,  propane.  Also
       known as  alkanes.  High molecular weight paraffin in solid
       form is known as paraffin wax.

PETROCHEMICAL:  A chemical compound, intermediate or product
       derived from  natural gas or crude oil.

PETROLATUM:  A semisolid product obtained by filtration containing
       residual oils and wax.

PETROLEUM COKE:  Coke derived from crude oil.  See Coke.

PETROLEUM SPIRITS:  A distillate product used in solvents,
       varnishes and paint thinners.

PHENOL:  An organic chemical used in solvent extraction
       processes.

PHOTOCHEMICAL REACTION:  The process  of chemical change in
       the presence of radiation,  such as the  reaction of hydro-
       carbons in sunlight to form smog.

PIPELINE GAS:  Refined natural  gas sold to residential, commercial
       and industrial customers.

PLUME:  The path taken by visible discharges from a stack or
       chimney.

POLYMER GASOLINE:  A gasoline component  obtained by combining
       two olefins.

POLYMERIZATION:  A process in which two or more molecules are
       combined.  Typically, refers to the combination of two
       olefins, such  as propylene and butylene, to  form polymer
       gasoline.
                               351

-------
POUR POINT: The minimum temperature at which a petroleum
       fraction will flow.

PRESSED DISTILLATE:  The oil obtained when wax is  separated from
       paraffin distillates.

PRESSURE DISTILLATE:  Distillate obtained from cracking stills.
QUENCH:  The process of cooling hot gases or liquids by direct
        contact with cold liquid.  Usually refers to quench tower or
        quench oil.
                                  R

RAFFINATE:  That portion of the oil which is not absorbed by the
        solvent in the solvent refining process.

RANGE OIL:  See Kerosene.

RAW GASOLINE: See Wild Gas.

REBOILER: A heat exchanger used to boil liquid to provide vapors
        to the bottom of a distillation column.

RED OIL:  A lube oil which is red in color.

REDUCED CRUDE: The crude oil remaining after distillate
        products  have  been removed in the crude distillation process.

REDWOOD  VISCOSITY:  A measure of viscosity used in the
        petroleum industry.

REFLUX:  That portion of  the overhead vapors  that is condensed
        and  returned to the distillation column.

REFORMING:  A process  in which the octane rating of naphtha  is
        increased by catalytic  reaction or mild thermal cracking.
        The reformed  product  is termed reformate.

REID VAPOR PRESSURE  TEST:  A standard test used to measure
        the vapor pressure of gasoline and other petroleum products.
                                 35Z

-------
RESIDUAL FUEL OIL: Fuel oils containing reduced crude.

RICH OIL: An absorption oil containing dissolved hydrocarbons.
SAYBOLT-FUROL,  SAYBOLT-UNIVERSAL: Measures of viscosity
       used in petroleum industry.

SCALE WAX:   Wax obtained by sweating the oil obtained from slack
       wax, that is  separating excess oil from oily wax.

SEDIMENT:  See BS&W.

SHIFT CONVERTER:  A reactor used to convert two compounds to
       two different compounds, such as are used in sulfur plants
       and hydrogen plants.

SHORT RESIDUAL:  The residual oil obtained after neutral oils have
       been removed by distillation.

SKIMMING: Distillation of crude oil to remove light fractions only.

SLACK WAX:   Crude wax obtained by pressing paraffin distillates.

SLOPS OIL:  Mixture of oils lost and recovered in the refining
       process.

SLUDGE: Degradation residue obtained when treating petroleum.

SMOKE POINT: An index  of diesel and kerosene fuels which measures
       smoking tendency when burned.

SOLVENT NAPHTHA:  See Stoddard Solvent.

SOUR:  Containing sulfur compounds such as hydrogen sulfide,
       mercaptans, as in  sour gas or sour crude.

SPINDLE OIL: A grade of lube oil.

SPRAY OIL:  A grade  of oil used as a pesticide.

STABILITY:  Resistance to change,  generally refers to oxidation
       resistance of gasoline, other products in storage.
                               353

-------
STABILIZER:  A distillation process which removes light ends,
        generally butanes, from naphthas.

STILL: A distillation tower.

STODDARD SOLVENT:  A naphtha used in dry cleaning or as a
        general solvent.

STRAIGHT RUN:  Products  directly obtained from distillation of
        crude oil before undergoing chemical change,  such as
        c racking.

STRIPPING:  The removal of volative products by heating.

SWEATING: A process in which oil is removed from wax by heating.

SWEET:  Containing little sulfur or  sulfur compounds, such as
        hydrogen sulfides and mercaptans.
TEL:  Tetraethyl lead.

TAIL GAS: Sulfurous gases unreacted in sulfur recovery process.

TAR:  Highly viscous polymerized residue produced in vacuum
        distillation, cracking coils.  By-product of the cracking
        process.

TEMPERING OIL:  Neutral oils.

THERMAL CRACKING:  See Cracking.

THERMAL REFORMING:  See Reforming.

THIEF:  A  device for taking samples of petroleum from specific
        location in the tank.

TOLUENE: An aromatic hydrocarbon derived from crude oil.

TOPPED CRUDE:  Residual crude oil obtained in topping  plant.

TOPPING:  See Skimming.

TOWER:  A vertical vessel in which petroleum is distilled,  or gases
        are absorbed, etc.

                                  354

-------
TREATING:  A process in which petroleum is contacted with chemicals
       to improve product quality.

TURNAROUND: A maintenance operation in which a refinery or
       process unit is shut down and repaired.
                               U, V

VACUUM DISTILLATION: Separation of crude oil by distillation
       below atmospheric pressure.

VAPOR PRESSURE:  Pressure exerted by a liquid at a given
       temperature in a closed vessel in the absence of air or
       other compounds.

VAPOR RECOVERY: A system used to  collect hydrocarbon vapors
       from vents and relief devices for reuse in the refinery.

VIRGIN STOCK:  See Straight Run.

VISBREAKING:  A process of mild thermal cracking in which oil
       viscosity  is reduced.

VISCOSITY:  A measure of resistance to flow, often determined by
       the time for liquid to pass through standard orifice.
                                 W

WATER WHITE:  A grade of oil color.

WAX DISTILLATE:  A neutral oil containing recoverable paraffin wax.

WAX TAILING:  Heavy tarlike distillate recovered in coking process.

WET GAS: Light hydrocarbon gas containing heavy hydrocarbons
       which are easily condensed.

WHITE OIL:  A grade of colorless, light lube oil.

WILD GAS:  Natural gasoline containing dissolved light ends.


                              X, Y,  Z

XYLENE: An aromatic hydrocarbon derived from crude oil.

YELLOW SCALE: Low-grade paraffin wax.

                              355

-------
                                 '  TECHNICAL REPORT DATA
                            (Please read iHUntiituns on the n-\\-rK bi'Jorc completing)
  EPA-450/3-74-Gffi
4,'TITLE AND SUBTITLE
  Field Surveillance & Enforcement-Guide for Petroleum
  Refineries
                                                           6. REPORT DATE
                                     6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
  Anker V. Sims
                                                           8. PERFORMING ORGANIZATION REPORT NO,
9. PERFORMING OR'ANIZATION NAME AND ADDRESS
  The Ben Holt Company
  201 South Lake Avenue
  Pasadena, California  91101
                                                           10. PROGRAM ELEMENT NO.
                                     11. CONTRACT/GRAN1 NO.

                                      68-02-0645
 12. SHONSCFUNG AGENCY NAME AND ADDRESS
  Control Program Development  Division
  Office of Air Quality Planning  and  Standards
  U.S.  Environmental Protection Agency
  Research Triangle Park, North Carolina  27711
                                     13. TYPE OF REPORT AND PERIOD COVERED
                                         Final Report
                                     14. SPONSORING AGENCY CODE
 15. SUPPLEMENTARY NOTES
 16. ABSTRACT
       The report entitled  "Field  Surveillance and Enforcement Guide  for Petroleum
  Refineries" describes petroleum  refining and natural gas processing,  refinery
  equipment, process instrumentation,  air pollution monitoring instrumentation,
  maintenance of refinery records  for  use by air pollution control  personnel,
  estimating and assessing  emissions,  plant and equipment maintenance and the
  qualifications and training  requirements of field enforcement  personnel.   The
  guide was prepared to familiarize  state and local air pollution  control officials
  with the operation of petroleum  refineries and natural gas processing plants and
  to aid agency personnel in developing surveillance, inspection,  monitoring,
  reporting and enforcement procedures.
17.
                                KEY WORDS AND DOCUMENT ANALYSIS
                  DESCRIPTORS
  Air Pollution
  Petroleum Refining
  Natural Gas
  Refineries
  Standards
  Instrumentation
  Inspection
  Personnel	
"Reporting
 Particles
 Sulfur Oxides
 Hydrogen Sulfide
 Organic Sulfur Com-
   pounds
13 DiSI Rl BUTION ST ATtMt NT

  Release Unlimited
                                              b.IDENTIFIERS/OPEN ENDED TERMS
Air Pollution ConTroT
Petroleum Refining
Natural Gas Processing
Inspection Procedures
                        19. SECURITY CLASS (I'lm Kcport>
                          Unclassified
                                              20. SECURITY CLASS lT>ns pu
                                                Unclassified
                                                                           COSATi F icId/Group
                           21. NO. OF PAGES
                               377
                                                  22. PRICE
EPA Form 2220-1 (9-73)

-------