United States
          Environmental Protection
          Agency
           Industrial Environmental Research
           Laboratory
           Research Triangle Park NC 27711
EPA-600/2-80-075a
April 1980
          Research and Development
SEPA
Assessment of
Atmospheric Emissions
from Petroleum Refining:
Volume 1. Technical Report

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                                   EPA-600/2-80-075a

                                             April 1980
      Assessment of Atmospheric
Emissions from  Petroleum  Refining
       Volume  1. Technical  Report
                          by

                R.G. Welherold and D.D. Rosebrook

                     Radian Corporation
                      P.O. Box 9948
                    Austin, Texas 78766
                Contract No. 68-02-2147, Exhibit B
                 Program Element No. 1AB604
               EPA Project Officer: Bruce A. Tichonor

             Industrial Environmental Research Laborjitory
           Office of Environmental Engineering and Technology
                Research Triangle Park, NC 27711
                       Prepared for

            U.S. ENVIRONMENTAL PROTECTION AGENCY
               Office of Research and Development
                   Washington. DC 20460

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                                  DISCLAIMER
    •This report has been reviewed by the Industrial and Environmental Research
Laboratory, U.S. Environmental Protection Agency, and approved for publication.
Approval does not signify that the contents necessarily reflect the views and
policies of the U.S. Environmental Protection Agency, nor does mention of trade
names or commercial products constitute endorsement or recommendation for use.
                                       ii

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                              TABLE OF CONTENTS

Section                                                                  Page
  1.0     INTRODUCTION	

          1.1   Program Objectives	      3
          1.2   Historical Perspective	      5
                1.2.1   Previous Studies on Refinery Emissions	      5
                1.2.2   Impact of Refineries on Ambient Air Quality .  .      8

  2.0     CONCLUSIONS	  .  .  .     16

          2.1   Fugitive Emissions	     16
                2..1.1   Major Conclusions	     17
                2.1.2   Significant Supporting Results	     20
          2.2   Control Technology	     27
                2.2.1   Fugitive Hydrocarbon Emission Controls	     27
                2.2.2   Stack and Process Emission Controls	     3.1
          2.3   Environmental Impact	     32

  3.0     AVAILABLE CONTROL TECHNOLOGY OPTIONS	     36

          3.1   Control Technology for Fugitive Emission Sources.  ...     36
                3.1.1   Baggable Sources	     36
                3.1.2   Nonbaggablc Sources 	     43
          3.2   Control  Technology for Process Emissions	     45
                3.2.1   Control  of Hydrocarbon (Including aldehydes)     ^
                        Emissions	     46
                3.2.2   Control  of Sulfur Compound Emissions	     47
                3.2.3   Control  of Nitrogen Compound Emissions	     49
                3.2.4   Control  of Particulate Emissions	     49
                3.2.5   Control  of Carbon Monoxide (CO)  Emissions  ...     50
                                    iii

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                      TABLE OF CONTENTS (Continued)

_S ec_t_ion_                                                                 Pa8e
  PART A
  4.0     EMISSIONS MEASUREMENTS	    53

          4.1   Experimental Design of the Program	    54
                4.1.1   Refinery Selection	    54
                4.1.2   Process Unit Selection	    56
                4.1.3   Baggable Source Selection  	    57
                4.1.4   Selection of Nonbaggable. Sources	    62
                4.1.5   Selection of Process Sources	    62
                4.1.6   Modification of the Original Experimental
                        Design	    63
          4.2   Sampling Methodology	    65
                4.2.1   Baggable Source Screening Procedure 	    65
                4.2.2   Sampling Emissions from Baggable Sources. ...    68
                4.2.3   Sampling of Nonbaggable Emission Sources. ...    72
                4.2.4   Sampling of Process Sources (Stacks and
                        Vents) •	    75
                4.2.5   Sampling for Organic Species Identification .  .    81
          4.3   Analytical Methodologies (Field Laboratory) 	    83
                4.3.1   Hydrocarbon Measurement 	    84
                4.3.2   NO/NO  Determination	    85
                             X
                4.3.3   Sulfur Gases	    85
                4.3.4   Aldehydes	    85
                4.3.5   Ammonia	    86
                4.3.6   Cyanide	    86
          4.4   Ide.ntlfication of Emitted Species	    87
                4.4.1   Qualitative Organic Analyses	    87
                4.4.2   Semi-Quantitative Organic Analyses	    90
          4.5   Quality Control	    91
                4.5.1   Screening	    91
                4.5.2   Sampling	    92
                                      iv

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                       TABLE OF CONTENTS (Continued)

Section                                                                   _
                4.5.3   On-Site Analyses	    93
                4.5.4   Species Identification	    93

  5.0     RESULTS OF REFINERY MEASUREMENTS  AND SURVEYS	    95

          5.1   Baggable Source Measurements  and  Results	    95
                5.1.1   Screening of Baggable Sources 	    95
                5.1.2   Hydrocarbon Emissions from Baggable
                        Sources	    102
                5.1.3   Relationships Between Screening Values  and
                        Leak Rates	    117
                5.1.4   Correlation of Leak Rates with  Process  and
                        Equipment Variables 	    159
                5.1.5   Effect of Maintenance Procedures  on Valve
                        Emissions	    165
                5.1.6   Number and Distribution of Baggable Sources  .  .    169
          5.2   Nonbaggable  Source Measurements and Results 	    171
                5.2.1   Cooling Tower Emissions Measurements	    174
                5.2.2   Wastewater Systems	    174
          5.3   Stack Emissions	    177
                5.3.1   FCCU Regenerator Stack Measurements 	    179
                5.3.2   Crude Unit Process  Heater Stack Measurements.  .    179
                5.3.3   Emissions from Tail Gas Treating  Units	    186
                5.3.4   Miscellaneous Source.  Emissions	    186
          5.4   identification of Emitted Species 	    186
                5.4.1   Species Present in  FCCU Regenerator
                        Flue Gas	    189
                5.4.2   Identification of Organic Compounds in
                        Fugitive Vapor Samples	    191
                5.4.3   Potentially Hazardous Organic Species in
                        Sampled Refinery Streams	    191

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                       TABLE OF CONTENTS (Continued)
Se c t i on                                                                  Page
          5.5   Quality Control	199
                5.5.1   Quality Control for Baggable Source
                        Hydrocarbon Measurements 	   200
                5.5.2   Quality Control for Hydrocarbon Screening
                        Devices	204
                5.5.3   Quality Control for Nonbaggable Sources	204
          5.6   Survey Information 	   206
                5.6.1   Maintenance Practices	207
                5.6.2   Process Unit Turnaround Procedures  	   208
                5-6.3   Blind Changing	208
                5.6.4   Sampling Procedures	210
  PART  B
  6.0     POTENTIALLY HAZARDOUS SUBSTANCES 	   212

          6.1   Origin of Potentially Hazardous Substances	   213
                6.1.1   Potentially Hazardous Substances in
                        Refinery Raw Materials 	   213
                6.1.2   Potentially Hazardous Materials Produced in
                        Refining Processes 	   219
          6.2   In-Line Fate of Potentially Hazardous  Suh.st.anc.es ....   227
                6.2.1   Potentially Hazardous Substances Present in
                        Refinery Products	   230
                6.2.2   Potentially Hazardous Materials in Refinery
                        Waste Streams	   231
                6.2.3   Destruction of Potentially  Hazardous
                        Compounds	   236
          6.3   Atmospheric Emissions of Potentially Hazardous
                Substances	   238
                6.3.1   Point Sources	   238
                6.3.2   Fugitive Sources  	   242
                6.3.3   Miscellaneous Factors Affecting Emissions  of
                        Hazardous Substances 	   243
                                     VI

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                        TABLE OF CONTENTS (Continued)

Section                                                                  Page
  7.0     REFINERY CHARACTERIZATION AND CONTROL TECHNOLOGY	    246

          7.1   Refinery Technology Characterization	    246
                7.1.1    Separations	    247
                7.1.2    Thermal Operations	    255
                7.1.3    Cracking Operations 	    266
                7.1.4    1-lydroprocessing	    276
                7.1.5    Conversion Processes	    285
                7.1.6    Gas Processing	    297
                7.1.7    Other Processes	    306
                7.1.8    Waste Treatment	    312
          7.2   Control Technology	    319
                7.2.1    Control of Fugitive Emissions  	    320
                7.2.2    Control of Stack and Other Process
                        Emissions	    357
                7.2.3    Emission Reduction Through Process
                        Modification	    374

  8.0     ENVIRONMENTAL ASSESSMENT	    384

          8.1   Definition of the Refinery Model	    386
                8.1.1    Refinery Process Configuration	    386
                8.1.2    Refinery Layout	    388
          8.2   Emission Calculations  	    388
                8.2.1    Emission Factors and Fitting Counts  	    388
                8.2.2    Emissions of Criteria Pollutants and
                        Total Hydrocarbons	    393
                8.2.3    Emissions of Selected Hydrocarbon
                        Coniponents	    393
          8.3   Atmospheric Dispersion Modeling 	    406
                8.3.1    Chojce of the.  Dispersion Model	    406

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                       TABLE OF CONTENTS (Continued)
                                                                        Page
               8.3.2   Application of the Dispersion Model to
                       the Hypothetical Refinery ............   407
         8.4   Impacts on Ambient Air Quality .............   410
               8.4.1   Criteria Pollutants and Total Hydrocarbons .  .  .   410
               8.4.2   Selected Hydrocarbon Components .........   412
               8.4.3   Discussion of Results ..............   422
         8.5   Effects of Existing and Potential Regulations and
               Policies ........................   426
               8.5.1   State Regulations ................   426
               8.5.2   Federal Regulations and Policies  ........   431
               8.5.3   Potential Regulations and Policies .......   436
         8.6   Effects of New and Developing Technology  ........   439
               8.6.1   Process Technology ...............   439
               8.6.2   Emission Control Technology ...........   440

 9.0     REFERENCES ..........................   441

10.0     CONVERSION FACTORS  ......................   4;>6
                                   VI11

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                              LIST OF TABLES
Tables                                                                  Page

  1-1     Emission Sources Examined in the Los Angeles County
          Joint Study	      6

  1-2     Detailed Annual Emission Estimates - 1976	      9

  1-3     Typical Plume Composition at a Distance of  1.5 Miles
          Downwind of Exxon's Refinery at Benicia,  California	     13

  1-4     Summary of Federal Ambient Air Quality Standards and
          Predicted Maximum Concentrations for 300,000 BPCD
          Refinery Emissions	     15

  2-1     Estimated Fugitive Nonmethane Hydrocarbon Emissions from
          Sources in Process Units of a Hypothetical  330,000 BPD
          Refinery	     18

  4-1     Range of Choice Variables for Screened Baggable Sources.  .  .     58

  4-2     Nominal Operating Conditions for Sampling with Adsorbents.  .     82

  4-3     Summary of Organic Samples for Quantitative Analyses ....     87

  5-1     Categories of Baggable Sources 	     96

  5-2     Summary Statistics for Screening of Baggable Sources ....     98

  5-3     Distribution of Maximum Screening Values  among Screened
          Sources	     99

  5-4     Distribution of Nonmethane Leak Rates from  Sampled Sources  .    104

  5-5     Skewness and Kurtosis Statistics 	    114

  5-6     Estimated Vapor Emission Factors for Nonmethane Hydrocarbons
          from Baggable Sources	    116

  5-7     Regression of Log Leak Rate on Log Maximum  Rescreening
          Value by Source and Stream Type.  .	    119

  5-8     Correlation of Screening (Or Rescreening) Values with
          Leak Rates	    121
                                     ix

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                        LIST OF TABLES (Continued)
Table                                                                  Page

  5-9     Confidence Tnte.rva.ls for Mean and Individual Leak
          Rates - Valves (Gas/Vapor Streams)	     134

  5-10    Percent of Total Mass Emissions Released by the Upper
          Ten Percent of Screened Sources 	     160

  5-11    Continuous and Discrete Variables Considered in This
          Study	     161

  5-12    Correlations Between Continuous Variables and Log10
          Leak Rate	     163

  5-13    Summary of Maintenance Reduction by Leak Rate Level ....     166

  5-14    Statistical Summary of Maintenance  Data - Percent
          Reduction	     167

  5-15    Summary of Hydrocarbon Emission Sources Counted in
          Selected Refinery Process Units 	     170

  5-16    Estimated Number of Individual Emission Sovirces in
          15 Specific Refinery Process Units	     172

  5-17    Average Number and Estimated Distribution of Valve and
          Pump Seals in Refinery Process Units	     173

  5-18    Estimated Emissions for Individual  Towers 	     175

  5-19    Summary of Cooling Tower Emissions	     1.76

  5-20    Description of Sampled Devices - Waste  Oil/Water  Systems.  .     178

  5-21    Results of Sampling Flue Gases from FCCU Regenerators
          Equipped with Electrostatic  Precipitators and CO  Boilers.  .     180

  5-22    Results of Sampling Flue Gases from FCCU Regenerators
          Equipped with CO Boilers and Scrubbers	     181

  5-23    Results of Sampling FCCU Regenerator Flue Gas Upstream
          and Downstream of  CO Boiler/ESP	     182

  5-24    Controlled Emission Rates from Fluid Catalytic Cracking
          Unit (FCCU)  Stacks	     183

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                        LIST OF TABLES (Continued)
Table                                                                   Pace
5-25

5-26
5-27

5-28
5-29
5-30

5-31

5-32
5-33

5-34

5-35
5-36
5-37
5-38
6-1
6-2

6-3
6-4
Results of Sampling Flue Gases from Crude Unit
Process Heaters 	
Composition of Refinery Heater Stack Gas 	
Composition of Stack Gas from Sulfur Recovery Tail Gas
Treating Units 	
Miscellaneous Stack Emissions 	
Organic Species Found in FCCU Flue Gaa Samples 	
Elemental Analysis of FCCU CO Boiler Flue Gas
Particulates (Stack A) 	
Elemental Analysis of FCCU CO Boiler Flue Gas
Particulates (Stack C) 	
Sampled Refinery Hydrocarbon Streams 	
Organic Species Present in Refinery Liquid Streams and
Emitted Vapors 	
Potentially Hazardous Species in Vapor Samples from
Refinery Streams 	
Vapor and Liquid Stream Identification Number 	
Potentially Hazardous Species in Refinery Liquid Streams . .
Summary of Baggable Leak Rate Quality Control Sample ....
Shutdown Frequency 	
Potentially Hazardous Hydrocarbons in Crude Oil 	
Trace Metals Found by Spectrographic Analysis of Ash
from Crude Oil 	
Principal Applications of Catalyst Materials 	
Major Chemicals Used in Refining and Their Principal Uses. .

184
185

187
188
190

192

193
194

195

196
197
198
203
209
214

217
218
220
                                   XI

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                        LIST OF TABLES (Continued)
Table                                                                   Page

  6-5     Hazardous Chemicals Potentially Emitted  from
          Process Units	    228

  6-6     List of Process Units for Table 6-5	    229

  6-7     Main Components of Gasoline	    230

  6-8     Typical Claus Tail Gas Compositions	    241

  6-9     Summary of Hydrocarbon Species Emissions from Fugitive
          Sources in a Large Existing Refinery  Model  (See  Appendix D
          Volume 4)	    244

  7-1     Typical Emissions from Atmospheric  Distillation  Unit
          Process Heaters	    249

  7-2     Estimated Fugitive Nonmethane  Hydrocarbon Emissions  from
          a Typical. Atmospheric Distillation  Unit	    250

  7-3     Estimated Composition of  Nonmethane Hydrocarbon  Fugitive
          Emissions from a Crude Distillation Unit	    251

  7-4     Typical Emissions from Vacuum  Distillation  Unit  Process
          Heaters	    253

  7-5     Estimated Fugitive Nonmethane  Hydrocarbon Emissions  from
          a Typical Vacuum Distillation  Unit  	    254

  7-6     Operating Parameters  and  Utility  Requirements for Three
          Aromatics Extraction  Processes 	  .  	    256

  7-7     Estimated Fugitive Nonmethane  Hydrocarbon Emissions  from
          a Typical Aromatic. Extraction  Unit	    257

  7-8     Estimated Composition of  Fugitive Emissions from an
          Aromatics Extractions Unit  	    258

  7-9     Typical Emissions from Visbreaking  Unit  Process  Heaters.  .  .    259

  7-10     Estimated Fugitive Nonmethane  Hydrocarbon Emissions  from a
          Typical Visbreaking Unit  	    261

  7-11     Typical Emissions from Delayed Coking Unit  Process
          Heaters	    263
                                    xii

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                         LIST OF TABLES (Continued)
Table                                                                   Page

  7-12    Estimated Fugitive ^onmethane Hydrocarbon Emissions
          from a Typical Delayed Coking Unit	264

  7-13    Estimated Composition of Fugitive Emissions  from a
          Delayed Coking Unit	265

  7-]4    Process Conditions for Fluid  Coking  and  Flexieoking  	   267

  7-15    Estimated Fugitive Nonmethane Hydrocarbon Emissions  from  a
          Typical Fluid Coking  Unit 	   268

  7-16    Typical Operating Conditions  for  Fluid Catalytic Cracking .  .   270

  7-17    Emission Rates from FCC Regenerators, Before and After  CO
          Boiler	271

  7-18    Typical Emission  from Catalytic Cracking Unit Process
          Heaters	273

  7-19    Estimated Fugitive Nonmcthane Hydrocarbon Emissions
          from a Typical Catalytic Cracking Unit	274

  7-20    Estimated Composition of Fugitive Emissions  from a Fluid
          Catalytic Cracking Unit 	   275

  7-2.1    Typical Emissions from Hydrocracking Unit Process Heaters .  .   277

  7-22    Estimated Fugitive Nonmethane Hydrocarbon Emissions  from  a
          Typical Hydrocracking Unit	278

  7-23    Typical Emissions from Gas Oil Hydrodesulfurization Unit
          Process Heaters 	   281

  7-24    Estimated Fugitive Nonmethane Hydrocarbon Emissions  from  a
          Typical Gas Oil Hydrodesulfurization Unit	282

  7-25    Estimated Composition of Fugitive Emissions  from a Gas
          Oil  Hydrodesulfurization Unit	283

  7-26    Typical Operating Conditions  for  Three Hydrotreating
          Operations	284

  7-27    Typical Emissions from Hydrotreating Unit  Process Heaters .  .   286
                                    xiii

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                        LIST OF TABLES (Continued)


Table                                                                   Page

  7-28    Estimated Fugitive Nonmethane Hydrocarbon Emissions
7-29
7-30
7-31
7-32
Estimated Composition of Fugitive Emissions from a
Typical Operating Conditions for Alkylation Operations . . .
Typical Emissions from Alkylation Unit Process Heaters . . .
Estimated Fugitive Nonmethane Hydrocarbon Emissions from a
Typical Sulfuric Acid Alleviation Unit 	
288
289
290
291
  7-33    Estimated Composition of  Fugitive Emissions  from an
          Alkylation Unit	    292

  7-34    Operating Conditions and  Utility  Requirements  for
          Paraffins Isomerization Processes	    293

  7-35    Typical Emissions  from Isomerization  Unit  Process Heaters.  .    294

  7-36    Estimated Fugitive Nonmethane  Hydrocarbon  Emissions  from  a
          Typical Butane  Isomerization Unit.  .  .  	    295

  7-37    Typical Emissions  from Catalytic  Reforming Unit  Process
          Heaters	    298

  7-38    Estimated Fugitive Nonmethane  Hydrocarbon  Emissions  from  a
          Typical Catalytic  Reforming Unit  	    299

  7-39    Estimated Composition of  Fugitive Emissions  from a Catalytic
          Reforming Unit	    300

  7-40    Typical Emissions  from Hydrodealkylation Unit  Process
          Heaters	    301

  7-41    Estimated Fugitive Nonmethane  Hydrocarbon  Emissions  from  a
          Typical Hydrodealkylation Unit 	    302

  7-42    Estimated Fugitive Nonmethane  Hydrocarbon  Emissions  from  a
          Typical  Hydrogen Production Unit  	    309

  7-43    Estimated Composition of  Fugitive Emissions  from a
          Hydrogen Production Unit  Utilizing  Naphtha as  Feedstock.  .  .    310

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LIST OF TABLES (Continued)
Table
7-44
7-45

7-46
7-47

7-48
7-49
7-50

7-51
7-52
7-53
7-54

7-55

7-56
7-57

7-58
7-59
7-60



Classification of End-of-Pipe Refinery Wastewater
Treatment Processes 	
API Separator Emission Factors 	
Approximate Distribution of Refinery Process Valves
by Tvpe and Service 	 	
Packing Materials - Process Valves 	
Distribution of Pump Seals in Radian Refinery Studv 	
Centrifugal Pump Seals - Cost Contribution to Total Pump
Cost 	
Estimated Energy Losses - Pimm Seals 	
Compressor Seal Leakage 	
Basic Agitator Seals ... 	
Safety Relief Valve (SRV) and Rupture Disk (RD) Assembly
Costs 	
Degree of Adoption of Various Wastewater Treatment
Processes 	
Radian-Generated Cooling Tower Emission Factors 	
Typical Compositions of Feed Stream and Tail Gas for a
94 Percent Efficient Glaus Unit 	
Existing Methods for Removal of Sulfur from Glaus Tail Gas .
Flue. Gas Desulfurization Process 	
Emission Factors for Reciprocating and Gas Turbine
Compressor Fueled with Natural Gas 	
Page
314

316
318

321
324
334

335
336
341
344

348

351
355

360
361
364

375
              XV

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LIST OF TABLES (Continued)
Table
7-61

7-62

7-63
8-1
8-2
8-3
8-4
8-5
8-6
8-7

8-8
8-9
8-10

8-1.1

8-12
8-13

8-14

8-15

Reductions of NO Emissions with Combustion Modifications
at Various Boiler Loads 	
Engine Modifications Which Reduce NO Emissions from
Internal Combustion Engines 	
Refinery Fuel Emissions at Equivalent Heat Release 	
Large Capacity Existing Refinery Module Key 	
Fugitive Sources and Emission Factors 	
Process Sources and Emission Factors 	
Summary of Emissions from the Model Refinery 	
Distribution of Unit Fugitive Emissions by Stream 	
Summary of Stream Quality Cata (PPMW) 	
Fluid Catalytic Cracking - Fugitive Emission
Characterization 	
Relief Valve Distribution 	
Relief Valve Summary - Fugitive Emission Characterization. .
Estimated Composition oi" Inlet Oil, Hydrocarbon Vapor, and
Outlet Oil Streams Around an API Separator 	
Summary of Hydrocarbon Species Emissions from Fugitive
Sources 	
Source Severity Factors for Criteria Pollutants 	
Hydrocarbon Species Ambient Concentration at the Point of
Maximum Total Hydrocarbon Concentration 	
Maximum Ambient Concentration of Selected Hydrocarbon
Species 	
Summary of "F" Values. . 	
Page

378

380
381
390
391
392
394
396
397

401
402
403

404

405
411

414

416
418

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                        LIST OF TABLES  (Continued)
Table                                                                   Page




  8-1.6    Source Severity Factors for Selected Hydrocarbon Species.  .  .   420
                                     XVJl

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                             LIST OF FIGURES
Figure                                                                 L?&§.

  4-1     Sampling Train for Baggable Sources  of  Hydrocarbon
          Emissions	     70

  4-2     Method 5 Train for SO?  and Particulates	     76

  4-3     Aldehyde Impinger Train	     77

  4-4     Grab Sample Collection  and Preparation  System	     78

  5-1     Distribution of Screening Values  for Valves  - Light  Liquid
          Streams	    103

  5-2     Distribution of Leak Rates for  Valves - Light Liquid/Two-
          Phase: Streams	    108

  5-3     Histogram of Ln of Nonmethane Leak Rate-Valves, Light
          Liquids/Two-Phase Streams	    113

  5-4A    Nomograph for Predicting  Total  Hydrocarbon Leak Rates
          from Maximum Screening  Values - Pumps (Light Liquids),
          Compressors, Relief Valves (Gas/Vapor Streams)  (Part I:
          Screening Values from 0 - 10,000  ppmv)  	    122

  5-4B    Nomograph for Predicting  Total  Hydrocarbon Leak Rates
          from Maximum Screening  Values - Pumps (Light Liquids),
          Compressors, Relief Valves (Gas/Vapor Streams)  )Part II:
          Screening Values from 0 - 100,000 ppm)	    123

  5-5A    Nomograph for Predicting  Total  Nonmethane Hydrocarbon
          Leak Rates from Maximum Screening Values - Valves  and
          Compressors in Hydrogen Service (Part I:  Screening  Values
          from 0 - 10,000 ppm)	    124

  5-5B    Nomograph for Predicting  Total  Nonmethane Hydrocarbon
          Leak Rates from Maximum Screening Values - Valves  and
          Compressors in Hydrogen Service (Part II:  Screening Values
          from 0 - 100,000 ppm)	    125

  5-6A    Nomograph for Predicting  Total  Nonmethane Hydrocarbon
          Leak Rates from Maximum Screening Values - Valves, Gas/Vapor
          Streams (Part I:   Screening Values from 0 -  10,000 ppm). .  .    126
                                  xv in

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                        LIST OF FIGURES (Continued)
F_ig_ur_e                                                                  Fage

  5-6'B    Nomograph for Predicting Total Nonmet.hane Hydrocarbon
          Leak Rates from Maximum Screening Values - Valves,
          Gas/Vapor Streams (Part II:   Screening Values from
          0 - 100,000 ppm)	     127

  5-7A    Nomograph for Predicting Total Nonmethane Hydrocarbon
          Leak Rates from Maximum Screening Values - Valves,  Light
          Liquid/Two-Phase Streams (Part I:  Screening Values from
          0 - 10,000 ppm)	     128

  5-7B    Nomograph for Predicting Total Nonmethane Hydrocarbon Leak
          Rates from Maximum Screening Values - Valves, Light
          Liquid/Two-Phasc Streams (Part II:   Screening Values from
          0 - 100,000 ppm)	     129

  5-8     Nomograph for Predicting Total Nonmethane Hydrocarbon
          Leak Rates from Maximum Screening Values - Drains 	     130

  5-9     Nomograph for Predicting Total Nonmethane Hydrocarbon
          Leak Rates from Maximum Screening Values - Flanges	     131

  5-10A   Nomograph for Predicting Total Nonmethane Hydrocarbon
          Leak Rates from Maximum Screening Values - Pumps, Heavy
          Liquid Streams (Part I:  Screening Values from
          0 - 10,000 ppm)	     132

  5-103   Nomograph for Predicting Total Nonmethane Hydrocarbon
          Leak Rates from Maximum Screening Values - Pumps, Heavy
          Liquid Streams (Part TI:  Screening Values from
          0 - 100,000 ppm)	     133

  5-11    Nomograph for Predicting Total Nonmethane Hydrocarbon
          Leak Rates from Maximum Screening Values - Valves,  Light
          Liquid/Two-Phase Streams (Part II:   Screening Values from
          0 - 100,000 ppm)	     135

  5-12A   Cumulative Distribution of Sources  and Total  Emissions by
          Screening Values for Valves  - Gas/Vapor Streams 	     137

  5-12B   Cumulative Distribution of Source and Total Emissions by
          Screening Values for Valves  - Gas/Vapor Streams 	     138
                                     xix

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                        LIST OF FIGURES (Continued)
Figure                                                                  Page

  5-13A   Cumulative Distribution of Source and Total Emissions
          by Screening Values for Valves - Light Liquid/Two-Phase
          Streams	    139

  5-13B   Cumulative Distribution of Source and Total Emissions by
          Screening Values for Valves - Light Liquid/Two-Phase
          Streams	    140

  5-14A   Cumulative Distribution of Sources and Total  Emissions
          by Screening Values for Valves - Heavy Liquid Streams. .  .  .    141

  5-14B   Cumulative Distribution of Source and Total Emissions by
          Screening Values for Valves - Heavy Liquid Streams  	    142

  5-15A   Cumulative Distribution of Sources and Total  Emissions by
          Screening Values for Valves - Hydrogen Service 	    143

  5-15B   Cumulative Distribution of Source, and Total Emissions by
          Screening Values for Valves - Hydrogen Service 	    144

  5-16A   Cumulative Distribution of Sources and Total  Emissions by
          Screening Values for Pump  Seals - Light Liquid Streams .  .  .    145

  5-16B   Cumulative Distribution of Source and Total Emissions by
          Screening Values for Pump  Seals - Light Liquid Streams .  .  .    146

  5-.17A   Cumulative. Distribution of Sources and Total  Emissions by
          Screening Values for Pump  Seals - Heavy Liquids	    147

  5-17B   Cumulative Distribution of Source and Total Emissions by
          Screening Values for Pump  Seals - Heavy Liquids	    148

  5-18A   Cumulative Distribution of Sources and Total  Emissions by
          Screening Values for Flanges 	    149

  5-18B   Cumulative Distribution of Source and Total Emissions by
          Screening Values for Flanges 	    150

  5-19A   Cumulative Distribution of Sources and Total  Emissions by
          Screening Values for Compressor Seals - Hydrocarbon  Service.    151

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                        LIST OF FIGURES (Continued)


Figure                                                                  Page

  5-19B   Cumulative Distribution of Source and Total Emissions
          by Screening Values for Compressor Seals - Hydrocarbon
          Service	    152

  5-20A   Cumulative Distribution of Sources and Total Emissions  by
          Screening Values for Compressor Seals - Hydrogen Service  .  .    153

  5-20B   Cumulative Distribution of Source and Total Emissions by
          Screening Values for Compressor Seals - Hydrogen Service  .  .    154

  5-21A   Cumulative Distribution of Sources and Total  Emissions  by
          Screening Values for Drains	    155

  5-21B   Cumulative Distribution of Source and Total Emissions by
          Screening Values for Drains	    156

  5-22A   Cumulative Distribution of Sources and Total Emissions  by
          Screening Values for Relief Valves 	    157

  5-22B   Cumulative Distribution of Source and Total Emissions by
          Screening Values for Relief Valves 	    158

  7-1     Simple Packed Seal	    322

  8-1     Block Flow Diagram of Model Refinery  	    387

  8-2     Model Refinery Layout	    389

  8-3     Hydrocarbon Isoploth 	    413

  8-4     PSD Applicability Chart	    434
                                   xx I

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                              ACKNOWLEDGMENTS

          Radian wishes to acknowledge the assistance of Dr. Dale Denny,
Dr. I. A. Jefcoat, and Dr. Bruce Tir.henor of the U.S. Environmental
Protection Agency under whose guidance this program has been carried out.

          Radian would like to thank the members of the. Ad Hoc Advisory
Panel of the American Petroleum Institute.  Their assistance in the formu-
lation of the emissions' measurement portion of the. study (Part A) and their
advice during its duration are greatly appreciated.  Radian especially wishes
to thank Mr. Edward P. Crockett of the American Petroleum Institute for his
considerable efforts in support of the emissions measurement project.

          Radian is also very grateful to Mr. Herbert W. Bruch of the National
Petroleum Refiners Association for his substantial assistance with the field
measurement program.

          The emissions measurement data which were used as part of the basis
of this report were obtained at a number of refineries throughout the
country.  The assistance and exceptional cooperation of the staffs of these
refineries is gratefully acknowledged.

          It would be impossible to individually thank everyone of the
Radian staff who participated in this program.   Their outstanding attitude
and dedication have made this project successful.
                                     xx 11

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 1.0        INTRODUCTION

           This  three year refinery assessment program was conducted by
 Radian Corporation under EPA Contract Nos. 68-02-2665 and 68-02-2147,
 Exhibit B.  The assessment report is being issued in five volumes.  Volume
 1 contains the main body of the report.  Volumes 2-5 contain six appendices
 to the report.

           This volume, Volume 1, contains eight major sections plus the
 reference  section and conversion table (English units to metric units).
 Section ], Introduction, contains a listing of the program objectives
 and a description of earlier studies of environmental impacts of petroleum
 refineries.  The major conclusions of the current program and the signifi-
 cant results which support the conclusions are presented in Section 2.
 Emission control options recommended for refinery emission sources are
 listed in  Section 3 of this report.

          The major segments of the. refinery assessment report can be
 logically  separated into two major parts, Part A and Part B.  Part A con-
 tains the description and results of the field measurement activities.
 Sections 4 and 5 of the report are contained in Part A.   The environmental
 assessment of refineries and the control technology evaluation are pre-
 sented In Part B.   The background information and data necessary for the
 assessment and evaluation art> also included in Part B, which contains
 Sections 6, 7, and 8 of the report.

          Section 4 contains a description of the methodologies used to
 determine fugitive and process emission rates as well as to characterize
 fugitive hydrocarbon emissions.   The results of the emissions measurements
 at 13 petroleum refineries are summarized in Section 5.   The results of the
program and interpretations of the data are presented in this section also.

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          Section 6 of this report contains a discussion of some potentially
hazardous substances which may be present in refinery feed, intermediate,
product, and waste streams.  The individual refinery process technologies
are described and characterized in Section 7.  An estimate of emissions is
also presented for each of the refinery processes.

          An environmental assessment was performed to examine the effects
of refinery emissions on the surrounding atmosphere.  The results are pre-
sented in Section 8 of this document.

          The appendices of this report, presented in Volumes 2-5, contain
more detailed descriptions of the program methodologies, a more comprehen-
sive presentation of results, and more extensive discussions about refinery
process technology and control, technology.

          Appendix A (Volume 2) contains detailed descriptions of the
sampling methodology used in the refinery assessment program.  Included
are descriptions of the experimental program design, the emissions sampling
methodologies, and the analytical techniques employed in the field sampling
segment of the assessment study.  Also described are the techniques used to
identify and quantitate individual species present in refinery streams and
vapor emissions.

          Appendix B (Volume 3) contains a detailed summary of the results
obtained while measuring emissions to the atmosphere at 13 petroleum refin-
eries.   The data and results from the sampling program are displayed in
tables and figures.  Emission factors, screening relationships, and corre-
lations are presented.  The frequency and distribution of emissions sources
in refineries are also included.  The effects of valve maintenance operations
on the leak rate from valves are described in Appendix B.

          The quality  assurance program and the statistical analysis of the
emissions data are presented in Appendix C (In Volume  4).  Quality control

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procedures for screening, sampling, analyses, species identification, and
data validation are described.  The various types of quality control data
collected during the. program are included in Appendix C.  The statistical
analysis of the data is described, and the accuracy and precision of the
various data types are discussed.

          The procedures used to develop a detailed environmental assess-
ment of refineries are described in Appendix I) (in Volume 4).  The large
volume of refinery emission rate data generated in the refinery assessment
program was used to predict ambient air pollutant levels in the vicinity
of a model refinery.  The environmental effects and the potential hazard
to the public are discussed in detail in Appendix D.

          Appendix E (in Volume 4) contains a detailed review and evaluation
of pollution control technology.  The state-of-the-art of fugitive and pro-
cess emission controls in refineries are reviewed.  Available controls are
described.  Control technologies used in related industries are examined
for potential applicability in the refining industry.

          A detailed characterization of refinery technology is presented
in Appendix F (Volume 5).   Petroleum refineries in the U.S.  are classified
and characterized.   Four types or sets of refinery models which could be
used to simulate the entire refining industry are included in this appendix.
The characteristics of crude oils, other raw materials,  intermediate pro-
ducts, and final products  are described.  Detailed descriptions of current
refinery process technology are included.  Atmospheric emissions which
result during the operation of each process are estimated and presented
in Appendix F.

1.1       F r o g r am Object, i v e s

          The refinery assessment program had three ultimate objectives, all
of which addressed  important environmental questions concerning the effect

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 of  refineries  on  air  quality:   (1)  quantification  of  fugitive  hydrocarbon
 emissions  from petroelum  refineries,  (2)  evaluation of  existing  and  develop-
 ing  refinery control  technologies,  and  (3)  assessment of  the potential
 impact  of  atmospheric  refinery  emissions  on the  surrounding environment.

           Over the  three  year period, the program  evolved  to focus on  these
 three objectives.   The program  originally planned  to  address objectives  (2)
 and  (3).   Objective (1) was  added after work x%?as initiated.  Several factors
 contributed to the  addition  of  Objective  (1).

           As the work  began, it became evident that fugitive emissions were
 a large, if not the largest, source of hydrocarbon emissions from refiner-
 ies.  Moreover, quantitative information  concerning fugitive emissions from
 refineries was scarce.  Because of  these  developments,  the program was
 modified to incorporate the measurement and estimation  of  fugitive hydro-
 carbon  emissions from  refineries.

           This objective was given  further  emphasis by  the Clean Air Act
 and  its emissions off-set regulations.  Compliance with these  rules  necessi-
 tated emission factors  for use.  in off-set calculations.

           In meeting Objective  1 Radian conducted a field sampling program
 to obtain  data  from a number of U.S. petroleum refineries.  When necessary,
 appropriate sampling and analytical methods were developed and verified.

           In order  to  evaluate existing and developing  control technologies
 (Objective 2), Radian analyzed the data obtained from the program's  field
 sampling program.   Information obtained from literature sources also con-
 tributed to the data base, as did information from vendors and equipment
manufacturers.

           Statistical and atmospheric dispersion models were used to meet
 Objective  3.   Emission factors developed from the project's field sampling

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results were used in these models  to assess the environmental impact of
petroleum refineries.

1.2       Historical Perspective

          Some of the more important studies of refinery emissions prior to
the refinery assessment program are described in this section.  Also
described are the potential impacts of refineries on ambient air quality.
Since emissions from storage and loading facilities were not within the
scope of the refinery assessment program, studies describing emissions
from these sources are not included.

1.2.1     Previous Studies on Refinery Emissions

          One of the earliest and most comprehensive studies of refinery
emissions was made in a joint (district, state, and federal) project carried
out in Los Angeles County in 1955-57."  Extensive field testing was per-
formed to obtain a data base, from which emission factors could be developed.
Emission sources considered in this study are listed in Table 1-1.

          Although substantial amounts of information were obtained from the
Los Angeles Joint Study, data gaps existed.  Leak screening methods were
sometimes inadequate.  Relatively insensitive techniques were sometimes
used to measure leak rates.  Losses from some unit operations may have
been inaccurately estimated.

          In 1971,  Litchfield published hydrocarbon emission factors for
uncovered and covered API separators.2  The hydrocarbon evaporative losses
were determined under laboratory controlled conditions with simulated
covered and uncovered API separators.   The simulated separator covers con-
sisted of a cellular glass insulation floating directly on the oil.  In
the laboratory simulation study, Litchfield found that evaporative loss
from an uncovered separator varied with ambient temperature, influent

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     TABLE 1-1.  EMISSION SOURCES EXAMINED IN THE LOS ANGELES COUNTY
                 JOINT STUDY
        Valves and flanges

        Pressure relief valves

        Catalytic cracking regenerator stacks

        Cooling towers

        Compressor seals

        Pump seals

        Boilers and process heaters

        Air blowing operations

        Blind changing operations

        Loading facilities

        Turnarounds, equipment maintenance, and blowdown systems

        Wastewater separators and process drains

        Gas compressor internal combustion engine exhaust

        Waste gas flares

        Vacuum jets
Source:  Reference 1.

-------
 temperature,  and  the  ten percent  true boiling point of the oil.  However,
 no  attempt was made to verify  the  laboratory findings with the performance
 of  actual API separators.

          In  1976, 19 valves,  four compressors, two pumps, and two regula-
 tors were tested  for hydrocarbon  emissions at a California gas plant.3  The
 fugitive hydrocarbon emission  rate was found to be very low, less than one
 percent of the rates found in  the Joint Study.  This small data base, how-
 ever, was inadequate for making any conclusions regarding the results.

          Ambient concentrations and fugitive emission rates from fittings
 (primarily valves and flanges) in a Colorado natural gas producing field
 were measured in  a 1976 study.1*  No leaking flanges were found, but ]6
 percent of the tested valves leaked.  The valve leak rates varied signifi-
 cantly with time.  Only cool valves were included in the study, but this
 included most of  the fittings in the gas field.

          Trie California Air Resources Board (CAKB) sponsored a study of all
 organic species emissions in the South Coast Air Basin.5'6  Oil refineries,
 accounting for about ten percent of all organic emissions, were included in
 the project.  Two refineries were visited over a three week period.  Fugi-
 tive emissions were monitored from 5,800 valves, 12,000 flanges,  .115 pumps,
 five compressors, three cooling towers and three oil/water separators.
 Soap solution was primarily used to detect and estimate emissions.   It was
 concluded that "the emission factors in AP-427 are reasonable estimates for
 average emissions, and that refinery fugitive emissions are primarily
paraffins with low photochemical reactivity."  However, economic  constraints
 limited the amount of testing conducted.   The emission rates from only 25
valves and 25 pump seals were actually measured.  The remaining leak rates
were estimated from visual observations or from hydrocarbon detector
readings.

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          In June 1978, EPA's Office of Air Quality Planning and  Standards
published a gu.ide.Jine report entitled "Control of Volatile Organic Compound
Leaks from Petroleum Refinery Equipment."8  In this document,  the frequency
of leaks found by EPA in source testing at four refineries was reported.
The tested sources included 482 pimp seals, 15 compressor seals,  940 block
valves, 287 control valves, 43 opei^-endcd lines, 367 drains, and  15 pressure
relief devices.  The devices were tested by monitoring the hydrocarbon con-
centration with a portable hydrocarbon de.tector at a position  five centi-
meters from the emission area.  A concentration of 1,000 ppmv  or greater
was designated a "leak."  Thirteen percent of the inspected pump seals,
seven percent of the compressor seals and six to seven percent of the
valves were found to leak.

          In February 1978, members of CARB conducted an inspection of
valves and flanges in six refineries in Los Angeles.  Sources  in 49 process
units were inspected.  Over thirteen thousand valves and nearly 25,000
flanges were included in the study.9  Sources were classified  as "non-
leaking," "slow-leaking," or "fast-leaking" based on visual inspection of
soap solution applied to the source.  CARB found that approximately nine
percent of the inspected valves leaked, and determined an average, leak rate
of 0.11 Ib/day for all of the inspected valves.  Apparently, no hot valves
(> ~ ISO0!1')  were inspected, since hot valves cannot be accurately inspected
with soap solution.   Error limits or a confidence interval for the emission
factor were not reported.

1.2.2     Impact of  Refineries on .Ambient Air Quality

          Petroleum refineries are sources of primary criteria pollutants
such as SO ,  CO, NO , hydrocarbons,  and particulates.   A detailed emission
          x        x
estimate for  1976 for major sources  of these pollutants is shown in Table
1-2.lC   As the table indicates,  emissions from refineries made up from 0.7
percent to 3.2 percent of the total  01 all  criteria pollutants from all
sources in the United States.   Hydrocarbon emissions from refinery processes

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                            TABLE  1-2.   DETAILED  ANNUAL  EMISSION ESTIMATES - 197610
Transportation Standard Fuel

3 of X of
Tons per U.S. Tons per U.S.
Pollutant "Year Emissions Year Emissions
Paniculate* (TSP) 1.2 9.0 4.6 34. 3
Sf)x 0.8 3.0 21.9 81.4
NflK 10.1 43.9 11.8 51.3
*
CO 69.7 79.9 1.2 1.4
Industrial Process

7, nf
Tons per U.S.
Year FjeLflflLono
0.1 0.7
O.7 2.6
0.3 1.3
0.9 3.2
2.6 2.B
Fjilflfilons Solid Vance Ml»c«l]n

I of I of
Tons per U.S. Tons per U.S. Tons per

6.2 46.3 0.4 3.0 0.9
3.4 12.6 0.0 0.0 0.1
0.4 1.7 0.1 0.4 0.3
8.5 30.5 0.8 2.9 5.i
5.4 6.2 2.8 3.2 S.7
.nfllona
Z of
Total
U.S.
6.7
O.4
19.7
6.5
Hydrocarbon emission estimates are basically for  total hyiirocarbcmu.  Sourcea tlut emit only  raethane *re generally not included.  Sources that vale
mixture of hydrocarbons,  including nethane, would include methane in the.total hydrocarbon caittsion cstiaatea.

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are approximately 3.2 percent of the  total hydrocarbon emissions from all
man-made sources in the United States.  Hydrocarbon emissions from
refinery-associated storage, facilities are included in the "Other Process"
category of Industrial Process Emissions.

          Sittig11 estimated the emissions from 262 United States refin-
eries  (1969) as follows (in 1.06 metric tons/year) :

                   Participates           0.1
                   S0x                    2.0
                   NOX                    0.1
                   HC                     2.1
                   CO                     2.2
Sittig's estimates of SO  and hydrocarbon emissions from refineries are
                        X
higher than shown in Table 1-2.  However, Sittig's calculations were very
general, and he assumed n<
of hydrocarbon emissions.
general, and he assumed no control of SO  emissions and 50 percent control
          More recently, Wallace22 estimated hydrocarbon emissions from
petroleum processes to be 4.5 x 106 and 4.6 x 1Q6 metric tons per year in
1974 and 1975, respectively.  This is much higher than the EPA estimate of
0.9 x 106 metric tons per year for 1976.  However, Wallace calculated the
emissions using emission factors from AP-42.7  The emission factors for
uncontrolled sources may have been exclusively used.  Additionally, hydro-
carbon emissions from storage facilities were also apparently included in
the total.

          The impact of refineries on ambient air quality has been studied
both theoretically and experimentally.  Several studies of ambient air
quality in the vicinity of petroleum refineries have been made.  In 1975,
the American Petroleum Institute published the results of a study involving
refinery odor control and ambient levels of pollutants from refinery
                                    10

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operations.13  As part of this project,  the amhient air at five refineries
was sampled.  The ambient air in nearby  residential areas was also sampled.
All of the ambient air samples were analyzed for  total hydrocarbons  (THC),
organic sulfur compounds  (RS11) , NH3, and S02 •

          Residential and other sites at distances of approximately  1-2
miles had ambient air concentrations of  pollutants as shown below:
                   SO;, :    0.00-0.04 ppmv
                   NH3 :    0.01-0.02 ppir.v
                   THC :    1.8  - 4.7  ppmv
                   RSH:    0.00
          Background concentrations of these pollutants were in the follow-
ing ranges:
                   S02 :    0.00  - 0.001 ppmv
                   NII3 :    0.007-0.01  ppmv
                   THC:    0.3   - 0.8   ppmv
                   RSH:    0.00  ppmv
          In another study, Westberg, et al.1'4 sampled ambient air for
hydrocarbons, CO, NO , and ozone downwind of the Texaco refinery in
                    X
Lawrenceville, Illinois.  This particular refinery was selected because
it was a large plant located in a region relatively devoid of other
industrial and urban emission sources.  Westberg found that the refinery
plume could be identified on the basis of elevated hydrocarbon levels out
to a distance of 25 miles.  At a distance of 1.5 miles from the refinery,
the plume contained nonmethane hydrocarbon (NM11C) at concentrations of 1 - 2
ppmv, CO levels of 3-5 ppmv, NO  concentrations in the range of 30 ppb.  A
decrease in the ozone concentration was noted in the plume compared with
the ozone levels outside the plume.  Background levels of the species
                                    11

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 outside of the plume, were about 0.2 ppm for NMHC, about 0.7 ppui for CO and
 15 ppb for N0x.

          Westberg found that most of the hydrocarbons in the plume were
 alkanes.  There was no evidence of ozone formation in the plume as it moved
 downwind of the refinery.  The deficiency of ozone in the plume was
 attributed to the reaction of ozone with NO  present in the plurae.
                                           X

          In 1975 Sexton and Westberg15 conducted an ambient air monitoring
 program to characterize airborne emissions from the Exxon petroleum refinery
 in Benicia, California.  The refinery plurae could be tracked up to eight
miles downwind of the plant.  Sexton and Westberg found elevated levels of
 total hydrocarbons (THC) , nonmethane hydrocarbons (NMHC), CO, and NO  within
                                                                    X
 the Exxon plume at distances of less than five miles downwind.  Elevated
 NMHC levels persisted as far downwind as eight miles.  A typical plume
 composition at a distance of 1.5 miles downwind of the refinery is shown
 in Table 1-3.  The ambient air composition outside of the plume is also
 shown.  All the measured species, with the exception of ozone, show elevated
 concentrations in the plurae.  The concentration of ozone in the plume was
 substantially below that found in the air outside of the plume.  This was
attributed to the scavenging action of nitric oxide, the low levels of
"reactive" hydrocarbons, and the velocity of the plurie.  Only about 30
minutes was required for the plume to travel eight miles.  Ozone was formed
when bag samples of plume air were irradiated in sunlight for six hours.

          Studies of refinery siting problems have been made in recent
years.  In these cases, atmospheric dispersion models are used to predict
maximum ambient air pollutant concentrations.  These concentrations are
then compared to various federal standards as well as state and local
ambient air standards.

          In 1974, Radian16  investigated problems associated with siting
refineries at five different locations in the United States.  Dispersion
                                    12

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    TABLE 1-3.  TYPICAL PLUME COMPOSITION AT A DISTANCE OF 1.5 MILES
                DOWNWIND OF EXXON'S REFINERY AT BENICIA, CALIFORNIA15
   Measured Species
                                    Concentration  of Species in Air, ppmv
   In Plume
500 ft. Above
Ground Level
 Out of Plume
 500 ft.  Above
 Ground Level
CHt
 2.0  ±0.1
  1.7   ±0.1
Total Hydrocarbon
 2.3  ±0.1
  1.7   -  0.1
Nonmethane Hydrocarbon
 0.3  ± 0.1
< 0.1   ±0.1
CO
 0.7  ± 0.1
  0.4   ±0.1
NO
 0.07 ± 0.005
  0.02  ±  0.005
                                    0.03 ± 0.005
                            0.06 ± 0.05
                                    13

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models were used to predict ambient air quality in the vicinity of
hypothetical refineries.  The size of the hypothetical refineries varied
from 180,000 to 250,000 barrels per day.  This study found that the pre-
dicted maximum ground level concentrations of S02, NO , particulates, and
GO from refinery operations did not exceed the federal primary and
secondary ambient air quality standards at any of the sites.  However,
the predicted hydrocarbon concentration exceeded the existing federal
guidelines at all sites by a factor ranging from 20-40.

          In a similar study, Cavanaugh, et al.,17 performed dispersion
modeling of a model 300,000 barrel per day refinery sited in Brazoria,
Texas.  The results of the modeling are shown in Table 1-4.  It can be
seen that the predictions indicate the ambient air levels of S02,  particu-
lates, N0x and CO are well below federal ambient air quality standards.
However, the predicted hydrocarbon concentration exceeded the federal
guidelines for three-hour maximum (6-9 AM)  nonmethane hydrocarbons con-
centration of 160 Ug/m3 (0.24 ppmv).   Nonmethane hydrocarbon concentrations
of 20-40 times the guideline concentrations were predicted in the ambient
a.ir in the vicinity of the refinery.   It should be noted that this federal
guideline, is no longer widely accepted or used because the relationship
between ozone formation and ambient hydrocarbon concentrations is  not
adequately defined.
                                    14

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TABLE 1-4.  SUMMARY OF FEDERAL AMBIENT AIR QUALITY STANDARDS AND PREDICTED MAXIMUM
            CONCENTRATIONS FOR 300,000 RPCD REFINERY EMISSIONS

         (Units arc Micrograrns per Cubic MeLer with Parts per Million  in Parentheses)





Sulfur oxides
Annual average
24 hr maximum "
3 hr maximum
Particulate
Annual average
24 hr maximum
Nitrogen dioxide
Annual average
Nonnethane hydrocarbons
3 hr maximum , 6 to 9 AH
Carbon monoxide
8 hr maximum
1 hr maximum0

Computed
Federal Federal Maximum3 Computed
Primary Secondary Annual Maximum
Standard Standard Average 24 hr Average
.
80(0.03) - 4.2(0.002)
305(0.14) - - 26.5(0.01)
1.300(0.5)

75 60 0.7
260 150 - 5.1

100(0.05) - 5.3(0.003)

160(0. 24) f -

10,000(9) -
40,000(35) -
Computed Computed Computed
Short-Term Short-Terra Short-Term
Maximum3 Maximum3 Maximum*
Unstable Stable Typical
Condition Condition Conditions
*. «. —
_
— -
135(0.051) > 36d 36.1(0.014)

- -
-

_

1,500(2.26) 40,000(60.26) 605(0.01)

9.6(0.01)
14.6(0.01) - 4.4(0.004)
Maximum values are those that occur on or outside the plant boundary.
b
Arithmetic mean.
Not to be exceeded more
This maximum Is beyond
Geometric mean.
f


than once per year.
the computational range used.









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 2.0        CONCLUSIONS

           Several important:  conclusions can be drawn from  the results
 generated  by  this work.  Conclusions and significant results which support
 them are highlighted in  this section.  A more complete summary of the
 results of  this program  is included in Section 5.  For convenience, the
 conclusions are presented in sections which correspond to  the three major
 objectives  presented in  Section .1.  Section 2.1 contains important con-
 clusions concerning fugitive emissions.  Control technology evaluations
 are presented in Section 2.2.  Section 2.3 presents conclusions derived
 from analysis of the environmental impact of refineries on their
 surrounding areas.

 2.1       F ugi t ive Emi s si on s

          Fugitive emissions are generally characterized by a diffuse
 release of vaporized hydrocarbon or other organic compounds.  They origi-
 nate from equipment leaks as well as large and/or diffuse sources.  In
 this study, fugitive emission sources are categorized as either "baggable"
 sources or  "nonbaggable" sources.

          Baggable sources are those that can be enclosed in some type of
 "bag" or "tent" to measure their emission rates.   Source types included in
 the baggable category include valves, flanges,  pump seals, compressor seals,
 drains, and relief valves.

          Nonbaggable sources of fugitive emissions are those sources which
 are too large or diffuse to enclose.   Emission  estimates must be made by
 indirect means.   Nonbaggable sources include cooling towers, wastewater
 treating units,  spills,  turnaround's,  blind changing, coking, air blowing,
vacuum jets, barometric  condensers, and sampling operations.  Only cooling
 towers, oil-water separators, and dissolved air flotation units were
                                    16

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actually sampled in  this study.  Information was obtained by  survey  forms
about maintenance practices, turnarounds, blind changing, and sampling
operations.

          Five major conclusions may be drawn about  fugitive  emissions  in
refineries.  These conclusions are presented below.   They are followed  by
significant results which support them.   Supporting  data are.  organized  by
source  type.

2.1.1     Major Conclusions

          Substantial hydrocarbon emissionsoccurfrom fugitive sources
          in^ refineries.

          The estimated nonmethane hydrocarbon emissions from eight  sources
in the process units of a hypothetical* 330,000 BPD  refinery  are about  630
pounds per hour (approximately 2,600 tons per year).  The emissions  and
their sources are shown in Table 2-1.  The hypothetical refinery was assumed
to have covered API separators.

          Hydrocarbon emissions froir. process sources  (stacks) are minimal.
An FCCU unit equipped with a CO boiler emits from 1  to 12 pounds of  non-
methane hydrocarbons per 1,000 barrels of feed.  This is equivalent  to  2 to
25 pounds per hour of emitted hydrocarbons.

          The only _ e.q_ulpinen_t or pjrocess variab] e. found to correlate with
          fugitive emission rates was the volatilityand/or the phase of
          the process stream.

          The variouvS source leak rates were correlated with  all available
process and equipment variables.   The volatility range and/or phase of  the
 Arthur D. Little Gulf Coast Cluster Mode] Kefinery - Capacity 330,000 BPD?37
                                    17

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   TABLE 2-1.  ESTIMATED FUGITIVE NONMETHANE HYDROCARBON EMISSIONS FROM
               SOURCES IN PROCESS UNITS OF A HYPOTHETICAL 330,000 BPD
               REFINERY

Fugitive Source
Valves
Flanges
Pump Seals
Compressor Seals
Drains
Vessel Relief Valves (gas)
API Separators (from AP-427 )b
Cooling Towers

Nonmethane Hydrocarboi
Ib/hr
305
25
60
29
48
21
138
2C
628
i Emission Rates
o
Tons/year
1,270
104
250
12.1.
200
87
574
8
2,614
 Assuming  95  percent  on-stream time  for  process  units.

 Separators are  covered.
"Controlled  emissions.
                                    18

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process stream correlated with the log of the leak rates with simple
correlation coefficients of 0.65 to 0.7.5.  Correlation coefficients between
log leak rate and other tested variables ranged between 0.01 and 0.35,
indicating very low degrees of correlate on.

          ValvesL were found to be the largest contributors of fugitive
          emissions from baggahle source types.

          For a 330,000 BPD hypothetical refinery, valves were estimated to
emit approximately 300 pounds of nonmethane hydrocarbons per hour.  The
total hydrocarbon emissions from fugitive sources in this refinery was
estimated to be about 630 pounds per hour.  Thus, valves are responsible
for about 50 to 60 percent of the fugitive hydrocarbon emissions.  The
hypothetical refinery was assumed to have covered oil-water separators.

          The major portion of fugitive emissions from any baggable source
          type come from a small fraction of the sources.

          For example, approximately 70 percent of the nonmethane. hydro-
carbon emissions from valves in gas service, corjp. from only one percent of
the valves in that service.  Tn this study, approximately 5,700 baggable
sources were screened and about 1,300 were sampled.   Sixty-five percent of
the total measured emissions came from one percent of the baggable sources.
          It is possible to estimate fugitive emission rates fromindividual
          sources using portable hydrocarbon detectors as monitoring
          devices.

          It was found that the measured leak rate from a baggable source
could be correlated with the hydrocarbon concentration very near the leak.
This hydrocarbon concentration (or "screening value")  was measured with
sensitive portable  hydrocarbon detectors.   The screening values correlated
                                    19

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quite highly with leak rates.  A correlation coefficient of 0.72 was
obtained for the screening values and the leak rates of valves.  The
correlation coefficients for leak rates and screening values for all
sources ranged between 0.67 and 0.79.

2.1.2     Significant Supporting Results

          Some of the significant results of this study which support the
conclusions presented in the previous Section 2.1.1 are presented below.
The results are. given for each source type.

2.1.2.1   Baggable Sources
          (a)   Valve emissions from a 330,000 BPD hypothetical refinery
               were estimated using valve counts and valve emission
               factors.   Approximately 300 pounds per hour of  nonmethane
               hydrocarbons or 64 percent of  the emissions from the six
               baggable  source types were emitted trom leaking valves.

          (b)   Valves in gas service have higher emission rates compared
               to valves in light liquid  and  heavy liquid service.   The
               emission  factor for valves in  gas service  is 0.059  Ib/hr-
               source.   Tn  comparison, valves in light liquid  and  heavy
               liquid service have emission factors of 0.024 and 0.0005
               Ib/hr-source,  respectively .

          (c)   The parameter which has the  most  influence on valve  emis-
               sions is  the stream type (gas, light liquid/ two-phase, or
               heavy liquid) .   All other  parameters which were evaluated
               had little or no influence on  the emission rate from valves,
                                    20

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 (d)  The majority of emissions come from a small fraction of
     valves which leak at relatively high rates.  B'or example,
     approximately 7.5 percent of the emissions from valves in
     light liquid service come from 10 percent of the valves
     in that service.

 (e)  Valve leaks of hydrocarbons can be detected with portable
     hydrocarbon detectors.  These instruments must be used at
     or very near the individual leak sources.  Leak rates as
     low as 0.00001 Ib/hr were detected with these devices.

 (f)  The leak rate of hydrocarbons from valves can be correlated
     with the concentration of hydrocarbons at the source as
     determined with a portable hydrocarbon detector.  Nomographs
     showing this relationship have been developed.   (See Section
     5 of this report.)

Pump Seals

 (a)  Pump seals are the.  second largest source, of emissions from
     baggable sources in refinery process units.  In a 330,000
     BPD hypothetical refinery,  pump seals were estimated to emit
     56 pounds per hour, or 12 percent of the total  nonmethane
     hydrocarbon emissions from the baggable sources.

(b)  Pump seals in heavy liquid  (kerosene and higher-boiling)
     streams  leak substantially  less than those in light  liquid
     (boiling below kerosene)  service.   The emission factors are
     0.25 Ib/hr-source for pump  seals  in light liquid service
     and 0.046 Ib/hr-source in heavy liquid service.

(c)  Variables and parameters  other than stream type
     did not  correlate to any  significant degree with the
                          21

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     seal leak rates.  Correlations were attempted but
     correlation coefficients ranged from 0.01  to 0.24.

(d)  Pump seal leaks could be adequately detected with a
     portable hydrocarbon detector.  Leak rates as low as
     0.00001 Ib/hr were detected and measured.

(e)  The leak rates froir. punip seals can be expressed as a
     function of the hydrocarbon concentration  (screening
     value)  at or very near the leak site.  Nomographs
     illustrating this relationship have been developed.
     (See Section 5 of this report.)

(f)  The major portion of the pump seal, emissions are emitted
     from a small fraction of the seals.  For example, 95
     percent of the total emissions from the pump seals in
     light liquid (liquids boiling below kerosene) service
     come from 20 percent of the seals.

Coir.presso r__Seals_

(a)  Seals on compressors handling hydrocarbon gas streams
     have the highest eir.lss.ion factor of any baggable
     source.  This  emission factor is 1.4 Ib/hr-source.

(b)  Compressor seal  leaks can be detected with a portable
     hydrocarbon detector.  Leak rates as low as 0.001 Ib/hr
     have been detected.

(c)  The emission rate from compressor seals can be correlated
     with the hydrocarbon concentration as determined with a
     portable hydrocarbon detector at or very near the leak
                          22

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     site.  A correlation coefficient of 0.68 was determined
     for this relationship.

(d)  Compressor seals leaked with a frequency higher than
     that of any other baggable source.  Seventy-seven percent
     of the screened compressor seals had screening values
     > 200 ppiuv.

(e.)  The bulk of the emissions from compressor seals are
     released from a minority of the seals.  Seventy-one
     percent of the total compressor seal emissions were
     emitted from 13 percent of the screened seals.

Flanges

(a)  Flanges have a very low frequency of leakage.  Less
     than three percent of the screened flanges had
     screening values > 200 pprav.

(b)  Flanges leak at very low rates.  They have the lowest
     emission factor of the six baggable source, types,
     0.00056 Ib/hr-source.

(c)  Hydrocarbon leaks from flanges can be detected with
     portable hydrocarbon detectors.  Leak rates as low as
     0.00001 Ib/hr have been detected.

(d)  The hydrocarbon leak rate from flanges can be estimated
     from the hydrocarbon concentration at or very near the
     leak point.  The correlation of leak rate, with screening
     values has a correlation coefficient of 0.77.
                          23

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 (e)  The  leak rate of flanges  is a statistically significant
     but  weak function of  the  diameter of  the flange.  The
     leak rate increases slightly with increasing diameter.
     The  pressure or temperature of  the process fluid d.id
     not  influence the leak rate from flanges.

Drains

 (a)  The  frequency of emitting process drains is relatively
     low.  Only 19 percent of  the inspected drains had
     screening values > 200 ppmv.

 (b)  Hydrocarbon emissions from drains can be detected with
     portable hydrocarbon detectors.  Leak rates of 0.0001
     Ib/hr were detected.

(c)  The hydrocarbon emission rate from drains can be
     estimated from the hydrocarbon concentration at or very
     near the emission point.  A correlation coefficient of
     0.68 was observed for th.is correlation.

(d)  Most of the hydrocarbon emissions come from a small
     fraction of drains.   For example, fewer than six percent
     of the screened drains were responsible for 95 percent of
     the total drain emissions.

Reli ef  V aIves

(a)  Portable hydrocarbon detectors are effective for
     detecting emissions  to the atmosphere from pressure
     relief valves.   Very low leak rates  (< 0.0001 Ib/hr)
     can be detected.
                          24

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          (b)  A substantial majority of the hydrocarbon emissions
               from pressure relief valves come from a small fraction
               of the relief valve population.  For example, 76
               percent of the hydrocarbon emissions from relief valves
               are emitted from just three percent of the sources.

          (c)  Tt is possible to estimate the fugitive hydrocarbon
               emission rate from the hydrocarbon concentration at
               the outlet of pressure relief valve.s.   A correlation
               coefficient of 0.68 was found for this relationship.

2.1.2.2   Nonbagg£ibJLe Sources

          Sampled nonbaggable emission sources include cooling towers and
units of the wastewater treating system.

          Cooling Towers

          (a)  The majority of coo.l ing towers in refineries do not
               emit significant quantities of hydrocarbons.  Only eight
               of the 31 sampled towers, or 26 percent,  had statistically
               significant emissions.

          (b)  The concentration of  volatile organic  compounds in the
               cooling tower streams were most precisely determined
               with a purging technique developed for this  purpose.

          (c)  Thirty-one cooling towers were tested  for hydrocarbon
               emissions  using two different analytical  techniques.
               One method (purge method)  was found to be significantly
               more precise  than the other procedure  (total organic
               carbon analysis).  Therefore,  an emission factor of
               0.00011 pound per .1,000  gallons of cooling water was
                                    25

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               developed using only the purge method data from the
               fifteen towers analyzed with this method.  A 95 percent
               confidence interval for this factor ranges from negligible
               to 0.0004 pounds per 1,000 gallons of cooling water.

          Wastewater Treatment System

          (a)  Intermittent sampling and subsequent analyses of
               oil-water separator liquids did not provide an
               adequate technique for accurately estimating
               hydrocarbon emissions from these devices.

          (b)  It is difficult, if not impossible, to make an accurate
               hydrocarbon material balance around oil-water separators.
               The rate and composition of the incoming liquid stream
               are continually changing.

          (c)  Hydrocarbon emissions from dissolved air flotation units
               were estimated from a material balance using measurements
               of volatile hydrocarbons in the inlet and outlet water
               streams.  However, the data were insufficient to allow
               the development of an emission factor which could be used
               with confidence.

2.1.2.3   Mis c e 11 an eo us Re f i ne.r y P r a c t i c e s

          The emission potential of a number of refinery practices were.
evaluated from survey forms and discussions with refinery personnel.  Ko
attempt has  been made to quantitate emissions  from these activities.
Results of the survey of these current practices are presented below:
                                    26

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          Turnaround and Blind  Changing

          (a)  Data on emissions  curing  turnarounds  could not be
               developed during this study.  However, it is felt  that
               the overall impact of turnarounds on  fugi tive hydro-
               carbon emissions is  small if  the units are adequately
               purged prior to  opening the process vessels.  Typical
               industry practice  provides venting of hydrocarbons and
               purge gases to flares or vapor recovery systems.

          (b)  Other emission sources during turnarounds include
               steaming of heat exchanger bundles, draining of pumps,
               emissions during startup, etc.  However, turnarounds in
               refinery units are generally  infrequent, so total
               emissions from these sources  are felt to be small.

          (c)  Refineries generally do not routinely change significant
               numbers of pipeline blinds.  Most blind changing takes
               place during the startup or shutdown of a unit.

2.2       Control Technolo^ v_

          As part of this study, pollution control technology for refinery
emission sources was reviewed and evaluated.  Research and development needs
were also evaluated.  The major conclusions reached in control technology
evaluation are organized in three parts:   2.2.1 Hydrocarbon Emission
Controls, 2.2.2 Stack and Process Emission Controls,  and 2.2.3 Research
and Development Needs.

2.2.1     Fugitive Hydrocarbon Emission Controls

          Effective control methods  are avai.1 ab 1.e for the  majori ty _oj~_hy_dr o-
carbon Emission sources  in refineries.   Although these methods arc being
                                    27

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currently used in some refineries, they may not be universally applied.
Safety and economic factors may deter their use in some refineries.
Comments on control techniques for fugitive hydrocarbon emissions arc
.included below by source, type.

2.2.1.1   Valves

          The existing method of controlling fugitive emissions from valves
and pump seals is based upon visual detection of leaks.  This method allows
numerous and substantial leaks to go undetected.  However, this study
determined that simple valve monitoring and maintenance programs employing
portable hydrocarbon detectors are effective in reducing fugitive emissions
from valves.  Such programs can reduce average valve emissions by 50 to 90
percent for the maintained sources.

          Fadeless valves have been suggested as alternatives to valves in
current use.  These valves (diaphragm and bellows valves) are currently
available.  However, their performance characteristics, size Limitations,
and cost may preclude wide-spread use in refineries.   However, their utility
and usefulness in refinery application, has not apparently been widely
tested.

2.2.1.2   Pumps

          As mentioned above in the discussion of valve controls,  the
present visual inspection technique is inadequate for control of fugitive
emissions.   Tt has been established that portable hydrocarbon monitoring
equipment is effective in locating pump seal leaks.   However, no study has
been made of the emission reductions  effected by replacing leaking mechani-
cal seals or tightening packed seals.

          Hermetically-sealed pumps would virtually  eliminate emissions from
pump seals.   However,  these pumps  currently have serious limitations for
                                    28

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general refinery use.  These limitations include efficiency, initial cost,
pump life, capacity, head, and maintenance cost.

2,2.1.3   Compressors

          Many compressor seal areas are enclosed and vented to a blowdown
flare system.  This is an effective means for reducing emissions to the
atmosphere.

          Portable hydrocarbon detectors can be used to detect emissions
from compressor seals and seal enclosures.  A program of seal monitoring
(with hydrocarbon detectors) and subsequent maintenance of leaking seals
may further reduce compressor seal emissions.  Such a potential reduction,
however, has not been experimentally determined or quantified.

2.2.1.4   Sa_fet7_Reli_eJf_Valves

          A significant fraction of safety relief valves in refineries
discharge to b]owdown/flare systems.  Atmospheric emissions from these
systems should be small if the flare system is operating effectively.
Leaks were found in approximately 40 percent of the. relief valves dis-
charging to the atmosphere instead of blowdown systems.  In some refineries,
pressure relief valves are inspected regularly, but these inspections are
apparently not completely effective in minimizing hydrocarbon emissions.
Rupture disks can be used in series with safety relief valves to reduce
emissions to the atmosphere.  The combination may,  however, present safety
problems in some applications.   A pressure or flow sensor could be installed
between the relief valve and the rupture disk as a safety precaution.

2.2.1.5   Flanges

          The leak frequency and emission rates of  flanges are low.  Refin-
eries currently depend on visual inspection to detect leaks.   The flange
                                    29

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 installation and inspection procedures are apparently adequate  for
 maintaining a low level of emissions.  Flanges may be less prone to
 developing leaks after installation since there are no moving parts.

 2.2.1.6   Process Drains

          The majority of process drains in refineries are uncovered, and
 a substantial fraction are also untrapped.  Emissions are significant in
 quantity.  Process drains could be trapped and covered (at least partially),
 if safe operating conditions can be maintained.  The buildup of explosive
 vapors in such systems is a potential safety hazard that must be considered.
 It should also be noted that the effectiveness of traps and covers for
 reducing emissions has not been evaluated.

 2.2.1.7   API Separators

          Many API separators in refineries do not have, covers.  These
 devices are assumed to emit significant quantities of hydrocarbons to the
 atmosphere.  Corrugated-plate interceptors (CPI) and parallel-plate inter-
 ceptors (PPT) are used in some refinery applications to separate oil and
water.  These devices generally allow very little exposure of oil to the
atmosphere.  In fact, they are often completely covered.

          According to AP-42,7 covered API separators emit smaller amounts
of hydrocarbons to the atmosphere than uncovered units.  The data obtained
in field measurements around both covered and uncovered oil-water separators
were inadequate for defining emission rates.   The AP-42  emission factors
are given a quality rating of "D."  Emission factors of this quality are
considered "below average," i.e., there is not very much  measured emission
data,  process data,  or engineering analysis upon which to base the factor.
Additional studies and data are needed to provide better  estimates of
control effectiveness.
                                    30

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 2.2.1.8    Cooling Water

           In many refineries  cooling  tower water  is  periodically monitored
 for hydrocarbon  content.  Frequent monitoring will provide  prompt  indica-
 tion of leakage  of hydrocarbons  into  the  cooling  water  (with  subsequent
 emission to the  atmosphere).  This procedure, followed  up with maintenance
 to repair  the leak, appears to be quite effective in maintaining a  low
 emission level.

 2.2.2      Stack  and Process Emission  Controls

           Although hydrocarbon emissions  from these  sources are low, other
 criteria pollutant emissions may be significant.  Of the criteria pollutants,
 sulfur oxijje emissions from stacks i_n jrefineries^are a  difficu 1 t^contr o 1
 pjrp_b_lem.   Although adequate controls may  be available,  they can he very
 expensive  and in some instances may present safety problems.  Furthermore,
 the decreased availability of low-sulfur  crude oil and  natural gas and the
 increased  use of heavier oils as fuel for refinery boilers  and heaters will
 result in higher emissions from these sources.

           Glaus plants are the accepted method for recovering sulfur in
 refineries.  The tail gas from Glaus units contains  substantial quantities
 of SO,  and H2S.   There are a number of Glaus tail gas treatment processes
     X
which are  capable of reducing the SO, content of  tail gas to  250 ppinv or
 less.   Some of these are currently in use in refineries.  In  the absence
of tail gas treating, the gas is incinerated to remove  H2S.

          No pollution control devices are currently in use to treat the
flue gases from refinery boilers and process heaters.   When low SO  and NO
emissions are required, low sulfur fuels and high efficiency burners are
used.   Flue gas desulfurization (FGD)  processes for removing SO  from com-
bustion gases have been developed for the electric power industry.  These
are potentially applicable, to heater/boiler flue gases.  Most of the
                                    31

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numerous individual combustion sources found in refineries arc relatively
small, however.  The flue gas from several sources would have to be com-
bined before scrubbing.  This is very costly and could present safety
problems.  Additionally, large amounts of scrubber waste could produce
disposal problems.

          The emissions of sulfur oxides from fluid catalytic cracking unit
(FCCU) regenerators can be reduced.  The available methods are, however,
expensive and in some cases have not been commercially proven.

          Amoco Oil Company (as well as other oil companies and catalyst
manufacturers) has developed an FCC catalyst which reportedly reduces the.
                                                      1 p
amount of SO  leaving the regenerator in the flue. gas.    This catalyst
            X
appears to be a promising alternative, to other potential control methods
such as flue gas scrubbing or feedstock desulfurization.  Results of
commercial scale testing of the. Amoco catalyst or tbose of other developers
has not been reported.
          Scrubbing of FCCU flue gas for the removal of S0v is currently
          in only a few refineries.  These scrubbers are
of removing up to 95 percent of the SO  in the flue gas.'
                                                          x
practiced in only a few refineries.  These scrubbers are reportedly capable
                                                        1 3
                                        in tine r i ue eas ,
                                      x
          The hydrodesulfurization (HDS) of FCCU feedstock can also result
in the reduction of SOX in the regenerator flue gas.  HDS is generally not
practiced for emission control purposes, but rather to increase the volume
and/or quality of saleable products.   The installation of a large hydro-
desulfurization unit is quite costly, and may also require the addition of
a hydrogen unit.

2.3       Environmental Jmpact

          An environmental assessment was performed to examine the potential
effects of refinery emissions on the  surrounding atmosphere.  The primary
                                    32

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objective of  this assessment is to provide guidance in identifying potential
problem areas.  For instance, it can provide insight into which sources and
which pollutants appear to be. the most likely to pose, potential hazards, if
such hazards  exist.  The approach taken in this study to an environmental
assessment of a generalized source (model refinery) is of limited value in
providing specific information on whether steps need to be taken to further
reduce emissions of a given pollutant.  As a result, this type of environ-
mental assessment is only a tool to aid in the evaluation of relative
potential environmental impacts.  It is not a method for making precise and
accurate predictions of such impacts.  The results should not be regarded
as an absolute value which can be used to predict violations of standards,
public health hazards, requirements for additional pollution control
technology or regulatory requirements.

          In  this assessment, an atmospheric dispersion model was used to
estimate the impact of a large model refinery on the ambient air quality in
the surrounding area.  The refinery configuration emission rates, -meteoro-
logical conditions, dispersion model, etc., are consistent with a "worst
case" study.  Worst case conditions were chosen to permit some generaliza-
tion of the results of the refinery assessment.  If the worst case analysis
shows little or no impact, then it can be said with some confidence that
refineries in general have, little or no impact.

          The EPA guideline dispersion model RAM (rural version) was used
in this assessment.  None, of the available models is perfect, and predicted
maximum concentrations may vary from half to ten times (or more) the actual
concentrations measured from a source.  In addition, the use of the rural
version of RAM to model a refinery is a conservative (or worst case) choice.
In the rural version, the heat island effect of the refinery, which would
tend to increase atmospheric diffusion, is not considered.   These factors
should be considered when interpreting the results of  this  study.
                                    33

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          Emissions from storage tanks were not included in the scope of
this study, and they were not considered in the dispersion model.  However,
the magnitude of these emissions were estimated to provide a basis of com-
parison to other hydrocarbon emission sources.

          The dispersion modeling results indicate that in the worst case
situation, hydrocarbon emissions were the only potentially significant
environmental pollutant.  Ambient levels of particulate matter, sulfur
oxides, nitrogen oxides, and carbon monoxide were all predicted to be. well
below the National Ambient Air Quality Standards (NAAQS).

          Total nonmethane hydrocarbon concentrations in excess of the.
federal, guidelines were predicted in an area which extended 3.5 kilometers
downwind of the model refinery and encompassed about four  square kilometers.
The maximum total hydrocarbon concentration was estimated  to be directly
downwind of a covered API separator.  The bulk of the hydrocarbons appeared
to be froTn the alkane family.  However, both the aromatic  and polynuclear
aromatic (PNA) species were estimated to be present at the part-per-billion
level.   Maximum concentrations of benzene, naphthalene, anthracene,  biphenyl,
and other PNA's were predicted to be located adjacent to and downwind of the.
covered API separator.

          Several factors should be kept in mind, however, when considering
the results concerning the API separators:

          •    The separator was located right on the plant boundary.
               This placement is quite unusual.

          •    There is a great deal of uncertainty in the emission
               factor for separators.   No conclusive results were
               obtained from limited testing of separators in this
               study.  As a result, factors from AP-42  were used
               in this environmental analysis.
                                    34

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          •    The emissions from an APT separator are highly
               variable In component breakdown.  The .species
               concentrations were based on grab samples of
               surface oil.  These samples may not have been
               reflective of "typical" operations.

          Another point oT uncertainty is the potential contribution of
storage emissions to the impacts predicted for the refinery process area.
Storage emissions were estimated and storage modules were located in the
refinery plot plan.  It was determined that the inclusion of storage emis-
sions in the dispersion modeling would probably not have significantly
increased the estimated maximum hydrocarbon concentration in the vicinity
of the model refinery.  It would, however, have increased the area of
impact in which relatively high concentrations of nonmethane hydrocarbons
would be predicted by the model.
                                    35

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3.0       AVAILABLE CONTROL TECHNOLOGY OPTIONS

          In this section, existing and available control options are
discussed.  Research and development programs for some specific controls
needs are also recommended.  These recommendations are Radian's and do not
necessarily reflect the positions or policies of the U.S. Environmental
Protection Agency (EPA).

 3.1       Control Technology for Fugitive Emission Sources

           Control technology for baggable and nonbaggable fugitive emission
 sources are reviewed in detail in Appendix E (Volume 4).  All of the avail-
 able technologies are discussed in Appendix E.   The available control
 options are listed below.

 3.1.1     Baggable Sources

 3.1.1.1   In-Line Valves

           Control Options—The following options are available for the
 control of hydrocarbon emissions from in-line block and control valves.

           (a)   Monitoring with portable hydrocarbon detectors of
                all accessible valves in gas and light liquid service
                is recommended.  The monitoring  should be done at
                regular intervals.

           (b)   Simple maintenance  (tightening packing glands,
                injection of grease)  should be performed on all
                accessible valves with screening (monitoring)
                values above some specified level.   The maintenance
                                     36

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               should be performed within a short interval of
               time after screening.

          (c)  A portable hydrocarbon detector should be used
               to guide the maintenance effort.  This assures
               that the maintenance effort will be continued
               unti.1 the leak is minimized.

          (d)  On-line valve maintenenacc can also be achieved
               by drilling and injection of a sealing compound
               into the packing area.

          (e)  Valves that cannot be maintained or repaired
               while in service should be identified and repaired
               during the next process unit shutdown and/or turn-
               around.  Packing replacement or valve replacement
               are feasible during shutdowns/turnarounds (or
               whenever the valve in question can be isolated).

          (f)  Monitoring of valves in heavy liquid service is
               not recommended.  Visual inspection should be
               adequate for detecting leaks.  Visible leaks should
               be repaired.

          Research and Development Recommendations—More effective methods
of controlling emissions from valves might possibly be developed.  Addi-
tionally, more data are needed regarding the effectiveness of existing/
recommended  controls.   The studies listed below should be considered:

          (a)  A study of the effect of deeper stuffing boxes on the.
               leak frequency and emission rates of smaller valves.
                                    37

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          (b)  A study to define the theoretical and practical
               limitations involved in developing and applying
               diaphragm and bellows sealed valves for some
               refinery services.

          (c)  A study to define the effectiveness, reliability,
               and limitations of on-line leak-sealing methods
               such as sealant injection.

          (d)  A study of the short-term and long-term effective-
               ness of valve maintenance.  Results from refineries
               which institute a monitoring/maintenance program
               would enhance such a study.

3.1.1.2   Open-Ended Valves

          Emissions to the atmosphere from open-ended valves (sampling
valves, drain valves)  occur through the valve seat.

          Control Options—Available control options for open-ended valves,
are listed below.

          (a)  The open-end of the line should be closed when
               not in  use.  This can be done by installing caps,
               plugs,  blinds, or a second valve on the open-end.

          (b)  The closures on open-ended valves in gas and light
               liquid  service should be monitored with hydrocarbon
               detectors  at regular intervals to ensure the con-
               tinuing effectiveness of the device.
                                    38

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3.1.1.3   Flanges

          The leak frequency and emission factor for flanges are both very
low.  Existing methods of flange installation and testing coupled with visual
inspection appear to be effective in minimizing emissions of nonrcethane hydro-
carbons.  Periodic monitoring of flanges for leaks is not recommended because
of the high cost and minimal expected emission reduction.

3.1.1.4   Pump Seals

          Contro1 Opti ons—Pump seals are an integral component of pumps and
are necessary for pump operation.  There are a number of types and configura-
tions of pump seals.  Some types are better suited than others for reducing
emissions in certain applications.   In addition to the two most commonly used
types, packed seals and single mechanical seals, the following options are
available:


           (a)  Double mechanical seals.

           (b)  Tandem mechanical seals.

           (c)  Double mechanical or tandem seals with barrier fluid
                reservoir degassing vent connected to a closed vent
                system.

           (d)  Periodic monitoring (with hydrocarbon detectors)  and
                repair (tightening  of packing gland,  replacement  of
                packing, replacement of seal, etc.).

            (e)  Pump  rep1acement.
                                     39

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          The data from this study are insufficient  to  determine  the  rela-
tive effectiveness of the above options  for  controlling pump  seal  emissions.
The utility of any of. these options depends  to a  great  degree on  the  appli-
cation.  The economics, safety, and effectiveness of  each  control  option
must he determined for each particular case.

          Research and Development Needs—Hermetically  sealed or  "canned"
pumps should achieve complete control ol emissions.   At the present  time
they are used sparingly in refineries because of  efficiency,  puir.p  life,
cost, capacity, and head limitations.  A study of these pumps is  recommended.
The study would define the probabilities and costs of. overcoming  some or all
of the current limitations for refinery  use.

3.1.1.5   Connresj?or_S£v?<_l_£

          Control_0p_tio_ns_—Compressor seals are an integral component of
compressors, and they are necessary for proper compressor  operation.  Methods
for controlling nonmethane hydrocarbon emissions from compressor seals are
available for some applications.  Those  identified below are  not the only
available options, however.  Compressor seals are often  engineered on an
individual basis.  Economic, operational, and safety problems  associated
with available control options must be evaluated for each  installation.

          (a)  Some compressor seals include a barrier  fluid
               (seal oil)  which circulates through the  seal area
               (similar to double mechanical pump seals) .  The
               fluid absorbs the compressed gas.  Where practical,
               th.is fluid can be circulated to a reservoir
               equipped with a closed degassing vent system.  The
               vent system can be routed back to the. compressor
               intake or be connected to a control device
               such as a vapor recovery system, flare,  or  a
                                   40

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               combustion/incineration device.  These seal vent
               systems arc complex and expensive.  The cost
               effectiveness, operating problems, and safety
               concerns must be evaluated for individual cases.

          (b)  Some compressor seals, particularly those of
               reciprocating compressors, arc not equipped with
               seal oil systems.  In these cases the seal area
               can be enclosed, if safety problems are nol
               encountered.  The enclosed area should be vented to
               a closed vent system which is equipped with a vapor
               recovery or incineration/combustion system.

          (c)  If it is not feasible to apply the above systems
               or comparable emission controls to a compressor
               seal, then regular monitoring of that seal with a
               hydrocarbon detector is recommended.  When signifi-
               cant emissions are detected, the seal can be repaired
               or replaced at the next opportunity such as a shut-
               down or turnaround.

3.1.1.6   Safety Relief Valves

          Safety relief valves which vent into a blowdown/f1 are system are
effective in limiting hydrocarbon emissions to the atmosphere.

          Contro1 Uptions—The control options given below apply to those
safety relief valves in hydrocarbon gas service which vent directly to the
atmosphere.

          (a)  Rupture disks upstream of safety relief valves can
               be used to reduce emissions to the atmosphere.
                                     41

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           (h)  Where rupture disks are installed, bubblers,
               pressure gauges, and/or excess flow valves
               should be installed between the rupture disk
               and the safety relief valve.  Such an arrange-
               ment is covered by ASME code.  Leaks through
               the rupture disks can be detected by the above
               devices.

           (c)  Safety or other considerations may preclude the
               installation of rupture disks upstream of safety
               relief valves.  Those relief valves not equipped
               with rupture disks should be regularly monitored
               for hydrocarbon emissions.

           (d)  In addition to regularly scheduled monitoring,
               pressure relief valves should be monitored after
               every pressure release.

          Research and Development Needs—There appear to be divergent
opinions concerning the practicality, safety, and costs of the universal
application of (a) the venting of relief valves to blowdown/flare systems
and (b) rupture disks upstream of pressure relief valves.   A comprehensive
and objective study is recommended to define the costs and safety problems
associated with these control measures.

3.1.1.7   Process Drains

          Many drains in refineries are used to frequently or continuously
carry away liquids such as condcnsate, oily water, and/or hydrocarbon
liquids.  Many of these .streams  are hot and/or volatile.   Emissions from
the open process  drains  are not  insignificant.

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           Control Option—Unless prevented by safety or economic factors
 the  covering  of existing open process  drains is recommended.  New process
 drains-  should be equipped with  traps and  covers.

           Research and Development Needs—A study is recommended to evaluate
 the  cost,  cost effectiveness, and hazard  potential of process drain emission
 control methods.

 3.1.1.8    Sampling Systems

           When taking samples of refinery process fluids, it is necessary
 to purge the sampling line of fluid present from the previous sampling.  If
 this fluid is purged into the air (gas) or into drain systems (or onto the
 ground), atmospheric emissions will result.  A closed sampling loop is
 recommended for sampling operations.  A closed sampling loop allows the
 purged material to flow back into the process line without being exposed
 to the atmosphere.

 3.1.2      Nonbaggable Sources

           Nonbaggahle sources include cooling towers and units of the waste-
water collection and treatment system.

 3.1.2.1    Cooling Towers

           Cooling towers can emit hydrocarbons to the atmosphere if the
 cooling water contains hydrocarbons from leaking process heat exchangers.

           Control Options—Cooling tower water can be. routinely  monitored
 for hydrocarbon content.   This is an effective method for detecting the
presence of hydrocarbons resulting from leaks.   It is recommended as the
most effective means for early detection of leaking heat exchangers.  Prompt
repair of such exchangers will minimize hydrocarbon losses to the atmosphere.

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3.1.2.2   Oil-Water Separators

          Liquid hydrocarbon wastes are separated from refinery wastewater
in oil-water separators.  A considerable amount of the. hydrocarbon wastes
make their way to the oil-water separators, and these units can be very
substantial hydrocarbon emission sources if they receive volatile material.

          Control Option—The most commonly used control option for reducing
hydrocarbon emissions from those, oil-water separators receiving volatile
material is to cover part or all of the separators.   Adequate data are not
available for a definitive evaluation of the effectiveness of covers on
oil-water separators for reducing atmospheric emissions.  It seems reason-
able to presume that covers will reduce emissions to some degree.  The
cost-effectiveness of this control option can only be determined after its
control efficiency has been defined through testing.  There can be safety
and operational problems associated with covering the separators.  These
must be evaluated on an individual basis.

          Research andDevelopmentNeeds—The Environmental Protection
Agency is now conducting a program to measure atmospheric emissions from
refinery wastewater treatment units.   In addition two topics should be
fully explored:

          (a)   The venting of covered separators to  flare systems
               should be investigated.  Such a system might sub-
               stantially reduce emissions from unvented covered
               separators.

          (b)   Corrugated plate interceptors (CPI) and parallel
               plate interceptors  (PPI)  are not widely or
               universally  used in refineries.   The  range of
               applicability,  efficiency,  limitations, and
               economics of operation should be comprehensively

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               explored.   If  there are serious  limitations  for
               refinery service, an R&D program to overcome them
               may be justified.

 3.1.2.3   Wastewater Collection System

          Included :in this system are. drains, process sewers, storm sewers,
 and ditches.

          Cont r o .1 Opt ion s—The methods for controlling emissions from the
wastewater collection system  include:

          (a)  Drains and sewers can be sealed  or vented through
               liquid seals if safe operating conditions can be
               maintained.  The buildup of explosive vapors in
               such systems is a potential safety hazard that
               must be considered.

          (b)  Pump bases should be constructed  or modified to
               allow rapid and complete drainage to the sewer.

          (c)  Process water should be segregated from storm
               water.

3.2       Control Technology for Process Eiiilss ions

          The major sources of atmospheric process emissions are sulfur
recovery processes,  fluid catalytic cracking (FCCU)  catalyst regeneration,
and process  heaters  and boilers.   The major types of atmospheric process
emissions from refineries are hydrocarbons, sulfur oxides (SO ), particu-
                                                             X
lates, carbon monoxide (CO),  and nitrogen oxides (NO ).   Process emission
controls for the various pollutant types are discussed  below.
                                    45

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3.2.1     Contro1 of Hydrocarbon  (Including Aldehydes) Emissions

          Potential major sources of hydrocarbon emissions include FCCU
catalyst regeneration, delayed coking, fluid coking, vacuum distillation,
and air blowing operations.  Most of these, sources- are effectively con-
trolled in existing refineries.

3.2.1.1   FluidCatalytic Cracking_Unit (FCCU)

          Control Options—Two methods for controlling CO emissions are
also effective, in reducing hydrocarbons in the flue gas.  The following con-
trols are recommended for controlling hydrocarbon emissions.

          (a)  Carbon monoxide can be further oxidized to C02 in
               a CO boiler.  This combustion effectively reduces
               hydrocarbon emissions to low levels.

          (b)  High temperature regeneration and combustion
               promoters also significantly reduce hydrocarbon
               emissions as well  as CO concentrations.

3.2.1.2   Delayed Coking

          The hydrocarbon emissions from delayed coking have not been
quantified.   In general, hydrocarbon emissions can be minimized by venting
quenching steam to a vapor recovery or blowdown system.  Cooling the coke
drum as much as practical will minimize hydrocarbon vaporization when the
drum is opened.
                                    46

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3.2.1.3   Fluid Coking

          The hydrocarbons in the flue gas from a f.1uid coking unit can be
controlled by a CO boiler, which is generally used to control CO emissions
from the unit.

3.2.1.4   Vacuum Distillation and Air Blowing Operations

          The noncondensable hydrocarbon vapors fron: vacuum distillation
and air blowing operations should be incinerated or vented to a blowdown
system.

3.2.2     Contro1 of Sulfur Compound Emissions

          Sulfur oxides and other sulfur compounds can be emitted from
sulfur recovery plants, catalytic cracking catalyst regeneration, and
boiler/process heaters.

3.2.2.1   SulFur Recovery Plants

          The Claus unit is the accepted method for recovering sulfur in
refineries.   However, the Claus plant is not totally efficient in removing
sulfur, and the tail gas from the uni'_ nan be a major source of sulfur com-
pound emissions.

          Contro1 Options—Tail gas treating methods are available lor
reducing SO  emissions to acceptable levels.   No particular system is
recommended;  more than 70 processes have been proposed,  developed,  and/or
commercialized.

          Research and Development Needs—There is a continuing high level
of research  and development activity in the area of sulfur recovery and
tail gas treating.   This activity should be monitored periodically  to
                                    47

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identify promising emerging  technologies which would be particul.ar.ly
applicable in petroleum refineries.

3.2.2.2   Fluid Catalytic Cracking Units

          Control Options—Scrubbing of FCCU flue gases and  the hydrodesul-
furization of feedstocks can both reduce SO  emissions.  These methods  can
be very costly.  The potential for use of either method as an S0x control
technique will depend on a number of complex factors including economics,
regulatory requirements, secondary pollution, and sulfur levels in the
feedstocks.

          Research and Devel opment_ Need_s_

          (a)  A comprehensive study of FCCU feed desulfurization and
               alternate methods of S0x control would be beneficial in
               guiding regulatory efforts as well as future  research
               and development.

          (b)  Amoco Oil18  (and other companies) has reported the
               development of a new catalyst which reduces SO  emis-
               sions from the regenerator.   This development should
               be followed closely,  especially if commercial tests
               are made.

3.2.2.3   Boilers and Process Heaters
          The only currently practical method of controlling SO  emissions
                                                               X
from refinery heaters and boilers is to minimize the sulfur content of the
fuel.
                                    48

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 3.2.3      Control of Nitrogen Compound  Emissions

           Nitrogen  compounds emitted  from  refinery sources  include nitrogen
 oxides, hydrogen cyanide, and ammonia.  Only NO  emissions  are of concern.
                                               X
 The major  source of NO  emissions are process heaters and boilers.
3.2.3.1   Process Heaters and Boilers
          Control Options—The available methods for NO  control from
                     ••    —                              X
refinery heaters and boilers are all combustion modification techniques.
These include:
          •    Low excess air.

          •    Flue gas recirculation.

          •    Staged combustion.

          •    Burner modifications.

          •    Load reduction/oversize firebox.
Currently available methods for removing NO  from flue gases are not
economically practical for the numerous and relatively small process
heaters and boilers found in refineries.
3.2.4     Control jjf Particulate Emi.ssions

          Particulate matter is emitted from FCCU regenerators, fluid coking
units and process heaters and boilers.  Particulate. emissions from refinery
heaters and boilers are relatively low.
                                    49

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 3• 2• 4• 1   FJLiiid  Catalyt4g  Cracking  Unites

          Control Options—Three methods  of  controlling  paniculate emis-
 sions from FCCU  regcncriitors  arc recommended.

          (a)  A combination  of cyclones  followed  by  an
               electrostatic  precipitator is effective for
               controlling participates.

          (b)  A scrubber  in  series with  and downstream  of
               cyclones is an alternative participate control
               method.

          (c)  In some applications multistage,  high  efficiency
               cyclones can provide effective participate control.

 3.2.4.2   Fluid  Coking Units

          Control Options—The two recommended methods of controlling
particulate. emissions from fluid coking units are:

          (a)  Scrubbers.

          (b)  Electrostatic  precipitatorfi.

3.2.5     Control of Carbon Monoxide (CO)  Emissions

          Carbon monoxide is  emitted from FCCU regenerators and from fluid
coking units.
                                    50

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3.2.5.1   FCCU Regenerators

          Control Qptions—Two methods  are  available  for  controlling CO
emissions from FCCU regenerators.

          (a)  CO boilers are very effective  in  reducing  the  CO
               content of regenerator flue  gas.

          (b)  High temperature regeneration  combined with  the.
               use of combustion promoters  is  an  acceptable
               alternative, to the CO boiler for  CO  control.

3.2.5.2   F]uld Coking Units

          ^ant_rpl__0p_ti_qn—A CO boiler is recommended  for  the  control of CO
emissions from fluid coking units.
                                    51

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                                 PART A
                       FIELD MEASUREMENT PROGRAM

          A major portion of the refinery assessment program was devoted
to field measurement activities.  in particular, fugitive hydrocarbon emis-
sion rates from numerous  source types in refineries were measured.   In
addition, a number of heater and process stacks were sampled.  The  methods
used in making the. field  measurements are described in Section 4.   The
results of the sampling program are presented in Section 5.
                                    52

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4.0       EMISSIONS MEASUREMENTS

          To fulfill the objectives of this program, as stated in Section
1.1 of this report, data on the rate and character of refinery emissions
were needed.  Much of these data had not been obtained.  In some cases
where data were available, the accuracy was unknown and/or suspect,   It
was, therefore, necessary for Radian to perform sampling and characteriza-
tion of atmospheric emissions from petroleum refineries.  Sampling programs
were carried out in 13 refineries throughout the United States.  The
sampling methodologies used in these refineries are described in this
section.

          Fugitive and process emission sources were sampled.  Fugitive
sources were devided into two groups, baggable sources and nonbaggable
sources.  Baggable sources are those sources that can be completely
enclosed with a "bag" to measure their emission rates.  This group
includes valves, flanges, pump seals, compressor seals, pressure relief
valves, and drains.  Baggable sources represent the majority of the  sources
selected for testing at each refinery.

          Nonbaggable fugitive sources are those that are not amenable to
sampling with bags or any other type of readily constructed enclosure.
There sources are broad in area, intermittent in operation, and/or very
complex in their functioning.  Nonbaggable sources include drainage/
wastewate.r systems, cooling towers,  barometric condensers, coke removal
operations, blind changing, sampling operations, and maintenance turnarounds.
Some of these sources can only be sampled using very elaborate and complex
sampling procedures and equipment.   Of the nonbaggable sources, only cool-
ing towers and units of the wastewater treating system were sampled  in the
current program.
                                    53

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          Stacks or vents which were identified as possible emission points
for hydrocarbons and other criteria pollutants are classified as process
sources.  The refinery process sources which were sampled during this
program include:

          •    Catalytic cracking unit regenerator stacks.

          •    Boiler and process heater stacks.

          •    Sulfur recovery and tail gas treating unit stacks.

          •    Compressor engine exhausts.

          •    Fume incinerator stack.

          •    Fluid coker flue gas stack.

          These sources were sampled for total hydrocarbons, other criteria
pollutants, and characterization of hydrocarbon emissions.

4.1       Experimental Design of the Program

          At the beginning of the sampling program,  an experimental design
was prepared to provide an optimum selection of sources to be studied.   The
design was modified during the. course of the program.  The initial design,
selection procedures, and design modifications are described in detail  in
Appendix A (Volume 2).   They are summarized in the sections which follow.

4.1.1     Refinery Selection

          A number of refineries were selected for sampling.  Refinery  age,
size, and geographical  location were used as selection criteria.  Differ-
ences among refineries  due to their different geographical locations are

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seen primarily in the types of potentially hazardous materials they generate.
Location influences the type and quality of the crude oil which is processed,
as well as the nature and relative quantities of the manufactured products.
It was not believed that the location would have a major influence on the
rates of hydrocarbon emissions.  Refineries were selected for sampling in
the following four geographical locations:

          •    East Coast,
          •    Gulf Coast,
          •    Midwest/Midcontinent,  and
          •    West Coast.

          The two other principal parameters which influenced the refinery
selection were size and age.  Age affects the characteristics of refinery
equipment, and it was thought that these characteristics might ultimately
influence fugitive emission rates from this equipment.

          Refinery size, can have  an effect on such  factors as  the number
and type  of manufactured products, the number and type  of potentially
hazardous species, the types of units available for  sampling,  the amount
of effort devoted  to a maintenance program, and the  size of  equipment.
The division point between  large  and small references was arbitrarily set
at 50,000 barrels per day.  To some degree, size and refinery  age are not
independent of each other.  There have not been many new refineries signifi-
cantly smaller than 50,000 barrels per day.  Therefore, refineries of
interest  in this program were classified  as one of  the  following types:

          •    old/small,
          •    old/1arge, and
          •    new/large.
                                    55

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An old refinery was one in which the oldest operating unit was over 20
years old.  New refineries had no units older than 20 years.

          Emission sampling took place in ]3 refineries.  Eight old/large
refineries, four old/sir.all refineries, and one new/large refinery were
sampled.

4.1.2     Process Unit Selection

          During the formulation of the experimental design of the .sampling
program, operating temperatures and pressures were expected to have major
effects on the frequency and rate of fugitive emissions.  Many combinations
of temperature and pi-essure can be found within refinery process units.
For the purpose of selecting process units for sampling, four pressure/
temperature categories were employed:

          •    high pressure/high temperature,
          •    high pressure/low temperature,
          •    low pressure/high temperature, and
          •    low pressure/low temperature.

The pressure, and temperature classifications  were defined as follows:

          •    pressure
                   high >  150 psig
                   low  < 150 psig

          •    temperature
                   high >  100°C
                   low <  100°C
                                    56

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          Each type of process unit (catalytic cracking, reforming, etc.)
was placed in a pressure/temperature category.  This classification
generally reflected only the operating condition in a major equipment area,
such as a reactor.  In each refinery,  6-9 process units were selected for
sampling.  These units were distributed as equally as possible among the
four pressure/teinperaturc categories,

4.1.3     BaggablcSource Selection

          The experimental design was  developed to assure the unbiased
selection of representative baggable emission sources for testing.  All the
variables that were felt to possibly influence the emission rate from each
of the baggable source types were classified into one of two groups:  choice
parameters and correlating parameters.   A choice parameter was defined as a
variable that was expected to have a significant effect on the fugitive
emission rate.  Thus, it was used as a category in selecting the individual
sources in each refinery and process unit.  The choice parameters use>d for
each fitting typo are listed in Table  4-1.

          All other factors which were thought to possibly affect the
fugitive emission rates (but not as strongly as the choice parameters) were
used as correlating parameters.  Correlating parameters were not considered
in the selection process,  but values of these parameters were obtained and
recorded for each selected source.

          After the process units were  selected for testing in each refinery,
the individual baggable sources were chosen in each unit.  A test plan was
prepared which specified the number of  each source type to be tested within
the range of choice parameters.  For example, four control valves in gas
service, 4-8 inches in size,  might be specified in a reforming unit.
Because the process units  were selected to include wide ranges of tempera-
tures and pressures,  these choice parameters were not deliberately speci-
fied.  It was thought that the selection of sources within a variety of
                                    57

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        TABLE  4-1.   RANGE  OF  CHOICE VARIABLES  FOR  SCREENED  BAGGABLE
                    SOURCES
  Baggable  Source
  Choice  Variable
  Variable Ranges Found

    for Screened Sources
Valves
 Pressure
 Temperature
 Fluid  State
 Service
 Function
 Si/.e
-10 -  3,000 psig
-190 - 925*1'
Gas, Liquid, 2-phasc
In-line, Open-ended
Block, Throttling, Control
0.5 -  36 inches
Flanges
 Pressure
 Temperature
 Fluid  State
 Service

 Size
-14 - 3,000 psig
-30 - 950°F
Gas, Liquid, 2-phase
Pipe, Exchanger, Vessel,
  Orifice
1-54 inches
Pump Seals
Pressure
Temperature
Capacity
Shaft Motion
Seal Type
Liquid RVP
0 -  3,000 psig
0 -  800°F
0 -  100,000 gpm
Centrifugal, Reciprocating
Mechanical Seal, packed seal
Complete range
Compressor Seals
Pressure
Temperature
Shaft Motion
Seal Type
Lubrication Method
Capacity
0 - 3,000 psig
40 - 300°F
Centrifugal,  reciprocating
Packed, labyrinth, mechanical
Hydrocarbon lubricant
0.06 - 66.0 MMSCFD
Drains
Service
                                                Active, Wash-up
Relief Valves
Pressure
Temperature
Fluid
                                                0 - 1,350 psig
                                                40 - 1,100°F
                                                Gas, Liquid
                                     58

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 process  units would provide  a  group  of  selected  sources which operated  in  a
 wide,  range,  of temperatures and pressures.  This  assumption proved  to be  true,

          With  the exception of washup  drains, all baggable sources were
 selected  for testing  from the  piping, instrumentation, and process diagrams
 for each  process  unit.  The  specified number of  sources in each of the
 various  categories of choice parameters were randomly chosen and located
 on the. diagrams.  Each was given a unique identification number.   This
 method of selecting (or preselecting) sources for testing had two
 important benefits.   It eliminated any  bias which might have resulted
 from visual selection in the field.  It was also possible to distribute
 the. allotted number of fittings so that a wide range, of process variables
 could be  included.

          The choice parameters and  selection criteria for each type of
 baggable  source are described  in inore detail in  the. following discussion.

          Valves—Approximately 250 - 300 valves were selected for  testing
 at each refinery.  All of the different hydrocarbon streams within the
 process unit were usually represented in the valve selection process.
 When there was more than one valve for each process stream (as was most
 always the case), valves were selected to give, a variety of temperature/
 pressure combinations for each process stream.  Valves in gas and liquid
 service were selected.

          A distinction was made between open-end and in-line valves.  The
 piping downstream of open-end valves  is open, and leakage through the valve
 seat can enter the atmosphere.   Examples of open-end valves are sample
valves and drain valves.

          However, most refinery valves are in-line.   Each in-line valve
was classed as a block valve or a throttling (control)  valve.   This valve
                                    59

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 function reflects  the effects of frequency of operation  and  type of  stem
 movement.

          Fl.anges_—Flanges were divided into 16  categories according  to the
 interaction of three variables:  size, fluid state  (gas/liquid), and  operat-
 ing conditions (pressure/temperature).  Approximately 100 to  750 flanges
 were sampled per refinery.  Flange sizes ranged  from two  inches to more
 than four feet.  The state of the fluid within the  line was  considered the
 characteristic state.

          A separate, category was established for flanges which connect end
 pieces to vessels  and heat exchangers.  Within this category  of vessel/
 exchanger/air cooler flanges, the choice variables were pressure/temperature
 and fluid state.

          Puinp_s_—Approximately 100 - 125 pumps were selected at each refinery.
 These pumps were distributed in proportion to the total number of pumps in
 each inspected process unit.  In addition, many  spare pumps were also
 selected.

          Choice variables for pumps were pressure/temperature, capacity,
 shaft motion/seal  type, method of lubrication and cooling methods.  Shaft
 direction/seal type is very significant.   Pumps  in three categories
 (mechanical, packed/centrifugal, and packed/reciprocating) were chosen to
 be sampled.   It was thought that the volatility  (or vapor pressure) of the
 liquid being pumped was an important parameter.  Pumps handling liquids with
 a variety of volatilities were tested.

          Compressors—Compared to most other baggable sources there are
 relatively few compressors in a refinery.   It was thought that compressors
might have relatively high leak rates.  For these reasons all compressors
 in the selected process units were selected for testing.  There were
 generally from 10  to 20 compressors selected in  each refinery.
                                    60

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          The method of lubrication of packed seals and the type, of shaft
seal were important considerations in the categorization of compressor
seals.  Packed seals without external liquid lubrication allow leakage of
light hydrocarbons; lubricated seals primarily leak heavy hydrocarbons.
Mechanical seals usually require a lubricating/sealing fluid.

          Pressure Relief Devices—Only those pressure devices which vented
to the atmosphere were selected for sampling.

          There are two types of pressure relief devices.  Those in liquid
service generally open in proportion to the pressure applied to them; those
in gas service generally pop open when a set pressure is exceeded.  Very
few pressure relief devices in liquid service vent to the atmosphere.  Only
pressure relief valves in gas service were selected for testing.

          Process Unit .Drains—'''wo types of drains were inspected during
the program.  These included active drains (those, used to drain various
process streams)  and washup drains.  Although the location of active drains
was not usually indicated on the process flow diagrams, these drains were
still selected before entering the unit by selecting drains associated with
pumps, towers, vessels, and other processing equipment.  The location of
washup drains, however, could not be predicted and these, drains were
selected after entering the process unit.

          After the preselection process was completed, each of the selected
sources was physically located in the refinery process units.   They were
tagged with the appropriate identification number.   When preselected
sources were found to be nonexistent or physically inaccessible, alternate
fittings were selected from the piping,  instrumentation,  and process flow
diagrams.
                                    61

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4.1.4     S e1ec t ign of Nonbaggab1e Soujces

          Cooling towers, oil-water separators, and dissolved-air flotation
(DAF) units were the only nonbaggable source types which were sampled
during this program.  The experimental design of the program called for the
sampling of any of these devices which were associated with the selected
process units in each refinery.  Sources were not selected if any of the
following occurred:

          •    Adequate sampling points were not available or
               accessible.

          •    The unit was not representative of normal refinery
               practice.

          •    Data required for the calculation of emission rates
               was not available.

          The nonraethane hydrocarbon emission rate from these nonbaggable
sources was calculated by material balance around each unit.

4.1 .5     Selec.tj.pn of Process Sources

          Process sources (stacks  and vents) were selected for sampling in
the majority of refineries.   Three stacks were to be chosen in each refinery,
One of these was to be a fluid catalytic cracking unit stack.   The other
two were to be stacks from heaters/boilers, sulfur recovery or tail gas
treating units,  compressor engine  exhausts, air blowing units,  fluid coking
units, or incinerators.   In each refinery,  the individual stacks were
selected on the basis of availability (sampling ports, platforms,  accessi-
bility, etc.)  and the need for data from a variety of process  source types.
                                    62

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4.1.6     Modification ofthe Original Experimental Design

          The emissions data were analyzed continuously during the sampling
program.  The results of these analyses were used to modify the experimental
design of the program to obtain the most useful data within the budgetary
and time constraints of the program.  The selection procedures for the
various source, types were modified as described below.

          Baggable Sources—As the program progressed, it was found that
those fugitive emission sources in gas or volatile liquid services tended
to leak with a greater frequency and a higher leak rate, than those sources
handling less volatile materials.  The selection process was modified to
include a higher proportion of valves and pump seals in gas and volatile
liquid service.

          It was also found that only a small fraction of flanges leaked
and the emission rates were low.  The number of flanges selected for test-
ing was drastically reduced in the latter stages of the field program.

          In the last four refineries that were visited, a study was per-
formed to evaluate the effects of simple maintenance on the reduction of
emissions from leaking valves.  Three variables were considered in selecting
valves for the study.  These were:

          •    Leak rate - leak rates (as estimated from screening
                           values) were classified into one of
                           three ranges.   Valves in each leak rate
                           range, were selected for testing in each
                           refinery (if they were available).

          •    Process stream type - process streams were divided
                           into three categories,  according to their
                           volatilities (gas streams,  hydrocarbon
                                    63

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                           liquids with vapor pressures above 0.1
                           psia at. 100°F, and hydrocarbon liquids with
                           vapor pressures below 0.1 psia at 100°F).
                           Valves in each type of stream service were
                           chosen for the study.

          •    Valve type - valves in four categories were studied.
                           The four categories were (1) block valves
                           (gate valves), (2) block valves (valve
                           types ether than gate valves), (3) control
                           valves (globe valves), and (4) control
                           valves (valve types other than globe).

          A selective experimental design based on categories of the above
variables was used to minimize the number of valves required in the study.
Maintenance was performed on a total of 86 valves.

          Noiibaggable' Sources—In the latter stages of the field sampling
program, no more nonbaggable sources were selected for sampling.  Cooling
tower emissions were found to be low and sampling of cooling towers was
discontinued.  The methods used to determine hydrocarbon emission rates
from oil-water separators were found to be unsatisfactory.  Sampling of
these sources was discontinued in the last four tested refineries.

          Process Sources—In some refineries, three stacks (as suggested
in the experimental design) with adequate sampling facilities could not
be located.  in these cases,  only the available stacks were .sampled.
Additionally, because of cost and time constraints, no stacks were  sampled
in the final four tested refineries.
                                    64

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4 . 2       Samp lingMethodo logy

          In  this section,  the methodologies  used  in  sampling  emissions  from
baggab.le, nonbaggable, and  process  sources  is described.   In the  case  of
baggable sources, a screening procedure was used prior  to  selecting  sources
to be sampled.
A . 2 . 1     _B.
-------
 leak source.  This reduced  the effect of the wind and increased the
 reproducibility of the readings.  The screening procedure differed slightly
 for each baggahle source type as discussed below.

 4.2.1.1   Valves Sereening  Method

          Most of the valves that were selected for screening were either
 gate, globe, or control valves.  Hydrocarbon leaks from these valves occur
 at the stem and/or the packing gland.  Some, plug valves were also selected.
 Hydrocarbon leaks from this type of valve can occur at the plug square or
 under the malleable gland.

          Both the stem and the packing gland of selected valves were
 screened.  The probe locations used included the four arbitrary compass
 points around the seal, relative to the valve casing.  Thus, a total of
 eight such readings were taken for each valve.  In addition, two more
 readings (one for the stem  and one for the glands) were obtained at a
 distance of 5 cm (using a wire extension as a guide) from the leak source.
When screening at 5 cm, the probe was rotated in a circular path around
 the leak source.   Only the maximum reading was recorded in these cases.

 4.2.1 .2   Flanges Screening Method

          Flanges were screened by placing the TLV Sniffer probe at two-
 inch intervals around the perimeter of the flange.  After locating the
maximum leak point,  three additional readings were taken at the remaining
 compass points,  relative to the location of the maximum leak point.  All
four readings were recorded.

4.2.1.3   Pumpand Compressor Seal Screening Method

          Pump seals  were screened in a manner similar to that used for
screening valves.   Leakage occurs around the rotating shaft at the point
                                    66

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where it enters the pump housing.  The Bacharach TLV Sniffer probe was
placed as close as possible to the potential leak point around the shaft
at the pump housing.  Four readings were taken at points 90 degrees apart
around the shaft.  Hydrocarbon concentrations of 200 ppm or greater at
any of the. four points resulted in the pump being bagged and sampled.

          Large pumps or pumps in severe services may have two seals, an
inboard seal and an outboard .seal.  Tn the.se cases, each seal was screened
separately.

          The screening procedure for compressors depended on the accessi-
bility of the seal area.  if the seal area was accessible, the screening
procedure was identical to that for pumps.  The TLV Sniffer probe was
placed at four locations 90 degrees apart around the shaft and right at
the point where the shaft enters the compressor housing.  A hydrocarbon
concentration of 200 ppm or more at any point indicated the need for bagging
and sampling of the seal.

          in many cases the seal area was enclosed and hydrocarbons leaking
from the seal were vented to the atmosphere or to a vapor recovery system.
When compressors vented to the atmosphere were encountered, they were
screened, if possible, at the point where the vent pipe discharged to the
air.  The TLV probe was positioned at a point located just inside the end of
the vent.  A hydrocarbon concentration of 200 ppmv or greater indicated the
need for sampling.

          Compressors often have more than one seal.  Each seal was
individually screened.

4.2.1.4   Pressure-Relief Valve Screening Method

          Only those pressure-relief devices that are vented to the
atmosphere were screened.  Those devices that are vented to blowdown and
                                    67

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flare systems can only leak to the atmosphere at the connecting flanges,
and these leak sources are considered to be flanges.

          The relief valves were screened using the Bacharach TLV Sniffer.
The probe was placed at two-inch intervals around the. perimeter of the
vent (horn) just at the exit.  The probe was also placed at the center of
the vent opening at a level with the vent exit.  When the top of the horn
was inaccessible, a screening value was obtained at the weep hole, located
near the bottom of the. horn.  The maximum TLV readings were recorded.  If
any readings exceeded 200 pom, the relief device was to be sampled and
bagged.

4.2.1.5   Drain Screening Method

          In this program, process unit drains were, classified as either
active or washup drains.  The screening process is the same, for both types.

          The probe of the Bacharach TLV Sniffer x^as placed at two-inch
intervals around the perimeter of the drain.  At each of these, points, the
probe was placed right at the inside edge of the drain at the level of the
exit.  Trie maximum concentration was recorded.

          Upon completing the traverse around the perimeter of the drain,
one additional reading was taken at the center of the drain.  The maximum
of the perimeter and center readings was recorded and used as the basis
for sampling decisions.  If the maximum individual value was equal to
200 ppmv hydrocarbon or greater the drain was bagged and sampled.

4.2.2     Sampling Emissions from Baggable Sources

          The method  preferred for sampling emissions from baggable sources
is the  dilution or flow-through method.   The sampling trains that were used
                                    68

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 in  this method  are shown  in Figure  4-1 .   The  train was  contained  on  a
 portable  cart,  which  could be easily pushed around the  process units from
 source to source.

           The major equipment items in  the sampling  train vjcre the vacuum
 pump used to draw air  through the system, and  the dry gas meter used to
 measure the flow rate  of  gas through the  train.  The main vacuum  pump was
 a 4.8 CFM Teflon-ring  piston-type pump  equipped with a  3/4  horsepower
 air-driven motor.  It  can maintain  a maximum  flow rate  of 2.5 CFM.   The
 dry gas meter was a Rockwell Model  1755 Test  Gas Meter  with a Number 83
 Test Index.

           Other equipment items in  the  train  include Whitey valves,  copper
 and stainless steel tubing, Teflon  hose,  thermometers,  mercury and water
 manometer, a cold trap, and a small air-driven diaphragm sampling pump.

          The cold trap was placed  in the system to condense water and
 hydrocarbons.   Downstream condensation in the  lines and sampling  train was
 thus avoided.   The cold trap was simply a 500  ml flask  in an Ice  bath,
 placed very close to the  enclosure.  The  collected condensate consisted of
 water and, in some, cases, organic material.

          The leak source is shown as a valve  in Figure 4-1.  However, the
 same sampling train was used for all baggable  source sampling with the
 flow-through technique.   The size and shape of the leak source enclosure
 (bag)  was changed and adjusted to fit each particular source shape and
 operating condition.

                                                                         (R1
          Each  leak source enclosure (bag) was made of 1.5  to 5 mil Mylar .
     ($*
Mylar  does not significantly adsorb hydrocarbons,  is very  tough, and has
a high melting point.   Each enclosure was kept as small as possible and was
connected by means of a bulkhead fitting and Teflon hose to the sample.
train.   A separate line was  connected from the tent to a magnahelic to
                                    69

-------
MAGNEHELIC
                  THIS LINE SHOULD
                     BE AS SHORT
                     AS POSSIBLE
   TENT
         LEAKING
          VALVE
                    COLD TRAP
                    (ICE BATH)
DRY GAS
 METER
                                                                       Hg MANOMETER
                  CONTROL
                    VALVE
1

                                                                             FILTER    VACUUM PUMP
                                                                              SAMPLE BAG
                                                             SMALL
                                                           DIAPHRAGM
                                                              PUMP       TWO  WAY  VALVE
                     Figure 4-1.   Sampling Train  for Baggable  Sources of Hydrocarbon
                                 Emissions

-------
allow for continuous monitoring of the pressure inside the tent.  A slight
vacuum was maintained inside the tent while air was being pulled through
to insure that hydrocarbons did not escape.

          Important considerations in constructing each source enclosure
were the metal skin temperature in the enclosed area and in the area of the
seal, the presence or absence of supports for the tent, and possible
interference with working parts.  At skin temperatures of 400°F or less,
seals could be made with duct tape; at higher temperatures, metal foil and
asbestos insulating tape were used.  Further details of enclosure construc-
tion for specific sources are given in Appendix A (Volume 2).

          During each sampling effort, the vacuum pump was started, and the
entire system was allowed to come to equilibrium.   The Bacharach TLV Sniffer
was used to monitor the effluent air from the sampling train to assure that
equilibrium had been established.

          The air flow rate, temperature, and pressure at the dry gas meter
were recorded during each sampling run.   When equilibrium was established,
samples of the gas passing through the sampling train were taken.

                                              ®
          In most instances an evacuated Mylar  sample bag which had
previously been completely flushed with  air was attached to a two-way valve
in the sampling line.   The bag was first flushed with sample  gas.  Then the
sample bag was filled  with 5-7 liters of gas.  While this sample bag was
being filled, another  bag was being filled by a large plastic syringe with
ambient air from near  the tent.   The bags and the  cold trap,  removed from
the train and sealed,  were sent to the mobile laboratory for  analysis.

          The air sample was analyzed for the total methane and nonmethane
concentration.  The quantity of  any organic condensate collected in the
cold trap was measured.   The total nonmethane hydrocarbon emission rates
                                    71

-------
were  calculated  from the air  flow  rate, nonmethane hydrocarbon  concentration,
and the volume, ur weight of organic condensate.

          The above method was altered  for special cases.  For  large  leaks,
the vacuum pump  was disconnected from the sampling train and the sample gas
allowed to pa«s  through the sample train (including  the  cold trap) and exit
immediately downstream of the dry  gas meter.  The flow rate through the dry
gas meter can be combined with the amount of organic condensate (if any) to
obtain a direct measure of the hydrocarbon vapor leak rate.

          Liquid leaks, in which no vapor leakage could be detected, were
treated as vapor leaks if the liquid vaporized immediately.  If the liquid
ultimately vaporized, it was collected  in a cooled,  covered graduated con-
tainer.  When water or water vapor was  present in a gas sample, it was con-
densed in the cold trap and did not interfere with hydrocarbon analysis.

4.2.3     Sampling of Nonbaggable  Emission Sources

          Nonbaggable sources which were sampled during this program include
oil-water separators, dissolved air flotation (MF) units, and cooling
towers.  Fugitive emissions from these  sources were estimated from a vola-
tile hydrocarbon mass balance around the unit.  The difference between the
volatile hydrocarbon content of the liquid influent and the volatile
hydrocarbon content of the liquid effluent was assumed to equal the fugitive-
hydrocarbons emitted to the atmosphere.

4.2.3.1   0II -Water S e p a r a t o rjj

          The API separator is the most  widely used type of oil-water
separator;  sampling methods developed for il_  could be used for other types
as well.   In large refineries with more  than one separator, each separator
was sampled individually.
                                    72

-------
          Inlet liquid to the separator was obtained from the separator
inlet line or from the separator itself at a point as near to the inlet
as possible.  The inlet liquid was a heterogeneous mixture of oil and water.
A representative sample was difficult if not impossible to obtain.

          Three streams normally exit from a separator:  the oil skimmed
from the surface of the water, the water itself,  and a sludge stream.  The
sludge was not considered a significant source of atmospheric emissions for
several reasons.

          •    It is normally not exposed to the  air in the
               separator.

          •    Any volatile material in the sludge would have to
               pass into the water and then into  the oil layer
               on top of the water before it could be emitted
               to trie atmosphere.

          •    The water,  being well mixed with the oil and sludge
               at the separator, was assumed to be saturated with
               volatile hydrocarbons at all points in the separator.

          •    The loss of volatile material from the oil phase  on
               the surface of the  separator liquid was  thought to
               be very much greater than that  from the  water itself.
               Tn many cases, the  water was completely  covered by a
               layer of oil up to  several inches  thick.

          •    The volatile hydrocarbon content of the  inlet and
               outlet  oil  streams  was  determined  after  sludge had
               been centrifuged from the samples.   Only  the
                                   73

-------
                centrif uged  oil  samples  were  analyzed  for
                volatile  hydrocarbons.

 The  sludge  phase wa.s  not sampled.

          Skimmed  oil samples were  taken  at  the  outlet  of  the  pump  to  the
 slop-oil  tank,  in  the .skim  pipe, in the line  from  the separator  to  the
 slop-oil  tank,  and from  the slop-oil tank  itself.  Water samples were  taken
 at several  points  along  the overflow weir  and composited.   Samples  were
 taken  in  tightly-capped  glass bottles from each  stream  several times a day
 for  several days.   Samples  from each source were composited daily.

 4.2.3.2   DAF Units

          Dissolved-air  flotation (DAF) units  process water from the oil-
 water  separators.   Some  are  partially enclosed and others  are  completely
 open.  Only the water phase  from the oil-v7ater separator carries a  signifi-
 cant amount of hydrocarbons  into the DAF unit.  The separator  outlet
 samples were used  as  the DAF inlet  water sample.  The outlet water  stream
 was sampled at the overflow weir.   Water samples were taken several times a
 day  for several days  and composited daily  for  each source.   The froth layer
was not sampled.   This layer was exposed to the air for only a short time.
 No rates for froth removal  could be determined.
4.2.3.3   Cooling Towers
          Water enters a cooling tower from two sources:  make-up water and
the hot water from process exchange.  Water leaves the tower as vapor from
the top of the tower, as cooled water returning to process exchange, and as
blowdown.  There is also some loss from windage and drift.  Make-up water
exactly equals blowdown plus evaporation, therefore only the incoming hot
water and the exiting cool water had to be sampled.  The blowdown stream
was considered to have the same volatile hydrocarbon content as the cool
                                    74

-------
 water  leaving  the  unit  (or  in  the basin).   The blowdown  stream was
 considered  in  the  overall hydrocarbon material balance.

          Inlet water was sampled from one  of the many small sampling valves
 which  normally branch off the  large  cooling water return risers.  Outlet
 water  was taken from the water  flowing downward through  the tower at a
 location just  above the level of the cooling tower basin.  All samples
 were kept in sealed bottles under refrigeration until analysis.

 4.2.4     S^ampling of Process  Sources (Slacks and Vents)

          In general, stacks and vents were sampled for  a determination of
 total  hydrocarbons, a speciation analysis, and analyses  for other criteria
 pollutants  on  an as-needed  basis.  Samples were taken from catalytic crack-
 ing unit regenerator stacks, sulfur  recovery or tail-gas treating unit
 stacks, process heater stacks,  fluid coker stacks, and an incinerator stack.
 Measurements made on these  samples included some or all  of the following:
 EPA Reference Methods 1, 2, 3,  and 4 on all stacks;2-1  methane and n.onmethane
 hydrocarbons on all stacks; partlculate and vapor collection for organic
 characterization on one stack;  and sulfur gasp.s on the sulfur recovery and/
 or tail-gas treating unit stack.
          Stack sampling procedures were a combination of EPA approved
methods for criteria pollutants"  (S02, S03, and particulates); EPA Level 1
screening procedures71  "organic vapor"); Texas
Air Control Board methodology;22and, Radian-devised methods (HCN,  NH3, THC).
Figures 4-2 through 4-4 depict the sampling trains used.  Methods for
individual species are given below.

          Particulates—Particulate samples were collected from each stack
according to EPA Reference. Method 5.    A l^ar-Sigeler,  Inc., stack sampling
train was used.  Sampling was performed isokinetically along two
                                    75

-------
6%
                                                                       6X
 "S" Type Pilot Tube
                                                 80% X IPA   H202
-------
                Teflon/Glass Tiber Filter
Sample
                Ice
                Bath
                                                                               Vacuum Pump
                                                    Rotcmieter/Flow Controller

                                   Figure 4-3.  Aldehyde Impinger Train

-------
         Caa  Sample
00
J.
Stainless Steel
Probe



















Rotosieter/
Flo
Teflon/Class
Fiber

Heated Teflon
Sample Line


Filter
v_



•K
Perma Pure Drier
j i
;

f
~T—
rH

cr=J

W
*'•! •»
r
1
Controller
' /


"""""*
Teflon-Lined
(Total Hydrocarb
	 > Glaae Bomb (N0x)

V Class Borah
(Sulfur Species)

	 ^, Scotchpak Bag
(Fixed Gases)
. 	 \ Imptngers
(11CN, NH.)
Vacutim Snmpla

Pump

Hum Id Dry
Air A'ir
                            Figure 4-4.   Grab Sample Collection  and  Preparation System

-------
perpendicular traverses of each stack.  Duplicate sample runs were made on
each stack if possible.

          SO—Oxides of sulfur (S03 and S02) were collected according to
                       9 0
EPA Reference Method 8.    Collection was done during each particulate
collection run by passing the filtered sample gases through an Impinger
train consisting of an 80 percent isopropanol impinger for SOa collection
followed by two six percent aqueous hydrogen peroxide impingers for S02
collection and a silica gel impinger.  The total mass of water collected
in this train was used to determine the moisture content of the stack gas.

          Aldehydes—The aldehyde train (Figure 4-3) consisted of two ice-
cooled impingers, each containing 10 ml of a 1.0 percent aqueous sodium
bisulfite solution.  Approximately 12 liters of stack gas were drawn through
each impinger train at a rate of 200 ml per minute.  A stainless steel
probe was inserted into the stack to a point of average velocity, then the
gas was transferred to the impinger train by a small vacuum sampling pump
through a heated Teflon sample line, equipped with a Teflon particulate
filter.

          A second impinger sampling train was sometimes used to sample for
total aldehydes.  it consisted of three ice-cooled impingers, the first
containing 10 ml water and the following two containing 10 ml of 0.05 per-
cent aqueous 3-methyl-benzothiazolone hydrazone (MBTH) solution.  The
aldehydes were collected by dissolution in the water and reaction with MBTH
to form a water-soluble adduct.   Approximately 12 liters of stack gas were
drawn through the impinger train at a rate of 200 ml per minute.

          NCH and NH3—Hydrogen  cyanide was collected with the Method 5"
stack sampling equipment by passing the filtered sample gases through three
impingers containing 2.0 N^ sodium hydroxide.   Ammonia was collected
similarly by using three impingers containing 0.1 _N sulfuric acid.   In each
                                    79

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 case, samp Ling was conducted over thirty-minute periods and resulted in
 approximately 10 SCF of gas for each sample.

          Grab Samples—The remaining four categories of species were all
 collected by grab sampling techniques.  A stainless steel probe was inserted
 into the stack to the point of average velocity, and the sample gas drawn
 out through a heated Teflon sampling line.  The sample passed through a
 heated Teflon glass/fiber filter to remove particulates, then through a
 permeation drying system to remove moisture.  The Perma-Purc Products, Inc.,
 multi-tube drier has been found to effectively remove moisture down to 100
 ppm while, causing only a 1-3 percent loss of the desired specie.s.  Move-
 ment of the sample through the system was accomplished by a miniature
 Thomas vacuum pump equipped with Teflon heads and diaphragm.  The outlet
 stream from the pump was directed to the several bags and bombs used to
 transport the samples to the field laboratory for analysis.

          Samples for methane and nonmethane hydrocarbons analysis were
 collected in 4-liter Tedlar sample bags.

          Samples for fixed gases (C02,  N2,  H2,  02, CO)  analysis were
 collected in aluminized Scotchpak sample bags.  These species are quite
 unreactive and arc not prone to adsorb onto  the bag walls significantly.

          The sulfur species (CS2,  H2S,  COS, and S02)  proved to be the most
 difficult to collect and transport.   Samples for analysis of these, species
were collected in glass bombs.

          Samples for NO  analysis  were  collected in evacuated 2 liter glass
 flasks to which had been added  25 ml  of  a potassium dichromate-aqueous
 sulfuric acid solution.
                                    80

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4.2.5      Sampling for Organic Species Identification

           A minimum number of .samples were taken for species identification
and quantification.  The. number of samples taken from a particular stream
depended on the likelihood of the presence of potentially hazardous
materials.  The relationship between the composition of a vapor leak and
the composition of the stream from which it came was investigated by taking
both liquid and vapor speciation samples wherever possible.  A listing of
the streams sampled for speciation studies is included in Appendix A
(Volume 2).  The sampling methodology discussed briefly below is explained
in more detail in Appendix A (Volume 2).

          Vapor Samples—Vapor samples were collected by passing the leaking
vapor through an adsorbent tube.  Tenax was used to adsorb volatile organ!cs
in the acetone-to-naphthalene range.  Charcoal was occasionally used for the
250°F to 300°F boiling range materials.  High molecular weight fugitives,
heterocyclic nitrogen + sulfur compounds, and polynuclear aromatics were
trapped with XAD-2 resin.  Operating parameters for the use of these
sorbents are given in Table 4-2.

          Tn the "blow-through" method, plant air (compressed air)  was
charcoal filtered and blown into the enclosure around the leaking source.
An outlet line was provided on the enclosure, and air exited through this
line.

          A separate sample line was connected to the enclosure outlet line.
Air was drawn through the sample line with a vacuum pump.   The air  first
passed through a glass knockout flask to remove any entrained condensate.
The air was then drawn through tubes packed with either XAD-2 resin,
charcoal, or Tenax adsorbent and finally the air was drawn through  a dry
gas meter.
                                    81

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                       TABLE 4-2.  NOMINAL OPERATING  CONDITIONS  FOR SAMPLING  WITH ADSORBENTS
                                                                    Recommended Ranges
                       Detection
          Sorbent        Limit       Method       Volume
                           Flow
                              Mass
    T.nlet
Concentration
          Ten.ix     ~.l. ppb         GC-MS
            1-2  £      10-25 ml/min    50-100  ng
                                        minimum
                                             5-20 ppbv(minimum)
          Charcoal  ~500 ppb

                    ~50 ppm
GC-MS

GC
5-1.0 I      20-50 ml/min   2-15 mg
200-500 ppmv
00
          XAD-2     -50-100 ppb    GC-MS        300-600  £    5-1.0  1/min      3-4 G maximum    100-1000 ppinv

-------
          The  "draw-through" method  (as in Figure 4-1)  for  taking vapor
samples on adsorbents differs  from the "blow  through" method  in only one
way.  Instead  of blowing air through  the enclosure around the  leaking
source, ambient air is drawn into and through  the enclosure with a vacuum
pump.

          All  adsorbent tubes  were sealed and  frozen until  they could be
analyzed.

          Liquid Samples—Samples of  various  representative liquid streams
were collected from sampling points along the  processing lines.  All
samples were taken in Pyrex sample bottles, tightly sealed with Teflon-
lined screw caps, and refrigerated until analysis.

          Stack Samples—Stack samples were collected for organic specia-
tion with the  use of a modified Ae.rothe.rrn Source Assessment Sampling System
(SASS).   A canister of XAD-2 resin replaced the original-equipment organic
concentrator.

          A 1,000-1,200 SCF sample of stack gas was drawn from a point of
average velocity in the stack.   Particulates were removed on a filter, the
gas was cooled, then nonvolatile organic compounds were removed by the
XAD-2 resin.   The participates, the condensate from cooling the gas, and
the resin were collected for analysis.

4.3       Analytical Methodologies (Field Laboratory)

          Analyses were done on-site in a mobile laboratory for methane and
nonmethane hydrocarbons,  NO/NO , sulfur gases, aldehydes, ammonia,  and
                              X         '""'
cyanide.   These are described in detail in Appendix A (Volume 2).
                                    83

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 4.3.1     Rydrocarbon Me.asjiremen t

          The methane and nonmethane hydrocarbon content, and  therefore
 total hydrocarbon content, of baggab.le emission gas samples was determined
 with the use of a Total Hydrocarbon Analyzer  (THC) Model 301C  made for
 Radian by Byron Instruments.

          The THC analyzer had a flame ionization detector for measurement
 of hydrocarbon concentration.  It produced a  linear readout in the 0 - 2 to
 0-20,000 ppmw ranges.  Dilution techniques were used for more concentrated
 samples.  Hydrocarbon-free air was used as the carrier gas.  Baggable
 samples were analyzed by pumping sample directly from the sample bag to the
 sample loop of the instrument with the. use of an integral pump in the
 instrument.  A detailed description of the theory and operation of this
 instrument is contained in Appendix A (Volume 2).

          Oil layer samples and wastewater samples were analyzed on-site
 for volatile organics, since only volatile components are lost to the
 atmosphere as fugitive emissions.

          To determine the volatile content of the oil samples, a small
 amount of the material was placed in an open  container and stired for
 eight hours.  The volatile content was represented by the change in sample
weight over the test period.

          Purgeable organics were, swept from  the water samples into Teflon
sampling bags.   The contents of the bag were analyzed on the THC analyzer
described above.

          The total organic carbon content of water samples was determined
with a Dohrmann DC52D TOG Analyzer.  This instrument oxidized organics to
carbon dioxide, then reduced the carbon dioxide to methane.   The methane
was measured with a flame ionization detector.
                                    84

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 4.3.2     NO/NC^ _De_t erm_ip_ation

          Nitrogen  oxides (NO and/or NOa,  or  collectively, N0x)  in  stack
 gases were determined as nitrate  (NO^)  colorimeterically.  The sample was
 collected in  a  glass flow-through  bomb.  The  NO   in  the  sample was  converted
 to  nitrate ion  by reaction with hydrogen peroxide injected immediately
 following collection of the  sample.  A  yellow color  was  developed in the
mobile laboratory by the addition  of potassium hydroxide and phenoldisul-
fonic acid as part  of a set procedure.  The intensity of the color, as
measured by a Bausch and Lomb Spectrcnic 21 spectrophotomcter, was  compared
against a set of standards to determine NO  content.
                                          x
          The procedure is accurate to within ± 3 percent for nitrate con-
centrations in the 10-20 ppm range; ± 2 percent for the 20-60 ppm range.
Samples with more than 60 ppm nitrate were diluted.  This method is
described further in Appendix A (Volume 2).

4.3.3     j3ulli?L Gases

          Separate analyses for SC2 and S03 were performed on the impinger
samples collected during each EPA Method 5 train operation.  An 80 percent
isopropanol impinger collected samples for S03 analysis: two 6 percent H202
impingers were used for S02 analysis.   S02 and S03 were converted to MrSO*.
in the impingers.   The contents of these impingers were titrated with barium
perchlorate to a Thorin indicator end-point (yellow color) as specified in
                           f\ ^
the EPA Reference Method 8.  '  The amount of sulfate found indicated the
amount of S02 or S03 in the original sample.

4.3.4     Aldehydes

          The contents of the one percent bisulfite impinger shown in
Figure 4-3 were analyzed for aldehydes.  The aldehydes collected in these
impingers formed an aldehyde-bisulfite complex with the bisulfite.   When
                                    85

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 the sample was to be analyzed, excess bisulfite was destroyed with an excess
 of iodine.  The excess iodine was destroyed by the addition of thiosulfate,
 which was then titrated to a faint blue end-point.  Addition of a carbonate
 buffer solution released the complexed bisulfite.  The released bisulfite
 was titrated with iodine to a final end-point.  The amount, of iodine titrant
 in the final titration indicated the amount, of aldehydes as formaldehyde
 in the solution.

 4.3.5     Ammonia

          Ammonia was collected from gas streams in impingers containing
 sulfuric acid at a pH < 2.  These impingers were part of the sample train
 pictured in Figure 4-4.  The contents of the impingers were then buffered
 with sodium hydroxide and sodium tetraborate to a pH of 9.5.  Ammonia was
 then driven from the samples and bubbled through a boric acid indicating
 solution which changed color on reaction with ammonia.  The boric acid was
 then titrated to its original color with a standard sulfuric acid solution.
 The amount of sulfuric acid titrant required indicated the amount of
 ammonia present in the original solution.

          This method for NH3 analysis has no known interferences and is
 considered very accurate to 0.05 ppn.

 4.3.6     Cyanide

          Cyanide was collected in impincers containing sodium hydroxide at
 a pH > 12.   These impingers were part of the sample train shown in Figure
 4-4.   The contents of the impingers were first tested for the presence of
 oxidizing agents and sulfide.   Any oxidizing agents were removed with
ascorbic acid;  sulfides were precipitated with lead nitrate and filtered
off.   A distillation procedure was then used to separate CN~ from other
cy£ino compounds.   The CN~ concentration in the resultant solution was
 determined colorimctrically on a Bausch and Lomb Spectronic 21
                                    86

-------
 Spectrophotometer with  the use of pyrldine-barbituric  acid, which  forms an
 Intense blue  color with free cyanide.
4.4
Identification of Emitted Species
          Analyses for organic species were performed in Radian's Austin
 laboratory.  Inorganic analyses were performed by Commercial Testing and
 Engineering.
4.4.1
jualitative Organic Analyses
          Trace organic species concentrations were determined by gas
chromatography/mass spectroscopy  (GC/MS) techniques for the samples listed
in Table 4-3.
        TABLE 4-3.  SUMMARY OF ORGANIC SAMPLES FOR QUANTITATIVE
                    ANALYSES
  Sample  Type
                  Sample  Composition
Emission Source
Process Liquid
XAD-8 Resin
Tenax
XAD-2 Resin
Particulate
Effluent Water
Charcoal
                 Organic  Liquid
                 Sorbed Organic  Vapor
                 Sorbed Organic  Vapor
                 Sorbed Organic.  Vapor
                 Particulate
                 Aqueous
                 Sorbed Organic  Vapor
    Fugitive
    Fugitive
    Fugitive.
    Point
    Point
    Point
    Fugitive
Preliminary treatment of GC/MS samples included isolation of the species of
interest, separation of the Isolated species into groups with similar chemi-
cal or physical properties, and concentration of the species of Interest.
Each sample required some or all of these preliminary treatments.
                                    87

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          Isolation—Organic species were isolated by solvent extraction or
thermal desorption.  Organics from particulate and XAD-2 resin samples were
isolated by Soxhlet extraction with diethy! ether; XAD-8 resin samples were
separated by Soxhlet extraction with pentane.  Pentane was also used as the
solvent for process liquids.  Aqueous samples were manually extracted with
diethyl ether in a separatory funnel.

          At the conclusion of the .isolation phase, the process liquid and
XAD-8 resin samples were, ready for analysis.  The effluent water samples
remained to be. concentrated.  The XAD-2 resin and particulate samples were
further separated as described in the following section.

          Trie organics in the Tenax tubes were thermal ly desorbed directly
into the GC/MS system by a Tekmar Liquid Sample Concentrator.  This process
is an integral part of the analysis itself.

          Separation—Radian developed an acid-base-neutral (ABN) separation
strategy for the separation of complex environmental samples.  This strategy
was used for the particulate and XAD-2 resin samples.  It was based on a
series of liquid-liquid extractions that separate a sample into three
principal fractions:

          A:   organic acids whose salts partition into water at
               a high pH,
          B:   organic bases whose, salts partition into water at
               a low pll, and
          N:   neutral hydrophobia compounds.

These principal fractions were then further subdivided into a total of
seven fractions to be analyzed by GC/MS.
                                    88

-------
          This  separation  scheme was  not  Intended  for  the  isolation  of
 every  compound  collected in  a  particular  sample; its purpose  was  to  effect
 a  sufficient  division  of organic components  so  that  those  compounds  of
 primary interest  could be  identified  and  quantified.

          The complete separation  scheme  is  presented  in Appendix A  (Volume
 2).  In brief,  the  acidic  and  neutral  components' of  the sample were
 extracted frora  the  basic component with acidic  water.  Basic  components
 were extracted  from the aqueous phase  with ether,  concentrated, then
 transferred to  a  hexane medium and reconcentrated.   The hexane concentrate
 was  transferred to  a silica  gel column and divided into four  fractions:
 nonpolar neutrals,  moderately  polar neutrals, polar  neutrals, and very
 polar  neutrals.

          The acid/neutral component  was  basified.   The extract containing
 the neutral species was dried  and  concentrated.  The alkaline extract con-
 taining the acidic  compounds was methylated  in  two steps to convert
 phenols to methyl ethers and carboxylic acids to methyl esters.   Dimethyl.
 sulfate was used  for the phenols and  diazomethane  for  the  carboxylic
 acids.

          Concentration—Each  extract  was concentrated with mac.ro  and micro
 Kuderna-Danish  (K-D) concentrators before analysis.  Typically, a  sample
 was concentrated  to  5-10  ml in a macro K-D, then to 1 ml   in  a micro K-D.

          Analysis—Each extract was analyzed by GC/MS in  a Hewlett-Packard
 Model  5982 or a Hewlett-Packard Model  5985 GC/MS computer  system.  Both
 capillary and packed column gas chromatography wp.re u.sp.d.

          Chroma tograp'nic  peaks we.re identified by analysis of individual
mass spectra.   The  three techniques used were:
                                    89

-------
          •    Manual interpretation of an unknown mass
               spectrum.

          •    Comparison of the unknown mass spectrum against
               the mass spectrum generated from the analysis of
               a previously analyzed standard.

          •    Computer search of the unknown mass spectrum
               against libraries containing reference spectra.

          Selected ion current profile (S1CP) searches were used to identify
trace levels of selected organic species.  This technique is based on the
appearance of key ions within a narrow retention time window.  It was used
primarily to search for polynuclear aromatic hydrocarbons in the extracts.

          Details of the analyses of the extracts are given in Appendix A
(Volume 2).

4.4.2     Semi-QuantIt ative Organic Analyses

          Semi-quantitative analyses of the identified compounds were
achieved by measurement of the area under the selected ion current profile
for each compound.   For a given compound, the area under the most abundant
ion was calculated with the use of the data system.   The computed area was
then compared to the area found for the most abundant ion of the appropriate
internal standard,  d10-anthracene or ds-toluene.

          Radian determined for many compounds the response factors relative
to d10-anthracene and de-toluene.  A value of 1.0 was used when the response
factor x^as not known.
                                    90

-------
          Electron impact (70 eV) ionlzatlon was used exclusively for
analyses.  The mass spectral information obtained was stored on magnetic
discs for future interpretation and reference.

4. 5       Quality Control

          Numerous procedures were used to insure the quality of the data
obtained.  Both accuracy and precision were considered vital to the success
of  the program.

4.5.1     Screening

          The Bacharach Instrument Company J-VJ Model TLV Sniffer was con-
sidered to be a reliable instrument for the screening of haggable sources.
To  insure that all screening results were obtained on an equivalent basis,
the procedures listed below were followed.

          •    The battery pack for the instrument was fully
               recharged each night.

          •    The instrument and the dilution probe were
               calibrated before the start of each sampling day.
               Each concentration range on the instrument was
               calibrated separately.

          •    The instrument, was allowed to warm up for ten
               minutes  before screening began.

          *    The meter was zeroed before each screening.

          •    The meter was always held in an upright position;
               meter  position affects  the distribution of heat
               in  the catalytic element.
                                    91

-------
          •    The small orifice in the dilution probe, the small
               diameter extension and the cotton filter chamber
               sections of the probe were inspected and cleaned
               frequently.

The TLV Sniffer was calibrated with several hexane-alr standards according
to the. procedure described in Appendix A (Volume 2).

4.5.2     Sampling

          Several procedures were followed to assure that baggable samples
were representative of their sources:

          •    Mylar and Tedlar plastics were used as sample
               bags because they do not adsorb hydrocarbons.

          •    A cold trap in the sampling train trapped water
               and hydrocarbons to prevent condensation in down-
               stream equipment.  The. contents of the cold trap
               were measured and the values recorded.

          •    Tent enclosures were kept as small as possible to
               minimize or prevent condensation in downstream
               equipment.   The contents of the cold trap were
               measured and the values recorded.

          •    Tent enclosures were kept as small as possible to
               minimize, or prevent condensation of heavy hydro-
               carbons.  Tents were sealed securely.

          •    Sampling was not begun until equilibrium was
               established throughout the sampling system.   The
                                    92

-------
               TLV Sniffer was used to indicate that equilibrium
               had been established.

          Duplicate samples were taken whenever practical.  Particular care
was given to the care of grab samples for fixed gases (C02, N2, H2, 02 and
CO), hydrocarbons, gaseous sulfur species, and NO  analyses.  If analysis
could not begin within 15 minutes of capture, a new sample was obtained.
These samples were also dried and participates were removed to help preserve
their integrity.

4.5.3     On-S i t e Analys es

          Approved analysis methods were followed.  All instruments were
calibrated frequently with approved standards.  Duplicate analyses were
made on many samples; titrations were repeated until reproducible results
were obtained.  Blanks were used whenever specified in a procedure, as
were standard curves.

          The organ Ics in water samples were purged from the samples into
a Teflon sample bag for analysis with the THC analyzer.   This bag was
thoroughly flushed with zero grade nitrogen between samples and a blank
sample analyzed for THC at the end of each flushing.

          A "zero carbon" water standard was prepared by Radian for the TOC
analyses.  This standard was considered superior to commercial standards.
Several TOC analyses were made for each sample because the analysis sample
is so small that it is difficult to obtain a single representative portion.

4.5.4     Sp ecies Identifi c at i on

          Special precautions were required in the preparation of samples
for determination of trace organic species.   Only high-purity distilled-in-
glass solvents (Burdick and Jackson) were used.   Only Teflon, glass, or
                                    93

-------
stainless steel labware contacted the samples.  All laboratory glassware
was cleaned with chromic acid and, imncdiately before use, rinsed with an
organic solvent to remove any traces of organic material.  Aqueous reagents
were presaturated with solvent before use.

          As with other procedures in this program, only accepted and
approved methods were used.
                                    94

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 5.0       RESULTS OF REFINERY MEASUREMENTS AND SURVEYS

          The results of measurements of atmospheric emissions at 13
 petroleum refineries are summarized in this section of the report.  Emission
 data were obtained from baggable sources (valves, flanges, pump seals, com-
 pressor seals, drains, and relief valves), nonbaggable sources (cooling
 towers and wastewater treating units), and process stacks.  Also included
 in this section are summaries of the species identification results and the
 results of the quality control activities.  The refinery survey results- are
 also discussed.  A more comprehensive presentation of the measurement data
 and results is given in Appendix 3 (Volume 3).  The statistical treatment
 of the data is discussed in detail in Appendix C (Volume 4).

 5.1       Eaggable Source Measurementsand Results

          As previously described in Section 4 and in Appendix A (Volume 2),
 all baggable sources were chosen on the basis of choice variables and were
 selected In each refinery from process flow diagrams.  The screening and
emissions measurement results, the statistical model development, the
valve maintenance study results and the distribution of baggable sources
 in refinery units are presented below.

5.1.1     Screening of Baggable Sources

          The "screening values" refer to the maximum hydrocarbon concen-
tration detected at selected baggable sources using the Bacharach TLV Sniffer
calibrated with hexane.   These screening values are expressed as  ppmv of
hydrocarbon.   The results of screening baggable sources are presented in
this  section.   It was found that the emissions sources were, most  conveniently
grouped into twelve categories for analyses,  presentation of  results, and
emission factor development.   These twelve categories are given in Table 5-1.
The total number of sources which were screened in each baggable  source cate-
gory  are also presented  in Table 5-1.
                                    95

-------
               TABLE 5-1.  CATEGORIES OF BAGGABLE SOURCES
                                                           Number of Sources
Category                    Source Description
                                                                Screened
    1              Valves, Gas/Vapor Streams                      563





    2              Valves, Light Liquid/Two-Phase Streams         913





    3              Valves, Heavy Liquid Streams                   485





    4              Valves, Predominantly Hydrogen Streams         135





    5              Open-ended Lines (all streams)                  129





    6              Pump Seals, Light Liquid Streams               470





    7              Pump Seals, Heavy Liquid Streams               292





    8              Compressor Seals, Hydrocarbon Service          142





    9              Compressor Seals, Hydrogen Service              83





   10              Flanges (all streams)                         2094





   11              Drains (all streams)                           257




   12              Relief Valves (venting to atmosphere)          148

-------
           The volatility of the process streams associated with each of the
 baggable source types was found to have a significant effect on the frequency
 and rate of hydrocarbon emissions.  Three hydrocarbon stream classifications
 were developed:  gas/vapor streams, light liquid streams, and heavy liquid
 streams.  The "gas/vapor" group contains those hydrocarbons which are com-
 pletely vaporized at the process conditions.   Light hydrocarbon liquids with
 boiling points below that of kerosene are included in the "light liquid"
 category.   This group contains material having a vapor pressure above 0.1
 ps.La at 100°F.

           Hydrocarbon liquids with boiling points equivalent to or above that
 of kerosene are classified as "heavy liquid"  streams.  Those liquids with
 vapor pressures equal to or below 0.1 psia at 100°? fall into this classifi-
 cation.  As a general rule., the most volatile stream component  (or mixture
 of components) present at a concentration of  20 percent or more determines
 the stream classification.

           The results of the screening activity are summarized  in Table 5-2.
 The number and percentage of sources found to have a maximum screening value
 of 200 ppmv or greater are given.   A Bacharach TLV Sniffer calibrated with
 hexanc was used as the screening device.   Both the screening instrument and
 the techniques are described in Section 4 of  this document.

          The 95 percent confidence interval for the. percentage of sources
screening > 200 ppmv is also presented for each of the source c.ategores.  If
all the sources in each category in refinery service could be screened, the
percentage of sources found to screen > 200 ppmv could be expected to fall
between the given upper and lower boundaries 95 percent of the time.

           The  distribution  of  maximum  screening values  among  screened  baggable
 sources are presented  in  Table  5-3.  They  are  given  as  functions  of  source
 types  and  process  stream  classification.
                                    97

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TABLE 5-2.   SUMMARY STATISTICS FOR SCREENING
            OF BAGGABLE SOURCES
Source Type
Valves
Gas -Vapor Streams
Light Liquid /Two-Phase
Heavy Liquid
Hydrogen
Open-Ended Valves
Pump Seals
Light Liquid Streams
Heavy Liquid Streams
Drains
Flanges
Relief Valves
Compressor Seals
Hydrocarbon Service
Hydrogen Service
Number Percent
Number Screening Screening
Screened > 200 ppmv > 200 ppmv

563 154 27.4
913 330 36.1
485 32 6.6
135 59 43.7
129 30 23.3

470 296 63.0
292 66 22.6
257 49 19.1
2094 62 3.0
148 58 39.2

142 102 71.8
83 69 83.1
95% Confidence
Interval for
Percent Screening
•? 200 ppmv

(24,
(33,
( 4,
(35,
(16,

(59,
(18,
(14,
( 2,
(31,

(64,
(75,

31)
39)
9)
52)
3D

67)
27)
24)
4)
47)

79)
91)
                      98

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TABLE 5-3.  DISTRIBUTION OF MAXIMUM SCREENING
            VALUES AMONG SCREENED SOURCES
Screening Range
(ppmv)
Valves - Gas/Vapor Streams
,,. . a
Missing
0
1-200
201-1000
1001-10,000
>10,000

Valves - Light Liquid/Two-Phase Streams
Mis s ing
0
1-200
201-1000
1001-10,000
>10,000

Valves - Heavy Liquid Streams
0
1-200
201-1000
1001-10,000
>10,000

Valves - Hydrogen Service
0
1-200
201-1000
1001-10,000
>10,000

Screened
Number

1
278
134
33
47
71
564

1
386
211
70
142
104
914

335
121
21
7
1
485

47
30
8
22
_2jJ
135
Sources Within Range
Percent

0.2
49.3
23.8
5.8
8.3
12.6
100%

0.1
42.2
23.1
7.7
15.5
11.4
100%

69.1
25.0
4.3
1.4
0.2
100%

34.8
22.2
5.9
16.3
2JD_._8
100%
                                   Continued
                     99

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Table 5-3.   Continued
Screening Range
(ppmv)
Valves - Open-Ended (All Streams)
0
1-200
201-1000
1001-10,000
>10,000
Flanges (All Streams)
,.. . a
Missing
0
1-200
201-1000
1001-10,000
>10,000
Pump Seals - Light Liquid Streams
0
1-200
201-1000
1001-10,000
>10,000
Pump Seals - Heavy Liquid Streams
0
1-200
201-1000
1001-10,000
>10,000
Screened
Number
74
26
7
12
10
129

64
1748
225
29
17
11
2094
67
107
79
104
113
470
114
115
24
28
11
292
Sources Within Range
Percent
57.4
20.2
5.4
9.3
7.7
100%

3.1
83.5
10.7
1.4
0.8
0.5
100%
14.3
22.8
16.8
22.1
24.0
100%
39.0
39.4
8.2
9.6
3.8
100%
                       Continued
        100

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                          TABLE 5-3.  Continued
Screening Range
(pprav)
Compressor Seals - Hydrocarbon Service
Missing
0
1-200
201-1000
1001-10,000
>10,000

Compressor Seals - Hydrogen Service
o
Missing
0
1-200
201-1000
1001-10,000
>10,000


Drains (All Streams)
Missing
0
1-200
20.1-1000
1001-10,000
>10,000

Relief Valves (All Streams)
Missing
0
1-200
201-1000
1001-10,000
>10,000

Screened
Number

16
23
7
11
13
72
142

9
8
8
8
17
33

83

2
138
73
18
14
12
257

112
61
33
11
23
12
252
Sources Within Range
Percent

11.3
16.2
4.9
7.7
9.2
50.7
100%

10.9
9.6
9.6
9.6
20.5
39.8
100%


0.8
53.7
28.4
7.0
5.4
4.7
100%

44.4
24.2
13.1
4.4
9.1
4.8
100%
Missing TLV value - screening data are not available.
Relief valves selected,  but not venting to the atmosphere, were  not
screened or sampled.
                                   101

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          The screening values are not evenly distributed.  For almost every
source and stream category, the majority of the sources have screening values
of 1000 ppmv or less (the only exceptions being compressor seal screening
values).  The skewness of the screening results is even more evident when
the data are presented in graphical form.  An example is Figure 5-1, where
the distribution of screening values is shown for valves in light liquid
stream service.  The apparent "spike" at 10,000 ppmv was due to the limita-
tions of the screening instrument.  The Bacharach TLV Sniffer has an upper
detection limit of 10,000 ppmv.  A dilution probe allows this limit to be
extended to 100,000 ppmv.  However, this dilution probe was not used in the
early stages of this study.  Thus, all sources which screened above 10,000
ppmv were given a screening value of 10,000 during this period.

5.1.2     Hydrocarbon Emissicms from Baggable Sources

          Nonmcthane hydrocarbon emissions from baggable sources were
measured.  Results and correlations of emission rates with process and
equipment variables are discussed in this section of the report.

5.1.2.1   Distribution o_f___ Hydrocarbon Emission Rates

          The results of the baggabie source emissions sampling are
summarized in Table 5-4.   The distribution of nonmethane hydrocarbon leak
rates among leak rate ranges is shown for the various source and process
stream categories.  As with the screening values,  the emissions data are
highly skewed for all sources.   It is obvious from Table 5-4 that the bulk
of emissions emanate from a small percentage of the fittings.   For example,
76 percent of the total measured emissions from valves in light liquid/two-
phase streams came from 3.5 percent of screened sources (or 9.7 percent of
the leaking sources).   This distribution Js clearly illustrated in
Figure 5-2 for nonmethane hydrocarbon emissions from valves in light liquid/
two-phase stream service.
                                    102

-------







z
UJ
or
UI
a:









300-
280-
260 -
240-
220-
200-
1BO-
160-

140-
120-
100-
80-
60-
40-
20-



















c


N















a c
c
L


•386














1 1 1 1 1 1 1 1 K 1 1 1
-- \T^ 	 ' ' 	 ' 	 • 	 ' ' 	 "
^SS2O° goooo^oo ooo o ooo
SSSi8§.SSgSg§gggi §§gg
'•"•^tO^frU"* *Or^ COCJ^O OC3 OOO O O O O
t-» cvjm 4-i/ivo r^. S o> o
TLV (ppn)
Figure 5-1.  Distribution of Screening Values for
             Valves - Light Liquid Streams

-------
TABLE 5-4.  DISTRIBUTION OF NONMETHANE LEAK
            RATES FROM SAMPLED SOURCES
Leaking Sources
Within Range

Leak Range
(lb/hr)

No.
% of % of Total
Leaking Sources
Sources Screened
Valves, Gas/Vapor Streams =
>1.0
0.1 .- 1.0
0.01 - .1
0.001 - 0.01
0.00001 - O.C01
7
18
43
49
37
154
Valves, Light
>1.0
0.1 - 1.0
0.01 - .1
0,001 - 0.01
0.00001 - 0.001
>1.0
0.1 - 1.0
0.01 - .1
0.001 - 0.01
0.00001 - 0.001
1
31
105
121
72
330
Valves,
0
0
5
13
14
32
4.6 1.2
11.7 3.2
27.9 7.6
31.3 8.7
24.0 6.6
10Q% 20.3%
Total Leakage
Within Range
Total
Leakage
(lb/hr)
563 Screened
17.7654
5.9187
1.4867
0.2052
0.0133
25.3893

% of Total
Source of Leakage
70.0
23.3
5.5
0.8
0.1
100%
Liquid/Two-Phase Streams = 913 Screened
0.3 0.1
9.4 3.4
31.8 11.5
36.7 13.3
21.8 7.8
100% 36.1%
Heavy Liquid Streams =
0.0 0.0
0.0 0.0
15.6 1.0
40.6 2.7
43.3 2.9
100% 6.6%
2.2297
9.3351
3.3877
0.5028
0.0266
15.4319
485 Screened
0.0
0.0
0.1773
0.0569
0.0051
0.2393
14.4
60.3
21.9
3.2
0.2
100%
0.0
0.0
74.1
23.8
2.1
100%
                                        Continued
                          104

-------
TABLE 5-4.   Continued
Leaking Sources
Within Range
Total Leakage
Within Range
* of % of Total Total
Leak Flange Leaking Sources Leakage % of Total
(Ib/hr) No. Sources Screened (Ib/hr) Source of Leakage
Valves, Predominantly Hydrogen Streams
>
0
0
0
0
>
0
0
0
0
>
0
0
0
0
1.0 0
.1 - 1.0 3
.01. - .1 19
.001 - 0.01 13
.00001 - 0.001 19
59
Open-Ended
1.0 0
.1 - 1.0 1
.01 - .1 9
.001 - 0.01 12
.00001 - 0.001 	 8
30
1.0 0
.1 - 1.0 4
.01 - .1 12
.001 - O.C1 23
.00001 - 0.001 18
62
0.0
5.1
32.2
30.5
32.2
100%
Lines, All
0.0
3.3
30,0
40.0
26.7
100%
Flanges =
0.0
6.4
19.4
45.2
29.0.
100%
0.0
2.2
14.1
13.3
14.1
43.7%
Streams = 129
0.0
o.s
7.0
9.3
6.2
23.3%
2094 Screened
0.0
0.19
0.57
1.33
0.86
2.95%
= 135 Screened
0.0
0.3789
0.6691
0.0532
0.0059
1.1071
Screened
0.0
0.1242
0.3475
0.0576
0.003.3
0.5326
0.0
0.8655
0.4117
0.0820
0.0096
1.3688
0.0
34.2
60.4
4.8
0.6
100%
0.0
23.3
65.3
10.8
0.6
100%
0.0
63.2
30.1
6.0
0.7
100%
                            Continued
          105

-------
TABLE 5-4.  Continued
Leaking Sources
Within Range


Leak Range
(Ib/hr) No.
Pump
>1.0
0.1 - 1.0
0.01 - .1
0.001 - 0.01
0.00001 - 0.001
Pump
>1.0
0.1 - 1.0
0.01 - .1
0.001 - O.C1
0.00001 - 0.001
% of
Leaking
Sources
Seals, Light
19
73
107
77
20
296
6.4
24.7
36.1
26.0
6.8
100%
Seals, Heavy
0
16
28
17
5
66
0.0
24.2
42.4
25.8
7.6
100%
% of local
Sources
Screened
Liquid Streams =
4.0
15. -5
22.7
16.4
4.3
62.9%
Liquid Streams =
0.0
5.5
9.6
5.8
1.7
22.67,
Total Leakage
Within Range
Total

Leakage % of Total
(Ib/hr) Source of Leakage
470 Screened
63.1913
22.0347
3.9^30
0.3274
0.0086
89.5051
292 Screened
0.0
4.3139
1.5089
0.0699
0.00178
5.8995
70.6
24.6
4.4
0.4
0.0
100%
0.0
73.2
25.6
1.2
0.0
100%
Drains = 257 Screened
>1.0
0.1 - 1.0
0.01 - .1
0.001 - 0.01
0.00001 - 0.001
4
12
17
13
3
49
8.2
24.5
34.7
26.5
6.1
100%
1.6
4.7
6.6
5.1
1.1
19.1%
7.3958
3.9615
0.5939
0.0630
0.0013
12.0155
61.6
33.0
4.9
0.5
0.0
100%
                             Continued
          -106

-------
TABLE 5-4.   Continued
Leaking
Within
Sources
Range
T, of % of Total
Leak Range Leaking Sources
(Ib/hr) No. Sources Screened
Total Leakage
Within Range
Total
Leakage 7, of Total
(Ib/hr) Source of Leakage
Relief Valves = 148 Screened
>1.0
0.1 - 1.0
o.or - .1
0.001 - 0
0.00001 -
5
15
22
.01 12
0.001 4
58
8.6
25.9
37.9
20.7
6.9
100%
Compressor Seals,
>1.0
0.1 - 1.0
0.01 - .1
0.001 - 0
0.00001 -
>1.0
0.1 - 1.0
0.01 - .1
0.001 - 0
0.00001 -
23
48
24
.01 7
0.001 3
105
Compressor
0
14
22
.01 21
0.001 12
69
21.9
45.7
22.9
6.6
2.9
100%
Seals
0.0
20.3
31.9
30.4
17.4
100%
3.4
10.1
14.7
8.1
2.7
39.0%
Hydrocarbon Service
16.2
33.8
16.9
4.9
2.1
73.9 %
, Hydrogen Service
0.0
16.9
26.5
25.3
14.5
83.2
15.5333
3.9313
0.9121
0.05SO
0.0022
20.4419
= 142 Screened
67.9440
22.2482
1.3014
0.0224
0.0013
91.5172
= 83 Screened
0.0
3.3954
1.0105
0.0794
0.0064
4.4917
76.0
19.2
4.5
0.3
0.0
100%
74.3
24.3
1.4
0.0
0.0
100%
0.0
75.6
22.5
1.8
0.1
100%
         107

-------
O
00
                       30-
                       25-
                       20-
                    fi   I5
                        10-
                        5-
                             N-197
                                      Illlll  lll
                           to in i/> m u"> to
                           000000
i	J1L,	L,	I  J  •  i	1
I
                                               Midpoint of No rune thane Leak Rate (Ibs/hr)
                            Figure 5-2.  Distribution of Leak Rates for Valves - Light
                                         Liquid/Two-Phase Streams.

-------
          The frequency distributions of the screening values and the
 leak rates are similarly skewed.  This suggested a possible correlation
 between the leak rates and screening values for the various baggable sources.
 Such correlations were found to exist, and they are presented in the. form of
 nomographs In Section 5.1.3 of this report.

 5.1.2.2   Statistical Treatment of Baggable Source. Emission Data

          The high degree of skewness in the distribution of noimethane leak
 rates from baggable sources precluded a conventional statistical treatment
 of the data.   In addition to the skewness,  a large percentage of the studied
 sources were considered "non-leaking."  The efficient estimation of emission
 factors and their variances, as well as the inclusion of non-leaking sources,
 required the development and use of sophisticated statistical  procedures.

          A lognormal  distribution was used to mode]  the distribution of
 leaking sources.   This distribution has the property that when the original
 data ore transformed by taking natural logarithms,  the transformed data will
 follow a normal distribution.   The lognormal distribution is often appropriate
when the standard error of  an individual value is proportional  to the magni-
tude of the value.   The form of the .lognormal  distribution is  as follows:
          f(x)  =
                    ,     n x -
                 exp|	__
for 0 > x > °°
               = 0                                   for x < 0
          Mean = exp M + -~-

          Variance = exp[ 2y + 2o2]  -  exp  [2^ + o
                                   109

-------
          To  develop  estimates  for  emission factors,  the nonleaking sources
 (leak rate assumed  equal  to  zero) also  had  to be  modeled.   A mixed distribu-
 tion, specifically  a  lognormal  distribution with  a discrete probability mass
 at zero, was  used for  this purpose.   Letting p equal  the fraction of non-
 leaking sources  in  the  population,  this mixed-] ognormal  distribution bas
 the  following form:
                          cxp   -
          f(x) = - .......... -- ____  ----- ..........          for 0 < x <
                               ~
               = p                                    for  x = 0

               = 0                                    for  x < 0


                             f   
-------
where
          n = number of  sources screened

          r = number of  sources screened   200 ppm  or with
              measured leak <10~5  .lb/hr

          m = n - r
            = number of  "leaking"  sources

       g(t) = infinite scries
            =      (in - 1)E    (m -_l)_i_tl
                     m       ^72"!  (m +1)
              D33!  (m + l)(m + 3)   	

          x = average of logarithm of leaking sources

             n - r
                   £n (nonmethane leaks)/(n - r)
        s2 = variance of the logarithm of leaking sources

             n - r
                   [£n (nonmethane leaks) - x ] */(n - r - 1)
                r
              1

          The mean and variance formulas hold whenever there is more than
one leaking source (n - r > 1).  When only one leaking source is identified,
the following estimates are appropriate:
                 xi                xi2
          mean = — and variance =	,
                  n                  n
                                   111

-------
 where x  is  the  single, measured leak.   If no leaks are  found  (r = n) , then
 the best estimate for both the mean and variance is zero.

          Computer programs were developed for these estimators and the
 estimator for the mean was used for all emission factors developed  from the
 emissions data.

          Data  distributed lognormally can be transformed to a normal dis-
 tribution by taking natural logarithms of the data.  The distribution assump-
 tion for the leaking sources was tested by examining distributions of the
 log-leak rates.  Histograms displaying these distributions were constructed
 for all important source type and process stream classifications.  An example
 is shown in Figure 5-3.   The data for most sources appeared to adequately
 approximate a normal distribution after the transformation.

          To statistically test the assumption of a normal distribution for
 the log-leak rates,  skewness and kurtosis statistics were computed for each
 data group and tested for departures from their expected values of zero in
 a normal distribution.   Table 5-5 summarizes these statistics.

          Only three of the twelve cases indicate significant lack of
normality.

          The development and refinement of the statistical procedures arc
presented in greater detail in Appendix C (Volume 4).   The emission factors
developed with these procedures are presented in the following section 5.1.2.3
of this report.   Also presented in Section 5.1.2.3 are the effects of various
equipment and process variables on leak rates and emission factors.
                                    112

-------
FKE1QUENCT
50

30




20




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* ****
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            -11    -10      -s     -a      -7      -&      -s>      -<4     -A      -'
-------
              TABLE 5-5.  SKEWNESS AND KURTOS1S STATISTICS
 Source Type/                    Number of
 Stream Group	Leaking Sources	Skewnes s	Kurtosis
Valves
Gas/Vapor Streams
Light Liqulds/Tvo-Phase
Heavy Liquids
Hydrogen Streams
Open-ended Valves
Pump Seals 1
Light Liquids
Heavy Liquids
Compressor Seals 2
Hydrocarbon Service
Hydrocarbon Service
Flanges
Drains
Relief Valves

154
330
32
59
30

296
66

102
69
62
49
58

0.19
-0.16
0.28
-0.18
-0.01

0.03
-0.77*

-0.99*
-0.29
0.39
-0.04
-0.05

-0.33
-0.18
-0.88
-1.09*
-0.98

-0.36
0.06

1.16*
0.69
0.20
-0.47
-0.21
 *  probability  <.05 given a normal distribution.
1A11 data needed to classify  sources  into  stream  type were not available
 Tor all pump seals and  valves.   Those  particular  sources are not included
 in this analysis.

^Compressor seals screening < 200 ppmv  were not Included in this analysis.
                                   114

-------
 5.1.2.3    Emission  Factors  for  Baggable  Sources  in  Refineries

           The  estimated  emission  factors  for nonmethane  hydrocarbon  emissions
 for  the  six  types of  baggable sources  are summarized  in  Table  5-6.   Twelve
 emission factors are  presented  representing the  twelve categories of  source
 type and process stream  group.  Confidence intervals  are given in each  case
 for  the  estimated emission  factor.  The  confidence  interval  for  the  emission
 factors  represents  the range of values which is  expected with  95 percent con-
 fidence  to include  the average  emission  rate for all  sources of  the particular
 type in  all  U.  S. refineries.   The confidence  intervals  include  consideration
 of both  potential biases and random variation  as discussed in  Appendix  C
 (Volume  4).

          The  emission factors  listed  in  Table 5-6  are slightly different
 than those published  in  a previous report  (KPA 600/2-79-044),23 The results
 given here are  based  on  further refinements of the  data  base and the  forma-
 tion of  emission factors for valves in hydrogen  service  which  were previously
 incorporated in other valve service categories.

          The effect  of process variables on emission factors  was investi-
 gated.   Any  discussion of the effect of process variables is complicated
 by the confounding between variables in the data base.   This confounding is
due  to the lack of independence between process variables as they naturally
occur.   Tn addition,  all combinations of  levels of many  variables could :iot
be obtained  in the study.

          A  fractional factorial experimental design was followed in select-
ing  sources  for screening and possible sampling.   Selection was based on key
process variables.   The design allowed the estimation of the main effects of
important variables, but not all variable interaction effects eould be esti-
mated.  Most second order interactions (e.g.,  stream type by line size by
source type) and higher order interactions are either confounded or there
are not enough replicate data to quantify their effects with any precision.
                                   115

-------
       TABLE 5-6.   ESTIMATED VAPOR EMISSION FACTORS  FOR NONMETHAKE
                   HYDROCARBONS FROM BAGGABLE  SOURCES
     Source Category
   Emission
    Factor
   Estimate
(lb/hr/source)a
 957. Confidence
  Interval  for
Emission Factor
(lb/hr/source)b
Valves
   Gas-Vapor Streams
   Light Liquid/Two-Phase
   Heavy Liquid
   Hydrogen
    0.059
    0.024
    0.0005
    0.018
(0.030,  0.110)
(0.017,  0.036)
(0.0002, 0.0015)
(0.007,  0.045)
Open-Ended Lines
    0.005
(0.0016, 0.016)
Pump Seals
   Light Liquid Streams
   Heavy Liquid Streams
    0.25
    0.046
(0.16,   0.37)
(0.019,   0.11)
Drains
    0.070
(0.023,   0.20)
Flanges
    0.00056
(0.0002,  0.0025)
Relief Valves
    0.19
(0.070,   0.49)
Compressor Seals
Hydrocarbon Service
Hydrogen Service

1.4
0.11

(0.66,
(0.05,

2.9)
0.23)
 The  estimated  mean level of emissions from all sources of this type in
 United States refineries.  This factor is an average and incorporates the
 fact that a significant number of sources have no emissions while others
 have emissions ranging from 10~3 to 10 Ibs/hr.
 The statistical procedures used to construct those intervals account £or
 both systematic and random errors in experimental design, sampling, chemi-
 cal analysis, and statistical analysis.  The procedures used are such that
 at least 957o of the intervals will include the time emission factor for a
 particular source category.
                                    116

-------
This means that it is difficult to break sources down by more than two
variables at a time to determine emission factors or effects.

          Emission factors and confidence intervals were developed for
selected classifications of the baggable sources (such as seal types for
pumps).  The results are presented in Appendix B (Volume 3).  Leak rates in
any category span three or more orders of magnitude.  Because of this
phenomenon, it is impossible to precisely estimate the emission factors from
the relatively small number of sources that were screened and sampled.  The
confidence intervals for the emission factors of selected classifications
of sources are very wide, and overlap in most cases.  Thus, any apparent
differences between emission factors for the various categories of a source
may not be real.

5.1.3     Relationships Between Screening Values and Leak Rates

          The results of the baggable source screening and leak sampling
program were analyzed.   It was found that relationships exist between the
screening values  and the source leak rates.

          Appendix C (Volume 4) of this report contains detailed descriptions
of the statistical techniques and models developed to correlate the emissions
data.   Statistical analyses were performed to determine:

          (a)  The linear regression equations for each
               baggable source and stream type combination.

          (b)  The possibility of combining some of the
               equations found in (a) to reduce the total
               number of necessary equations.

          A linear equation of the form below was proposed.

                   o  L  = Bo + BX  loglo M                  (5-1)
                                   117

-------
where

               L      = nonmethane hydrocarbon leak rate, Ib/hr

               BO,BI  = constants, intercept and slope respectively.

               M      = maximum screening (or rescreening) value, ppmv.

          The regressions for each source type-process stream combination
are given in Table 5-7.

          Analyses of covariance were performed to determine which source
and process stream types could be combined for prediction purposes.   It
was found that the source and stream types cou]d he grouped such that seven
equations were adequate for predicting leak rates from screened sources.
The seven groups are as follows:

          •    Pumps in light liquid streams,  compressors and
               relief valves in gas/vapor streams.

          •    Valves and compressor seals in hydrogen service.

          •    Valves in gas/vapor streams.

          •    Valves in light llquid/two-phase streams.

          •    Flanges.

          •    Drains.

          •    Pump  seals  in heavy liquid streams.
                                   118

-------
         TABLE 5-7.   REGRESSION  OF LOG LEAK  RATE OK  LOG
                       MAXIMUM RESCREEN1NG VALUE BY SOURCE
                       AND  STREAM  TYPE
Process Stream
Gas/Vapor




Light Liquid/.
Two-Phase



Hydrogen




Heavy Liquid




Stream
Information
Hissing


Type3
Bo
SE(Bo)
Bl
SE(Bi)
R2
N
Bo
SE(Bo)
Bi
SE(Bi)
R2
N
Bo
SE(B
-------
          The resulting seven equations are summarized in Table 5-8.  Also
included in this table are the correlation coefficients and the confidence
intervals for the slope and intercept values.  The equations were used to
develop nomographs which relate the predicted leak rate to the screening
values for the various source and stream types.  These nomographs are shown
in Figures 5-4(A & B) through 5-10(A & B).   Each nomograph gives the pre-
dicted mean leak rate as a function of the maximum TLV Sniffer screening
readings taken directly at the source of the leak.

          Although the equations were developed on a logarithmic scale, the
nomographs are shown on an arithmetic scale for ease in reading and
interpolation.

          The 90 percent confidence intervals shown on the nomographs are
for the mean leak rate.   They should not be confused with confidence
intervals for individual leak rates for given screening values.  There is a
substantial difference between the two leak rates.  The differences are
illustrated in Table 5-9.   For example, the mean leak rate for a valve (gas/
vapor stream) with a screening value of 10,000 ppmv is predicted to be
0.038 "Ib/hr.   Any single valve with this screening value would be expected
to have a leak rate between 0.0019 and 0.75 Ib/hr 90 percent of the time.
On the other hand, a large number of valves with a screening value of 10,000
ppmv should have a mean leak rate falling between 0.025 and 0.057 Ib/hr.
There is an order-of-magnitude difference between the two types of confidence
intervals.   This difference can be seen clearly in Figure 5-11.

          The results of the baggable source screening and sampling can be
presented and displayed  in other useful ways.   Nomographs have been prepared
relating screening values to the percentage of each source type expected  to
have screening values above any selected value.   Other nomographs have been
prepared relating screening values to the percentage of total mass emissions
which can be expected from sources with screening values greater than any
given value.   A discussion of nomograph development is presented in
Appendix C (Volume 4).
                                    120

-------
                   TABLE  5-8.   CORRELATION  OF  SCREENING  (OR RSSCREENING)
                                VALUES WITH  LEAK RATES
Constants for Linear
Number Equation3 95 Percent Confidence Interval
of Coirir^lat Ion " " ' ' '
Source onrt Stream Typo Group Data Coefficient, Intercept, Slope, For
Pairs R Bo Bi Intercept
Pump Seals (Light I.iquld/Two Phase Streams), 259 0.68 - 4.4 0.83 (- 4.9, - 3.9)
Compressors (Gas/Vapor Streams) , and
Relief Valves (Gas/ Vapor)
Valves and Compressor Seals (Hydrogen 47 0.67 - 7.0 1,06 (- 8.5, - 5.5)
Streams)
Valves (Gas/Vapor Streams) 79 0.76 - 7.0 1.23 (- 8.1, - rj.9)
Valves (Light Liquid /Two-Phase Streams) 119 0.79 - 4.9 0.80 (- 5.3, - 4.5)
Drains 61 0.68 - 4.9 1.10 (- 5.8, - 4.0)
Flanges 52 0.77 - 5-2 0.88 (- 5.9, - 4.5)
Pump Seals (Heavy Liquid Streams) 61 0.75 - 5.1 1.04 (- 5.8, - 4.3)
For
Slope
(0.72, 0.94)


(0.72, 1.40)

(0.99, 1.4V)
(0.69, 0.91)
(0.80, 1.40)
(0.68, 1.08)
(0.80, 1.27)
io [leak rate (lb/hr)]  = B0 + BI Iog10 [Screening or Rescreening value, ppmv]

-------
    0.45  -
                                                      Upper Limit of 90X Confidence
                                                    / Interval  for Mean
                                                      Mean
                                                      Lower Limit of 90S Confidence
                                                      Interval  far Mean
                                   Log.., (NM Leak Raw) = -4.4 * 0.33 Log,, (Max Screening Value)
                                   Correlation Coefficient » 0.68
                                   Number of Data Pairs » 259
                                   Standard Error of Estimate = 0.76 Logs a  (NM Leak Rate)
                                   Scale Bias Correction Factor • 4.58
            J	I
                     1.1    I    I
           1,000
5,000
10,000
              Maximum  Screening Value  (pprav as Hexane)
          Using J.U. Bacharach TLV  Sniffer at the  Source.
Figure 5-4A.  Nomograph for Predicting Total Hydrocarbon Leak
                Rates  from Maximum Screening  Values - Pumps
                 (light  Liquids),  Compressors,  Relief Valves
                 (Gas/Vapor Streams)  (Part I:  Screening  values
                from 0  - 10,000 ppmv).
                                         122

-------
 0)
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c
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                                                      Upper Limit of 90S Confidence
                                                   /  Interval for Mean
                               /
                                                      Mean
                                                     Lower Lfmit of 90% Confidence
                                                     Interval  for Mean
                                           X
                                logio (HI Leak Rate) « -4.4 + 0.93 Logu (Max Screening Value)
                                Correlation Coefficient = 0.68
                                Nuraaer of Data Pairs « 359'
                                Standard Error of Estimate • 0.75 Logta (NM Leak Rate)
                                Scale Bias Correction Factor • 4.58
                         till
         10,000
          50,000
100,000
              Maximum Screening Value (ppmv as  Hexane)
          Using  J.H. Bacharach TLV Sniffer at the Source.
Figure  5-AB.
Nomograph for  Predicting Total Hydrocarbon Leak
Rates from Maximum  Screening  Values - Pumps
(Light Liquids), Compressors,  Relief Valves
(Gas/Vapor Streams)  (Part II:   Screening Values
from 0 -  100,000 ppm).
                                    123

-------
 10
 01
 o
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 1.
T3
 c
 iu
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o

TJ
                                         '  Upper Limit of 90S Confidence
                                       /  Interval for Mean
                                                       Mean
                                                       Lower Limit of 90S Confidence
                                                       Interval  for Mean
                                      Log!t  (NH Leak Rate) • -7.0 + 1.05 Log,,,  (Max Screening Value)
                                      Correlation Coefficient « 0.67
                                      NuTiber of Data Pairs - 47
                                      SUnoard Error of Estimate «= 0.98 Loglt (NM Leak Rate)
                                      Scale  Bias Correction Factor = 1C.67
           1.000
         5,000
10,000
               Maximum Screening Value  (ppmv as Hexane)
            Using J.W. Bacharach TLV  Sniffer at the Source.
   Figure  5-5A.
Nomograph for Predicting Total Nonniethane
Hydrocarbon Leak Rates  from Maximum Screening
Values  -  Valves and Compressors  in Hydrogen
Service  (Part I:   Screening Values from
0 -  10,000
                                     124

-------
    0.45
    0.40
    0.35
    0.30
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 S  0.25
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 « 0.20

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"S 0.15
*j
o
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   0.10
   0.05
Loglt (KM Leak Rate) - -7.0 + 1.06 Log)( (Max Screening Value)
Correlation Coefficient * 0.67
Nunber of Data Pairs » 47
Standard Error of Estimate = 0.98 Log.la (UN LeaV Rate)
Scale Bias Correction Factor - 10.67
                                                    / Upper Limit of 90* Confidence
                                                    '  Interval  for M.ean
                                                      Mean
                                   Lower Limit of BQ%  Confidence
                                   Interval for Mean
         10,000
          50.000
100,000
              Maximum Screening Value  (ppirv as Hexane)
          Using J.W. Bacharach TLV  Sni'fer at the Source.
  Figure  5-5B.
 Nomograph  for Predicting  Total  Nonmethane
 Hydrocarbon  Leak Rates from Maximum Screening
 Values  - Valves  and  Compressors in  Hydrogen
 Service (Part II:   Screening Values from
 0  - .100,000  ppm).
                                         125

-------
   0.07
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 2 o
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 o
 JQ
 t-
 Q
   .06
    .05
   ).04
£ 0.03
 01

 c
 D
 * o.oz
•o
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   0.01
                Log,, (KM Leak Rate) = -7.C + 1.23 Log]t  (Max Screening Value)
                Correlation Coefficient = 0.76
                Number of Data Pairs <= 0.79
                Standard Error ar Estim;te = 0.78 Logi5 (NM Leak Rats)
                Scale Bias Correction Factor « 4.81
                                                      Upper Limit of 90* Confidence
                                                    / Interval  for Mean
                                                       Mean
                                                     Lower Limit  of  90% Confidence
                                                     Interval  for Mean
          1,000
                           5,000
10,000
            Maximum Screening Value (ppnw as  Hexane)
         Using J.W. Bacharach TLV Sniffer et  the  Source.
Figure 5-6A.
                Nomograph for  Predicting Total Nonmethane
                Hydrocarbon Leak Rates  from Maximum  Screening
                Values -  Valves, Gas/Vapor  Streams  (Part I:
                Screening Values from 0 - 10,000  ppm).
                                         126

-------
0.95 -
                                               /
                                                 / Upper Limit of 90* Confidence
                                                 ' Tnr»pvji1  fnr Mf»£n
                                                   Mean
                                                /  Lower Unit  of 90? Confidence
                                                   Interval for Mean
                               Log, i (KM Uak. Rite) • -7.0 + 1.Z3 LOO.H (tax Screening Value)
                               CorrrUtlofl Cc*ff1c1ent • 0.76
                               NicAcr of Data Pairs * 0.79
                               Standard Error of Estimate » 0.78 Ljqi« (MM Leik Rite)
                               Scale 31al Correction factor • 4.B1
0.05 -
      10,000
     50.000
100,000
          Maximum Screening Value (ppmv as Hexane)
      Using J.W. Bacharach TLV Sniffer at the  Source.
  Figure  5-6B.
Nomograph for  Predicting Total Nonmethane
Hydrocarbon  Leak  Rates  from Maximum  Screening
Values -  Valves,  Gas/Vapor  Streams  (Part II:
Screening Values  from  0 - 100,000 ppm).
                                   127

-------
   0.07
- 0.06
 S  0.05
   0.04
01
e

5 0.03
ai
E
£ 0.02
  0.01
            Logic (NX Leak Rate) « -4.9 * 0.60 Logic (Max Screening Value)
            Correlation Coefficient • 0.79
            Number of Data Pairs = 119
            Standard Error of Estimate - 0.60 Logi, (NK Leak Rate)
            Scale Bias Correction Factor «2.53
                          Upper Limit of 9M Confidence
                          Interval  for Mean
                                                     Mean
                          Lower Llnrlt of 901 Confidence
                          Interval  for Mean
         1,000
5,000
10,000
           Maxlmua Screening Value  (ppwv as  Hexane)
        U$1ng J.W. Bachjrach TLV Sniffer at  the Source.
 Figure 5-7A.  Nomograph  for Predicting  Total  Nonmethane
                  Hydrocarbon Leak Rates from Maximum Screening
                  Values  - Valves,  Light Liquid/Two-Phase  Streams
                   (Part  I:   Screening  Values from 0  - 10,000  ppm).
                                         128

-------
C.45 -
                                                  Upper Limit of 90*  Confidence
                                               /  Interval  for Mean
                                                  Mean
                                                  Lower Limit of 90S  Confidence
                                                  Interval  for Mean
0.05  -
                           Logit (N« Leak Rate) = -4.9 + 0.80 Logn (Max Screening Value)  I
                           Correlation Coefficient « 0.79
                           Number of Data Pairs - US
                           Standard Error Of Estimate = 0.60 Logn (ffil Leak Rate)
                           Scale Bias Correction Factor «2.53
      10,000
50,000
                                             100.000
         Maximum Screening Value  (pprav as  Hexane)
       Iking J.U. Bacharach TLV Sniffer at  the Source.
 Figure  5-7B.   Nomograph for Predicting Total Nonmethane
                  Hydrocarbon  Leak  Rates  from Maximum  Screening
                  Values  - Valves,  Light  Liquid/Two-Phase  Streams
                  (Part  II:  Screening Values from 0 - 100,000 ppm),
                                 129

-------
     4.5
    4.0
    3.5
                            Upper  Limit of 90?
                            Confidence Interval

                            for  Mean
 ID
 a
    3.0
 C
 o
 o
 o

 t
 Q
-C
 VI
 E
01
+J
o

•O
 - D.fi6 Log,, (NM leak Rate)

                   Scale  Bia> Correction Factor • 6.53
                                                         Mean
                          Lower Lildt  of 90S

                          Confidence Interval

                          for Mean
          1,000
5,000
10,000
              Maximum Screening Value  (ppmv  as  Hexane)
          Using J.W. Bacharach TLV Sniffer at the Source.
         Figure 5-8.   Nomograph for Predicting  Total  Nonmcthane

                         Hydrocarbon  Leak  Rates from Maximum Screening

                         Values -  Drains.
                                            130

-------
     0.07
C.   0.06
     0.05
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0.04 -
5   0.03 •
*i   0.02 '
    o.oi •
             Logic (W- Leak Raw) • -5.Z * 0.88 Logn (Max Screening Value)
             Correlation Coefficient * 0.77
             Number of Data Pairs * 52
             Stsndard Error cf Estimate • 0.52 Logit (NX Leak Rate)
             Scale Bias Correction Factor = 2.02


                                                      Upper Limit of 93? Confidence
                                                    / Interval for Mean
       Mean
                                                           Lower Llm'.t of 90* Confidence
                                                           Interval for Mean
            1,000
                          5,000
i     I
  10,000
                Maximum Screening Value (ppnw as  Hexane)
            Using J.W. Bacharach TLV Sniffer at the Source.
      Figure 5-9.   Nomograph for Predicting  'i'ota.l Nomnethane
                       Hydrocarbon  Leak  Rates from  Maximum  Screening
                       Values -  Flanges.
                                       131

-------
     0.45  -
Upper Limit of 90S Confidence
Interval  for Hear
                                                       Mean
                                                       Lower Limit  of  90% Confidence
                                                       Interval  for Mean
                                    LOQie (NM Leak Rate) = -5.1 + 1.04 Log)0  (Mix Screening Value)
                                    Correlation Coefficient - Q.75
                                    Nunber of Data Pairs = 61
                                    Standird Error of Estimate • 0.59 Log,, (NM Leak Rate)
                                    Scale Bias Correction Factor * 2.44
                2,000     4,000     6.000     8,000    10,000

               Maximum Screening Value (ppmv as  Hexane)
            Using J.H.  Bacharach TLV Sniffer at the Source.
Figure 5-10A.   Nomograph  for  Predicting Total Nonmethane
                  Hydrocarbon Leak Rates  from Maximum Screening
                  Values - Pumps,  Heavy Liquid  Streams  (Part  I:
                  Screening  Values from 0  - 10,000 ppm).
                                         132

-------
  L.
  .£=
     7.5
     6.5
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     4.5
     3.5
     Z.5
     1.5
     0.5
                Logic (m Leak Rate) - -5.1  + 1.04 Log,., (Max Screening Value)
                Correlation Coefficient « 0.75
                Nimber of Date Pairs « 61
                Standard Error of Estimate = C.S9 Lagio (NK Leak Rate)
                Scale Bias Correction Factor « 2.44
                                                       Upper Limit of  9C? Confidence
                                                       Interval for Mean
                                     Mean
                                     Lower Limit of 90* Confidence
                                     Interval  for Mean
          10,000
          50,000
100,000
              Maximum Screening Value (ppmv  as Hexane)
          Using O.K.  Bacharach TLV Sniffer at the Source.
Figure 5-10B.
Nomograph for Predicting Total  Nonmethane
Hydrocarbon  Leak  Rates  from Maximum  Screening
Values -  Pumps, Heavy Liquid Streams  (Part II:
Screening Values  from 0 -  100,000 ppm).
                                      133

-------
          TABLE 5-9.   CONFIDENCE INTERVALS  FOR  MEAN AMD  INDIVIDUAL
                      LEAK RATES -  VALVES  (GAS/VAPOR  STREAMS)
 Value
 (ppmv)
Predicted
  Mean
Leak Rate
 (lb/hr)
                                        90% Confidence  Interval
    Mean Leak
     (lb/hr)
  Individual Leak
      (lb/hr)
      1
    200
    500
  1 000
  3,000
  5,000
 10,000
 20,000
 50,000
100,000
 4xlO~7
 0.00030
 0.00094
 0.0022
 0.0085
 0.016
 0.038
 0.089
 0.27
 0.64
(0.00010,
(0.00038,
(0.0010,
(0.0048,
(0.0097,
(0.025,
(0.063,
(0.19,
(0.43,
3.6x10 6)
0.00089)
0.00023)
0.0048)
0.015)
0.026)
0.057)
0.13)
0.39)
0.96)
(0.0,
(1.3x10
                                  -5
       — 5
(4.3x10'
(0.00010
(0.00042
(0.00080
(0.0019,
(0.0045,
(0.014,
(0.032,
  1.67x10
,  0.0071)
,  0.021)
  0.047)
  0.17)
  0.32)
  0.75)
  1.75)
  5.4)
 13.0)
                                                                            -5-
                                  134

-------
   3.5
   2.5
"  z.o
O
01

I  1.5
   1.0
   0.5
             Logit  (KM Leak Rate) - -4.9 * C.BC Logti (Max Screening Value)
             Correlation Coefficient » 0.79
             Number of Data Pairs • 119
             Standard Error of Estimate « 0.60 Logit (NM Leak Rate)
             Scale  Bias Correction Factor -2.53
                    Upper Limit of 901 Confidence
                    Interval for Mean Le*k Rate
                                                     Upper Limit of 90S  Confidence
                                                     Interval for Individual Values
                                                                Mean
                                              Lower Limit of 901
                                              Confidence Interval
                                              for Mean Leak Rate
                                                         Lower Limit of 901 Confidence
                                                         Interval for Individual Values
        10,000
      50,000
                                                100,000
  Figure  5-11.
homograph  for Predicting Tota.l Nonmethane
Hydrocarbon  Leak Rates  from Maximum  Screening
Values  - Valves, Light  Liquid/Two-Phase  Streams
(Part  II:   Screening Values  from 0 - 100,000  ppra),

-------
          These nomographs for the six source types  (and stream groups for
valves, compressors, and pump seals) are presented in Figures 5-12 (A & B)
through 5-22(A & B).  The "A" figures relate the percent of total mass emis-
sions  for a  given source category to screening values; the "B" figures relate
the percent  of sources to screening values.

          Confidence intervals are included on each of these nomographs.  The
statistical  procedures used to develop these intervals are 'discussed in
Appendix C (Volume 4).  The confidence intervals for both types of nomographs
indicate how well the cumulative function has been estimated from the data
collected in this program.

          The 95 percent confidence, intervals for the cumulative, percent of
sources can be interpreted as ranges of values which contain the actual
percent from the population of sources studied.

          The 90 percent confidence interval for the cumulative percent of
total emissions function has a similar interpretation.  These intervals
describe how well the function has been estimated for the entire population
and are not directly applicable to a particular refinery situation with a
finite number of sources.   The variation of the function for a particular
sample of sources is a complex function of the number of sources.   Because
of the nature of the function, however,  the confidence intervals wj 11 be.
approximately valid any time a random sample of  greater than 100 sources
is being considered.

          The nomographs are useful in evaluating the potential effectiveness
of maintaining and  repairing sources for reducing emissions.   For  example,
approximately five  percent of valves in gas vapor stream service can  be
expected to have screening values above 50,000 ppmv (Figure 5-12A).   However,
these five percent  of the  valves  are responsible for  an estimated  95  percent
of the mass emissions (Figure 5-12B).   Similarly, for a screening  value of
10,000 ppmv,  the percent of sources and  percent  of emissions  are nine per-
cent and 99 percent,  respectively.
                                    136

-------
  100

   90

   80

   70
V
E 60
                        Upper Limit of 951  Confidence Interval
                                      Estimated Percent of Sources
             Lower Limit gf 9SJ
             Confidence  Interval
  10 -
     1  2  345  10      50 100       1,000       10,000

                  Screening  Value (pptnv) (Logio  Scale)
100,000    1.000,000
   Percent of Sources - indicates the  percent of sources  with scree/ling
                      values greater than the selected  value.
   Figure 5-12A.   Cumulative  Distribution of  Sources and Total
                     Emissions by Screening Values for Valves -
                     Gas/Vapor Streams.
                                    137

-------
   100





    90






    30

Wl

O

«   70
i/>


LU


s   60





«   50
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o   40 [-


c
01

"   30  -
91
O.




    20  -





 •   10  -
                                     Estimated  Percent of

                                     Tot^l Mass  Emissions
                                                               Upper Limit of 90S

                                                               Confidence Interval
                                          Lower Limit of the

                                          901 Confidence Interval
        I  MI
                        i	I
                                                 j_
     1   2 345  10
                        50 100
1.000
10,000
100,000     1,000,000
                      Screening Value (ppav)  (Logio Scale)
  Percent of Total Mass Emissions - Indicates the percent of total emissions

                                 attributable to  sources with screening  values

                                 greater than the selected value.
Figure 5-12B.
                   Cumulative. Distribution  of Source  and  Total

                   Emissions  by  Screening Values for  Valves -

                   Gas/Vapor  Streams.
                                 138

-------
                          Upper Limit of 95% Confidence Interval
         Lower Limit  of 95%
         Confidence interval
                                    Estimated Percent of Sources
  1   2  345  10      50 100       1.000      10,000

               Screening Value  (ppmv)  (LogiQ Scale)
100,000    1,000,000
Percent of Sources -  indicates  the percent of sources with  screening
                   values greater than the selected value.
 Figure.  5-13A.   Cumulative  Distribution of  Source  and Total
                  Kmissions by Screening Values for  Valves -
                  Light  Liquid/Two-Phase Streams.
                                  139

-------
100


 90



 80


 70


 SO



 50



 40 -


 30 -


 20 -


 10  -
                                       Upper Limit of SOS
                                       Confldenct Interval
    Estimated Percent cif
    Total Mass Emissions
      I  11 i   i
              Lower Limit of the
              90* Confidence Interval
                                   j_
   1  2 345  10
 50 100
1,000
10,000
100,000    1,000,000
Screening Value  (ppov)
                                               Scale)
Percent of Total Mass Emissions -  Indicates  the percent of total  emissions
                               attributable to sources with screening values
                               greater than the selecttd value.
  Figure 5-13B.   Cumulative  Distribution of  Source and  Total
                    Emissions by Screening Values  for Valves -
                    Light  Liquid/Two-Phase Streams.
                                140

-------
  100

   90

   80


   70
a
2  60
3
o
«/>
S  50
V
S  40
a;
30


20 [-


10 -
                   Upper Limit of  95»  Confidence Interval
                           Estimated Percent of Sources
      'Upper Limit of
       Confidence Interval
      1  2 345  10      50 100       1,000       10.000     100,000    1,000,000

                   Screening  Value (ppmv) (Logi0  Scale)

    Percent of Sources - indicates the  percent of sources with screening
                      values greater than the selected value.
 Figure  5-14A.   Cumulative  Distribution of  Sources  and  Total
                   Emissions by Screening Values for Valves  -
                   Heavy  Liquid Streams.
                                    141

-------
                                          Upper Unit of 902
                                          Confidence Interval
a
*j
o
t.
o>
                                     \   \  \
            Lower Limit of the         \   \ \
            901 Confidence Interval      \  \  \
      1   2  34.5  10      50  100       1,000      10,000      100,000    1,000,000



                      Screening Value (ppav) (LogjQ Scale)



   Percent of Total Mass Emissions - indicates the percent of total emissions
                                 attributable to sources with  screening values
                                 greater than the selected value.
   Figure  5-14B.   Cumulative Distribution of  Source and Total

                     Emissions  by Screening Values  for Valves  -

                     Heavy Liquid Streams.
                                     142

-------
     100


      90



      80


      70
I*
at
w
i»
o
trt


*     50
C
u
I     40


      30 J-



      20 -


      10 -
                                 Upper Limit of 9SS Confidence Interval
                                              Estimated Percent of Sources
                                N       \
                                 \
            Lower linrit of the 95S   \
            Confidence Interval
         111   i
    1 2  345  10      50 100       1,000      10,000


                 Screwing Value (ppmv) (Logjo Scale)
                                                           100,000    1,000,000
Percent of Sources - indicates the percent of sources with screening
                   values greater than the selected value.
Figure 5-15A,   Cumulative  Distribution of  Sources and Total
                  Emissions  by Screening Values for Valves -
                  Hydrogen Service.
                                 143

-------
100


 90


 80


 70


 60


 50


 40


 30


 20


 10
Estimated Percent of
Total Mass Emissions
      I   HI
                                         Upper Limit of 90S
                                         Confidence Interval
            Lower Limit  of the 90*
            Confidence Interval
   1   2 345  10      50 100        1,000      10,000     100,000    1,000,000


                    Screening Value (ppov)  (Logjg Scale)


Percent of Total Mass Emissions - Indicates the percent of total emissions
                               attributable to  sources with screening values
                               greater than the selected value.
  Figure 5-15B.   Cumulative Distribution  of Source  and Total
                    Emissions  by  Screening Values  for  Valves  -
                    Hydrogen  Service.

-------
            Lower limit of the 95
            Confidence Interval
                           Upper Limit of 95J Confidence  Interval



                    \
                             \\\
                              °\\
                                         Estimated Percent of Sources
                                  ^\
10 -
   1  2  345  10      50 100        1,000      10,000

                Screening Value  (ppmv) (Log-jQ Scale)
100,000    1.000,000
 Percent of Sources -  indicates the percent of sources with screening
                    values greater than the selected value.
  Figure 5-16A.   Cumulative Distribution  of Sources  and Total
                    Emissions by  Screening Values  for Pump Seals
                    Light  Liquid  Streams.
                                    145  "

-------
 100


  90


  80


  70


  60


  50


  40


  30


  20 j-


  10 -
                                  uPPer Limit of 905
                                  Confidence Interval
    Estimated Percent of
    Total  Mass Emissions
       t 11 i   i
            Lower Limit of the
            .901 Confidence Interval
    1   2 345  10
50 100
1,000
10.000
100,000     1,000,000
                     Screening Value (ppcnv)  (Log-|Q Scale)
 Percent of Total Mass Emissions - Indicates the  percent of total emissions
                                attributable to  sources with screening values
                                greater than the selected value.
Figure 5-16B.   Cumulative Distribution  of Source  and Total
                  Emissions  by Screening Values  for  Pump  Seals
                  Light Liquid Streams.
                                146

-------
                Upp«r Limit  of  95%  Confidence Interval
                               S
                          N  \ \
       the 95% Confidence   \
       Interval                    \.  s.
                              Estimated Percent of Sources
    1  2 345 10      50 100       1,000      10.000     100,000    1,000,000

                 Screening Value (pprov)  (Log-|Q Scale)

  Percent of  Sources - indicates the percent of sources with screening
                    values greater than the selected value.
Figure 5-17A.   Cumulative Distribution of  Sources  and Total
                 Emissions by Screening Values for  Pump Seals -
                 Heavy  Liquids.

-------
s
(A
l/l
£
o
i.
a
a.
100


 90


 80


 70


 60


 50


 40 H


 30 -


 20 -


 10 -
Estimated Percent of
Total Mass Emissions
         i  111   i
                                               Upper Limit of 90S
                                               Confidence Interval
                      Lower Limit of the
                      90S Confidence Interval
                         i	i
                                                     \
                                                        \
                                                        \
      1   2 345  10      50  100        1.000      10,000      100.000


                       Screening Value (ppnv)  (LogjQ Scale)
                                                                  1.000,000
   Percent of Total Hass Emissions - Indicates the percent of total emissions
                                  attributable to  sources with  screening  values
                                  greater than the selected value.
 Figure  5-17B.    Cumulative  Distribution of  Source  and Total
                   Emissions by Screening Values  for  Pump  Seals
                   Heavy  Liquids.
                                       148

-------
 100


 90


 80



 70


 60


 50


 40


 30


 20
Upper Limit of 95S Confidence Interval


                 .Estimated Percent of Sources
 10 =	^	-
                                        Lower Limit of 95S Confidence Interval
                                        _•-.	i	i	i
    1   2  345  10      50 100   '    1.000      10,000      100,000    1,000,000


                 Screening  Value (ppmv)  {Logic Scale)

  Percent of Sources - Indicates the  percent of sources with  screening

                     values greater than the selected value.
Figure 5-18A.   Cumulative Distribution  of Sources  and Total
                  Emissions  by  Screening Values  for Flanges.
                                  149

-------
100


 90


 ac


 70


 60


 SO


 40


 30


 20


 10
         Estimated Percent of
         Total Mass Emissions
        i  11
                                                  Upper limit of 90S
                                                  Confidence Interval
                Lower Limit of the
                90% Confidence Interval
     \  2 345  10
                     SO 100
1,000
10,000
100,000     1,000,000
                      Screening Value  (ppov) (Logic Scale)
  Percent of Total Mass Emissions - Indicates the percent of total  emissions
                                 attributable to sources with screening values
                                 greater  than the selected value.
Figure 5-18B.   Cumulative Distribution  of  Source and  Total
                  Emissions by  Screening  Values for Flanges.
                                     150

-------
  100



   90




   ao




   70


M

2  60
a
o
\n

•S  50
u

-------
100


 90


 80


 70


 60


 SO


 40


 30


 20 -


 10 -
                                     Upper Limit of 902
                          \\ s     Confidence Interval

                            ^
Estimated Percent of
Total Mass Emissions
      i  i r i   i
                     j	i
                                        \ \  \
                  Lower Limit of  the       \ \ \
                  90X  Confidence  Interval    .  \ \
      2 345  10
   50  100
1,000
10,000      100,000     1,000,000
                   Screening  Value (ppav)  (Log-|0 Scale)

Percent of Total Mass Emissions - Indicates the percent of total  e«1ss1ons
                               attributable to sources with screening values
                               greater than the selected value.
 Figure 5-19R.   Cumulative  Distribution of  Source and Total
                   Emissions by Screening Values  for Compressor
                   Seals  - Hydrocarbon  Service.
                                 152

-------
01

-------
O
u
Ol
O.
100


 90


 80


 70


 60


 50


 40


 30


 20


 10 h
                                    Estlmated Percent of
                                    Total Mass  Emissions
         t  MI
                                                                  Upper Utnlt of 901
                                                                  Confidence Interval
                                    Lower Limit of the
                                    90% Confidence Interval
      1   2 345  10      50  100        1,000      10,000      100,000     1,000,000


                      Screening  Value (ppov)  (LogjQ Scale)


   Percent of Total Mass Emissions - Indicates the percent  of total  emissions
                                  attributable to sources with screening values
                                  greater than the selected value.
      Figure  5-2OB.   Cumulative Distribution  of Source  and  Total
                        Emissions by  Screening Values  for  Compressor
                        Seals -  Hydrogen Service.
                                       154

-------
01
u
100



 90



 60



 70



 60



 50



 40



 30



 20



 10



 0
      — -,    Upper Limit of  95J Confidence Interval
                                 Estimated Percent  of Sources
     1  2  345  10      50 100       1,000      10,000      100.000    1,000,000



                   Screening  Value (ppmv)  (LDgjg Scale)


   Percent of Sources - Indicates the percent of sources with  screening

                      values greater than the  selected value.
  Figure 5-21A.   Cumulative  Distribution of  Sources and  Total

                    Emissions by Screening Values for Drains,
                                   155

-------
100


 90


 80


 70


 60


 50


 40


 30 h


 20


 10 h
         Percent of
Total Mass Emissions
      i 1 LJ   i
                                       Upper Limit of 90S
                                       Confidence Interval
        Lower Limit of the
        90S Confidence Interval
   1   2 345  10
      50 100
1,000
10,000
100,000     1,000,000
                    Screening Value  (poov) (Log10 Scale)
Percent of Total Mass Emissions - indicates the percent of total  emissions
                               attributable to sources with screening values
                               greater than the selected value.
 Figure  5-21B.   Cumulative  Distribution  of Source  and Total
                    Emissions by Screening Values  for  Drains.
                                 156

-------
100


 90


 80


 70


 60


 50


 40


 30


 20


 10 H


 0
             Upper Limit of 95S Confidence Interval
                                 Estimated  Percent of Sources
    -   Lower Limit  of 955
        Confidence Interval
\
       t  111   i
                     _l	_L
                                              > ^.
    1   2  345  10     50 100       1,000       10.000      100,000    1,000,000

                 Screening  Value (pptnv) (Logjo  Scale)

  Percent of Sources - Indicates the percent of sources with  screening
                     values greater than the selected value.
Figure 5-22A.   Cumulative Distribution of Sources and Total
                  Emissions  by Screening Values  for Relief
                  Valves.
                                   157

-------
100


 90


 80


 70


 60


 50


 40


 30


 20


 10
                                            Upper L1ra1t of 90J
                                            Confidence Interval
Estimated Percent of
Total Mass Emissions
      i  in   i
                      I	I
                   90! Confidence Interval     y  \  \
   1   2 34B  10      50 100
                       1,000       10,000      100,000    1,000,000
                    Screening Value  (ppav)  (Logio Scale)
Percent of Total Mass E«1ss1ons - Indicates the percent of total emissions
                               attributable to sources with  screening values
                               greater than the selected value.
 Figure  5-22B.   Cumulative Distribution of  Source and  Total
                   Emissions by  Screening Values for Relief
                   Valves.
                                    158

-------
          Analyses, using the nomographs, can also be done for other
sources and process streams.  For example, Table 5-10 shows the percent of
emissions for various sources and process streams when the upper 10 percent
of screened sources arc considered.  Confidence intervals are also shown.
Table 5-10 is presented only to illustrate the use of the nomographs and to
emphasize the fact that a small fraction of the sources within any one source
category account for the majority of emissions in that category.  There is
no intent here to prejudge that a reasonable level  of control is 10 percent
of sources, or any other specific number.  Ultimately, the decision regarding
reasonable control will be based on relative levels of emission reduction
and the cost of achieving these levels.  Therefore, percentage reduction
goals for each source category may be different.
5.1.4     C°_rJLe 1 at ion of Leak Rates with Process and Equipment
          Variables
          The relationships of various continuous process variables and
other discrete variables with leak rates were investigated.  The variables
which were considered in this investigation are listed in Table 5-11.  The
results of the study are summarized in the discussion below.  A more detailed
discussion is given in Appendix B (Volume 3) of this report.

          (Correlation of Leak Rate with Continuous Variables^—The correlation
studies were complicated by three factors:

          (a)  The degree of skewness in the leak rate data and the
               inherent variability of the measured leak rates.

          (b)  The dominating effect of process stream composition
               on the leak rate.

          (c)  Inaccuracies or missing values when determining the
               values of variables.
                                    159

-------
              TABLE  5-10.  PERCENT OP TOTAL MASS EMISSIONS RELEASED BY THE UPPER
                          TEN PERCENT OF SCREENED SOURCES
Minimum
Screening Value
(ppmv)
Valves
Gas/Vapor
Light Liquid/Two-Phase
Heavy Liquid
Hydrogen Service
Pump Seals
Light Liquid
Heavy Liquid
Compressor Seals
Hydrocarbon Service.
Hydrogen Service
Flanges
Drains
Relief Valves

9
11

9

47
1

68
76

1
4

,200
,000
120
,400

,000
,100

,000
,000
14
,100
,700
95% Confidence
Interval for
• Percent of Source

(6,
(7,
(3,
(3,

(7,
(5,

(4,
(3,
(6,
(4,
(3,

13)
13)
15)
16)

13)
15)

15)
17)
14)
16)
17)
Percent of Total Emissions
s Mean

99
85
80
83

75
81

59
77
99
94
83
90% Confidence
Interval

(98,
(82,
(74,
(70,

(71,
(76,

(46,
(64,
(98,
(92,
(78,

100)
87)
87)
91)

79)
86)

72)
87)
100)
96)
90)
The upper ten percent of screened sources is defined as the ten percent of  sources  having  the
highest screening values.

-------
        TABLE 5-11.  CONTINUOUS AND DISCRETE VARIABLES CONSIDERED
                     IN THIS STUDY
     Variable
             Source Types  Considered
Continuous:
  Temperature

  Pressure
  Age

  Size
  Speed
  Capacity

  Load

  Stroke Length
All Source Types

Valves, Flanges, Pump Seals, Compressor
Seals, Relief Valves

All Source Types

All Source Types

Punp Seals, Compressor Seals
Pump Seals, Compressor Seals

Compressors

Pump Seals, Compressor Seals
Discrete:
  Manufacturer

  Sea]. Type, Number

  Pump Type
  Valve Type
  Valve Service

  Stem Movement

  Vibration

  Location on Line (In-line,
    End-of-llne)

  In/Out of Service
  Lubricant
  Attitude
  Materials of Construction

  Gland Type
Valves, Flanges, Pump Seals, Compressor
Seals, Relief Valves
Pump Seals, Compressor Seals

Pump Seals

Valves
Valves
Valves

Valves, Flanges


Valves

Valves, Pump Seals, Compressor Seals
Pump Seals, Compressor Seals
Pump Seals
Valves, Flanges, Pump Seals, Compressor
Seals, Relief Valves
Pump Seals, Compressor Seals
                                    161

-------
          The logarithm  (base 10) of the leak rate (Ib/hr) was related to
the variables to reduce the effect of skewness and variability of leak rate
data.  The data were grouped by the important process stream classifications
to minimize the effect of the stream composition.  Table 5-12 contains the
simple correlation coefficients between the log leak rate and the appropriate
Independent variable for each source type and stream classification.  The
simple correlation coefficient, r, is a statistical measure of the linear
relationship between two variables.  Values of  r  fall between - 1 and + 1.
Values of  r  near + ] mean that one variable increases proportionally to the
other.  Negative values of  r  indicate that one variable decreases as the
other increases.  The value of  r  will be zero if the data are randomly
scattered.

          The value of r2 indicates the approximate percentage of the total
variation in the log leak rate that is accounted for by the relationship of
the leak rate with the correlating variable.  For instance if r = 0.50,
then r2 = 0.25 and about 25 percent of the variation In the leak rate is
attributable to the relationship with the process variable.  The remaining
75 percent of the variation is due to other variables and random variation.

          The statistically significant correlation coefficients are indicated
with an asterisk in Table. 5-12.   A clearer indication of the significance of
the correlations can be seen from a scatter plot of the data.  Scatter plots
for all correlations are given in Appendix B (Volume 3).

          Relationships Between Discrete Variables and Leak Rates—Unlike
continuous variables,  correlation coefficients are not easily interpreted
for discrete variabJ.es, i.e.,  manufacturer,  material, and seal type versus
leak rate.  A visual method for comparing the relationships between levels
of the discrete variables and  leak rates is the schematic plot.   Schematic
plots show the mean,  median, upper/lower quartile and range of leak rate
values.   Schematic plots are contained in Appendix B (Volume 3).   The results
can be briefly summarized.
                                    162

-------
           TABLE 5-12.   CORRELATIONS5 BETWEEN CONTINUOUS VARIABLES  AND  LOG10 LEAK RATE

Valvee
lias/Vapor Streams
Light Liquid Streams
Heavy Liquid Streams
Hydrogen Service
Open-Ended
Pimp Seal g
Light Liquid Service
Heavy Llqold Service
Flanges
Ccmpreesor Seals
O1* Hydrocarbon Service
UJ
Hydrogen Service
Ornlns
Relief Valven
Treasure

.230*
.1U3*
-.351*
-.08B
.23ft

..088
.097
.072

.346*
.398*
-
.045
Temperature

.077
.051
.144
.129
.242

-.012
-.098
.021

.218*
.112*
-.408*
.096
Line .Stroke
Af>e Slip THmneter Area RPM Capacity Load Length

.263* .150* ______
.096 .1'.3* - - - . -
.220 .046 ______
-.531* .288* _-__-_
.230 -.078 ______

.OM - .021 - --.064 -
.237 - .128 - -.1B2 -
-.1BO .336* __-__-

.105 - -27»* - -.141° -.118 -.007 -.012
.052 - .343* - -.034 .21B -.099 -.071
-.039 -.191 - - ' -
_.075 ______
*  Correlation Coefficient statistically different from zero  (P > .90).

  Log it RPM vas correlated with logH  leak rate.

  Values ahown in table are correlation coefficients,  r.   The correlation between
  X and Y is  computed as
                'XY
                             - X)
 -  7)

,"- TV
  and is bounded
                 - 1 <
                          <  1

-------
          When sample size is taken into consideration, there appears to
be no significant correlation of valve leak rates with any of the discrete
variables.  For pumps in heavy liquid service, a small difference can be
seen between single and double seals.  However, the small sample size pre-
vents any firm conclusions from being drawn regarding this difference.

          Effect of Process Variables on Percent of Sources Leaking—Previous
analyses have shown that the percent of leaking sources varies with the
source type and process stream volatility.  The effect of other process
variables on the percent of leaking sources was examined.  The results  of
this examination are presented in detail in Appendix B (Volume 3).

          Some significant differences in percent leaking were noted for
valves due to age and unit type and vibration.  Valves less than one year
old have a higher percent leaking for gas/vapor and light liquid streams,
but not for heavy streams.  The percentage of leaking valves increases  with
increasing line size.   No significant differences were noted for the
different valve manufacturers.

          For pump seals in light liquid service,  the percent of seals
leaking appeared to increase as the pressure and temperature increased.   No
significant differences were noted for the discrete variables, including
manufacturer.   Single seals had a higher percent leaking than double seals
for both light  and heavy liquid streams, although the confidence intervals
did overlap.

          For compressors in hydrocarbon service,  significant differences
in the percent of seals leaking were noted for gland type and seal  type.
The percent leaking also appeared to be increasing as discharge pressure
increased.
                                    164

-------
 5.1.5     Effect of Maintenance Procedures on Valve Emissions

          A study to define the short term effect of maintenance on valve
 emissions was conducted.  The study was performed on 86 valves at four
 refineries.  Routine maintenance, such as tightening the packing gland or
 adding grease, was performed on the selected valves.  Maintenance is
 described as "directed" or "undirected."  Directed maintenance involved
 simultaneous maintenance and screening of the valve until no further reduc-
 tion in hydrocarbon detector reading could be achieved.  Undirected mainte-
 nance was not monitored with a hydrocarbon detector during the performance
 of maintenance.

          The screening value and emission rate for each valve was determined
 before and after maintenance.   The percentage reduction in leak rates after
 maintenance was calculated with the following equation:

 -,    ,   .      Leak Rate Before Maintenance - Leak Rate After Maintenance
 % Reduction = 		;	—	—-	,—;—	
                             Leak Rate Before Maintenance

          The. effects of the valve maintenance studies are summarized in
 Table 5-13.   Two results are noteworthy.   The percentage leak reduction for
 those valves that were subjected to directed maintenance is considerably
 greater than that of the. valves that had  undirected maintenance.   It is also
 apparent that  the level of the initial leak rate has a marked effect on the
 percentage reduction in emission rate for both directed and undirected
maintenance.   The percentage reduction achieved by maintenance is lower for
 the initially  small  leak rates.   In the very low initial leak range, ^0.001
pounds per hour,  the average and weight percent reduction was actually nega-
 tive for undirected  maintenance.

          A statistical summary of the maintenance results is presented in
Table 5-14.   For directed maintenance, the median  percent reduction is
approximately  constant  across  the screening value  range.   However,  for the
undirected maintenance  group the median percent reduction increases
                                    165

-------
               TABLE  5-13.   SUMMARY OF MAINTENANCE REDUCTION BY LEAK RATE LEVEL
Original Leak Rate
Level Range (Ib/hr)
1 <;0.001 n
P"
pw
pm
2 0.001 - 0.01 n
_
pw
pm
3 0.01-0.1 n
F
pw
pm
4 >f).l n
P
pw
pra
n = Number of valves maintained


„ . ,„ , . ^leakage before
r\\j =z WOT ant" n o f r* 
-------
            TABLE  5-14.    STATISTICAL  SUMMARY OF  MAINTENANCE  DATA - PERCENT  REDUCTION
Scteunlng
                     Block Valves
                                                         Directed Maintenance
                                                                  Control Vaivea ..
Range
(ppmv)

<5K.


iK-SOK


>50K

C/V
Scream
2 SB. 8
56.5
5R.fi
2 76.1
90.7
76.1
3 93.8
97.8
98.0
LL
Streaa
5 63.1
90.5
93.1
It 89.8
B». 0
90.1
2 -26.4
36.7
-26.4
HL
Strenn
0


0


0





Total*
Block
7 61.8
80.5
87.3
6 85.2
89.1
BB.7
5 45.7
92.3
91. 1







C/V
Strenn
0


1 45.7
45.7
45.7
1 77.2
77.2
77,2
IX
Stream
4 39,5
84,9
89.8
1 95.0
95.0
95.0
2 97.2
96,4
97.2
HL
Seres*
0


0


0


18 64.2 (32.96)
91.0 (B2.99)
86.2 (75.97)
Total All
Control Vulvco
4 39.5
84.9
89.8
2 70.4
91.5
70.4
3 90.5
95.0
94.5







11 53.74
85.6
88.4
8 81.5
89.2
88. 7
8 62.5
92.6
93.1
9 66.8 (12,100)
89.7 (79,99)
91.1 (9.3.98)
(3.7,100)
(72.99)
(10,98)
(65,98)
(69,100)
(-55.96)
(7.9,100)
(81,100)
(-3J.99)







27 A4.fi (18,91)
90.7 (83,98)
91.2 (79.95)
•numbers  In parentlieaes Indicate an approximate <9*iZ confidence Interval (or the  average reduction for the three different estimations.
                                                                                                                          (ContlnuuTiJ
  Code  for
  Kach  Cell
  In Table
1 ~ Number of valvefl nalntalned
                               .              .        1UO x (leak before - leak alter maintenance)
2 •= Average of percent reduction wher« percent reduction	ESa'k bc7o~re  maintenance	
                               3 - Weight percent reduction -

                               4 " Median percent reduction
                             £ teak rate bgf ore »a in t en aneg - Eieak rate ^ftcr «aintctiancb
                                          I leak r/ite  before maintenance

-------
                                                        TABLE 5-14.   Continued
                                                                 Undirected Maintenance
00
Screening
Value
Range
(ppmv)

<5K


5K-50K


>SOK

Bluck Valve*
r,/v
Scrcao
6 S4.0
52.2
6b.2
4 69.8
47. £
82.6
1 75.3
88.4
84.3
LL
Struua
6 42.6
SB. 9
76.9
4 -64.9
- 9.0
28. 2
4 81 .3
93.0
90.9
111.
Serena
4 -26.1
-43.4
7.37
0


0





Total*
Block
16 29.7
48.5
33.1
8 2.4
20.2
50.1
7 78.7
91.1
85.4







Control Valvee
C/V
StrcaB
7 -1320
- 717
-5H.4
2 54.2
53.8
54.2
8 29.4
61.3
19.3
LL
Stroau
5 5.2
91.1
26.56
4 87. 8
96.9
95.6
1 90.6
90.6
90.6
III
Stieaii
0


1 82.1
82.1
82.1
0


31 31.7 (-1.8.69)
68.7 (48,89)
61.1 (31,85)
Total*
Total All
CoaLcul Valvufl
12 - 769
-50.5
24.1
7 77.4
90.2
82.1
9 36.2
87.0
29.5







28 -112
33.0
VS. 9
15 37.4
67.4
82.1
16 54.8
89.6
67.0
2B 298 (-940,100)
HI. 0 (64,98)
51.4 (13,85)
(-950,100)
(-39.100)
(-0.5,79)
(-28.100)
(34,100)
C.2,Ub)
(31, /8)
(81.98)
(21,92)







59 -124 (-410,100)
71. » (69, 88)
5J.R (29,82)
*NuLih<*ra In |
Code for
Each Cell
iu Table
ATcuthc-Hcc Indicate
1 2
3
4

2
3
an approxiBi
• Average of

ite y>X confidence
interval for the av«i*ge
percent reduction where porctmt reduction
Eleak rate before aalnecn



lleak rate
percent
100 x
reduction for the three different eutLmationa.
(leak before - leak after oalnteuance)
Leak before
once - Elcak rate after
before
nalntenance
maintenance
B19-1J!?9.IM?L1CI! » JQO


                                     4 u Median percent reduction

-------
 dramatically with  increasing  screening values.  Within  the  low screening
 value  range the median percent  reduction  is very  low, only  28.9 percent.
 This may  indicate  that undirected maintenance  at  this screening level is not
 effective at all.

 5.1.6     Number and Distribution or Saggable  Sources

          The analyses of the emission rate data  showed that the emission
 rates  of  hydrocarbons from valves, pump seals, and compressor seals were
 functions of the process stream properties.  To estimate total hydrocarbon
 emissions from these sources  in a complete refinery or  in individual process
 units  within refineries, the distribution and number of the sources in the
 various types of process stream services must be  available.

          As part  of the refinery assessment program, individual fugitive
 emission  sources were physically counted in a number of process units within
 five different refineries.   Valves, flanges, pumps, compressors, drains, and
 relief valves (only those venting directly to the atmosphere) were counted.
 The counted sources are listed  in Table 5-15.   The capacities of each unit
 in which  sources were counted arc also presented.

          Some sources are not  included in this tabulation.  Only those
 valves in hydrocarbon service on process,  vent, or fuel  lines were counted.
Valves in auxiliary services such as steam, air, compressor lubrication,
 pump seal flushing, and sight glass shut-off were not included in the source
numbers listed in Table 5-15.

          Pumps and compressors operating on non-hydrocarbon streams such as
water and air were not counted.   Only those relief valves  that were venting
directly to the atmosphere were Included as emission sources.   Those relief
valves venting into blowdown and flare systems were not  included in the
numbers given in Table 5-15.   All drains in a  unit were  counted.
                                    169

-------
                  TABLE 5-15.  SUMMARY OF HYDROCARBON EMISSION SOURCES COUNTED
                               IN SELECTED REFINERY PROCESS UNITS
Unit
Procenu Unit BI'i'D
• AiMiaiihurlc Diminution) Mult A 50,000
Unit B 10,000
Kni: 1 Cua/I.Jglit Guo I'roccaulngl Unit A
Unit B —
Cultilytlc llyjf ojULjceBiilngi Unit A 16,000-
Unlt 1 10,000
VlulJ Cutdlyllc Cracking! Ulllt * 9,000
llyJiucjacklugl Unit A 14,000
Catalytic llafotMlngi Unit A 11,000
'--J Unit 1 5,000
O
Unit C 1,000
AlkylatlQiu Unit A 6,04)0
Unit B 2,000
IliilJ Coklmjl Unit A 7,000
U^uunliig/Treat IIIK 1 Unit A C4,OOQ
Unit B "4,000
Unit C "
-------
          All the sources were counted only within the battery limits of
 each process unit.

          The visual source counts were used as a basis for estimating the
 total source populations in some of the major types of refinery process units.
 These estimated source populations are presented in Table 5-16.  Sources were
 not counted in some types of process units including vacuum distillation,
 aromatics extraction, delayed cokir.g, hydrodealkylation, and sulfur recovery
 units.  The number of sources in these units were, estimated from source
 counts obtained in other types of units.

          An estimate of the number of valves, pump seals, and compressor
 seals in various process stream services is required to develop total hydro-
 carbon emission rates from refinery process units.   These source distribu-
 tions were determined for pumps and compressors during the field sampling
program in refineries.   Stream service distributions were not established
 for valves,  however.  Thus,  the valve distributions were estimated by
 indirect means.   The method is described in Appendix B (Volume 3).

          The estimated distribution of pump seals  and valves in selected
refinery process units  is given in Table 5-17.

5.2       Nonbaggable Source Measurements and Results

          The nonbaggable sources that were sampled included cooling towers,
API separators,  corrugated plate interceptors, and  dissolved air flotation
units.   Other potential nonbaggable emission activities such as spills,
turnarounds,  blind changing, coking operations,  and air blowing were not
sampled.   The emission  potentials of some of these  activities were  evaluated
by  surveys.   The results are summarized in Section  6 of this report.
                                    171

-------
              TABLE  5-16.
ESTIMATED NUMBER OF INDIVIDUAL EMISSION SOURCES2
IN 15  SPECIFIC REFINERY PROCESS UNITS
                                     Estimated Number of Sources Within Battery Limits of Process
                                                                Units
Process Unit
Atmospheric Distillation
Vacuum Distillation1
Fuel Gas/Light Ends Processing
Catalytic Hydroprocessing
Catalytic Cracking
Hydrocrar.klng
Catalytic Reforming
AromaticB Extraction
Alkylation
Delayed Coking1
Fluid Coking
Hydroealkylation*
Treat ing /Dewaxing
Hydrogen Production
Sulfur Recovery1
Valves
890
500
180
650
1310
930
690
600
680
300
300
690
600
180
200
Flanges
3540
2000
760
2600
5200
3760
2760
2400
2280
1240
1240
3760
2290
640
800
Pumps3
31
16
3
10
30
22
14
181
11
91
9
141
18
5
61
Compressors'*
1
o1
2
3
3
3
3
O1
0
O1
4
31
1
3.
O1
Drains
69
35
11
24
65
58
49
41
41
28
28
58
44
17
20
Relief
Valves
6
6
6
6
6
6
6
6
6
6
6
6
6
4
4
Sources were not counted in process  units of this type.   The number of sources was  estimated.
Only those sources in hydrocarbon (or  organic compound)  service.
Number of  pump seals - 1.4 x number  of pumps.
Number of  compressor seals - 2.0 x number of compressors.

-------
                    TABLE 5-17.
AVERAGE NUMBER AND ESTIMATED DISTRIBUTION OF VALVE
AND PUMP SEALS IN REFINERY PROCESS UNITS
Puap Service
Distribution




Atmospheric Distillation
Vscuuas Distillation
Fuel Ca«/Llght End* Processing
Catalytic llydroproceselng
Catalytic Cracking
Hydrocracklng
Catalytic Reforming
ArumaCicB Extraction
Alkylatlon
Delayed Coking
Fluid Coking
Hydrodcalkylatlon
Deuaxlng/Trcaclng
Hydrogen Production
Sulfur Recovery

Average
No. of
Valvea
U93
SOU1
181
645
1314
911
691
600'
571
3U01
304
7(10 l
399
182
2001

Average
No. of
Pumps
31
16'
3
10
30
22
H
18'
11
91
9
14'
18
5
6'

Average
No. of
Compressors
1
o1
2
3
3
3
3
0'
0
0'
4
3'
1
3
O1

Valve
To Pump
Ratio
29
34
60
65
44
42
49
33
52
33
34
50
33
36
33
Light
Liquid
Service,
%
35
10
83
67
44
55
9O
0.90"
100
21'
21
90'
39
60
84'
Heavy
Liquid
Service,
X
65
90
17
33
56
45
10
0.101
0
79'
79
ID1
61
40
16l
Eattaated
Valves.


Gas
Service
90
55*
88
335
384
250
260
60'
230
30'
30
2661
60
27
90'
Distribution of Estimated Distribution of
, Number/Unit Pump Seals, Number/Unit

Light
Liquid
Service
281
50'
77
2C8
409
375
388
486'
341
57'
58
3911
210
93
901

Heavy
Liquid
Servica
522
945*
16
102
521
306
43
54'
0
213'
216
43'
329
62
20'

Light
Liquid
Service
15
2'
4
9
IB
17
18
15'
15
•3'
3
IS'
11
5
8

Heavy
Liquid
Service
28
l
19
0
5
24
14
2
21
0
10'
10
21
18
3
2

Total
Pump
Si-ale
43
2l'
4
14
42
31
23
17'
15
Ul
13
20'
29
0
10
Sourca counts were not made In tht field. These values are estlaated.

-------
 5.2.1      Coo ling Tower Ernisjjions^leas^irenie n t_s_

           Hydrocarbon emissions from cooling towers were determined  from
 hydrocarbon material balances around each tower.  The hydrocarbon  content of
 the incoming and outgoing water streams were determined by a total organic
 carbon  (TOG) analysis a.nd/or by a volatile organic purging procedure.  Both
 of these methods are described in Section 4 of this report.  A more  detailed
 description of the sampling and analytical techniques are included in
 Appendix A (Volume 2).  Calculation methods and complete measurement data
 are contained in Appendix B (Volume 3).

          Thirty-one cooling towers were sampled.  Eight of these had statis-
 tically significant emissions.  The estimated  emissions from the individual
 cooling towers are presented in Table 5-18.  Streams from five towers were
 analyzed by both TOC and purge analyses.  Thus, streams from a total of 21
 towers were analyzed by TOC and streams from 15 towers were analyzed with
 the purging technique.  An analysis of the results from both these analytical
methods indicated that the purging technique was more accurate and precise
 than the TOC analysis.  Where both analytical techniques were used,  the
 results with the purging technique were chosen for calculation purposes.

          The results of the cooling tower sampling program are presented
 in Table 5-19.   Because the purge method of analysis was found to be the
more precise method,  an emission factor of 0.00011 lb/1000 gallons of
circulating cooling water was developed using only the purge method results
 from the fifteen towers.   A 95 percent confidence interval for this  factor
ranges from negligible to 0.0004 lb/1000 gallons.

5.2.2      Wastcwater Systems

          APT separators,  corrugated plate interceptors, and dissolved air
flotation (DAI'1)  units were sampled to determine atmospheric emissions of
hydrocarbon.   The emissions were estimated from a hydrocarbon material
                                    174

-------
       TABLE  5-18.   ESTIMATED EMISSIONS FOR INDIVIDUAL TOWERS
Tower
Nmber
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
26
27
28
29
30
31
Analysts
Method
Purge
Purge
TOC
Purge
TOC
TOC
TOC
TOC
TOC
TOC
TOC
Purge
TOC
TOC
TOC
Purge
Purge
TOC
TOC
Purge
TOC
TOC
Purge
TOC
Purge
TOC
Purge
TOC
TOC
Purge
Purge
Purge
Purge
Purge
TOC
TOC
Average
A PPM
0.002
0.018
0.35
0.061
2.14
1.25
-1.17
1.61
0.61
0.38
-5.03
-0.008
10.09
0.29
3.94
0.015
0.034
-0.14
0.83
0.013
-0.03
2.22
0.131
1.45
0.019
1.46
-0.155
-0.30
3.45
-0.025
0.016
0.006
0.011
0.024
-2.09
-0.24
Standard
Deviation
0.020
0.015
2.49
0.139
1.63
1.53
1.82
2.12
1.46
3.69
7.53
0.046
10.49
2.19
1.63
0.035
0.016
1.37
1.57

0.72
3.79
0.090
0.70

2.68
0.324
1.26
4.96
0.045
0.037



3.05
1.64
Student
t Test
0.24
2.00
0.24
0.87
2.63**
1.82**
-1.43
1.86**
1.03
0.23
-1.16
-0.35
2.35**
0.32
4.83**
0.34
4.36**
-0.20
1.19

-0.10
1.17
2.92**
3.61**

1.09
-0.96
-1.42
1.20
-0.94
0.88



-1.67
-0.36
Circulation
(GPM)
1,000
5,000
58,000
58,000
5,250
5,000
5,500
5,900
6,900
9,000
1,800
1,800
714
6,200
3,597
2,350
21,150
25,000
6,700

3,900
48,000
48,000
3,500

5,000
5,000
10,000
15,000
15,000
29,600



8,570
8,300
Slowdown
(GPM)


155.0
155.0
28.5
10.0
15.7
12.3
24.8

30.0
30.0
1.4
23.3
9.7



14.3

15.4
131.7
131.7


50.0
50.0
16.9
106.7
106.7




17.1
106.0
Emissions
(Ib/hr)




6.47±4.44
3.73*3.27

5.56±5.24




4.30+3.20

8.46±3.15

0.36*0.18





3-14±2.32
3.03±1.56












**Statistically significant
                                 175

-------
                                TABLE 5-19.  SUMMARY OF COOLING TOWER EMISSIONS
o\
               Cooling Towers Sampled
               Cooling Towers Having Statistically Significant Emissions
               Range of Cooling Tower Circulation Rates
                                                                         31
                                                                         8
                                                                         714 to 58,000 GPM
                                                  Results (estimate with 95% confidence interval)
       Mean Cooling Tower A HC Concentration
            From Emitting Towers
                 Both Analyses
                                 0.101 t 0.19 ppm
     From All Towers Sampled
          TOC Analysis
          Purge Analysis
          Both Analyses3

Mean Cooling Tower Emissions
     From Emitting Towers
          Both Analysis

     From All Towers Sampled
          TOC Analysis
          Purge Analysis
          Both Analyses
                                        1.25 ± 1.24 ppm
                                        0.01.30 ± 0.0299 ppm
                                        0.0173 ± 0.058 ppm
                                        0.00088 t 0.0016 lb/1000 gal
                                        0.0124 + 0.0123 lb/1000 gal
                                        0.000108 ± 0.00025 lb/1000 gal
                                        0.000151 ± 0.00051 lb/1000 gal
(negligible,  0.29 ppm)
(0.01,  2.5 ppm)
(negligible,  0.043 ppm)
(negligible,  0.075 ppm)
(negligible, 0.0025 lb/1000 gal)
(0.0001, 0.025 lb/1000 gal)
(negligible, 0.00036 lb/1000 gal)
(negligible, 0.00066 lb/1000 gal)
       Range of Measurable Emissions    0.36 to 8.46 Ib/hr
        Calculated for 15 towers analyzed by TOC only plus 16 towers analyzed by purge.  The 5 towers
        analyzed by both methods were represented only by the purge values, considered more accurate
        than TOC values.

-------
balance around each unit.  The methods used to determine the hydrocarbon
content of the oil and water streams are described in Section 4 of this
report.  The methods arc described in greater detail in Appendix A (Volume 2)

          The results of the sampling program are presented in Table 5-20.
There is a great deal of scatter and uncertainty in the data and results,
particularly in the determination of emissions from the oil phase of the
oil-water separators.  Negative value.s are even indicated for some emissions.
The one conclusion that can be made regarding these results is that the
material balance approach, as implemented in this program, is inadequate for
defining emission rates from oil-water separators.  The composition of the
incoming stream varies widely, and grab samples are not generally representa-
tive.  For this reason, emission factors for oil-water separators were not
developed from experimental results.

          Emission measurements for dissolved air flotation (DAF) units were
obtained from four different units using a material balance on the water
phase only.  The oily froth was not considered in the material balance.
Emissions from the four water-phase units averap3ed 0.05 lb/1000 gallons of
wastewater.  The 95 percent confidence interval about the average value was
from negligible to 0.24 lb/1000 gallons of wastewater.   The DAF data were
insufficient, to allow the development of an emission factor which can be
used with confidence.

5. 3       Stack Emissions^

          The results of sampling FCCU regenerator stacks,  heater stacks,
sulfur recovery/tail gas treating unit stacks,  and other miscellaneous stacks
are summarized in the sections below.
                                   177

-------
                          TABLE 5-20.   DESCRIPTION OF SAMPLED DEVICES - WASTE OIL/WATER  SYSTEMS
CO
Average Hydrocarbon Emissions
Refinery
1
2
3
4
5
6
7
8
Device
R Rectangular API Separator
Circular DAF
Rectangular API Separator
Corrugated Plate Interceptor
Corrugated Plate Interceptor
Rectangular API Separator
Forebay Covered
Surge Tank
Two Rectangular Separators
Rectangular DAF
Rectangular API Separator
Rectangular API Separator
Rectangular DAF
Circular Separator
Circular DAF
Covered/Uncovered
C
U
C
C
C
U
U
U
U
U
II
U
U
U
Losses from
Oil Phase,
Ib/gal slop oil
1.6 j- 2
1.84 + 1.11
-1.5 + 0.08
-0.11 + 0.06
0.12 + 1.3
0.45
-1.1 + 0.74
0.14 ± 0.4
0.48 ± 0.61
LOBBCE from
Water Fltasft,
IL/gal water
2.7x10"" -r 1.8x10*"
8.2x10 s + 1.5xlO~"
-3.01xlO~* + Ixio"5
—
2.2x10"" ± 2. 7x10" "
1.6xlO'5 + 3xlO~6
-2.4x10 5 + 2.7x10 5
1.5x10"" j- 2.4xlO~"
6.5x10"" + 1.9xlO~"
1.1x10"" + 1.3x10 "
3.4x10"" + 1.8x10""
1.4x10 5 + 1.7xlO"s

-------
 5.3.1     FCCU Regenerator Stack Measurements

          A total of seven stacks from five different FCCU's were sampled
 for criteria pollutants and individual organic species.  The results of
 the sampling are presented in Tables 5-21 through 5-23.  The FCCU regenerator
 stacks included in Table 5-21 were all equipped with electrostatic preclpita-
 tors and CO boilers.  Stacks No. 13 and 18 were from separate CO boilers on
 the same FCCU.

          The results shown in Table 5-22 were obtained from an FCCU whose
 flue gases passed through a CO boiler and then through a scrubber.  Two
 scrubber units each handled approximately one-half of the fine gas.  Both
 particulates and S0_ were removed in the scrubbers.
                   X

          In only one case were samples obtained upstream of the CO boiler
and/or ESP.   The results are shown in Table 5-23.   Only grab samples could be
be taken upstream of the control devices.  The CO boiler was effective, in
removing the organic species such as aldehydes and HCN.

          In Table 5-24, the FCCU regenerator emissions are expressed as
functions of the fresh feed rate to the FCC units.  Although data are limited
on the effectiveness of the scrubbers,  they appeared to be somewhat more
effective than electrostatic precipitators in reducing particulate emissions.
The level of SO  in the flue gases was  quite low in the two FCCU scrubber
               s{
stacks.

5.3.2     Crude Unit Process Heater Stack Measurements

          Process heater stacks from five crude oil distillation units were
sampled.   The results are summarized in Tables 5-25 and 5-26.   Detailed data
are given in Appendix B (Volume 3).
                                    179

-------
              TABLE 5-21.   RESULTS  OF SAMPLING  FLUE GASES FROM FCCU REGENERATORS EQUIPPED
                             WITH ELECTROSTATIC PRECIPITATORS  AND CO  BOILERS
CO Boller
Stack No. 11
S peel us
Aldnhydfs
(ns Formal dr.hydc)
Methane Hydrocarbons
Nonmethaae Hydrocarbons
(as 'Jexane)
i'articulates
SO,
SO,
H.:S
M COS
C»
0 rs,
NOX (ns N02)
HCN
Nib
pprnv "
0.0 (••,(>

0.602
16.1

(U.184)C
96.8
8.30
ud
rroft

mi
u
0.80
0.87
th/scf
5.12x10"'

2.49x10""
3.57xlO~f>

2.63xlO~'
1.60x.lO~s
1 .72x10"°
U
ND

MO
U
5.58x10""
3.81xlO~8
CO Boiler
Stack No. 14
ppm ^
10.0

2.Vi
9.51

U
625
7.27
ND
Nl)

U
184.9
1.03
0.73
Ib/scf
/. 76x10"'

9.75xlO~"
Z.llxlO"6

U
1.03x10"''
1.50xlO~(
NO
HD

U
Z.20,10-5
7.19xlO~"
3.19xlO~'
CO BoJler
Stack No. 16
ppmv ^
6.70

o.n
2.6J

(0.0154)'
13.4
1.15
<0.10
0.067

<0.06/
415.3
0.204
<4.25
Ib/ncf
5.19x10"'

0.0
5.79xlO"7

: 2.20xlO~6
2.22xlC"6
2.37x10""'
< 8. 7 9xlO~'
1.03x10""'

<1. 31x10" "
4.938xlO"s
1.42xlO~"
< 1.8 7x10"'
CO Boiler
Slack Ho. 13 a
ppmv "B
7.30

KD
3.80

(0.0426)c
406.6
1.14
0.58
KD

0.40
257.7
0.012
0.2H>

5.

NO
8.

6.
6.
7.
5.
Ib/sr.f
66x10"''


44xlO~7

09xlO~6
725x10" s
35x1 0~ '
12xlO~s
ND

7.
3.
8.
1.

86x10 "
064x10"^
37xlO~I(1
48xlO~8
CO
Slack
ppmv ^
5.54

KD
1.91

(0.0493jr
327.3
1.81
ND
ND

1.33
225.0
0.005
ND
Bollc-r
No. 18a
Jb/scf
4.:50xl()"7

NH
4.24xlO~7

7.04xlO~''
5.4l4xlO-s
3.91x10"'
ND
Nl)

2.6lAlO~7
2.675x10" s
3. 49x1 O"'"
NT)
Total Gas Flow Rate,
SCFM
                           2.70x10*
1.26x10"
8.97xlOG
                                                                                   9.15x10
acn  hollors  in same FCC unit..
 lily basis.
'"Given as f,raiiiR/SCF.
 U =• UrideLerinined.
eNll  = Not detected.

-------
                         TABLE 5-22.  RESULTS OF SAMPLING FLUE GASES FROM FCCU REGENERATORS
                                      EQUIPPED WITH CO BOILERS AND SCRUBBERS
oo
FCCU CO Boiler
Scrubber-Stack No. 12a
Species
Aldehydes (as Formaldehyde)
Methane Hydrocarbons
Nonme thane Hydrocarbons (as Hexane)
Particulates
S02
S03
H2S
COS
CS2
NOX (as N02)
HCN
NH3
Total Gas Flow Rate, SCFM
ppmv ^
46.3
89.4
28.3
(U.019)C
5.13
0.16
ud
U
U
41.1
U
U
9
Ib/SCF
3.59xlO~6
3.70xlO~G
6.28xlO~6
2.71xlO~6
8.49xlO~7
3.31xlO~a
U
U
U
4.89xlO~6
U
U
.08xl06
FCCU CO Boiler
Scrubber-Stack No. 17a
ppmv b
36.1
14.3
12.7
(0.024)°
12.5
0.35
U
U
U
180.8
U
U
8.
Ib/SCF
2.80xlO~6
5.92xlO~7
2.83xlO~6
3.43xlO~6
2.07xlO~6
7.24xlO~8
U
U
u
2.15xlO~b
U
U
53xl06
         Both scrubbers located on same unit.

         Dry basis.
        f\
         Given as grains/SCF.

         U = Undetermined.

-------
                       TABLE 5-23.   RESULTS  OF SAMPLING FCCU REGENERATOR FLUE GAS UPSTREAM
                                    AND DOWNSTREAM OF CO BOILER/ESPa
CO
NJ
Species Concentration
Upstream of CO
Boiler and ESP
Species
Aldehydes (as Formaldehyde)
Methane Hydrocarbons
Nonmethane Hydrocarbons (as Hexane)
Particulates
SO 2
SO 3
H2S
COS
CS2
NOX (as NO 2)
HCN
NH3
Total Gas Flow Rate, SCFM
ppmv a
208
Uc
U
U
332.5
U
U
U
U
41.5
109.5
3.99

Ib/SCF
1.61xlO~ 5
U
U
U
5.50xlO~5
U
U
U
U
4.93xlO~G
7.64xlO~6
1.75xlO~7
U
Species Concentration
Downstream of CO
Boiler (Stack No. 15)
ppmv a
17.2
U
U
(0.0686)d
677
0.954
U
U
U
100
19.1
11.0
6.
Ib/SCF
1.33xlO~
U
U
9.80x10"
1.12xlO~
1.97x10"
U
U
U
1.19xlO~
1.33xlO~
4.83x10"
53xl06

6


6
'i
7



5
6
7

          Flue  gas from FCCU regenerator passed through an ESP and into  the CO boiler;  samples  were  obtained
          prior  to the ESP and from  the CO boiler stack.
          Dry basis.
          "U = Undetermined.
          Given  as grains/SCF.

-------
                            TABLE 5-24.  CONTROLLED EMISSION RATES FROM FLUID CATALYTIC
                                         CRACKING UNIT (7CCU) STACKS
00
Control Devlcua lit Uue During TraLlng
Spectea
Aldcltydca (as Formaldehyde)
Mctliane
Nonrcethane Hydrocarbons (ao llcaano)
P«« clculate Mutter
SO,
so,
II. S
COS
cs,
NO (is ,'in,)
MCN
Nil,
TOTAL Cat Plow, SCFM
CO Seller, CO Boiler, ESP,b ESP, ESP,
ScruU.tr ScruLber CO Uoller CO Holler CO Boiler


Stack .£tack Stuck , Stack Stick
Na. U* ito. 17* No. 15 Mo. 11 Ha, 13°
13 S J < 1 3
11 2 < 1 0
2tt 9 — 5 S
9 10 33 36 34
3 6 381 22 378
0.1 0.2 0.7 2.3 1.3
0.3
— — — o o
0 0,4
16 65 «L -- 173
4.5 0.1 0.005
1.7 0.1 0.07
9.08x10* a.53»10* 6.53«10' J.70«ID' 9.15x10*
*Aimro»l«ata ezlaelon rates. Stacks Ho. 12 and 17 were located en ttie Sana unit. The feed rate Co
LcCwecn Che two stacks for the purpose of calculating emission ratfrQ.
E5i' • elect roat AC Ic prec Ipitntor ,
CApi> re, trout e eiulnaion ralui. KCCll liaJ cuu CO bollcra, Scacka Ho. 13 and No. 18. Tlx faad rata to
between ttie two hollers for the ptirpoee ot calculating eelaaiunt ralea.
ESP, ESP, ESf,
CO Boiler CO Boiler CO Colter
Freih Feed
Stack Stack Stick
No. lac Ho. 14 No. 16
J < 1 5
0 < 1 0
1 1 )
37 ~ 10
186 46 10
2.1 0.7 2.1
0 0 < 0.1
0 0 0.09
1.4 -- < U.I
141 10 441
0.002 0,03 0.13
0 0.01 < 1.7
B.58x 10* 1.26x 10* 8.97 » 10*
tlio FCCU was equally divided
the FCCU wai equally divided

-------
                                     TABLE 5-25.   RESULTS  OF SAMPLING FLUE  CASES FROM
                                                    CRUDE UNIT PROCESS HEATERS
00

Species
Aldehydes
(as Formaldehyde)
Methane Hydrocarbons
Nonmethano Hydrocarbons
(as Hexane)
FartlcuJ.ates
SO?
SOi

HjS
COS
cs,
NOX (a;; NO?.)
HCN
Nit)
Total Gas Flow Rate,
SCFM
Stack No. 2
ppmv*1 Ib/SCF
6.6? 5.13xlO~7

O.U 0.0
0.77 T./2xlO"7

(0.04?)h 5.94x10"°
2.15 3.56xlO"7
(I.I.I3 1. 25x10" 7

U I!
U U
U U
U U
0.021  5.40xlO~r' (0.064)b 9.07xlO~f> llc
1.06 1.75xlO~7 295.5 4.89xlO~s 95
O.i_r> 3.02x10"* 0.72 1.49xlO~7 21

U U U U U
U U U I) U
U U U I! U
U U U U U
<0.001 <6.98xlO"n U U 0.
<0.30 <1.32y_LO"8 U U 1.
2.34xlOf 7.03xlOr'

Stack No. 5
nva Ib/SCF
11 R.TlxUr"

67 1.14xlO"7
26 1.39x10"°

U
.7 1.58xlO~s
.2 4.38x10"*

U
U
U
U
85 5.93xJO~"
23 5.40x10"'
2.78x10''

Stack
ppfnv3
8.9.3

0.45
1.80

U
0.18
U
d
ND
ND
ND
92.9
U
U
U

Mo. 6
Ib/SCF
6.92x\0~7

1.86x10"'
3. 99x1 0"7

U
?.98xlO~R
U

ND
ND
ND
1 . 1 0x1 0~ '•
U
U


          Dry hnm's.

          Given as grains/SCF.

         CU = Undetermined.
          NP = Not detected.

-------
                                 TABLE  5-26.   COMPOSITION OF REFINERY  HEATER STACK GAS
QO
Ul

Species

Aldehydes (as Formaldehyde)
Methane Hydrocarbons
Norjnethane Hydrocarbons (as Hexane)
Partlculate Matter
SO,
S03
II, S
COS
csa
N0x (as NO,}
HCN
HH,
TOTAL Ga9 Flow Rate, SCFM
Stack Gag Composition, Parts per million by Volune(ppmv)a
Stack Stack Stack Stack Stack
No. 2 No. 3 No. 4 No. 5 No. 6
6.6 6.8 0.05 0.1 8.9
0.0 0.0 0.5 2.7 0.5
0.8 0.9 1.1 6.3 1.6
(0.042)b (0.038) (0.064) Ue U
2.2 1.1 296 96 0.2
0.6 0.2 0.72 21 U
Ud Ud U U NDC
U U U U ND
U U U U ND
U U U U 93
< 0.021 < 0.001 U 0.9 U
< 0.030 < 0.3 U 1.2 U
3.26x10' 2.34x10' 7.03 x 10* 2.78x10* U

L)ry basis

"J • undetermined

                          ND • not detected
                                                                reported

-------
          The process heaters were fired with mixed refinery fuel gas-fuel
oil.  No external emission controls were in use during any of the sampling
activities.

5.3.3     Emissions From Tail Gas Treating Units

          The stack gases from the tail gas treating processes of two sulfur
recovery units were, sampled and analyzed.  The compositions of these gases
are given in Table 5-27.  The accuracy of the hydrocarbon and SO  analyses
of the gas from Stack No. 7 is uncertain.  The concentration of hydrocarbons
in the gas is very high.  At the same time alnost no S02 was found.   No
satisfactory explanation of these results has been put forward.

5.3.4     Miscellaneous Source Emissions

          Several miscellaneous source, stacks were sampled.  The results are
summarized in Table 5-28.  The flue gas from a fluid coker was sampled up-
stream and downstream of the control devices, a scrubber and a CO boiler.
The effectiveness of the controls can be seen in Table 5-28.  The table also
contains data on a resin fume oxidation unit, a TCC regenerator and  FCCU
compressor engine (internal combustion) exhausts.

5.4       Identification of Emitted Species

          The. characterization and measurement of organic emissions  from
controlled and uncontrolled sources were conducted at several petroleum
refineries.  The controlled sources from which samples were taken and analyzed
include FCCU CO boiler stacks,  TCC CO boiler stacks,  fluid coker CO  boiler
stack and a fume oxidation unit.

          Uncontrolled sources included valves,  flanges,  pump seals,  com-
pressor seals, and drains.   Fugitive vapor emission samples and corresponding
liquid samples were obtained in many cases.   Vapor samples were obtained from
leaking valves and pump seals.   Corresponding liquid  samples were obtained
                                    186

-------
          TABLE 5-27.  COMPOSITION OF STACK GAS FROM SULFUR
                       RECOVERY TAIL GAS TREATING UNITS
Species
Aldehydes (as Formaldehyde)
Methane Hydrocarbons
Nonmethane Hydrocarbons (as Hexane)
SO,
S0a
H2S
COS
CS,
N0x (as N02)
HCN
NH3
TOTAL Gas Flow, SCFM
I3ry Basis
b
Species Concn.
Stack
No. 7
ub
5870
2080
0.2
U
U
6-4
9.0
15.0
U
U
U


in Flue Gas, ppmv
Stack
No. 8
4.0
0.8
5.7
460
0.7
x
0.5
1.9
16.7
< 0.001
< 0.03
(2.02x 103)C


     undetermined

Provided  by  plant personnel

 ND - not  detected
                                  187

-------
                         TABLE  5-28.   MISCELLANEOUS STACK EMISSIONS

Froet.a Unit: flM Coklng

Ga. Stre..: *"^*>"
Inlet
Control Devlcaa In Uae- During Teala: Sciubtur, CO
Caa
Coapoal t Ion,
Ib per 1000
tpeclea bbl f««d
Alditiydte (•• Formaldehyde) 3.2
Methane Kydrocarbona 433
Honaethini Hydrocarbon* (aa llexane) 135
rartlculate Hattar 437
OT SO, NDC
00
50, ND
fl,S ND
COS ND
CS. ND
HO^ (» NO,) 7.1
HCH 36.9
Nil. 39.3
TOTAL Caa Mow Rate. SCFM 1.77«10*

Unit

CO Boiler
Out lit
Butler
Imleaion
Rate,
Ib per IOOD
bbl lead
1.3
3.7
12.7
133
267
1.4
ND
ND
ND
159
1.2
0.2
2.44 « 10'
Rtieln Fume
Oxidation
Unit

Flue
—

Cna
Conposlt lont
>4
1.5
2.3
(0.0063)b
ia
0.4
MDC
KD
KO
V*
U
u
3.09» 10*
TC.CU
TCC Unit Cowpie^Ror
60 g
Flue E»haiiat
Caa mva
2.3 U
0.0 4.0
0.2 72
IS (O.U42)'
121 0.50
O.J 0.61
U U
U U
U U
43 U
ND 3.1
0.3 1.4
3.10K 10" 0,35 » 10*
Dry b»la
                                     ND - not d.t.ct.d
Cxpr«aa«4 ••
                                     U - und«t«i»Incd

-------
 from liquid .process streams  at  locations  as  near  as  possible  to  the vapor
 sample point.   Both the  liquid  and  vapor  samples  were  analyzed.  Details of
 the sampling  and analyses  procedures  are  described in  detail  in  Appendix A
 (Volume 2).   They are summarized  in Section  4  of  this  report.

           The collection and  analysis of  vapor samples is  time consuming.
 The collection and analysis  of  liquid samples  is  much  simpler.   Laboratory
 experiments were conducted to determine the  relationship between fugitive
 vapor composition and the  corresponding process liquid  composition.  These
 experiments indicated that the  composition of  fugitive emissions from
 refinery equipment is identical to  the composition of  the  liquid within the
 leaking source.   (See Appendix  B, Volume  3.)   As  a result  of  these experi-
 ments,  liquid stream  samples  were preferentially  analyzed, wherever possible,
 instead of the corresponding  vapor  samples.

           The. analyses were done by GC-MS.   The analytical emphasis was
 placed  on the Identification  and quantisation  of  aromatic  and polynuclear
 aromatic compounds.   The detailed results of these analyses are  presented
 in  Appendix B (Volume 3).  For  brevity, the  results  are only  summarized here.

5.4.1     Species Present in  FCCU  Regenerator Flue Gas

           Particulate matter  in the flue  gas was  collected by cyclones in a
 Source  Assessment  Sampling System (SASS)  train.   Fine  particulates were
 collected on  a filter downstream of the cyclones.  The  sampled gas also
 passed  through a cannister packed with adsorbent  to  collect volatile organic
 compounds.  The  organic  material present  on  or in the  particulate matter was
 extracted and  subjected  to GC-MS analysis.   The organic material on the
 adsorbent  was  similarly  analyzed.

           Individual  species  found and identified in particulate matter
 and/or  adsorbed  material are  listed in Table 5-29.  A  total of seven particu-
 late  and  seven adsorbed  vapor samples  were analyzed.   Those species other
                                    189

-------
                TABLE 5-29.  ORGANIC SPECIES FOUND IN FCCU
                             FLUE GAS SAMPLES3.b
            Organic Compounds0 Present at Concentrations >0.1 ppb
                       Anthracene/phenanthrene
                       Methylanthracene/phenanthrene
                       Naphthalene
                       Methylnaphthalenes
                       C ?. -naphthalenes
                       Benzole acid
                       Biphenyl
                       Cresol
                       Cyclohexane dlol
                       Cyclohexanol
                       Cyclohexanone
                       Cyclohexene oxide
                       Methylcyclohexanone
                       Benzaldehyde
                       Acenaphthene
                       Acenaphthylene
                       Benz(a)anthracene/chryscne
                       Cz-alkylphenols
                       Ca-alkylphenols
                       Dibenzofuran
                       Fluorcne
                       Fluoranthene
                       Indanol
                       Methylphenols
                       Nonylphenol
                       Octylphenol
 Species found in particulatc matter and/or vapor samples.
 Cjj-Cai alkanes detected but not listed.
CA11 samples were taken downstream of CO  boilers and ESP or scrubber.
                                    190

-------
than alkanes which were found in any of the samples at concentrations
above 0.1 ppb are listed.  Alkanes were present, but they are not listed.

          Particulate samples from two FCCU were subjected to an elemental
analysis.  The results are shown in Tables 5-30 and 5-31.
5.4.2     Identification of Organic Compounds in Fugitive Vapor
          Samples
          Some .samples of hydrocarbon vapors from leaking valves and pump
seals were collected in canisters packed with adsorbent.  However, laboratory
experiments indicated that the composition of liquid streams inside a leaking
source was the same as that of the emitted vapor.  The analysis of liquid
samples was less time-consuming and more economical.  Thus, most of the
sampled material is liquid from process lines.

          The sampled stream types are listed in Table 5-32.  The organic
compounds which were detected in the vapor samples or which were found in
concentrations above 10 ppm in liquid samples are listed in Table 5-33.
5.4.3     Potentially Hazardous Organic Species in Sampled Refinery
          Streams
          The results of the detailed analyses of vapor and liquid  samples
taken from refinery process streams and emission points are summarized  in
this section.  Only those organic species which are. potentially the most
hazardous of those which might be present in refinery streams are considered.
These species and their concentration ranges which were found in process
streams are presented in Tables 5-34 and 5-36.  The stream identification.
numbers and descriptions are given in Table 5-35.
                                    191

-------
                 TABLE 5-30.   ELEMENTAL ANALYSIS OF FCCU CO BOILER
                              FLUE GAS PARTTCULATES (STACK A)
Element
Uran i um
Thorium
Bismuth b
Lead
Thallium
Mercury
Gold
Platinum
Ir idlum
Osmium
Rhenium
Tungsten
Tantalum
Hafnium

Lutetium
Ytterbium
Thul i.um
Erbium
Ho 1m i.um
Dysprosium
Cone .
5
6
—
54
—
—
—
—
—
—
—
5
<1
3

1
5
0.9
22
24
230
Element
Terbium
Gadolinium
Europium
Samarium
Neodymium
Praseodymium
Cerium
Lanthanum
Barium
Cesium
Iodine
Tellurium
Antimony
Tin

Indium
Cadmium
Silver
Palladium
Rhodium

Cone.
29
150
14
490
MCC
MC
MC
MC
790
0.2
—
—
0.9
5
e
STD
<0.5
o.s
—
—

Element
Ruthenium
Molybdenum
Niobium
Zirconium
Yttrium
Strontium
Rubidium
Bromine
Selenium
Arsenic
Germanium
Gallium
Zinc
Copper

Nickel
Cobalt
Iron
Manganese
Chromium

Cone .

66
15
48
240
120
<0.5
<3
36
4
<0.7
10
260
40

300
50
MC
300
840

"Element
Vanadium
Titanium
Scandium
Calcium
Potassium
Chlorine
Sulfur
Phosphorus
Silicon
Aluminum
Magnesium
Sodium
Fluorine
Oxygen

Nitrogen
Carbon
Boron
Beryllium
Lithium
Hydrogen
Cone.
150
MC
17
MC
MC
22
MC
MC
MC
MC
MC
MCC
MC
NRc1

NR
NR
69
1
280
NR
Concentration i.n ppra by weight.
.Concentrations < 0.2 ppmw were not listed.
"MC - major component(70.1%)
 NR - not rspur Led.
 ST!) - analytical method

-------
               TABLE 5-31.  ELEMENTAL ANALYSIS OF FCCU CO BOILER
                            FLUE GAS PARTICULATES (STACK C)
a
Element Cone .
Uranium
Thorium
Bismuth
Lead
Thallium
Mercury
Gold
Platinum
Iridium
Osmium
Rhenium
Tungsten
Tantalum
Hafnium
Lutecium
Ytterbium
Thulium
Erbium
Holmium
Dysprosium
, Concentration
It
5
19
—
29
—
NR
—
—
—
—
—
2
1
4
0.4
2
0.6
1?.
10
30
in ppm
Element
Terbium
Gadolinium
Europium
Samarium
Neodyraium
Praseodymium
Cerium
Lanthanum
Barium
Cesium
Iodine
Tellurium
Antimony
Tin
Indium
Cadmium
Silver
Palladium
Rhodium

by weight.
Cone.
7
94
9
930
MC -
MC -
MC -
MC -
860
1
0.4
—
3
4
STDS
<0.3
<0.3
—
—

Element
Ruthenium
Molybdenum
Niobium
Zirconium
.4% Yttrium
. 3% Strontium
2% Rubidium
4% Bromine
Selenium
Arsenic
Germanium
Gallium
Zinc
Copper
Nickel
Cobalt
Iron
Manganese
Chromium

Gone.
—
150
80
260
88
130
< 8
< 3
5
4
< 1
53
130
1/40
550
60
MC
680
MC

Element
Vanadium
Titanium
Scandium
Calcium
Potassium
Chlorine
Sulfur
Phosphorus
Silicon
Aluminum
Magnesium
Sodium
Fluorine
Oxygen
Nitrogen
Carbon
Boron
Beryllium
Lithium
Hydrogen
Cone.
100
MC ^
12
MC
MC
150
MC
MC
MC
MC
200
MC
MC
NRd
NR
NR
8
0.3
1.1
NK
^MC - major component (>0. 1/0 .
Concentrations < 0.2 ppmw were not listed.
CNR - not reported.
 il'D - analytical standard.

-------
              TABLE 5-32.  SAMPLED REFINERY HYDROCARBON STREAMS


Gas Stjr earns

            Reformer Recycle Hydrogen
            Atmospheric Crude Distillation:  Overhead Gas
            FCCU Low Pressure Separator Gas


Liqu.id Streams

            Atmospheric Crude Distillation:  Intermediate Naphtha
                                             Full Range SR Gasoline
                                             Virgin Distillate
                                             Atmospheric Gas Oil

            Vacuum Distillation:   Light Vacuum Gas Oil
                                  Vacuum Gas Oil
                                  Heavy Vacuum Gas Oil
                                  Vacuum Residuum

            Reforming:   Naphtha to Feed Hydrotreating
                        Naphtha to Reformer
                        Reformate

            FCCU:   Reflux Accumulator Bottoms
                   Separator Bottoms
                   Main Fractionator  Overhead Liquid
                   Light Cycle Gas Oil
                   Heavy Cycle Gas Oil

            Desulfurized Naphtha

            Desulfurized Gas Oil

            Alkylation:   Reactor  Product
                         Crude Alkylate

            TCC:   Heavy Cycle Gas Oil

            Absorber Lean Oil

            Slack  Wax from Dewaxing

            API  Separator:   Inlet Oil
                            Surface Oil
                            Skimmed Oil
                                    194

-------
           TABLE 5-33.  ORGANIC SPECIES PRESENT IN REFINERY LIQUID
                        STREAMS AND EMITTED VAPORS3
       alkanes
 Benzene
 Toluene
 Xylenes
 Ethylbenzene
 TrimeLhylbenzene
 Dicthylbcnzene
 Dimethylethylbenzene
 Tetramethylbenzene
 sec-butylbenzene
 Naphthalene
 Methylnaphthalenes
 Biphenyl
 C2~alkylnaphthalenes
 C 3-naphthalen es
 Phenanthrene/anthracene
 Methylphenanthrene/anthracene
 Cz-alkylphenanthrene/anthracene
 C3-alkylphenanthrene/anthracene
 Propylbenzene
 Ethyltoluene
 Methyl.Isopropylbenzene
Methylpropylbcnzene
 Dlethylbenzene
Dimethylethylbenzene
 In dan
Methyl indan
C .s -a Ikylb en 7, cm e
Tetralin
Biphenyl
Methylbiphenyl
CT-alkylbiphenyls
Fluorene
Methylfluorene
C2-alkylfluorenes
Acenaphthcne
Methylacenaphthene
Ci, -alkylacenaphthene
C2-alkylnaphthalenes
Dibenzo Chiophene
Methyldibenzothiophene
Co-alkyIdibenzoChiophene
Ca-alkyldibenzothiophene
C^-alkyldibenzothiophene
C5-alkyldibenzothiophene
Fluoranthene
Pyrene
Methylfluoranthene/pyrene
C?-alkyIfluoranthere/pyrene
C3-alkyIfluoranthene/pyrenc
Cu-alkylfluoranthene/pyrene
Naphthabenzothiophene
Cs-phenanthrene/anthracene
C3-alkylchrysene/benzanthracenes
 Listed compounds were detected in vapor samples or were present in liquid
 streams at concentrations of 10 ppm or greater.
                                    195

-------
          TABLE 5-34.  POTENTIALLY HAZARDOUS SPECIES IN VAPOR
                       SAMPLES  FROM REFINERY STREAMS

                             Potentially  Hazardous  Species  Concentration in
                                 Vapor  Samples  From The, Various Sampled
                                                Streams
                          0.01 - 0.1 ppb
0.1 - 1.0 ppb
> 1.0 ppb
Benzene                          —
Isopropylbenzene                 —
Trimethyl benzenes               —
Naphthalene                   1, 4
Anthracene/Phenanthrene       1, 2, 3
Biphenyl                      1, 3, 4
Methyl naphthalene            2, 4
Perylene                         —
Benzo(a)-pyrene               1
Benzo(e)-pyrene                  —
Methylcholanthrene               —
Benzanthracenes                  —  -
Pyrene                        1, 2, 3,  4
Fluoranthene                  1, 2, 4
Benzofluorenes                1
Benzo(ghi)-perylene           1
    1,  2
    1,  4
    1,  2
    1
Acenaphthene
Fluorene
Phenol
o, m, p-cresol
1
1, 2
1
1, 4
1
—
4
1
—
—
—
~
 Samples taken from leaking vapor or present on particulate matter from FCCU
 regenerator flue gas.
 See Table   5-35  for stream type identification.
                                   196

-------
TABLE 5-35.  VAPOR AND LIQUID STREAM IDENTIFICATION NUMBER
Scream
ID
Number
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
Sample
Phase
Vapor
Vapor
Vapor
Vapor
Liquid
Liquid
Liquid
Liquid
Liquid
Liquid
Liquid
Liquid
Liquid
Liq'uid
Liquid
Liquid
Liquid
Liquid
Liquid
Liquid
Liquid
Liquid
Liquid
Liquid
Liquid
Liquid
Liquid
Liquid
Stream Type Description
FCCU CO Boiler Flue Gas
Fluid Coker CO Boiler Flue Gas
Resin Fume Oxidation Unit Flue Gas
TCC CO Boiler Flue Gas
API Separator - Inlet Oil
API Separator - Surface Oil
API Separator - Skimmed Oil
Crude Oil Desalter Water
Sour Water Stripper Feed (Water)










Desulfurized Naphtha (from hydrodesulfurization)
Intermediate range Naphtha frqm Atmospheric
Distillation
Naphtha to Hydrotreating (for Reformer
Naphtha to Reforming
Straight Run Gasoline from Atmospheric
FCCU Reflux Accumulator Bottoms
FCCU Separator Bottoms
FCCU Main Fractionator Overhead
Ref ornate
Absorber Lean Oil
Crude Alkylate (Alkylation. Unit)
Feed)

Distillation






Virgin Distillate from Atmospheric Distillation
Desulfurized Gas Oil
Atmospheric Gas Oil
Light Vacuum Gas Oil
FCCU Light Cycle Gas Oil
FCCU Heavy Cycle Gas Oil
TCC Unit Heavy Cycle Gas Oil
Flashed Crude







                            197

-------
                     TABLE 5-36.   POTENTIALLY  HAZARDOUS SPECIES IN REFINERY  LIQUID  STREAMS


                                  Potentially Hazardous Bpeclea  Concentration  in Liquid Baaplea from the Various Hydrocarbon fitrcama*
     Potentially Hazardous	r   	
          Compounds                   1Q _  IQQ fpn                               10Q _ iQiOOQ pfa                      > 10>OOT ppB

Denernc                        4, 5, 7, 10,  11, 14, 18, 27            5, 12, 13, 15, 16, 18. 19, 20, 26
laopropylbcnzene               4, 5, 10. 11,  14, IB                   6, 7, 12, 13,  15, IB,  19, 20, 26
Trtmethyl  benzenes             24, 25, 26                            4,5,6,7,10,11,12.13,14,18,19,20,21,26,27        IS, 16. 17
1,2,3,4-tetrahydronaphthalene   —
Naphthalene                    11. 14, IS, 19, 21, 24, 25, 26         4, 5, 7, 12. 18, 20, 26, 27                    13, 15, 16, 17,  2)
Anthraccne/Phenanthrene        13, 21. 25                            4, S, 6, 7,  25, 26,  27
Blphenyl                       IB                                    4. S, 6, 7,  13, 25
Methyl naphthalenes            11, 18, 24                            4, 5, 7, 12, IB, 20. 21, 26                    6. 13, 15.  16,  25
Perylene                       -—                                    —                                            —
Benzo(a)-pyrene                —-                                    —                                            ~—
Benzo(e)-pyrena                --                                    —                                            —
Benzanthracenea                —                                    —                                            —
Pyrene                        21                                    26,  27
Fluorantliene                   21                                    —                                            --
Benzofluorenea                 -—                                    --                                            —
Benzr>(g)il)-perylene            —                                    —                                            ~
Coroncne                       -—                                    —                                            -—
Acenaplithene                   21                                    6                                             ~-
Fluorene                       4.  IB,  21                             5, 6, 7, 25, 27
Phenol                        —  •                                  ~                                            ——
o, m, p—crcsol                 --                                    —                                            ——


 3Sec Table  5-35  for  Stream  Type  Identification.

-------
          The species listed in Tables 5-34 and 5-36 met one or more of the
following criteria:

          •    Threshold limit value  (TLV) < 5.0 pprav

          •    Acute local inhalation rating of 3 (Materials which on a
               single exposure lasting seconds or minutes cause injury to
               mucous membranes of sufficient severity to threaten life or
               cause permanent physical impairment or disfigurement).^

          *    Acute systemic inhalation rating of 3 (Materials which can
               be absorbed into the body by inhalation and which can cause
               injury of sufficient severity to threaten life following a
               single exposure lasting seconds, minutes, or hours).

          •    Known or suspected carcinogen.

          •    Detected by analyses in at least one sample.

          The stream identification numbers may appear in more than one
concentration range for a given species.   Many stream types were sampled
at several different refineries.   The resulting analyses showed different
concentration ranges for some species.

5.5       Quality Control

          A comprehensive quality assurance program was an integral part of
this program.  The quality assurance program for the sampling and analysis
activities included the following elements:

          •    Formatted data collection forms for direct
               keypunching of data recorded in the field.
                                   199

-------
          •    Repealed sampling of individual sources with the
               same and different sampling teams and sampling
               equipment .

          *    Sampling and subsequent analysis of standard
               gas mixtures.

          •    Continuous sample runs over an eight-hour period.

          •    Daily testing of screening devices on the same
               sources.

          •    Multiple screenings of the same devices by different
               engineers.

          •    Replicate sample analysis and blind standard
               analysis in the laboratory.

          Some of the more important results of the quality assurance effort
are summarized in this section of the report.  A much more detailed descrip-
tion of the quality assurance program is presented in Appendix C (Volume 4)
of this report.
5.5.1     Quality Cpnt rol fo r_ Baggable Source Hydrocarbon Measurements

          The quality control precedures for baggable source hydrocarbon
emissions measurement include laboratory analyses of blind standards,
repeated total hydrocarbon (THC)  analyses, recovery studies of the sampling
train,  and reproducibility of the sampling/analysis from a given source.
                                    200

-------
5.5.1.1   Laboratory Standard Analyses

          Regularly scheduled analyses of blind standards were used to
evaluate the daily calibration of the Byron THC analyzer as well as the
stability of the calibration.  The percent differences between the known
and the measured concentrations ranged from - 55 percent to + 13 percent.
The average difference was - 1.75 percent with a standard deviation of
10 percent.  The 95 percent confidence interval for the mean difference
was -4.7 percent to + .1.4 percent.

5.5.1.2   Replicate Analyses for Total Hydrocarbons

          The precision of the nonmethanc hydrocarbon analysis as determined
with the Byron TL1C analyzer were determined from a statistical analysis of
duplicate analyses made at each refinery.  The following statistics summarize
the results of the duplicate analyses:

          Number of replicate pairs:             130

          Pooled standard deviation:               2.4%

          Repeatability - maximum difference
          expected between 2 readings 95  %
          of the time:                             6.2 %

          95 %  confidence interval for mean
          reading based on a single  analysis:    ±4.8%

          95 %  confidence interval for mean
          reading based on the average of
          two  analyses:                          ±  3.4%
                                    201

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          Since the average of two analyses was used in computing leak rates
for all sources, the ±3.4 percent interval best describes the precision of
the THC analysis.

5.5.1.3   Results of Recovery Studies

          The overall accuracy of the baggable source sampling and analysis
procedure was evaluated.  Known leak rates were generated and measured.  The
percentage of the leaking material which was recovered in the sampling train
was used as a measure of overall accuracy.  Sixty-three recovery studies were
made at nine of the visited refineries.  The induced leak rates ranged from
0.007 to 2.93 Ib/hr.  The recoveries ranged from 44 to 161 percent.   The
average recovery was 98.7 percent x^ith a standard deviation of 17 percent.
The 95 percent confidence interval for the average recovery was 94.5 to
102.9 percent.

5.5.1.4   RepeatabilityofIndividual Source Sampling

          Repeated sampling of leaking sources was done to determine the
variability of the measured leak rate.  This variability is due to sampling
procedures, sampling teams, process (leak) changes, and variations in the
actual leak rate.   Approximately 16 percent of the sampled sources were
resampled at least one time.

          Table 5-37 summarizes the statistical analysis of the repeat QC
samples.   The variability for drains is significantly higher than the other
sources while the variability for relief valves is significantly less.  The
other sources have a standard deviation averaging about 40 percent or a 95
percent confidence limit based on a single test of ± 80 percent.

          Tnis standard deviation of 40 percent is composed of variation due
to analysis, sampling train components, sampling team effect,  and variability
in the actual leak rate.  The standard deviation for the THC analysis was
                                    202

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                               TABLE 5-37.   SUMMARY  OF  BAGGABLE  LEAK RATE QUALITY CONTROL SAMPLE
l-o
O
OJ

Source Type
Va 1 v e s
Pump Seals
Compressor Seals
Flanges
Relief Valves
Drains
Overall
Number
Of Sources
WlLh QC
65
62
',0
7
16
14
204
Standard
Total QC
Samples
137
133
66
12
30
33
411
Average %
Difference'1
37
44
39
40
IS
71
41
.8
.7
.5
.0
.5
.1
.9 '
Deviation of
Sampling Analysis
36.
41.
38.
39.
19.
59.
40.
6
9
1
1
5
1
7
S5%
Reproducibility of
Sampling/ Ann lysis3
101
116
105
108
54
153
112
.4%
.2%
.6%
.2%
.0%
.7X
.8%
90% Confidence
Interval about a.
Sample Test Result "*
± 71.
± 82.
± 74.
± 76.
± 38.
±115.
t 79.
7X
2%
4Z
6%
27.
8%
8X
              'Average % difference - average  of  pooled percent differences for each source with QC  sample.

                                Where:   7, cliff - [original - QC leak] / (average of original and QC leak).

              2Stanaard deviation of sampling/analysis - estiriated standard deviation of the sampling and
              analyses procedures for non-methane hydrocarbons.  Estimated from the pool individual
              percent differences for each QC sample.
              395% rcprodiir.Jbility of sampllng/nnnlysls -  quantity that will bs exceeded only about  5X
              of the time by the difference of  two  test results on a given source under similar process
              cnncl.it inns.  The quantity is equal Lo 2.77  x standard deviation.

              U90% confidence interval - When  tnken  about  a single test result, 95X of these intervals
              would be expected to include the •  "actual"  leak rate (without bias considerations);
              the quantity is equal to 1.S6 x standard deviation.

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about 2.4  percent, and  the standard deviation  for sampling and analysis
of standard  gases was about  .17 percent.  No significant differences between
sampling teams or sampling carts were  found, therefore a significant portion
of the variability in the measured leak rates  is apparently due to real
variations in the leak  rate.

5.5.2     Quality _Contro1. for Hydrocarbon Screening Devices

          The Bacharach TLV  Sniffer was the principal device used for
screening baggable sources in this study.  The Century Model OVA-108 was
also used for some screening activities.  Each was calibrated on a daily
schedule.  Two concentrations of standard gases were used.  Daily calibration
at two concentration levels with standard gases gave consistent, unbiased
readings.

          The repeatability of the screening procedure (including vari-
ability of the leak rate) was investigated by performing repeated screenings
on the same source by the same operators.  The percent difference between
duplicate readings were less than 75 percent with the TLV Sniffer and below
40 percent for the OVA-108.

5.5.3     Quality Control for Nonbaggable_ Sources

          Quality control for nonbaggable sources (cooling towers,  waste-
water systems, and process stacks) involved an evaluation of the accuracy
and repeatability of all analytical procedures.  Sampling procedures usually
do not lead themselves to accuracy evaluations although day-to-day  variations
give an indication of sampling repeatability.

5.5.3.1   Cooling Towers

          The total organic carbon (TOC) content of cooling tower water was
determined with a Dohrmann DC 52D TOC analyzer.  However,  the average
differences for 48 comparisons of the inlet  and outlet cooling water gave a
                                    204

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 standard  deviation of  4.2 ppn  for  the analytical method.   This deviation
 is  greater  than desired, and a purge-arid-trap method was developed  to  obtain
 better  accuracy.

          An  evaluation of the purge method showed that an average  of  78
 to  93 percent of volatile organics in standard mixtures was recovered.  These
 standard  mixtures contained less than 10 ppm volatile organics.  The purge
 method  was  preferentially used to  estimate losses of hydrocarbons from
 cooling towers.

 5.5.3.2   Wastewater Systems

          The purge and trap method was used to estimate losses of  hydro-
 carbon  from water passing through  the wastewater treatment system.  Volatile
 organic content of inlet and outlet oil layer samples was  determined by
 gravimetric means.  Standard mixtures of volatile hydrocarbons in a base
 oil were  prepared.  The average percent recovery of volatile hydrocarbons
 from these  standards was 98.3 percent.  The 95 percent confidence interval
 for the average recovery is 98.3 ± 3.5 percent.

 5.5.3.3.  Process Stack Emissions

          The major emphasis on quality control for stack  samples was on
 strict  calibration of metering and temperature control, devices, leak testing,
 and laboratory standard analysis.

          Upon arrival at each refinery site and before setting up on a
 stack, all equipment was examined,  set up, and the operation of all
 thermometers/thermocouples,  pumps,  and flow meters was checked.  All measure-
ment devices were calibrated.   All fittings and equipment were checked for
 leaks both on the grcmnd and when set up on the stack.
                                    205

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          Quality control procedures during the analyses of the stack
samples were primarily analyses of standards.  Blind standards were analyzed
for aldehydes, sulfur gases, and NO .
                                   X

          The percent differences for Lhe 28 aldehyde standard analyses
averaged 0.9 percent with a standard deviation of 5.2 percent.  The vari-
ability appears greater at the lower concentration levels  (about ± 12 percent)
than for the higher concentration standards (about ± 6 percent).  The aldehyde
analysis procedure is concluded to be unbiased with a precision averaging
about ± 10 percent.

          The percent differences for the 18 sulfur analyses averaged 0.5
percent with a standard deviation of 14.6 percent.  Only two standards above
100 ppm were tested.   The percent differences ranged from - 39 percent to
+ 20 percent, but only three of the 18 analyses were low.  The overall
accuracy of the method for concentrations below 100 ppm is about ± 30 percent.

          The three standard analyses for NO  ranged from 21 percent to 73
percent low, indicating potential inaccuracies in the method.

5.6       Survey Information

          There are many factors in a refinery which might contribute
directly to the fugitive emission load or indirectly affect the overall
emission level.   However, they do not lend themselves to direct sampling.
Among these factors are maintenance practices, laboratory techniques, unit
shutdown procedures,  blind changing procedures and blending operations.  In
order to evaluate the.se items,  a general survey form for each  of them was
submitted to the refiner.   The results are summarized below.
                                    206

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5.6.1     Maintenance Practices

          Generally speaking, the refineries used combinations of in-house
and contract maintenance personnel.  The in-house maintenance people did much
of the routine maintenance, and supplemental contract labor was used during
turnarounds and larger maintenance projects.

          Some form of preventive maintenance program was in force at five
of six refineries.  In one refinery an inspection of each unit is performed
once a year.  Piping, furnace tubes, etc. are replaced if it is felt that
they might fail during the following year.  Pumps, valves, flanges, etc. are
inspected and adjusted/replaced only when a problem is reported.

          At another refinery, however, a preventive maintenance program is
practiced on instrumentation, electric motors and pumps.  This includes a
prescribed maintenance schedule for each piece of equipment.  The packing
and seals of pumps, valves, etc.  are routinely inspected by operating
personnel.  Some minor adjustments may be made when the need is observed.
More extensive work is done by maintenance personnel.

          In five of the six refineries, equipment files are kept on pumps
and compressors.   Seal failures and packing leaks are recorded.  However,
valve maintenance records were kept at only one refinery included in this
summary report.

          Three of the six refineries reported that 17 percent, .18 percent
and 20 percent of the operating budget is devoted to maintenance.   One
reported that 44 percent of its manpower was devoted to maintenance.

          Significant differences in emission rates were not found among the
refineries.   This would indicate that the variations in maintenance programs
found do not affect the emissions rates.
                                    207

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5.6.2     process Unit Turnaround Procedures

          Most normal maintenance in a refinery can be performed while
running, but some major items require that the unit be shut down and opened.
The entire unit must be purged of all hydrocarbons and tested to insure that
it is "gas free."  This large scale overhaul of a processing unit is called
a "turnaround."

          The following purging procedure is typical of industry practice.
The unit is shut down and process gases are vented to a vapor recovery
system, if available, or to the f2are.  Then steam is charged to the unit
to strip out the remaining hydrocarbons.  Most of this steam is vented to a
closed blowdown system which will remove condensed water and route the gases
to the flare.  A f.ew "high-point" vents are opened to the atmosphere during
the latter stages of steaming out.  The amount of hydrocarbons lost at this
point is not known.  However, the concentration of hydrocarbon in the unit
should be low by that time.  At that point, the steam flow is stopped and
the unit is cooled, thus condensing the steam.  The condensate is drained
off.   Then the vessel manways are opened and the interiors are gas tested.
This procedure is thorough and effective,  and its overall impact on fugitive
emissions is negligible, especially in light of the infrequent nature of its
occurrence.

          The frequency of shutdowns for various units at one refinery is
presented in Table 5-39.

5.6.3     Blind Changing

          Only when handling very expensive and exotic materials,  such as
some lube oil stocks, would the use of blinds be warranted as a means of
controlling direction of flow to prevent any cross-contamination.   The
refineries reported that they do not routinely change any significant number
                                    208

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TABLE 5-38.   SHUTDOWN FREQUENCY

Crude Unit
Crude Unit
Catalytic Cracker
Fuel Reformer
Naphtha HDS
Alkylation
Aromatics Reformer
AromaLics Extraction
Times Down in
Last 12 Months
1
1
1
0
0
1
2
1
Scheduled Period
Between Turnarounds
1 year
1 year
1 year
1 year
3 years
1 year
1 year
3 years
               209

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of blinds.  Most blind changing takes place during the startup or shutdown
of a unit, and at these times, the unit has generally been purged of
hydrocarbons.

5-6.4     SamplingProcedures

          Quality control sampling of light ends and volatile hydrocarbons
in refineries has the potential for adding to the overall fugitive, emission
rate.  General surveys were made of sampling, flushing and sample waste
disposal procedures.

          At one large refinery, laboratory personnel were observed while
drawing routine liquid samples in the field.  Line flushings were routed to
a covered oily water drain system with a maximum of 18 inches free fall and
minimum exposed retention time (i.e., less than two minutes).  Readings were
taken with the J. W. Bacharach "TLV Sniffer" at the drain entrance immedi-
ately before and after sampling.  No significant difference in readings was
discernible, and the absolute parts per million readings were below the
selected sampling limit of 200 ppm.  These procedures were typical of those
performed at visited refineries.  However, hydrocarbon screening during
sample collection was not done at any other refinery.

          The overall sample load at one large refinery was approximately
200 samples per day.  Of these, about 40 percent were gas samples for
chromatographic analysis, about 24 percent were volatile liquids (naphtha
or lighter), and about 36 percent were nonvolatile liquids.  Sample wastes
were emptied into one of two slop oil collection systems, one for naphtha
and one for heavier materials.

          Daily sample loads of 50 to 200 samples per day were reported by
four refineries.
                                    210

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                                 PART B
         REFINERY  TECHNOLOGY  REVIEW AND  ENVIRONMENTAL ASSESSMENT

          The results of the field measurement program were combined with
data from other sources (literature,  government agencies, vendors, etc.) to
develop refinery control technology reviews/evaluations, refinery technology
characterizations, and an environmental assessment of refineries.  Section
6 describes potentially hazardous compounds which were found in selected
refinery streams or which might be present in refinery emissions.  Refinery
process technology is characterized and control technology is reviewed in
Section 7.  An environmental assessment of petroleum refineries is contained
in Section 8.
                                   211

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6.0       POTENTIALLY HAZARDOUS SUBSTANCES

          The objective of this section is to present an overview of
potentially hazardous substances which are found in refinery feed,
intermediate, product, and waste streams.  Since the potential for fugitive
emissions exists for a wide variety of process equipment, all materials
utilized in refining operations can be emitted to the atmosphere.

          The term hazardous is used here to describe a compound which has
shown the potential to cause adverse human health effects.  The use of the
term hazardous does not necessarily indicate that the chemical compound
has been designated as hazardous, in a regulatory sense, by EPA.  A few
compounds (e.g., benzene) do fall within this legal definition of
"hazardous".  For these reasons, the term "potentially hazardous" is
used in many instances to indicate that while the substance has the
potential for causing adverse health impact, it may not be classified by
EPA as hazardous, in a legal sense.

          The origin of potentially hazardous substances is discussed in
Section 6.1.  Included are substances or classes of substances which
enter the refinery as raw materials.  Raw materials include the crude
oil as well as numerous other chemicals required for processing.  Also
included in this section are substances which are formed or concentrated
within refinery processes.

          Section 6.2 contains a discussion of potentially hazardous
substances leaving the refinery as constituents of the product streams
or of solid and liquid waste streams.   Also included in this section is
information on the destruction of certain substances during processing.

          Section 6.3 contains information on atmospheric emissions of
potentially hazardous substances.  Emissions from both point sources and
fugitive sources are included.   This section concludes with a discussion
                                    212

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of factors which affect atmospheric emissions of potentially hazardous
substances.  These factors include the type of refining, the processing
scheme, and the properties of the incoming crude oil.

6. 1       Origin of Potentially Hazardous Substances

          Many hazardous substances enter the refinery with the raw
materials.  Others are produced within various process units.  Particular
compounds or groups of compounds which enter via the above mechanisms are
discussed below.

6.1.1     Potentially Hazardous Substances in Refinery Raw Materials

          Many of the potentially hazardous substances found within
petroleum refineries enter the refinery as constituents of crude oil.
Classes of potentially hazardous materials include hydrocarbons, sulfur
compounds, nitrogen compounds, and trace elements.

          Hydrocarbons—A list of potentially hazardous hydrocarbons which
have been identified in crude oil is given in Table 6-1.  The compounds
included in the table have been assigned either a threshold limit value  (TLV)
by the American Conference of Governmental Industrial Hygienists or a
rating of 2 or 3 (capable of causing permanent damage to humans) by Irving
Sax in Dangerous Properties of Industrial Materials, 1975 edition.26

          A complete listing of all potentially hazardous substances of
crude oil would be nearly impossible since there can be more than 3,000
                           r\ rj
compounds in any one crude."

          One group of hydrocarbons,  commonly called polynuclear
aromatics (PNA's),  has received considerable attention due to their
hazardous nature.   These compounds are composed of fused aromatic, rings and
                                     213

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              TABLE 6-1.  POTENTIALLY HAZARDOUS3 HYDROCARBONS
                          IN CRUDE OIL


    Compound                                               Concentration


Methane                                                         T
Ethane                                                          T
Propane                                                         m
Methylpropane                                                   T
Butane                                                          m ->- M
Methylbutane                                                    m
n-Pentane                                                       m
2,2-Dimethylpropane                                             T -> m
n-Hexane                                                        tn
2-Methylpentane                                                 m ->• M
3-Methylpentane                                                 m
2,2-Uimethylbutane                                              m
2,3-Dimethylbutane                                              m
n-Heptane                                                       m-M
2,3-l)imethylpentane                                             m
2,4-Dimethylpentane                                             m
n-Octane                                                        m
2-Methylheptane                                                 m
2,3-Dimethylhexane                                              m
2,3-Diroethylhexane                                              m
2,3,4-Trimethylpentane                                          T
n-Dodecane                                                      T -»• m
Cyclopentane                                                    m
Cyclohexane                                                     m
Methylcyclohexane                                               m -> M
Cycloheptane                                                    m
Benzene                                                         T ->- m
Toluene                                                         T -»- m
Ethylbenzene                                                    T ->• m
Dimethylbenzene (Xylene)                                        T -* m
n-Propylbenzene                                                 m
Isopropylbenzene (Cumene)                                       ra
1,2,3-Trimethylbenzene                                          m
1,3,4-Trimethylbenzene                                          m
1,3,5-Trimethylbenzene                                          m
Isobutylbenzene                                                 ra
sec-Butylbenzene                                                m
tert-Butylbenzene                                               m
l-Methyl-5-Isopropylbenzene                                     m
1,2-Diethylbenzene                                              m
1,3-Diethylbenzene                                              m
                                                           (Continued)
                                    214

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                          TABLE 6-1.  Continued
    Compound                                              Concentration
1,4-Diethylbenzene                                             m
l-Methyl-4-tert-butylbenzene                                   T
1-Methylnaphthalene                                            T
2-Methylnaphthalenc                                            M
Pyrene                                                         T
Coronene                                                       T
Benzo(a,e)pyrene                                               T
1,2,3,4-Tetrahydronaphthalene                                  T
Biphenyl                                                       T
Acenaphthene                                                   T
Benzofluorenes                                                 T
Phenanthrenc                                                   T
Benzophenanthrene                                              T
Naphthenophenanthrenes                                         T
Dinaphthenophenanthrenes                                       T
Trinaphthenophenanthrenes                                      T
Tetranaphthenophenanthrenes                                    T
Pentanaphthenophenanthrenes                                    T
Fluoranthrenes                                                 T
Perylene                                                       T
Phenyleneperylene                                              T
Dibenzopcrylcne.                                                T
Chrysene                                                       T
Benzo(g)chrysene                                               T
3-Methylchrysene                                               T
Naphthenochrysencs                                             T
Anthracene                                                     T
Bcnzanthraceno                                                 T
Sources:  References 28,29,30,31,32,33,34,35,36.

   The compounds included in this list have either been assigned a
   Threshold Limit Value (TLV) by the American Conference of Governmental
   Industrial Hygienists or assigned a rating of 2 or 3 (capable of causing
   permanent damage) by Irving Sax in Dangerous Properties of Industrial
   Materials, 1975 edition.

   Key to concentrations:     T = trace:   <100 pptn

                              m = minor:    100 ppra to 2.99%

                              M = major:   >3.0%
                                   215

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are found in crude oils at levels of up  to 0.1 percent.    Several of
these materials are known carcinogens.
          Sulfur Compounds—The sulfur content of crude oil can vary
from 0.06 to 8.0 weight percent.38  Sulfur is incorporated into the
structure of a variety of hydrocarbons and tends to concentrate in
compounds of higher molecular weight.
          Potentially hazardous sulfur compounds in crude oil include
trace quantities of 48 thiols, almost 200 sulfides, and a number of
sulfites, sulfonates, and sulfones.  In lower boiling point fractions
(up to 400°F), mercaptans (thiols) appear to predominate.  Cyclic
mercaptans appear in the kerosene range; thio-ethers and cyclic sulfides
in the naphthenes.  in higher boiling fractions, there is a tendency
toward sulfur substitution in saturated rings.

          NitrogenCompounds—The nitrogen content of most crude oils
is less than  1 percent.38   Approximately one-fourth to one-third of this
nitrogen is contained in basic compounds including alkyl-substituted
quinolines and pyridines.  All of these alkyl quinolines and some of the
pyridines have been designated potentially hazardous by the criteria in
Table 6-1.  Other hazardous nitrogen compounds in crude oil include
indole and the carbazoles.

          Oxygen Compounds—Crude oil generally contains less than 2 percent
oxygen.   The  oxygen compounds designated as potentially hazardous by the
criteria in Table 6-1 include the lower molecular weight carboxylic
acids and alkyl ketones,  and some cyclic ketones and phenols.

          Trace Metals—Trace quantities of a number of metals have been
found in crude oil.   Twenty-eight metals, most of which are considered
potentially hazardous, are listed in Table 6-2.  Of the metals listed,
vanadium,  nickel, and iron are usually present in the greatest quantities.
                                     216

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             TABLE 6-2.  TRACE METALS FOUND BY SPECTROGRAPHIC
                         ANALYSIS OF ASH FROM CRUDE OIL
Ag
Al
As
B
Ba
Ce
Co
Cr
Ca
Cu
Fe
Ga
K
La
Mg
Mn
Mo
Na
Nd
Ni
Pb
Sn
Sr
Tl
V
Zr
Zn
U
Source:  Reference 39.
          In addition to crude oil, a variety of other raw materials
enters the refinery.  These materials, many of which are considered
potentially hazardous, are used as treating agents, solvents, catalysts
or additives.

          Catalysts—Both solid and liquid catalysts are used in a wide
range of petroleum processing operations.  The hazardous nature of liquid
catalysts such as hydrofluoric, sulfuric, and hydrochloric acids is well-
known.  Many of the solid catalysts contain metals listed as hazardous
in Table 6-2.

          Catalyst fines are emitted to the atmosphere during catalyst
regeneration.  Most catalysts are regenerated only a few times a year;
therefore,  the escaping catalyst fines are considered insignificant.
Fluid catalytic cracking catalysts, on the other hand, are regenerated
continuously.  In this case, particle collection devices are used
extensively to control the emissions, both for environmental protection
and for economic reasons.  Table 6-3 lists some of the commonly used
catalysts and the processes in which they are used.
                                    217

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                             TABLE 6-3.  PRINCIPAL APPLICATIONS OF CATALYST MATERIALS'
ho
M
00
Alumina
Aluminum chloride
Antimony trichloride
Bauxite
Bentonite clay
Clay
Cobalt-molybdena
Cobalt molybdate
Cobalt oxide
Copper
Copper pyrophosphate
Hydrochloric acid
Hydrofluoric acid
Iron oxide
Kaolin clay
Magnesia
                                                     Processing  Application
                                Crack-
                                  ing
                                      Reform-
                                        ing
            Hydro-
           treating
Isomeri-
 zatlon
                                  X
                                  X
                                  X
                                  X
                                  X
                                  X
                                  X
X
X
                                                            X
                                                            X
                            X
                            X
                            X
   X
Alkyla-
 tion
         Many catalyst materials are also used for other purposes in a refinery.

      Source:  Reference  40.
                                                                                       X
                                                                                       X
Polymer-
ization
Molybdena
Molybdenum
Nickel sulfide
Phosphoric acid
Platinum
Potassium X
Rhenium
Silica-alumina X
Sulfuric acid
Tungsten nickel sulfide
X
X

X

X
X


X

X


X

X

X



X
X


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          Gasoline Additives—Gasoline is  the primary product in many
refineries.  Additives arc introduced to improve the burning characteristics
and other qualities of the gasoline.  These additives include:

          •  Antiknock compounds such as tetraethyl lead or
             similar alky1-lead compounds.

          •  Metal deactivators.

          •  Anti-corrosion additives.

          •  Anti.sta.il additives including light alcohols, polyalkylene
             glycols, and alkyl phosphates or amines.

          •  Antipreignition agents containing phosphorus compounds.

          •  Luhricants.

          Many of these materials are potentially hazardous and some can
form hazardous combustion products.

          Other chemicals—Numerous other chemicals are utilized during
the refining process.  And, many are considered hazardous.  Some of the
major chemicals used in refining are listed with their principle uses
in Table 6-4.

6.1.2     Potentially Hazardous Materials Produced in Refining Processes

          Many of the potentially hazardous materials found in refinery
process streams are produced within the process units rather than entering
with various raw materials.  Alternatively, certain other processes serve
to concentrate hazardous materials, either as product or intermediate
                                  219

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              TABLE 6-4.  MAJOR CHEMICALS USED IN REFINING AND
                          THEIR PRINCIPAL USES
        Chemical
               Uses
Acetic Acid
Acetone
Aluminum Chloride


Aluminum Oxide (Bauxite)

Aluminum Naphthenatcs

Aluminum Phenates

Aluminum Soaps

Aluminum Stearate

Barium Hydroxide
Barium Salts
Break up emulsions
Increase treating of sul.furic acid
Reduce sulfur content
Extract polymers from cracked
   distillates
Separate waxes

Regenerate clays
Isolate benzene in azeotropic
   distillation
Solvent in determining oil content
   of waxes

Cracking, alkylation, and iso-
   merization catalyst

Cracking catalyst
Detergent additive for lubricating
   oils
Treat spent caustic solutions
Neutralize acid-treated oils
Precipitate naphthenic acids
Prevent foaming before caustic soda
   treating for mercaptan removal
Remove inorganic salts from furfural
   before refining

Oxidation inhibitors, detergent
   additives in lube oils
                                                         (Continued)
                                     220

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                            TABLE 6-4.  Continued
        Chemical
               Uses
Benzene


Bone Char

Cadmium-Ammonium
  Chloride

Cadmium Hydroxide

Cadmium Chloride

Cadmium Sulfide

Cadmium Oleate      j

Cadmium Naphthenate /

Cadmium Dithiocarbamate

Cadmium Sulfonate

Calcium Oxide

Calcium Hydroxide

Calcium Carbonate

Calcium Chloride

Calcium Hypochlorite

Chlorine
Solvent extraction to improve viscosity
   index of lube oils and remove waxes-

Decolorize oil
Distillate Desulfurizing
Oxidation inhibitor in lube oil
De.tergent additive
Neutralize acid-treated oils
Remove hydrogen sulfide and organic
   acids from oils
Dessicant

Oxidize sulfides and mercaptans in oils

Oxidize dlsulfides to sulfonyl halides
   and to remove mercaptans
Regenerate Bcntonite clay
Regenerate sodium plumbite "doctor
   solution"
Prepare calcium and sodium hydroxide
Improve cetane number of fuels
                                                         (Continued)
                                     221

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                            TABLE 6-4.  Continued
        Chemical
               Uses
Clays
Cupric Chloride
Cresol
Dichloroethyl Ether
Ethanolamines
   (MEA, DEA, TEA)
Ethylenc Bichloride

Ethylene Glycol


Formaldehyde

Furfural
Hydrogen
Adsorbents to improve color, odor, and
   stability of waxes and lube oils
Cracking catalysts

Convert mercaptans to insoluble
   disulfides

Extraction of high-viscosity-index,
   light-color, ,1 ow-carbon-residue
   lubricants from residual or
   distillate base stock

Solvent in chlorex extraction to
   improve viscosity index and yields
   of paraffinic oils

Removal or recovery of water, hydrogen
   sulfide, or carbon dioxide from
   gaseous streams

Removing wax from lube oil

Selective recovery of benzene, toluene,
   and xylenes from petroleum stocks

Laboratory reagent and solvent

Extraction of diesel fuels, burning
   oils, cracking stocks, and crude oils
Removal of low-eetane materials,
   unstable and acidic materials, sulfur,
   organometallic and nitrogen
   compounds
Extraction of aromatic, naphthene,
   olefinic, and unstable hydrocarbons
   from lube oils

Hydrotreating
Hydrocracking
Hydroalkylation
                                                         (Continued)
                                     222

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                            TABLE 6-4.  Continued
        Chemical
               Uses
Hydrogen Fluoride

Methyl Ethyl Ketone (MEK)

Methyl Isobutyl Ketone
(MIBK)

Natural Oils

Nitrobenzene


Phenol
Phosphorous Compounds

Phosphorous Pentoxide

Potassium Hydroxide

Potassium Phosphate

Propane


Sodium Carbonate (Soda Ash)

Sodium Hydroxide
  (Caustic Soda)

Sodium Hypochlorite
Alkylation Catalyst

Remove wax from oils

Deoiling high-quality waxes


Production of lubes and greases

Extract carbon and sludge-forming
   compounds from lube oils

Extraction of high-viscosity-index,
   high-color, low-carbon-residue
   lubricants from residual or
   distillate base stock
Improve viscosity index, color and
   oxidation resistance, and to reduce
   carbon and sludge-forming tendencies
   of lube oils

Polymerization catalysts

Catalyst for air-blowing of asphalt

Remove acids from petroleum

Remove hydrogen sulfi.de from gas

Solvent, extractions-deasphalting,
   dewaxing,  and decarbonizing

Neutralize acids in processing streams

Remove acidic substances


Sweeten gasoline
                                                         (Continued)
                                     223

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                           TABLE 6-4.  Continued
        Chemicals
               Uses
Sodium Phenolate


Sodium Plurabite


Sulfur Chlorides

Sulfur Dioxide
Sulfuric Acid



Toluene

Trichloroethylene
Remove hydrogen sulfide from gasoline
Stabilize color of gasoline

"Doctor sweetening" agent to convert
   raercaptans to disulfides

Solvents

Extract aromatic, hydrocarbons and
   sulfur-bearing compounds from
   paraffins and naphthenes
Improve viscosity index and remove
   waxes from lube oils

Remove aromatics from kerosene
Remove or dissolve resinous and
   asphaltic materials and sulfur

Remove waxes from lube oils

Extract carbon- and sludge-forming
   constituents of lube oils and
   increase their viscosity index
Source:  Reference 40.
                                    224

-------
streams, or as waste streams.  Examples of hazardous materials production
or concentration are discussed in this section.

          Hydrogen Sulfidc—Hydrogen sulfide is an extremely toxic gas.
It is found in small quantities in crude oil and is produced in a variety
of refining operations including reforming, desulf irrigation processes,
coking, catalytic cracking, and hydrocracking.

          The H2S from these processes is usually concentrated in acid-gas
absorption processes for use as sulfur plant feed.  Common absorption
processes utilize aqueous solutions containing an alkanolamine such as
moncthanolamine (MEA) or diethanolamine (DEA) as the absorbing agent.

          Mono-aromatic Hydrocarbons—A variety of mono-aromatic hydro-
carbons are considered potentially hazardous.  The simplest component
in this group, benzene, is suspected of being carcinogenic and has been
officially designated by EPA as a hazardous compound.  These compounds
are produced and purified for use in gasoline, petrochemicals, plastics,
and synthetic fibers.

          A refinery's major source of aromatics is usually the catalytic
reforming unit.  Here, hydrocarbon molecules containing six or more
carbon atoms are converted to aromatics.   This type of processing is useful
in increasing the octane rating of certain naphthas.  Products from these
processes include benzene, toluene, xylenes, and other substituted
aromatics.

          Aromatic hydrocarbons are found in varying concentrations in a
large number of refinery streams.   The results of analyses conducted during
this program for aromatics in 60 refinery streams are given in Appendix B
(Volume 3)  of this report.
                                    225

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          Polynuclear Aromatic Hydrocarbons—As was previously discussed,
polynuclear aromatic hydrocarbons are found In abundance in coal tar and
are minor constituents of crude oil.  Environmental concern over these
compounds centers on the carcinogenic activity of certain PNA compounds.
Several, most notably benzo(a)pyrene, have been shown to induce cancer,
while others are suspected  carcinogens or may inhibit or accelerate
the activity of benzo(a)pyrene.    Hazardous PNA's have been identified or
                                                      1, y
are suspected to be in the  following refinery streams.
          •  Catalyst regeneration gases from fixed-bed desu.lfurization,
             hydrocracking, and sweetening processes.

          •  Fluid catalytic cracker regenerator off gases.

          •  Fluid catalytic cracker cycle oil streams.

          •  Fluid coking off gases.

          •  Asphalt blowing off gases.

          •  Decoking operations.

          •  Oil-fired heater f.lue gas,

          •  Certain brines and sour water condensates.

          •  Flare combustion gases.

          •  Heavy oil sludges, wastewater system sludges, and
             spent catalysts.

          The above list represents potential sources of atmospheric
emissions of PNA's.   PNA's have also been identified in other refinery
                                     226

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streams in samples analyzed during  this program.  The results of these
analyses are given in Appendix B  (Volume 3) of this report.

          Carbon Monoxide—Carbon monoxide is formed as a result of
incomplete combustion.  It is found in process heater flue gas and in
the off gas formed during catalyst  regeneration.  By far, the largest
source of CO in refining operations is FCC catalyst regeneration.  The
flue gas contains CO in concentrations ranging from 5-10 percent.  This
gas is usually burned in a CO boiler to recover the energy content of
the off gas.

          Other Potentially Hazardous Materials—A list of potentially
hazardous materials has been provided in Table 6-5.  For each material,
a list of processes is given in which that material has been identified
or is suspected present.  These processes are listed as numbers and may be
identified by referring to Table 6-6.

6.2       In-Line Fate of Potentially Hazardous Substances

          Potentially hazardous materials present in refining streams
must eventually leave, the refinery.  Many of these mate.rials leave as
components of the final products.  Examples of this are discussed in
Section 6.2.1.

          Additional hazardous materials exit as components of the numerous
waste streams generated during refining.   Some of these waste streams
require additional, treatment or careful disposal to minimize environmental
danger.   Potentially hazardous constituents of various waste streams are
discussed in Section 6.2.2.

          Other hazardous materials may be destroyed prior to leaving the.
refinery.   This may occur as a by-product of a refining process, or as
a result of specific efforts to remove the material in question.  Examples
                                     227

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            TABLE  6-5.   HAZARDOUS  CHEMICALS  POTENTIALLY  EMITTED
                               FROM PROCESS  UNITS
                    Cnealcal
                Halelc Acid
                Betuolc Acid
                Cresyllc Add
                Acetic Acid
                Foralc Acid
                Sulfurlc Acid
                DtethylaBlne
                Methylelhylamine
                Arcxutic Awines
                Amnonii
                Chlorides
                Sulfates
                C« routes
                Kilones
                Aldehydes
                Formaldehyde
                Acetaldehyde
                Carbon Monoxide
                Sulfur Oildes
                Nitrogen Glides
                Pyridines
                Pyrroles
                Qvinolines
                Indoles
                Furins
                Benzene
                Toluene
                lylene
                Phenol
                Dinethylphenol
                Cresols
                Xylenols
                Thiophenols
                Cirbaioles
                Anthracenes
                8enio(a)pyrene
                Pyrene
                ftenzo(e)pyrene
                Perylene
                tenzolghOperylene
                Coronene
                Phenanthrene
                Fluoranthrene
                Httilloporphrfns
                Nickel Csrbonyl
                Cobalt Carbonyl
               Tttraethyl  Lead
                Sulfides
                Sul fates     .   '
                Sulfonates
                SuHones
               NercapUns
               Thiophenes
               Hydrogen Sulfide
               HethylnercipUn
               Carbon Dtlsulfide
               Cirbonyl  Sulfidt
               ThlosuUide
               Dtbenzothiopher*
               AUyl  SuUide
               Vanadium
               Nickel
               Lead
               Zinc
               Gobi It
               Molybdenum
               Copper
               Strontium
               Biriutn
               Sulfur Partlculatcj
               Catalyst  Fines
               Code Fines
               Cyanides
                                                    Potential  Emission Source
                                                     Process  Module ttunbm
 \ ,2,3.«.7,16.17.18.19,20.22.23,», 25.26.27.28.30
 1,2.30
 3,7.16.17.18.19.20.Z2.23.24.25.26.27.28.30
 4.30
 4.30
 27.30
 4.S.3D
 4.5,30
 18.19.26,30
 3.S.7.16.17.IB.19.20.22.23.24,25.26.27.30
 1.2.30
 27.30
 30
 1.2.3.7.16.17.18.19,20.22,23,24.25.26,27.30
 1.2.3.7 ;i6.17.18.19,20.22.23,24,25.26.27,30.32
-18,19,26
 18,19.26
 5,9,10,12,13.16.17,18,19,20.22.24,25,26,27.32
 5,10,13,16,17,18,19,20.22,24.25,26,27,32
 31.32
 1,2,3.7,16,17,18,19,20,22.23,24,25.26.27,28,30
 1.2.3,7,16.17,18.19,20.22,23,24,25,26,27,28,30
 28.30
 18,19.26.30
 28.27,30
 1,2,3.7,10,13,14,16,17.18.19,20.21.22,23,24,25,26,27,28,29.30
 1.2.3,7,10,13,14.16,17.IB,19,20,21.22,23,2<.25,26,27,28,29,30
 1.2.3.7.10,13,14.16.17.18,19.20.21,22,23,24,25.26,27,28,29.30
 1.2.7,18,19,25,26.28,30
 1.2,27
 1,2,7.18,19.25,27,28,30
 7.18,19,25,26,27,28,30
 26,30
 1,2,28,30
 1.2.18,19,26,28.30
 18,19,26.28,32
 18,19,26.30
 18,19.26
 18,19,26,30
 18.19
 18.19.26
 18.19.26
 18.19.26
 1.2.30
10,16,17,20.22,24.27
 10.16,17,20,22,24,27
14,21
3,7.15,16,17,18,19,20,22,23,24,25,26,27,28,29,30
30
3,7.16,17.18,19,20,22.23,24,25,26,27,28,29,30
30
1,10,15,26,30
1,2,3,7,16,17.18,19,20,22,23,25,25,26 ,27 ,28,30
1.3,5,7,10,13,15,16,17,18.19,20,22,23,24,25,26,27
3.4,7,16.17,13,19,20,22.23,24.25,26,27
4,5,10.16,17,18,19,20,22,24,27
a.5.ID,13.16.17.IB,19.20.22.24,27
4
28
28
1,2.10.16.17.18.19.20,22,24.25.26.27,28,30.32
1.2.10.16.17,18.19.20.22.24.25,26,27,28.30.32
1.2.32
1.2.18,19,25,26.28.30
10,16,17,20.22,24.27
10.16,17,20.22,24,27
18.19,25,26,28,30,28
23
28
5
9.10.12.16,17.18,19,20.22.24.27
10.16.17,20,22.24,25.26,27.32
4.5.18,19,26,30
Source:    Reference  42.
                                          228

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               TABLE 6-6.  LIST OF PROCESS UNITS FOR TABLE 6-5
                   1   Crude storage
                   2   Desalting
                   3   Atmospheric distillation
                   4   Acid gas removal
                   5   Sulfur recovery
                   6   Gas processing
                   7   Vacuum distillation
                   8   Hydrogen production
                   9   Polymerization
                  10   Naphtha HDSa
                  11   Alkylation
                  12   Isomerlzation
                  13   Catalytic reforming
                  14   Light hydrocarbon storage & blending
                  15   Chemical sweetening
                  16   Kerosene HDS
                  17   Gas oil HDS
                  18   Fluid bed catalytic cracking
                  19   Moving bed catalytic cracking
                  20   Catalytic hydrocracking
                  21   Middle distillate storage & blending
                  22   Lube oil HDS
                  23   Deasphalting
                  24   Residual oil HDS
                  25   Visbrcaking
                  26   Coking
                  27   Lube oil processing
                  28   Asphalt blowing
                  29   Heavy hydrocarbon storage & blending
                  30   Wastewater treating
                  31   Steam production
                  32   Process heaters
r\
   HDS = hydrodesulfurization
                                     229

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illustrating the destruction of certain hazardous materials are included
in Section 6.2.3.

6.2.1     Potentially Hazardous Substances Present in Refinery Products

          Refinery Gases—Refinery gases consist of saturated and
unsaturated hydrocarbons in the C-x to C5 range along with varying amounts of
inert gases such as N2, H20, anc^ C02.  Also, gases such as H2 and
H2S may be present.  These gases might have been part of the original
crude, or they might be by-products of certain process units.  Process
units producing refinery gases include atmospheric distillation, catalytic
reforming, fluid catalytic cracking, hydrocracking, hydrorefining, and
coking.

          Hydrogen sulfide is often a constituent of raw refinery gases.
It is produced from heavier sulfur compounds during hydrotreating and
hydrocracking processes and is extremely hazardous.  In addition to
hydrogen sulfide, many of the hydrocarbons in refinery gases are considered
potentially hazardous.

          Aviation Gasolines—Aviation gasolines consist of high octane
hydrocarbons with a boiling range of 85 to 300°F.  In general, these fuels
contain a high percentage of isoparaffins and smaller percentages of
naphthenes and aromatics.  Although most of the components of aviation
gasoline are not extremely toxic, many are considered potentially hazardous.
In addition, tetraethyl lead is added to prevent knocking.

          Jet Fuels—Jet fuels consist of hydrocarbons with a boiling
range of 300 to 460°F.  The aromatic content of these fuels is limited
to reduce smoke formation during combustion.

          Additives are added to the fuel to control oxidation,  to
chelate any copper remaining after refining, to ensure that any  water
                                    230

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dissolved in the fuel will not freeze, to inhibit corrosion, and to
increase conductivity and thus reduce static electricity.  Most
constituents of jet fuel are considered potentially hazardous.

          Automobile Gasoline—Gasoline is defined as a petroleum fuel
for use in reciprocating, spark-ignition, internal combustion engines.  It
is a complex mixture of hydrocarbons, mostly in the C^ to C^2 ran8c»
which distill between 85°F and 410°F.  Gasolines from different refineries
may vary widely in exact composition according to the processes used at
the refinery.  A summary of the main components of gasoline and their
sources is given in Table 6-7.

          Gasoline contains a relatively high proportion of aromatics,
supplied mainly by the catalytic reforming process.   Gasoline also
contains a variety of additives including anti-knock compounds, anti-icing
additives,  anti-oxidants, metal deactivators, carburetor detergents, and
anti-corrosion additives.

          Distillate and ResidualFuels—A variety of heavier fuels are
manufactured by refineries.   These include diesel fuels, heating oils,
gas oils,  and fuel oils.  Some of these fuels contain PNA's and PNA's
have also  been found in their combustion products.   Heavier fuel oils
also contain other potentially hazardous materials,  including sulfur
and nitrogen compounds.

          Solvents (Industrial Naphtha)— A variety of solvents are
produced by refineries.   These range from pure hydrocarbons such as
benzene, toluene,  xylene, ethylbenzene, hexane, and  cyclohexane, to
blends consisting  of varying proportions of  paraffins, cycloparaffins,
and aromatics.

          Asphalt—Asphalt cement is the -material remaining after the
removal of  light and heavy distillates from asphaltic crudes.   It is
                                    231

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                                      TABLE 6-7.   MAIN COMPONENTS  OF GASOLINE
                      COMPONENTS
      SOURCE
 BOILING
RANGE,°F
                                          REMARKS
to
LO
                      Paraffinic
                        Butane

                        Isopentane



                        Alkylate


                        Isotnerate
                        Straight-run
                          Naphtha
                        Hydrocrackate
                      Olefinic
                        Thermal Reformats
                        Catalytic Naphtha

                        Steam Cracked
                          Naphtha
                        Polymer

                      Aromatic
                        Catalytic
                          Reformats
Crude oil distillation      30
Conversion processes
Crude ollidistillation      81
Conversion procesaes
IsomerIzatlon of •
  n-pentane
Alkylation process     100-300
Isomerlzatlon process   100-160
Crude oil               90-200
  distillation
Hydrocracklng          100-390
  process
Thermal reforming      100-390
Catalytic cracking     100-390

Steam cracking         100-390
      \
Polymerization of      140-390
  olefins
Catalytic reforming    100-390
                                 Widely used in proportions
                                 up to 10%.
                                 Widely used as high-octane.
                                 high-volatility component.
          Used widely in aviation gaso-
          line, but lesa frequently In
          motor gasoline.
          Relatively little used at
          present.  Excellent anti-
          knock properties under severe
          engine  conditions.
          Widely  used low-octane compo-
          nent.
          Heavy products used as feed
          for catalytic reforming.  Con-
          tains also nromatica.
          Obsolescent process.'
          Widely  used component, par-
          ticularly  in premium gasoline.
          By-product of chemical processes,

          High-octane component but not
          widely  used.


          Host  widely used high-octane
          component  of gasolines.
                      Source:   Reference 38.

-------
usually mixed with distillates in varying proportions to obtain materials
for specific purposes.

          Cutback asphalts contain lighter distillates such as naphthas,
gasoline or kerosene.  They may be medium- or rapid-curing.  Emulsified
asphalts are emulsions of asphalt ceraent with chemically treated water.

          "Blown asphalt" may be produced by blowing air through a
                                                               O Q
residual oil at temperatures usually ranging from 400 to 600°F.    Asphalt
blowing operations have been identified as a source of polynuclear
aromatics.  Compounds detected in one study included pyrene, anthracene,
                                                  ^ o
and trace amounts of phenanthrene and fluoranthene.     Asphalt also contains
heavier PNA's which apparently are not volatilized at air blowing temperatures.

6.2.2     Potentially Hazardous Materials in Refinery Waste Streams

          Potentially hazardous materials in solid or liquid refinery waste
may find their way into ground waters or Lhe atmosphere if improperly
disposed of.  Hazardous materials in the more common refinery waste
streams are discussed below.

          Storage Tank Bottoms—Crude oil storage tanks contain solid
sediment which accumulates on the tank bottom.   This sludge is usually
composed of iron rust, iron sulfides, clay,  sand, water, and oil.
Hazardous materials contained in the sludge include various organics
and organo-metallic compounds, and heavy metals found in incoming crude oil.

          Tanks containing refinery products will also accumulate sludges
over a period of time.  Tanks with leaded products will produce sludges
containing lead residues.

          Wastewatcr Processing Sludges—Wastewatcr processing sludges
are produced by operations including primary separation, chemical
                                    233

-------
coagulation and precipitation, air flotation, and biological  treatment.
Since refinery wastewaters can contain water utilized in all  process units,
they may contain nearly any hazardous material found in the refinery.  Many
of these materials are found  in the sludge by-product, along  with chemicals
used in processing the water.  Volatile hazardous materials can readily
leave the wastewater system due to weathering and turbulence  generated
by some treating units.

          Spent or Neutralized Acid Sludges—Acid sludges are produced
by the sulfuric acid and the hydrofluoric acid alkylation process.  In
addition, sulfuric acid is used as a treating agent.  Spent acid from
sulfuric acid alkylation is usually regenerated off-site.  Spent acid
from hydrofluoric acid alkyiation is usually neutralized rather than
regenerated.  Neutralization with lime produces an insoluble  calcium
fluoride sludge.    Spent sulfuric acid from treating operations may
contain a high proportion of oil.

          Spent or Neutralized Caustic Solutions—Large amounts of caustic
are utilized by refineries for the neutralization of acidic materials in
crude oil, the neutralization of acidic products such as those formed in
catalytic cracking, and for use in chemical treatment processes.  These
solutions may contain sulfides, mercaptans, sulfonates, phenolates,
napthenates, atmaonia, and various other organic and inorganic compounds.1*3

          Coke Fines—Coke fines are produced during decoking operations.
The coke fines produced by attrition may become airborne particulates if
allowed to dry.  Additionally, heavy hydrocarbons entrained in the coke
may be released during the coke cutting procedure.  Often, vapors are
condensed during the earlier stages of decoking to recover heavier
hydrocarbons.   A water quench is used to minimize particulate emissions.
                                    234

-------
           The  feedstock  to  the  coking  unit  is  usually  atmospheric  or
vacuum resicl.  Heavy metals present  in the  feed will concentrate within
                  kit
the coke product.
           Spent Clay—Filter clays are used  in removing  color bodies,
chemical  treatment residues, and  trace moisture from gasoline, kerosene,
jet fuel,  light fuel oil and lube oil.  The  spent filter clay forms a
sludge or  cake which contains  traces of oil  and heavy metals.

           Spent Catalysts and  Catalyst Fines—Solid catalysts are used in
a number of processes.  These  catalysts are  deactivated by contaminants
within the process and must eventually be replaced.  These spent catalysts
can contain heavy metals plus  organics absorbed from process feedstocks.
In some cases, the spent catalysts are reprocessed to recover their
metals content.

          Catalyst fines are produced by attrition within fluid-bed catalytic
cracking units.  These fines contain vanadium and nickel and arc emitted
from the catalyst regenerator.  The emission of fines frora this source
is reduced by passing the regenerator flue gas through a series of cyclones.
Further reductions are obtained using electrostatic precipitators.

          Foul or Sour Water—Distillation products are often stabilized by
steam stripping.  The resulting condensate can contain sulfides, ammonia,
mercaptans, phenolics, organic acids, nitrogen bases, and cyanides.  Foul
water from the catalytic cracking unit, often high in phenolics, is
occasionally used as raw desalter water.   In the desaltcr, the phenolics are
absorbed by the crude oil resulting in lower phenolic loading at the
                          h 5
wastcwater treatment plant.
                                    235

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6.2.3     Destruction of PotentiallyHazardous Compounds

          Several compounds, or groups of compounds which are suspected
to be hazardous are not contained in either the product or waste streams.
Instead these compounds are chemically converted to less toxic materials
during processing.  Often, the destruction of these materials is not the
primary purpose of the processing step.  In other cases, units arc designed
for specific removal of a particular contaminant.  Other hazardous compounds
may be eliminated by pollution abatement equipment.  Examples of the
destruction of hazardous materials arc described below.

          Hydrogenation Processes—A variety of hydrogenation processes are
utilized by refiners.  In most of these processes, potentially hazardous
sulfur compounds are converted to I^S.  And, the products of these processes
are often low in residual sulfur.  Higher severity hydroprocessing can
also lead to a reduction in the nitrogen content.  In this case, potentially
hazardous nitrogen compounds are converted to ammonia.

          Hydrogen sulfide and, under certain circumstances, ammonia can
be removed in a Glaus sulfur plant.   Tail gas from the. Glaus plant contains
significant quantities of sulfur compounds including ^S, 862, COS, and
CS2.   This tail gas is either treated further to remove sulfur compounds or
flared to produce S02, the least toxic of these sulfur compounds.

          Destruction of Potentially Hazardous Materials by Combustion—A
variety of potentially hazardous materials may be destroyed by combustion.
These materials include:

          •  Hydrocarbons (rnono-aroraatics,  PNA's, other hazardous
             hydrocarbons)

          •  Organic chemicals
                                     236

-------
             Hazardous  gases  (CO,
          •  Hazardous  solid wastes

          The most common  types of combustion equipment for waste disposal
 include flares, CO boilers, process heaters, and incinerators.

          Flares — Flare systems are common  to all crude oil refineries.
 The use of flares, or any  other combustion  sources, will, result in the
 discharge of combustion pollutants such as  SO  and NO  .  Incomplete
                                             X       X
 combustion can result in carbon monoxide, unburncd hydrocarbons, and smoke
 emissions.

          Combustion is improved by injecting steam into the combustion
 zone.  Steam improves combustion by increasing turbulence, by reacting
with the fuel to form oxygenated compounds  that burn readily, and by
 retarding full polymerization that results  in heavier and more difficult
 to burn hydrocarbons.

          CO Boilers — CO Boilers are commonly used to burn CO in the
catalyst regenerator gas from fluid-bed catalytic cracking units and flue
gas from fluid cokers.   Additionally, the CO boiler is also effective
in reducing the levels of aldehydes, cyanides, and hydrocarbons, including
PNA's generated during catalyst regeneration. J

          Incineration — Incineration is a disposal technique used to minimize
the volume of combustible wastes.   It has been used successfully on
streams such as API separator bottoms, DAF float, waste biosludge, and slop
oil emulsion solids.   The resulting product consists of non-combustible
material which occupies only 10 to 20 percent volume of the original waste.1*7
Incineration can be quite effective in destroying hazardous hydrocarbons and
other organic chemicals.
                                     237

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6.3       Atmospheric Emissions of Potentially Hazardous Substances

          This section contains information on atmospheric emissions of
potentially hazardous substances.  Sources of atmospheric pollutants can
be divided into two groups.  The first group, discussed in Section 6.3.1,
consists of process emission sources (point sources).  The second group of
sources of atmospheric emissions are fugitive sources.  In contrast to
point sources, the emission rates of pollutants from individual fugitive
sources are quite low.  However, there, are thousands of Fugitive sources in
refineries, and fugitive emissions constitute a large portion of the total
emissions from the refinery.  In addition, fugitive emissions can occur
on lines containing nearly any process fluid.  Hence, the potential exists
for atmospheric emissions of nearly every hazardous material in the
refinery.  Fugitive emissions of hazardous materials are discussed in
Section 6.3.2.

          Section 6.3.3 concludes with a discussion of miscellaneous
factors affecting emissions of potentially hazardous substances.  The
various factors considered include the type of refinery, the type of
processing units, and the type of crude oil processed.

6.3.1     Point Sources

          There are several operations within the refinery which produce
a waste gas stream for discharge to the atmosphere.   Most of these point
sources emit potentially hazardous materials.  The quantity of  emissions
depends on the size of the unit and the degree to which control methods
have been adopted for the source.

          Atmospheric emissions point sources discussed in this section
include:

          •  FCC catalyst regenerator flue gas
                                     238

-------
          •   Claus  sulfur  plant  tail  gas

          •   Asphalt blowing emissions

          •   Process heater flue gas

          •   Flare  emissions

          A brief discussion of  the mechanism for pollutant formation and
 the  types of  hazardous materials generated  is included for each source.
 In addition,  emission factors or estimates  of the quantity of emissions
 generated by  each source are included where possible.

          FCC Catalyst Regenerator Flue Gas—Coke is deposited on cracking
 catalysts during processing, and it must be removed to restore catalytic
 activity and  selectivity.  This  is accomplished by introducing air into
 the  regenerator and burning the coke  to CO and C02.  In conventional
 operation, the conversion  of CO  to C02 is minimized to avoid high tempera-
 tures which might damage internal regenerator materials.  The resulting
 flue gas contains from 5-10 percent CO.  Many refiners utilize CO-burning
waste heat boiler to recover the energy contained in the flue gas and to
 reduce CO emissions.

          Emissions from the FCC regenerator, with and without the use of
 a CO boiler, are listed in Section 5.  Also given in that section are
 the results of sampling conducted during this program.  The section contains
 a summary of data obtained from five FCC unit CO boiler stacks.  Detailed
 information on these sampling results is given in Appendix B (Volume 3)
of this report.

          Aromatic species from cracking catalyst regeneration operations
were also identified during this study.  These compounds are listed in
Tables B5-1 through B5-8 in Appendix B (Volume 3) of this report.
                                     239

-------
          Glaus Sulfur Plant Tail Gas-^—Claus sulfur plants are unable  to
remove all the sulfur from the acid gas feed stream.  Table 6-8 shows  the
typical composition of a sour gas feed, the Claus unit  tail gas, and the
thermally incinerated tail gas.

          Asphalt Blowing Unit Tail Gas—Air blowing is used  to improve the
hardness and increase the melting point of asphalt.  Available data
indicate that uncontrolled emissions  amount to 60 pounds per  ton of
asphalt.7   The operating conditions  are favorable for  the production  of
extremely hazardous polynuclear aromatics.  The PNA's identified in one
study include pyrene, anthracene, and traces of phenanthrenc  and
             'i i
rluoranthcne.

          Process Heater Flue Gas—Potentially hazardous compounds in  the
flue gas of fired heaters and boilers include various sulfur  and nitrogen
compounds, carbon monoxi.de, and unburned hydrocarbons.  Sulfur emissions
generally occur as S02 and are dependent on the amount of sulfur in the
fuel.  Nitrogen oxide (NO ) emissions depend on the nitrogen  content of the
fuel but are also influenced by the combustion conditions.  Carbon monoxide
and unburned hydrocarbon emissions are usually quite low.  However, improper
firing condition can cause a significant increase in emissions of both
carbon monoxide and hydrocarbons.

          EPA emission factors for process heaters are listed in Section 7
of this report.

          Flares—Flares are. used as final disposal method for hydro-
carbon gases and other waste gas streams.  In general, emissions of carbon
monoxide and hydrocarbons from flares are higher than those from process
heaters of boilers.   Factors which may account for less effective combustion
in flares include:
                                    240

-------
              TABLE 6-8.  TYPICAL GLAUS TAIL GAS COMPOSITIONS'
Component
H2S
SO 2
Sg vapor
SB aerosol
COS
CS2
CO
C02
02
N2
H2
H20
B.C.

Temperature, °C
Pressure, atm.
Total gas volume
Sour Gas Feed,
Volune Zb
89.9
0.0
0.0
0.0
0.0
0.0
0.0
4.6
0.0
0.0
0.0
5.5
0.0
100.0
40
1.45
2
Claus Tail Gas ,
Volume Zb
. 0.85
0.42
0.10 as S-i
0.30 as Si
0.05
0.05
0.22
2.37
0.00
61.04
1.60
33.00
0.00
100.00
140
1.1
3.0 x'feed
gas volume
Thermally Incinerated
Tail Gas,
Volume 2b
0.001
0.89
0.00
0.00
0.02
0.01
0.10
1.45
7.39 -
71.07
0.50
13.57
0.00
100.00
400
1
5.8 x feed
gas volume
  Two catalytic reactors - overall efficiency of 94%.
  Gas volumes compared at standard conditions.
Source:   Reference 48.
                                       241

-------
          •  Variable firing rates which make control of steam and
             combustion air flow rates difficult.

          •  Variable heat values for fuel which may also contain
             significant quantities of oleflus or aromatics.

          •  Relatively low combustion temperatures with short
             residence times compared to process heaters and boilers.

          Emission factors for smokeless flares are listed in Section 7.
The emissions listed are given as pounds of pollutant per thousand
barrels of refinery capacity.

6.3.2     Fugitive Sources

          To quantify fugitive emissions of a particular component, the
emission rate of each type of source emitting that component must be
known.  In addition, knowledge of the total number of each source type
and the concentration of the component within the leaking process stream
is also required.

          During the course of this program, Radian has accumulated much of
the information required for such an anlysis.  Estimates of total fugitive
emissions of a particular component may be estimated in a direct manner
using that data.  For example, the following procedure can be used to
estimate the emissions of any hazardous substance from a refinery process
unit.  The first step consists of identifying different process streams
characteristic to the unit.  Then, the fugitive emission sources, developed
from source counts taken during this program, are divided between the
available process streams.

          Finally, the component analyses can be applied to these process
stream emissions.  That is, total stream emissions are multiplied by the
                                      242

-------
weight fraction of each component  in  the process stream.  And, total
emissions of a particular component will be the sum of emissions from
all refinery streams containing that  component.

          Radian has performed this analysis for a number of pure components.
Other components have been consolidated into groups containing compounds
with similar chemical properties.  The results of this analysis, given in
Table 6-9, show total fugitive emissions from a large existing refinery
model (see Appendix D, Volume 4) on a component basis.  This procedure is
discussed in detail in Appendix D  (Volume 4) of this report.

6.3.3     Miscellaneous Factors Affecting Emissions of Hazardous Substances

          The characteristics of the  crude oil and the type of processing
utilized by a refinery can have a marked effect on the quantity of various
hazardous materials emitted to the atmosphere.  Factors influencing
emissions of hazardous substances are discussed below.

          Characteristics of Crude Oil—Fugitive emissions sources include
equipment located in every process unit in the refinery.  Hence, it is
likely that all materials contained in the crude oil feed to the refinery
will be emitted to the atmosphere to some extnet.

          The concentration in crude oil of several  groups of potentially
hazardous materials can vary widely.  These groups include sulfur and
nitrogen containing compounds, aromatics,  and heavy metals.   Sulfur and
nitrogen are incorporated into the structures of a wide variety of compounds,
many of which are potentially hazardous.  High sulfur crudes may require
substantial hydrodesulfurization to meet product specifications.   This
increases the quantity of hydrogen sulfide fed to  the sulfur recovery unit
and results in increased emissions of sulfur compounds with the tail gas.
                                        243

-------
K:
*-
•P-
                            TABLE 6-9.  SUMMARY OF HYDROCARBON  SPECIES EMISSIONS FROM
                                        FUGITIVE  SOURCES  IN  A LARGE  EXISTING REFINERY
                                        MODEL  (SEE APPENDIX  D,  VOLUME 4)
Source
V
CouiponL-nt

Benzene
Toluene
Ethylbcnzene
Xylencb
Other Alkylhenzenea
Naphthalene
Anthracene
Dlphenyl
Other PNA's
n-llexane
Other Alkalies
Olefins
Cycloalkanes
Hydrogen
TOTALS
. r, c, F,
ppmu
7.200
21.000
5.600
31,000
42,000
1,700
20
230
7,700
16,000
651,000
46,000
135,000
31,000

I), CT*
kg/hr
2.8
tt.2
2.2
12.1
16.6
0.7
0.01
0.1
3.0
6.3
255.9
18.1
52.9
12.3
391.2
Kollof Valves
ppmw
23,000
24,000
A, 500
26,000
35,000
1,400
1
110
3,300
9,700
67 8, GOO
30,000
82,000
,82,000

kg/hr
0.4
0.4
0.1
0.4
0.6
0.02
0.0
0.0
0.05
0.2
11.3
0.5
1.4
1.4
16.8
API Scparulors
pptnu
700
2.200
590
2.100
7.900
2,900
390
1.800
1.500
i**
980,000
i.
i.
4.

kg/hr
0.4
1.1
0.3
1.1
4.1
1.5
0.2
0.9
0.8
•I.
502.4
4.
4.
i.
512.8
Totala
ppraw
3,900
11,000
2,800
15,000
23,000
2,400
220
1.100
4,200
7,100
840,000
20,000
59,000
15.000

kg/hr
' 3.6
9.7
2.6
13.6
21.3
2.2
0.2
1.0
3.9
6.5
769.6
18.6
54.3
13.7
920.8
               i-fre emissions  from valves,  pumps,  compressors,  flanges, drains, and cooling towers.
       ** Components marked with "-c"  are  indicated present,  but no quantifiable concentration data
          v;crc available.

-------
          Effect of Processing—An important finding of this program is
that both the frequency and the magnitude of fugitive leaks increase with
increasing volatility of material being processed.  Therefore, fugitive
emissions, on a per source basis, are most likely higher from refineries
with substantial light ends processing or refineries producing gasoline as
opposed to heating oil.
                                   245

-------
 7.0       REFINERY CHARACTERIZATION AND CONTROL TECHNOLOGY

          The individual refinery technologies are described in Section 7.1.
 Refinery control technology is discussed in Section 7.2.  Existing and
 available control techniques are included for fugitive and process emission
 sources.

 7.1       Re finery Technology Characterization

          This section contains a brief description of each of the major
 refinery processes and a description of their respective emissions.  Emis-
 sion factors for fugitive emission sources were determined as a part of the
 refinery assessment program.

          The estimated fugitive nonmethane hydrocarbon emissions from each
 source type and stream category as well as an estimate of emissions from
 the entire unit are included for most processes.  Many of these estimates
 are listed as a range because of variations in the estimated sources and
 source distributions.  In addition to the source counts and estimates
 developed by Radian, a second set of source counts is given for most process
units.  These counts were based on information contained in a study by
Pacific Environmental Services (PES).'|J  In this study, process flow dia-
grams were used to determine the number of pumps and compressors within
 the unit.  Other sources were estimated from pump counts.

          It must be emphasized that all of the source counts and stream
service distributions given in this report are, at best, rough estimates.
Even those values based on actual source count data should be considered
rough estimates since only a small number of process units were counted.
In addition, source counts for similar types of process units showed large
variations.   Therefore, reliable estimates for emissions source counts and
distributions should be obtained for the particular process unit in
                                   246

-------
question rather than using the estimates which are designed to characterize
typical refinery operation.

          Additional information concerning the emissions estimates is con-
tained in Appendix B (Volume 3) and  Appendices C and D  (Volume 4) of this
report.  More detailed process descriptions are included in Appendix F
(Volume 5).

7.1.1     Separations

          Crude oil is separated by distillation into a variety of inter-
mediate products which are used as feedstocks for downstream processing
units.  Boiling ranges of each fraction vary with the intended use for
the fractions.

          Higher efficiencies and lower costs are achieved if crude oil
separation is accomplished in two steps:  (1) fractionating the total crude
stream at atmospheric pressure, then (2) fractionating under a high vacuum
the high boiling bottoms fraction (topped crude.) from the first fractiona-
tion.  A third separation in petroleum refineries is the extraction of
aromatic compounds from reformate streams.  These arornatics are then used
in gasoline blending or petrochemical operations.

7.1.1.1   Atmospheric Distillation

          Nearly all crude oil feed must pass through a refinery's atmo-
spheric distillation unit before it can be further processed.   Atmospheric
distillation separates the hydrocarbon components of the crude into frac-
tions by distillation and steam stripping.

          Process Conditions—Typical operating parameters and utility
requirements for an atmospheric distillation unit with a capacity of
24,000 bbl/day are listed below:
                                    247

-------
           •    Pressure:  Atmospheric

           •    Temperature:  250 °F - at top of fractionator
                              700°F - at bottom o£ fractionator

           •    Electricity:  4.1 kW/bbl

           •    Thermal Energy:  10s 3tu/bbl

           •    Steam:  50 Ib/bhl

           •    Process Water:  5C gal/bbl

          Potentially Hazardo u s Atmospheric Enijssions—Emissions from atmo-
spheric distillation operations include process heater flue gas emissions and
fugitive emissions.  These emissions are summarized in Tables 7-1 and 7-2.
Table 7-3 provides information on the composition of the fugitive emissions.

 7.1.1.2   Vacuum Distillation

           Vacuum distillation is used to fractionate, topped crude from the
 atmospheric distillation unit into  a heavy residual oil  and one or more
 heavy gas oil  streams.  A vacuum distillation unit is  an integral  part of
 most refineries.

           P r o ces_s Condi t ions—Typical operating parameters and utility
 requirements for a vacuum distillation unit are listed below:

           •    Temperature:   750 to 830°F.

           •    Pressure:   0.4 to 0.7 psia.

           •    Thermal  Energy:   74,900 Btu/bb].
                                    248

-------
        TABLE  7-1.   TYPICAL EMISSIONS FROM ATMOSPHERIC
                      DISTILLATION UNIT PROCESS  HEATERS
                                EPA Eaission ?accor
                               (lb/103  gal-oil fired)
                               (lb/10s  scf-gas fired)
                    Tocal Emissions
                    (lb/103 bbl of
                     crude  oil  feed)
Oil Fired Heaters
    Particulars
     - Distillate oil
     - Residual oil
          Grade 4
          Gradft 5
          Grade 6
    Sulfur Dioxide
     - Distillate oil
     - 'Residual oil
    Sulfur Trioxide0
    Carbon Monoxide
    Hydrocarbons (as
    Nitrogen Oxides
    (as NQ2)
     - Distillate oil
     - Hesidual oile
  7
 10
 10(S)+3
142(S)
157(3)
  2(S)
  5
  1
 22
 22+400(N)'
  1.4
  5.0
  7.1
101(S)
112(S)
  1-4(3)
  3.6
  0.71
 16
 16+286(N)'
Gas 7ired Heaters
Particular as
Sulfur Oxides (as SC2)'i'
Carbon Monoxide
Hydrocarbons (as CHu)
Hitrogen Oxides (as N02)

5-15
0.6
17
3
120-230

0.43-L.43
0.057
1.6
0.29
11.4-21.9
aSource:   Reference   7.
 Based on 3 heat  input of l.OxiO5 Btu/bbl of fresh feed with the following
 fuel heating  values:   Oil - 140,000 3tu/gal; Gas - 1050 3tu/scf.
C5 - Wt 2 sulfur in the fuel  oil
 Improper combustion  xay cause  a significant increase in emissions
 Use this emission factor for residual oils with less than 0.52 QK.5)  nitro-
 gen content.   For oil with higher nitrogen content QJ>0,5}, use emission
 factor of L2Q lb/103  gal
 Based on sulfur  content of 2000 gr/10s scf
                                 249

-------
                             TABLE  7-2.   ESTIMATED FUGITIVE NONMETHAKE  HYDROCARBON  EMISSIONS
                                           FROM A TYPICAL  ATMOSPHERIC DISTILLATION UNIT
ho
Oi
o
Eniiag ions
Source Type
Valvea

(V?

 0.1 putj 6 100'F)
Heavy Liquid
< 0.1 pal> % 100'F)
Hydrogen Service
Total

All

Light Liquid
> 0.1 pfilJ 3 100'F)
Heavy Liquid
< 0-1 p«U * 100'K)
To c u 1
All

All
All
Hydrocarbon
Hydrogen
Total

Number of Sources In Process Unit _
	 •• " Source
founts or Estimates Counts or Estimates Emission
From Radian Study From PES Study >e Factor. Ib/li
80

281

521
0
893"

-


11(15)

20(2B)
31(43)a
69a

3997
6C
1(2)
0
l(2)a

263 - 270 0.059

1663 - 1727 0.024

704 - 703 0.0005
0 0.018
2630 - 2700C

56 - 57b 0.005


26(36)-27(38) 0.25

11 (lb)-ll<15) 0.0',6
37(52)-38(53)b
0.070

8695 - 8930C 0.00056
0.19
0 1.4
0 0.11
0

Estimated Total
Emissions,
ir Ib/hr
5.25 -

6.74 -

0.262 -
0.
12.3

0.280 -


3.75 -

0.690 -
4.44 -
4.

2.24 -
1.
0.0
0.
0.0
25.2 _
15.9

41.4

0.352
0
57.7

0.285


9.50

1.29
10. 6
83

5.00
14
2. HO
0
2.60
82.6
 Physically Counted

 Counted  From Flow
c

dHeference  49.
                                            Ttiiu PES estimate Includes vacuum distillation as part  of the crude
                                            distillation unit.  Kitdlun ebtlmiitea for emissions from vacuum
                                            distillation are listed In Section  7.1.1.2 and may be added to the
                                            Radian estimates for atmospheric distillation tor comparJson to the
                                            PES estimates.

-------
                           TABLE  7-3.   ESTIMATED COMPOSITION  OF NONMETHANE HYDROCARBON FUGITIVE
                                          EMISSIONS FROM A  CRUDE DISTILLATION UNITa
Ni
S t rcaei


Estimated percentage ot emissions
attributed to each stream - %
Weighted contribution uf each ,
component to unit emissions - ppmw
Uunzenu
Toluene
Ethylbiinzune
Xy Leiics
Other Alkylbenzenea
Naphthalene
Anthracene
Ulplicny 1
Other I'olynuclear Aror»it5cs
n-ll«>xanc
Other Alkanea
Olefins
Cyclo Alkan«s

Crude
Oil
74



46
522
169
676
2S71
660
108
246
6051
13820
673680
0
44770

Straight run
naphtha
24



59
617
208
382
3904
344
1
147
3528
9167
117660
0
'J9503

Middle
distillate
1



0
0
0
1
8
1
1
0
56
0
8627
0
1024

Atmospheric
gas oil
1



0
0
0
0
1
0
0
0
2
0
9724
0
512


Totals
100Z



105
1139
377
1059
6/84
1005
110
391
9637
22987
&09691
0
145BOO
999096
                Based on GC-MS analysis of  liquid stream samples (and some vapor samples) ,
                Estimates hasc-ri on tho assumption thar fugitive emission compos! t. ion a  from
                sources in liquid stream service is the same composition as that of the
                liquid contained in the emission source.

                Compositions are estimated  to  2-3 significant figures.  Additional significant
                figures are a result of calculations! procedures, and they should not  be  given
                any Importance.

-------
          •    Electricity:  0.10 to 0.20 kW/bhl.

          •    Steam:  8 Ib/bbl.

          Atmospheric Emissions—Emissions from vacuum distillation units
include emissions from steam ejectors and barometric condensers, process
heater flue, gas emissions, and fugitive emissions.

          The size and number of ejectors and condensers used are determined
by the vacuum needed and the. vapor load.  To maintain a fractionator pres-
sure of no more than 0.4 psia, three ejector stages are usually required.
Process hydrocarbon emissions from steam ejectors have been estimated at
50 lb/10J bbl charge.  If barometric condensers are used, emissions may be
as much as 1,060 lb/103 bbl charge.   Nonc.ondensable hydrocarbon vapors
removed by the ejector system are released to the atmosphere unless com-
busted in a furnace, firebox or other combustion device.  Fugitive emissions
and emissions from process heaters are summarized in Tables 7-4 and 7-5.

7.1.1.3   Aromatica Extraction

          Aromatics are extracted from reformate streams by a liquid/liquid
solvent extraction process.  There are a number of proprietary commercial
extraction processes.  The Sulfolane and Udex processes account for the
majority of commercial installations for aromatics extraction:  each is in
use in more than 50 refineries throughout the world.  The Tetra process is
installed in more than 35 refineries.  Sulfolane, originally developed by
Royal Dutch/Shell, is licensed by the UOP Process Division of COP, 'Inc.,
as Udex.   The Tetra licensor is Union Carbide Corporation.  Most of the
remaining commercial installations are processes licensed by Howe-Baker
Engineers (Aromcx),  Snamprogetti S.p.A.  (Formex), and the Institute
Francais  due Petrole (IFF).
                                    252

-------
       TABLE 7-4.   TYPICAL  EMISSIONS FROM  VACUUM DISTILLATION
                     UNIT PROCESS HEATERS
                                EPA Emission Factor
                               (lb/103.gal-oil fired)
                               (lb/106 scf-gas fired)
                    Total Emissions
                    (lb/103 bbl  of
                     crude  oil feed)
Oil Fired Heaters
    Particulates
     - Distillate oil
     - Residual oil
          Grade A
          Grade 5
          Grede 6
                  Q
    Sulfur Dioxide
     - Distillate oil
     - Residual oil
    Sulfur Trioxidec
    Carbon Monoxide
    Hydrocarbons (as CHi,)
    Nitrogen Oxides
    (as N02)
     - Distillate oil
     - Residual oile
  7
 10
 10(S)+3
142(S)
157(S)
  2(S)
  5
  1
 22
 22+400(N)'
  1.4
  5.0
  7.1
  7.1(5)4-2.1
112 (S)
  3.6
  0.71
 16
 16+286 (N)'
Gas Fired Heaters
Particulars
Sulfur Oxides (as S02)
Carbon Monoxide
Hydrocarbons (as CH^)
Kitrogen Oxides (as NDj)

5-15
0.6
17
3
120-230

0.48-1.43
0.057
1.6
0.29
11.4-21.9 -
 Source:   Reference 7.
 Based on  a heat input of  l.OxlO5  3tu/bbl  of  fresh  feed with the following
 fuel heating values:   Oil -  140,000  Btu/gal;  Gas - 1050 Btu/scf.
CS = Vt %  sulfur  in the fuel oil
                                                                 f
 Improper  combustion may cause  a  significant  increase  in emissions
 Use this  emission  factor  for residual  oils with less  than  0.5% (N^-5). nitro-
 gen content.   For  oil with higher nitrogen content 0^0,5), use emission
 factor of 120 lb/103  gal
 Based  on  sulfur  content  of  2000  g,r/10s  scf
                                      253

-------
TABLE 7-5.   ESTIMATED FUGITIVE NONMETHANE HYDROCARBON EMISSIONS
            FROM A TYPICAL VACUUM DISTILLATION UNIT


Emissions
Source Type
Valves






Open-End
(Sample)
Valveu
Pumpu (Pump
Seals)



Drains
Flanges &
Fittings

Kellef Valves
Couiprctisoru
(Compressor
Seals)

"CounueJ From
Kul 1 mated
cRef ereur.e W


Stream Service
Classification
Gas/Vapor
Light Liquid
(VI- > O.I psla j> 100'K)
Heavy Liquid
(VP < 0.1 p»la 8 100'f)
Hydrogen Service
Total

All

Light Liquid
(VP > 0.1 polu 8 100'T)
Heavy Liquid
(VP < o.i psia a inn'F)
Total
All

All

All
Hydrocarbon
Hydrogen
Total

Flow Diagrams


Number of Sources In

Counts or Estimates
From Radian Study
50

45

405
0
5()0b

-


2( 2)

14(20)
I6(22)b
42b

1785
b
6
0
0
0




Process Unit

Counts or Estimates
From PES SCudyc
71

142

497
0
7lOb

14*


2( 3)

7(10)
9(13)a
-
K
2350D

-
0
0
0






Emission
Factor, Ib/hr
0.059

0.024

0.0005
0.018


0.005


0.25

0.046

0.070

0.00056

0.19
1.4
O.I I







Emissions,
Ib/hr
2.95 - 4.19

1.08 - 3.41

0.203- 0.249
0.0
4.23 - 7.85

0.070


0.50 - 0.75

0.46 - 0.92
0.96 - 1.67
2.04

i . 00 - 1 . 32

1.14
0.0
0 . 0
0.0
10.3 - 15.0




-------
          Tetraethylene glycol, mixtures of several glycols, diinethyl-
sulfoxide, formul-raorpholine, and tetrahydrothiophene-dioxide are some of
the .solvents used.

          Process Conditions—Typical operating parameters for the most
widely used processes are given in Table 7-6.

          Atmospheric Emissions—Since aromatlcs extraction is a closed
process, the only significant emissions are fugitive hydrocarbon emissions.
These emissions are summarized in Tables 7-7 and 7-8.

7.1.2     Thermal Operations

          Thermal operations are noncatalytic processes used to convert
large hydrocarbon molecules into smaller molecules at high temperatures.
These processes convert low value stocks such as heavy gas oil into lighter,
more valuable products.  The thermal operations currently used by U.S.
refineries include delayed coking, fluid coking, visbreaking, and thermal
cracking.

7 .1.2.1   Visbreaking

          Visbreaking (viscosity breaking)  is a mild thermal cracking
operation used to reduce the viscosity of materials such as atmospheric or
vacuum residuals and pitch.  This procedure reduces the amount of valuable
light heating oil which must be blended with the residuum to produce a fuel
oil of acceptable viscosity.

          Process Conditions—Typical operating parameters and utility
requirements for a visbreaking operation are given below.38>°°
                                   255

-------
         TABLE 7-6.  OPERATING PARAMETERS AND UTILITY REQUIREMENTS
                     FOR THREE AROMATICS EXTRACTION PROCESSES
      Condition
                                 Udex
                                                  Process
                  Sulfolane
                    Tetra
Stripping Steam
  Ratio, wt/wt
    0.6
  0.13
Stripper Bottom
  Temper a t u re, ° F
  290
375
Extractor Top
  T emp e r a t u r e,  °F
  290
212
Extractor Pressure,
  psig
  110
 15
Feed Temperature, °F
  240
240
Utilities, per barrel
  of feed
Steam, Ib
  400
  2.5
125
Fuel, 103 btu
                    190
Cooling Water, gal
1,200
530
650
Electricity, kWh
    1.3
  0.8
  0.3
                                    256

-------
                          TABLE 7-7.  ESTIMATED FUGITIVE NONMETHANE HYDROCARBON EMISSIONS

                                      FROM A TYPICAL AROMATIC EXTRACTION UNIT
ro
Ln
—l

Emissions
Source Type
Valves





Open-End
(Sample)
Valviia
1'uiopa (Pump
Seals)

Drains
Flmigiia 61
Fittings
Relief Vnlvea
Compressors
(Compressor
Seals)

Counted from
Ear 1 mated

Stream Service
Classification
Gas/Vapor
Light Liquid
(vr > o. i psin C' IOU'F)
Heavy !Ji|uUl
(VP < 0.1 pala a IflO'F)
Hydrogen Service
Total

All

Light Liquid
(VV > 0.1 pals t* 100'F)
Heavy Liquid
(VF < 0.1 poia e IQO'K)
Totul
All

All
All
Hydrocarbon
Hydrogen
Total

Flow Diagrams

Number of Sources In
Countb or Kutlmateu
From Radian Study
60

486

54
o.
600b

-

16(23)
2( 3)
18(25)k


2142b
6b
0
0
0



Process Unit
Count u or R^Llrautua
From PES Study
206

1370

4B3
0
20591*

29a

17(24)
6( 8)
23(32)a
-

6815L
-
0
0
0




Emission
Factor, Ib/hr
0.0b9

0.024

0.0005
0.018

0.005

0.25
0.046
0.070

0.00056
0.19
1.4
0.11





Einlsulouu,
Ib/hr
3.54 - 12.

11.7 - 32.

0.027 - 0.
0.0
15.3 - 45.

0.145

• 5.75 - 6.
0.138 - 0.
5.89 - 6.
3.29

1.20 - 3.
1.14
0.0
0.0
0.0
27.0 - 59.



2

9

242
y~



00
368
37


B2




6


CKeferenc<: 49,

-------
                                     TABLE 7-8.  ESTIMATED  COMPOSITION OF FUGITIVE EMISSIONS
                                                   FROM  AN AROMATICS  EXTRACTION UNITa
r-o
OT
CO
Scream


Reformats
Solvent
Aromatic
Extract
Raf flnate
Totals
Estimated percentage oC emissions
attributed to each stream - %
12
0
44
44
1002
Weighted contribution of. each
component to unit emissions - pprnw^













Benzene
Toluene
Ethylbenzene
Xylcncis
Other Alkylbenzenes
Naphthalene
Anthracene
Biphenyl
Other Polynuclear Aromatics
n-Hexane
Othar Alkanes
OlefJ.ns
Cyclo Alkanes
648
9324
4020
20508
38923
858
0
0
84
2380
42/20
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
7850
112948
48695
248420 '
21120
44
0
0
44
44
836
0
0
22
330
132
660
1012
22
0
0
22
27720
410080
0
0
8520
122602
52847
269588
61060
954
0
0
150
30644
453637
0
0
1000000
             3Baseil on GO-MS  analysis of liquid stream samples  (and some vapor samples).
              Estimates based on the assumption that fugitive emission compositions from
              sources in liquid stream service is the same  composition as that of the
              liquid contained in the emission source.

             ^Compositions are estimated to 2-3 sip.njfic.int figures.  Additional significant
              figures are a result of calculations! procedures, and they should not be given
              any  importance.

-------
          •    Temperature:  85C to 950°F.

          •    Pressure:  50 to 300 psig.

          •    Electricity:  0.47 kWh/bbl.

          •    Steam  (300 psig):  8.7 Ib/bbl.

          •    Fuel:  88 x 103 Btu/bbl.

          Atmospheric Er.iissions—Emissions from visbreaking operations
include process heater flue gas and fugitive emissions.  A typical vis-
breaking unit will have one heater.  Emissions from this heater are
summarized in Table 7-9.  Fugitive emissions are summarized in Table 7-10.

7.1.2.2   DelayedCoking

          Delayed coking is a semi continuous process in which the heated
charge (heavy gas oil or residuum)  is transferred to large coking drums.
The coking drums provide sufficient residence time fur the cracking reac-
tions to proceed to completion.  During the reaction, coke is produc.ed and
deposited within the coke drum.  Delayed coking is likely to remain an
important refining process since it simultaneously converts low-value
materials to lighter, more valuable products while producing coke as a
valuable by-product.

          In many cases, the coker  is mounted over a railroad track so that
the coke can be discharged directly into railroad cars.  The coke is
retained in the cars while water and coke fines drain off and flow to a
sump.  Alternatively, the coke can  be directed to a concrete apron or pit.

          1'rocess Conditions—Temperature and pressure influence the rate
of cracking and coking reactions.   At higher heater outlet temperatures
                                   259

-------
          TABLE 7-9.   TYPICAL  EMISSIONS FROM  VISBREAKTNG
                        UNIT PROCESS HEATERS
                                                   a
                                EPA Emission Factor
                                (lb/103.gal-oil fired)
                                (lb/106 scf-gas fired)
Total Emissions
(lb/103 bbl of
  fresh feed)
Oil Fired Heaters
Particulates
- Distillate oil
- Residual oil
Grade A
Grade 5
Grade 6
Sulfur Dioxide
- Distillate oil
- Residual oil
Sulfur Trioxide0
Carbon Monoxide
Hydrocarbons (as CHi,)
Nitrogen Oxides
(as N02)
- Distillate oil
- Residual oil6
Gas Fired Beaters
Particulates
Sujfur Oxides (as S02)
Carbon Monoxide
Hydrocarbons (as CHi,)
Nitrogen Oxides (as N02)


2

7
10
10(S)+3

1A2(S)
157(S)
2(S)
5
1


22
22+400 (Mr

5-15
0.6
17
3
120-230


1.3

A. 5
6. A
6.4(S)+1.9

91.3(S)
101 (S)
1.3(S)
3.2
0.6A


1A
1!<.5) nitr
 gen content.   For oil with liigher nitrogen content (N-'O^S),  use cciission
 factor of 120 lb/103  gal
 Based  on sulfur content  of  2000  £r/106  scf
                                    260

-------
            TABLE 7-10.  ESTIMATED FUGITIVE NONMETHAflE  HYDROCARBON EMISSIONS
                         FROM A TYPICAL VISBREAKING  UNIT
Source Type
Valves






Open-End
(Sample)
Vulvea
Piiiipu (Pump
iiuals)



Dralna
Plunges &
Fittings
Relief Valvea
Compressors
(Compressor
Seals)

Process
SLreaiE Service
Classification
Gaa/Vu|ior
Light Liquid
(V? > 0.1 (isla (f 100'C)
Heavy Liquid
 0.1 pslJ « 100'F)
Heavy LlquLJ
(VP < 0.1 pil» 8 100'K)
Total
All

All
All
Hydrocarbon
Hydrogen
Tocal

Number of Suurceu in Process Unit
30

46

224

300*
20Q


2C 2)

7(10)
9(12)a
23a
•
1071°
6a
0
0
0

Sunroc
tiuiiseioii
Factor. Ib/hr
0.059

0.024

0.0005
O.Olfa

0.005


0.25

0.046

0.070 '

0.00056
0.19
1.4
0.11


Estimated Total
Emissions,
Ib/hr
1.77

1.10

0.112
0.0
2.98
0.100


0.50

0.46
0.96
1.61

0.60
1.14
0.0
0.0
0^0
7.29
Estimated

-------
and/or increased drum pressure, the yield of gas, naphtha and coke is
increased at the expense of a lower gas oil yield.  Typical operating
parameters for delayed coking are shown below.  >J">J >J

          •    Heater outlet temperature:  900 to 975°F.

          *    Coke drum pressure:  20 to 100 psig.

          •    Recycle ratio:  0.1 to 1.0.

          Atmospheric Emissions—Emissions from delayed coking operations
include emissions from decoking operations, process heater flue gas, and
fugitive emissions.

          The steam injected into the drum as part of the decoking operation
is condensed and the remaining vapors usually flared.  During the removal of
the coke from the drum, particulates are released, as are hydrocarbon vapors
entrained in the coke.  A water quench is often used to minimize particulate
emissions.  This water contains sulfur components and it may be a source of
objectionable odors.  Emission factors for the decoktng operation were not
available.  Process heater and fugitive emissions are summarized in Tables
7-11, 7-12,  and 7-13.

7.1.2.3   Fluid _Cg_k_ing

          Fluid coking, like delayed coking,  was  developed to convert
residuals, tars, and resins produced during certain refining operations
to lighter,  more valuable liquid products and coke.   Yields are similar
to those  from delayed  coking,  except that coke production is significantly
lower.  Also, the coke produced is usually of insufficient quality for
-   ,    .  ,     38,53
industrial use.
                                   262

-------
         TABLE 7-11.   TYPICAL EMISSIONS FROM DELAYED COKING
                        UNIT PROCESS  HEATERS
                                EPA Emission Factor
                                Clb/103 gal-oil fired)
                                (lb/106 scf-gas fired)
                    Total Emissions
                    (lb/103 bbl of
                      cokcr  feed)
Oil Fired Heaters
    Particulates
     - Distillate oil
     - Residual oil
          Grade 4
          Grade 5
          Grade 6
    Sulfur Dioxide
     - Distillate oil
     - Residual oil
    Sulfur TrioxideC
    Carbon Monoxide
    Hydrocarbons (as CK4)'
    Nitrogen Oxides
    (as. N02)
     - Distillate oil
     - Residual oile
  7
 10
 10(S) + 3
142(S)
157(S)
  2(S)
  5
  1
 22
 22+400 (N)'
  3.4
 12
 17
 17(S)  + 5.1
243(S)
269(S)
  3.4(S)
  8.6
  1.7
 38
 38+686(N)'
Gas Fired Heaters
Particulates
Sulfur Oxides (as SC^)
Carbon Monoxide
Hydrocarbons (as CH^)
Nitrogen Oxides (as ^02)

5-15
0.6
17
3
120-230

1.1-3.4
0.14
3.9
0.69
27-53
 Source:   Reference 7«
 Based on a heat  input of 2.4xlt)s.  Btu/bbl  of  fresh  feed  v.'ith  the following
 fuel heating values:   Oil - 140,000 Btu/gal;  Gas - 1050 Btu/scf,
CS = Wt % sulfur  in the  fuel oil
 laproper coxbustion raay cause  a  significant  increase  in emissions
"Use this emissior.  factor for residual  oils with less  than  0.5%  (JK.5) nitro-
 gen content.   For  oil with higher ni'trop.en content (K>0,5),  use c-caisslon
 factor of 120 lb/103  gal
 Based  on  sulfur  content  of  2000  gr/10G  scf
                                   263

-------
           TABLE 7-12.  ESTIMATED FUGITIVE NONMETHANE  HYDROCARBON EMISSIONS
                         FROM A TYPICAL DELAYED COKING  UNIT
Emissions
Source 'i'yi'e
Vulvea






Open-End
(Sample)
Valves
Pumps (Pump
Seals)

Proceisu —
Scream Service C,
Clasuli lent Jon
Gas/Vapor
Light Liquid
(VP > O.l p«u e loa-t)
Heavy Liquid
(VP < U.I pala !_' 100'F)
Hydrogen Service
Total

All

Light Liquid
(VP > 0.1 psU @ lOO'F)
Heavy Liquid
(VP < 0.1 p.la 8 UK)'?)

Drains
Flanges &
Fittings
Relief Valveu
Compressors
(Compressor
Seals)

To Lai
All

All
All
Hydrocarbon
Hydrogen
Total

Niimher of Sourceu
In Hroceaa Unit

ounts or Estimates Counts or Estimates Em
From Radian Study From PES Studyc Fuci
30

57

213
0
300l)

-


2( 3)

mo)
9(13)''
23b
K
1071
6b
0
0
0

17H

1308

291
0
1777b

43a


lfl(25)

4( 6)
22(31)"
-
i,
5B7i
-
3( 6)
0( 0)
3( 6)

a.

0.

0.
0.


0.


0.

0.

0.

a.
0.
i.
0.


jrce Estimated Total
laalon Emisalons.
tor, Ib/lu Ib/hr
059

024

0005
01 b


005


25

046

070

00056
19
4
11


1.

1.

0.

3.




0.

0.
1.


0.

0.

0.
a.
77 -

•37 -

107 -
0.
25 -

0.


750 -

460 -
21 -
1.

60 -
1.
0
0.
0
03 -
10.

31.

0.
[>
5

4

146

42.0

215


6.

0.
6.
61

3.
14
8.
0
a.
63.




25

276
53


29

4

*
5
Counted From Flow Ulagramu
EsrImuiod
Reference 49.

-------
                                    TABLE 7-13.   ESTIMATED  COMPOSITION  OF FUGITIVE  EMISSIONS
                                                    FROM  A DELAYED COKING  UNITa
Ui
Stream

Estimated percentage of emissions
attributed to each stream - %
Weighted contribution cf each
component to unit emissions - pprnw*5
Benzene
Toluene.
Ethylbenzene
Xylencs
Other Alkylbenzenes
Naphthalene
Anthracene
ftiphenyl
Other Polynuclear Aromatics
n— Itcxnnc
Other Alkaiies
OlcCins
Cyclo Alkanas
Hydrogen
Vacuum
Re 3 id
0


0
0
0
0
0
0
0
0
0
0
0
0
0
0
Coke
0


0
0
0
0
0
0
0
0
0
0
0
0
0
0
Cracked
Naphtha
57


1642
51175
12215
97727
138778
6242
0
0
3694
6743
116340
97322
38122
0
LPG
OleEins
14


0
0
0
0
0
0
0
0
0
0
56000
84000
0
0
Fuel
Gas
29


0
0
0
0
0
0
0
0
0
0
266800
17400
0
5800
Totals
100%


1642
51175
12215
97727
138778
6242
0
0
3694
6743
439140
198722
38122
5600
1000000
                  Based on  GC-MS analysis of liquid stream samples (and some vapor samples).
                  Estimates based on the .incumption that fugitive emission  coirrpositions iron:
                  sources in liquid stream  service is the same composition  as that of the
                  liquid contained in the emission source.

                  Compositions are estimated to 2-3 significant figures.  Additional significant
                  figures are a result oi calculational procedures, and they should not be given
                  any Importance.

-------
          Flexicoking is a relatively recent integration of conventional
 fluid  coking  and  coke gasification.  The coke gas produced may be sub-
 stituted  for  refining fuel gas or natural gas.  The net coke production is
 1-2 weight percent of the feed, as compared to 10-20 percent for con-
 ventional fluid coking.  No commercial flexicokers have been installed in
 the U.S., but extensive commercial experience has been accrued abroad.

          Process Conditions—Fluid coking and flexicoking operating condi-
 tions  are summarized in Table 7-14.

          Potentially Hazardous At mo spheric. Em 1s s ions—Emissions from fluid
 coking include burner vessel flue gas and fugitive emissions.  No process
 heaters are needed, because heat is supplied by the coke.

          Combustion of the coke produces a flue gas containing substantial
 quantities of carbon monoxide with lesser amounts of SO ,  NO , organics,
 and particulates.  CO emission rates have been estimated at 30 pounds per
 barrel of feed."J  CO boilers are used to recover the substantial energy
 in this gas and to reduce the concentrations of CO and other combustibles.
 However, high combustion temperatures may cause an Increase in N0x emissions.
 Both SO, and NO   concentrations will increase if auxiliary fuel is used.
       X       X

          Fugitive emissions are summarized in Table 7-15.

 7.1.3     C rack ing Ope rations

          Cracking operations convert heavy petroleum fractions into lighter,
more valuable products.   Two processes,  catalytic cracking  and hydrocracking,
provide a substantial portion of the cracking capacity in  the United States.
Although these processes are similar in that they crack heavy fractions to
produce lighter products,  there are considerable differences between them
in both the operating principles and the pollution potential.   The choice
of one process over the other is usually an economic one.
                                   266

-------
             TABLE 7-14.  PROCESS CONDITIONS FOR FLUID COKING
                          AND FLEXICOKING
                                        Fluid Coking             Flexicoking
Temperature, °F

          Reactor                            950                     950

          Burner                           1,150                   1,150

          Gasifier                          —                  1,300-1,800


Pressure, psig

          Reactor                             10                      10

          Burner                              11                      11

          Gasifier                          	                     24-45


Utilities - per barrel feed

          Electric Power, kWh                  5.5                    13

          Fuel, MM Btu                         0                       0
Source:  References 38,50,54,56.
                                    267

-------
                               TABLE 7-15.   ESTIMATED FUGITIVE NONMETRANE HYDROCARBON
                                            EMISSIONS FROM A TYPICAL FLUID COKING UNIT
O\
00

Emluaions
Source Type
ViiLvea





Open-End
(Sample)
Valvea
PuiD|ia (Pump
Sealu)


Drains
Flanges &
Fittings
Relief Vulveu
Copipruesora
(Compressor
St;n la)

Process
Stream Service
Clusulf icut Ion
Gas/Vapor
Light Liquid
(VT > 0.1 fata 6 100'F)
Heavy Liquid
(VP < O.L paU e 100'K)
Hydrogen Service
To en I

All

I.lgllC Liquid
(VF > 0.1 psla 0 LOO'F)
Heavy l.i(|nlil
(VP < 0.1 paltt @ LOO*P)
Total
All
All
All
Hydrocarbon
Hydrogen
Total



Number of Sources In Process Unit
30

58

216
0
304 a

-

2( 3)
7(10)
9(13)a
28a
1047a
6b
4(8)
0(0)
4(8)a

Source
Emission
Factor, ib/hr
O.OS9

0.02/1

O.OOOb
0.018

0.005

0.25
0.046

0.070
0.00056
0.19
1.4
0.11

Estimated Total
Emissions.
Ib/hr
1.77

L.39

0.10B
0.0
3.27

~

0.75
0.46
1.21
1.96
0.5B6
1.14
11.2
0.0
11.2
19.4
Physically Counted
'Estimated





-------
 7.1.3.1    Catalytic  Cracking

           Several  types  of  catalytic  cracking  processes  have  been  developed:
 fluid-bed  catalytic  cracking  (FCC) units,  and  moving  bed designs such  as
 Thermofor  (TCC)  and  HoudrifJow  (11CC)  cracking  units.  With  the advent  of
 new  catalysts, major  design and operational  changes have been incorporated
 in FCC unit operation.   By  contrast,  no major  changes in moving bed  type
 units have been  observed and  these, units are being phased out.

           In a typical FCC  unit the reactor  contains  a bed  of powdered
 catalyst which is kept in a fluidized state by  the flow  of  vaporized feed
 material and steam.

          Thermofor and  Koudriflow catalytic cracking units use beaded or
 pelleted catalysts.

          Process Conditions—Typical operating conditions  for a conven-
 tional FCC unit  and for  one with high temperature regeneration (KTR) are
 given in Table 7-16.

          Atmospheric Etuissions—Emissions from catalytic cracking units
 include catalyst regeneration emissions, process heater  flue  gas emissions,
 and fugitive emissions.

          Many refiners use a CO-burning waste heat boiler  to recover  the
 energy contained in the flue gas from the regenerator.   This  boiler also
 significantly reduces the emission of CO and other combustible contaminants.
 Increased emissions of "thermal NC ." nay occur, however,  along with the
                                  X
production of SO,, from sulfur in the auxiliary fuel.   Typical emission
                A.
 levels for regenerator flue gas with and without a CO boiler  are given in
Table 7-17.  This table also lists results of sampling conducted during
 this program.   Detailed information on these sampling results is given in
Appendix B (Volume 3 of this report).
                                   269

-------
           TABLE 7-16.  TYPICAL OPERATING CONDITIONS FOR FLUID
                        CATALYTIC CRACKING
Reactor Temperature, °F                                        885 - 1,025


Regenerator Temperature, °F

     Conventional Regeneration                                1,000 - 1,100

     HTR                                                      1,100 - 1,350


Coke Content of Spent Catalyst, Wt %

     Conventional Regeneration                                      6

     HTR                                                            5


Coke Content on Regenerated Catalyst, Wt %

     Conventional Regeneration                                  0.2 - 0.3

     HTR                                                       0.0.1 - 0.1
Source:   References 57,58.
                                    270

-------
                       TABLE 7-17.   EMISSION RATES PROM FCC  REGENERATORS,
                                      BEFORE AND AFTER CO BOTLER
Chemical Spccieo
' S02, ppcnv
SOa, ppmv
K0x (33 N02), ppmv
CO, Z Vol.
C02, Z Vol.
Oj, Z Vol.
Nj, Z Vol.
HjO, 7. Vol.
Hydrocarbons, ppmv
Ammonia, ppmv
AldrhydcR, ppmv
Cyanides, ppmv
Participates, gr/SCF
Temperature, °F
Emi9.glons without
.CO Boiler
(Reference 58)
130-3300
HAC
8-394
7.2-12.0
10.5-11-3
0.2-2.4
78.5-80.3
13.9-26.3
98-1213.
0-675
3-130
0.19-0.94
0.08-1.39
1000-1200
Emissions with
CO Boiler
(Reference 58)
Up to 2700
NAC
Up to 500
0-14 ppmv
11.2-14.0
2.0-6.4
82.0-84.2
13.4-23.9
. NAC
KAC
MAC
NAC
0.017-1.03
485-820
Data from ,
Current Program
14.4-371
0.65-13.5
94.1-453
0.0-1.0
13.5-16.1
3.2-7.0
77-82.7
9.2-22.7
0.28-46.2
0.0-15-4
0.0-19.6
0.0-19.1
0.012-0.304
386-727
Total Emissions based on Data frora
Current Program - (lb/1000 bbl feed)
3-332
0.5-9.0
41-193
0.0
-
-
-
1.1-12.0
0.06-1.65
0.0-4.6
0.0-4.S4
7.9-C5.2
—
.All concentrations on dry basis
 Based on sampling of 5 otacks
"Hot available

-------
          High temperature regeneration or combustion promotion catalysts
can reduce the level of CO in the regenerator flue gas to 200-2,000 ppra,
                  S 5
usually < 500 ppm."   Because the temperatures involved are lower than those
                                                         r o
in a CO boiler, thermal NO  emissions are somewhat lower.   Fugitive, emis-
sions and emissions from process heaters are summarized in Tables 7-18,
7-19 and 7-20.
7.1.3.2   Hydrocracking

          Hydrocracking is a high-tenperature,  high-pressure process for
converting heavy feedstocks into lighter products in the presence of
hydrogen and a catalyst or series of catalysts.  The process is highly
flexible and produces low-sulfur, low-nitrogen products.  A hydrocracker
    ,    .,                     38.51,59,60
may be single-stage or two stage.  '   '

          Process Conditions—The severity of the process conditions
required for hydroeracking depends on the type of feedstock and the degree
of cracking desired.  The primary reaction variables are the reactor
temperature and pressure and the nitrogen and sulfur content of the feed
and off-gases.  A summary of typical operating conditions and utility data
is given below:59,GO

          •    Pressure:  1,000 to A,000 psig.

          •    Temperature:  400 to 850°F.

          •    Hydrogen recycle:  8,000  to 15,000 scf/bbl feed.

          •    Hydrogen consumption:   1,500 to  2,500 scf/bbl feed.

          •    Fuel:  100 to 250 x TO3 Btu/bbl  feed.
                                   272

-------
      TABLE 7-18.   TYPICAL EMISSIONS  FROM CATALYTIC CRACKING
                    UNIT PROCESS HEATERS
                                EPA Emission Factor
                               (ib/IO3 gal-oil fired)
                               (lb/10G scf-gas fired)
                    Total Scissions
                    (lb/103 bbl of
                      fresh feed)
Oil Fired Heaters
    Participates
     - Distillate oil
     - Residual oil
          Grade 4
          Grade 5
          Grade 6
    Sulfur Dioxide0
     - Distillate oil
     - Residual oil
    Sulfur Trioxide0
    Carbon Monoxide
    Hydrocarbons (as CHt,)
    Nitrogen Oxides
    (as N02)
     - Distillate oil
     - Residual oil6
Gas Fired Heaters
    Participates
    Sulfur Oxides (as S02)
    Carbon Monoxide
    Hydro carbons (as CH1+)
    Nitrogen Oxides (as  N02)
  7
 10
 10(S)+3
142(S)
157(S)
  2(S)
  5
  1
 22
 22+400(N)'

  5-15
  0.6
 17
  3
120-230
 10
 10(S)+3
160(S)
  2(S)
  5
  1

 22
 22+409(N)'

  0.7-2.0
  0.08
  2.3
  0.41
 16-31
 Source:   Reference  7.
 Based on a heat  input of  100,000 Btu/bbl of  fresh feed vlth the following
 fuel heating  values:   Oil -  140,000  btu/gal; Gas - 1050 Etu/scf
CS = Wt % sulfur  in the oil
 Improper combustion nay cause a significant  increase in emissions
EUsc this emission  factor  for residual oils vith lass than 0.5% (N<.5)_ nitro-
 gen content.   For  oil with higher nrtrogen content (N>0,5), use emission
 factor of 120 lb/103  gal
 Based on sulfur  content of 2000 gr/106 scf
                                    273

-------
              TABLE 7-19.   ESTIMATED FUGITIVE NONMETHANE HYDROCARBON  EMISSIONS
                            FROM A TYPICAL CATALYTIC  CRACKING UNIT

Em I tin Ions
Source Type
Valves






Open-End
(Sample)
Valves
Purana (Pump
Seals)


Drains
Flangea &
Fittings
Kellei Valves
Compressors
(Compressor



Stream Service
Glaus If leal, ion
Gas/Vapor
Light Liquid
(«p > o.i p»u e loo'K)
Heavy Liquid
 0.1 l>sls (J IQO'F)
Heavy Liquid
Total
All

All
All
Hydrocarbon
Hydrogen
Totul

Number of Sources In
Counts or Estimates
From Radian Study
184

400

521
0
1314a

-


13(18)
17(24)
30(42)a
65a

4214a
6C
4(a)
0
4(8)a

Process Unit
Counts or Estimates
FroiD I'KS Study
849

889

1167
0
2905C

67


16(22)
21(29)
37(52)b
-

96:i!.c
-
4(8)
0
4(8)«>


Emission
Factor, Ib/hr
0.059

0.024

0.0005
o.oia


0.005


0.25
0.046

0.070

0.00056
0.1!)
1.4
0.11



Emissions.
Ib/hr
22.7 - 50.1

9.82 - 21.3

0.261 - 0.584
0.0
32.8 - 72.0

0.335


4.5 - 5.50
1.10 - 1.13
5.60 - 6.83
4.55

2.36 - 5.40
1.14
11.2
0.0
11.2
58.0 - 101
 Physically Counted

 Counted From 1 low Diagrams
r>
 Hbtiiunted

 Reference  49.

-------
                                     TABLE  7-20.   ESTIMATED COMPOSITION OF  FUGITIVE  EMISSIONS
                                                     FROM A  FLUID CATALYTIC CRACKING UNIT3
ro
^j
Ln

Estimated percentage of emissions
attributed to each stream - %
Weighted contribution of each
component to unit emissions - ppmw "
Benzene
Toluene
Ethyl-benzene
Xylerics
Other Alkylbenzenes
Naphthalene
Anthracene
Eiphenyl
Other Polynucl.ear Aroroatics
n-Hexane
Other Alkan.es
Olcf Lnsj
Cyclo Alkanes
Hydrogen


Atmospheric
Gas Oil
1



0
0
0
0
1
0
0
0
2
0
9495
0
500
0

S trcam
Fuel
Gas
30



0
0
0
0
0 .
0
0
0
0
0
216000
18000
0
6000


LPG
Olefing
23



0
0
0
0
0
0
0
0
0
0
92000
138000
0
0


Cracked
Naphtha
45



1296
40401
9644
77153
109562
497.8
0 .
0
2916
532-1
91850
76833
30096
0


Lt. Cycle
Gas Oil
1



0
0
0
6
267
590
103
102
6245
0
1906
368
412
0


Hvy. Cycle
Gas Oil
0



0
0
0
0
0
0
0
0
0
0
0
0
0
0


Totals
100%



1296
40401
9644
77159
109830
5518
103
102
9163
5324
471251
233201
31008
6000
10000CO
             8Based on GC-MS analysis of liquid  stre.nm samples  (and some vapor samples).
              Estimates based on  the assumption  that fugitive emission composition;-;  from
              sources in liquid stream service is  the same composition as that of  the
              liquid contained in the emission source.

             ^Compositions are estimated to 2-3  significant ligures.  Additional significant
              figures are a result of calculational procedures, and they should not  be  given
              any  importance.

-------
          •    Power:  6  to  15 kWh/bbl feed.

          •    Space velocity:  0.2 to 1.0 v/hr/v.

          Atmospheric Emissions—Emissions from hydrocracking include emis-
sions  during periodic catalyst regeneration, process heater flue gas emis-
sions, and fugitive emissions.

          During regeneration large quantities of carbon monoxide and other
pollutants may be released,  but, because regeneration may only be required
after  several months or years of operation, total averaged emissions from
this source are generally insignificant.

          Process heater and fugitive emissions are summarized in Tables
7-21 and 7-22.

7.1.4     Hydroprocessing

          Hydroprocessing refers to those processes in which hydrogen is
mixed with a variety of feedstocks and passed over a catalyst at elevated
temperature and pressure.  The hydrogen reacts with .sulfur and nitrogen
containing compounds in the  feedstock to form hydrogen sulfi.de and ammonia.
Heavy metals, oxygen and halides are also removed via hydroprocessing.
Hydroprocessing may also be used to stabilize unsaturated hydrocarbons
such as olcfins by converting them to saturated materials.

          Hydroprocessing operations may be. divided into three categories,
according to the severity of the process:  (1) hydrocracking, in which 50
percent or more of the feed is reduced in molecular weight;  (2)  hydro-
refining, in which 10 percent or less of the feed is reduced in molecular
weight; and (3) hydrotrcating, in which essentially no reduction in molecu-
lar weight occurs.
                                   276

-------
         TABLE 7-21.   TYPICAL EMISSIONS FROM HYDROCRACKING
                        UNIT  PROCESS  HEATERS
                                EPA Emission Factor
                               (lb/103 gal-oil fired)
                               (lb/106 scf-gas fired)
                                                         Total EiaissioDS
                                                         (lb/103 bbl of
                                                           fresh  feed)
Oil Fired Heaters

    Particulates
     - Distillate oil
     - Residual oil
          Grade 4
          Grade 5
          Grade 6
                  £
    Sulfur Dioxide

     - Distillate oil
     - Residual oil
                   ^
    Sulfur Trioxide

    Carbon Monoxide

    Hydrocarbons (as

    Nitrogen Oxides
    (as N02)
     - Distillate oil
     - Residual oile
Gas Fired Heaters
    Particulstes
    Sulfur Oxides (as S02)
    Carbon Monoxide
    Hydrocarbons (as CHi^)
    Nitrogen Oxides (as N02)
                                                              2.9
7
10
10(S)+3
1«(S)
157(S)
2(S)
5
1
22
2 2+400 (N)
5-15
0.6
17
3
120-230
10
lit
14(S)+4.3
203(S)
224(S)
2.9(3)
7.1
1.4
31
31+571 (N)'
0.95-2.9
OJ1
3.2
0.57
22.9-43.8
 Source:  Reference  7.

 Based on a heat input of 200,COO Btu/bbl  of  fresh  feed with the following
 fuel heating values:  Oil - 1-40,000  Btu/gal;  Gas -  J050 Btv./scf

:S = Wt•% sulfur in the oil

 Improper combustion nay cause  a  significant  increase ir. emissions
e.
 Use this emission factor for residual  oils with  less than 0.5% 0^-5) nitre*
 gen content.   For oil with  higher  nitrogen content  G^CKS), use emission
 factor of 170  lb/103  gal
 Based on sulfur content  of  2000  gr/10c scf
                                    277

-------
                          TABLE  7-22.   ESTIMATED  FUGITIVE NONMETHANK  HYDROCARBON EMISSIONS

                                        FROM A TYPICAL HYDROCRACKING UNIT
M
-~J
oo

Emlasloiiu
Source Type
Valves






Open-End
(Sample)
Valves
Pumps (Pump
Seal a)



Uraina
Flanges &
Fittings
Htillef Valveu
Compressors
(CompreBSor
Seals)

Process
Stream Service
Classification Number
Gas /Vapor
Light Li O.L pala $ 100' f)
Heavy Liquid
(VP < 0.1 p»l» S 100*10
llyti IOKKH Service
Total

All

LigliC Liquid
(VP > 0.1 pa 1,1 (! IDO'F)
Heavy Liquid
(VP < 0.1 pala 9 100'F)
Total
All

All
All
Hydrocarbon
Hydrogen
Total



of Sources In Process Unit
175

375

307
75

-------
          Hydrocracking is discussed  in Section 7.1.3.  The. following
sections describe hydrorefining and hydrotreating processes.

7.1.4.1   _Hy drorefining

          Hydrorefining is used primarily for reducing the sulfur, nitrogen,
or metal content of heavy feedstocks for farther processing, blending, or
direct use.  Hydrodesulfurization is particularly important for catalytic
cracking feeds.

          The mechanism of the hydrorefining process is essentially the same
as that for one-stage hydrocrackir.g, discussed in Section 7.1.3.2, except
that the emphasis Is on removal of H2S and NH3 and cracking conditions are
much less severe.

          Process Conditions—Process conditions lor hydrorefining vary with
the feedstock and the desired products.  A range of typical conditions and
utility requirements is given below.

          •    Temperature:   390 to 800°F.

          •    Pressure:   500 to 800 psig.

          •    Electricity:   19 to 365 kWh/bbl.

          •    Heater Fuel:   0 to 70,000 Btu/bbl.

          •    Steam:  1  to  10 lb/bb.1 .

          •    Cooling Water:  160 gal/bbl.
                                   279

-------
          Atmospheric Emissions—Emissions  from hydrorefining operations
include emissions during catalyst regeneration, process heater flue gas
emissions, and fugitive emissions.

          During catalyst  regeneration, large quantities of carbon monoxide
and other pollutants may be released.  However, regeneration may be required
only after several months  or years of operation.  Therefore, total averaged
emissions from this source are generally considered insignificant.

          Fugitive emissions and those from process heaters are summarized
in Tables 7-23, 7-24 and 7-25.

7.1.4.2   Hy dro t reating

          Hydrotreating operations are less severe than hydrorefining
processes.  As in hydrorefining, hydrotreating is used to remove sulfur,
nitrogen, and metallic compounds fron the feed.  It is also used to saturate
olefins and aromatics and  to polish and dewax lube oil stocks.

          The mechanism of hydrotreating processes is essentially the same
as that for one-stage hydrocracking, discussed in Section 7.1.3.2, except
that, cracking conditions are. even less severe than those for hydrorefining.
The product may he fractionated or steam-stripped to remove H2S, NH3, and
light hydrocarbons.

          Process Conditions—Operating conditions for hydrotreating vary
with the feedstock and with the desired product.  Typical  operating condi-
tions and utility requirements for three types of hydrotreating are given
in Table 7-26.

          Atiuospheric Emissions—Emissions from hydrotreating include emis-
sions during catalyst regeneration,  process heater flue gas emissions, and
fugitive emissions.
                                   280

-------
          TABLE 7-23.   TYPICAL EMISSIONS FROM GAS OIL  HYDRO-
                         DESULFURIZATION UNIT PROCESS HEATERS
                                EPA Emission Factor
                               (rb/103 gal-oil fired)
                               (lb/106 scf-gas fired)
                    Total Emissions
                    (lb/103 bbl of
                      fresh feed)
Oil Fired Beaters
    Particulates
     - Distillate oil
     - Residual oil
          Grade A
          Grade 5
          Grade 6
    Sulfur Dioxide
     - Distillate oil
     - Residual oil
    Sulfur Trioxide0
    Carbon Monoxide
    Hydrocarbons (as
    Nitrogen Oxides
    (as N02)
     - Distillate oil
     - Residual oile
Gas Fired Heaters
    Particulates
    Sulfur OxidP.s (as S02)f
    Carbon Monoxide
    Hydrocarbons (as CHiJ
    Nitrogen Oxides (as N02)
  7
 10
 10(S)+3
142(S)
157(S)
  2(S)
  5
  1
 22
 22+400(N)
  5-15
  0.6
 17
  3
120-230
 0.86
 3.0
 4.3
 4.3(S)+1.3
60.9(S)
67.3(S)
 0.86(S)
 2.1
 0.43
 9.4
 9.4+171 (N)'

 0.29-0.86
 0.034
 0.97
 0.17
 6.86-13.1
 Source:   Reference, 7.
 Based on  a  heat  input  of  60,000 .  Btu/bbl of fresh  feed with the following
 fuel heating  values:   Oil -  140,000  Btu/gal; Gas - 1050 Btu/scf
 S •= vt X  sulfur  in the oil
 Improper  combustion ony cause  a significant increase in emissions
 Use this  emission  factor  for residurl  oils with less than 0,5% (N<.5). nitre--
 gen content.   For  oil  with higher nitrogen content Q^O^S), use emission
 factor of 120 lb/103 gal
 Based on  sulfur  content of 2000 gr/10K scf
                                    281

-------
                          TABLE 7-24.   ESTIMATED FUGITIVE NONMETHANE HYDROCARBON EMISSIONS
                                       FROM A TYPICAL GAS OIL HYDRODESULFURIZATT.ON UNIT
CD
Linlbslonu
Source Type
Valves






Open-End
(Sample)
Valves
Fumpu ({'map
Seals)



Drains
Flanges &
Flttlngu
Process
Stream Service
Classification
Gas/Vapor
Light Liquid
(VP > 0.1 H«!a e lOU'F)
Heavy Liquid
(VH < 0.1 pal. 8 IOO"F)
Hydtogcn Service
Total

All

Light Liquid
(VP > 0.1 psla 8 lOG'F)
llli.ivy 1. lljuLil
(VP < 0.1 pain e 100"F>
Total
All

All
Number of Sources
Coulter or KslJmare;
From Hadlan Study
235

208

102
J01
64 5 a

-


6( 9)

4(_ 5}
10(14)a
24a

2743a
in Process Unit
) Counts or Estimates
from HKS Study
205

244

97
164
" 710^

16


5( 7)

2( 3)
7(10)b
-

2350C
Hiilief Vulvea All 6C
Coinpreasora
(Compressor
Seals)

Physically
Hydrocarbon
Hydrogen
Total

Counted
0(0)
T(6)a


0(0)
3(6)
3(6p


Source
Em Is til on
Factor, Ib/lir
0.059

0.024

0.0005
0.018


0.005


0.25

0.046

0.070

0.00056
0.19
1.4
0.11


Estimated Total
Emissions ,
Ib/l.r
13.9 - 12.1

4.99 - 5.86

0.049- 0.051
1.82 - 2.95
20.8 - 21^0

0.080


1.75 - 2.25

0.14 - 0.23
1.89 - 2.48
1.68

1.44 ~ 1.54
1.14
0.0
0.66
0.66
27.7 - 28.6

Counted Krom Flou Diagrams
Clistlra/Ued
Reference

49.









-------
                                    TABLE 7-25.   ESTIMATED COMPOSITION  OF FUGITIVE EMISSIONS
                                                    FROM A GAS OIL 1IYDRODESULFUR1ZATION  UNlTa
ro
CO
OJ
Stream

Estimated percentage of omissions
attributed to each at ream - %
Weighted contribution of each
component to unit emissions - ppmw
Benzene
Toluene
Ethylbenzene
Xyler.es
Other Alkylbenzenes
Naphthalene
Anthracene
Biphenyl
Other Polynuclear Aromatics
n-Ik*xnne
Other Alkanes
Olefins
Cycle Alkanes
Hydrogen

Gas Oil

22


0
1
1
5
8 •
6
2
2
146
0
208756
0
11000
0

Dcsulfurizcd
Con Oil

22


0
1
1
5
81
6
2
2
146
0
208756
0
11000
0

HZ Rccyc-lp.
Cos

56


0
0
0
0
0
0
0
0
0
0
364000
0
0
196000

Totals

100%


0
2
2
10
162
12
4
4
292
0
781512
0
22000
196000
1000000
               3BasP.d on CO'-MS  analysis of  liquid stream samples  (and some  vapor samples).
                Estimates based on the assumption that fugitive emission compos j L ion;; from
                sources in liquid stream service is the same  composition as that of: the
                liquid contained in the emission source.

                Compositions are estimated  to  2-3 significant figures.  Additional significant
                figures are a result of calculations! procedures, and Limy  should not be given
                any importance.

-------
            TABLE  7-26.   TYPICAL  OPERATING  CONDITIONS FOR THREE HYDROTREATINC OPERATIONS

Condition
Temperature, °F
Pressure, psig
Electricity, kWh/bbl
Heater Fuel, Btu/bbl
Cooling Water, gal/bbl
Steam, Ib/bbl

Light Hydrocarbon
Hydrodesulfurization
600-800
300-1,000
2.6
36,000-75,000
264
30-903
Process
Olei in/Aroma tics
Saturation
480-660
100-1,500
0.5-2.5
1,000
120-680
12-35

Lube and Wax
Hydrotreating
600-750
500-700
2.5
35,000-140,000

15-30
o
 30 to 90 Ib/bbl with steam stripper,  5  Ib/bbl  without  steam  stripper.

-------
          During regeneration, large quantities of carbon monoxide and
other pollutants may be released.  However, regeneration may be required
only after several months or years of operation.  Therefore, total averaged
emissions from this .source are generally considered insignificant.

          Fugitive emissions and emissions from process heaters are
summarized in Tables 7-27, 7-28 and 7-29.

7.1.5     Conversion Processes

          Conversion processes use catalyzed chemical reactions to upgrade
certain refinery streams or to produce valuable products from less valuable-
materials.  Conversion processes include alkylation, isoiuerization,
catalytic reforming, and hydrodealkylation.

7.1.5.1   Alkylation

          Alkylation is the chemical combination of an olcfin and an
isoparaffln, visually isobutane, to produce higher molecular weight isopar-
affins.   The alkylate product is usually used to upgrade the octane rating
of gasoline.  Almost all alkylation units use H2SO^ or 1IF as a catalyst.

          Process Conditions—The most important variables in alkylation
are reactor temperature, acid strength, isobutane concentration, and, in
sulfuric acid alkylation,  the olefin space velocity.   Ranges for these
and other variables are included in Table 7-30.
                                   285

-------
       TABLE 7-27.   TYPICAL EMISSIONS FROM HYDROTREATING
                      UNIT PROCESS  HEATERS
                                EPA Emission Factor
                               (lb/103 gal-oil fired)
                               (lb/106 scf-gas fired)
                    Total Emissions
                    (lb/103  bbl  of
                     fresh feed  )
Oil Fired Heaters
    Participates
     - Distillate oil
     - Residual oil
          Grade A
          Grade 5
          Grade 6
    Sulfur Dioxide0
     - Distillate oil
     - Residual oil
    Sulfur Trioxide0
    Carbon Monoxide
    Hydrocarbons (as CHi()
    Nitrogen Oxides
    (as N02)
     - Distillate oil
     - Residual oile
  7
 10
 10(S)+3
157(S)
  2(5)
  5
  1
 22
 22+400(N)'
 1.1
 3.8
 5.4
 5.4(S)+1.6
76.KS)
84.1(S)
 l.l(S)
 2.7
 0.54
12
12+214(N)'
Gas Fired Heaters
Particulates
Sulfur Oxides (as S02)
Carbon Monoxide
Hydrocarbons (as CKi< )
Nitrogen Oxides (as NC^)

5-15
0.6
17
3
120-230

0.36-1
0.043
1.2
0.21
8.6-16

.1



.4
 Source:   Reference 7.
 Based on a haat input  of   75,000  Btu/bbl of  fresh feed with the following
 fuel heating values:   Oil  - 140,000  Btu/gal; Gas -  1050 Btu/scf
CS •= wt 7, sulfur in the oil
 Improper combustion may cause  a significant  increase in emissions
n
"Use this emission  factor for residual oils with less than 0.5% (N<-5). nitro-
 gen conr.enr.   For  oil  with higher nitrogen content  (N>0.5), Use emission
 factor of 120 lb/103 g«l
 Based on sulfur content cf 2000 sr/106 scf
                                  286

-------
                           TABLE 7-28.  ESTIMATED FUGITIVE  NONMETHANE HYDROCARBON EMISSIONS
                                         FROM A TYPICAL HYDROTREATING UNIT
Ni
CO
Number of Sources in Process Unit „
Emissions
Source Type
Va) vea






Open-lind
(Sample)
Valves
Puiups (Pump
Seals)



Drulnu
Flangeu &
Fittings
Relief Valvea
Comproaaora
(Comprcatior
Seals)

• L u t< c a u — — — — 	
Stream Service Counts or Estimates
Classification From Radlun Study
Gas/Vapor
Light Liquid
(vy > 0.1 ii.la « lOO'l?)
Heavy 1. Inn id
(VH < 0.1 |>*U * 100't)
Hydrogen Service
Total

All

Light Liquid
(VP > 0.1 paifl 9 100'f)
Heavy Liquid
(VP < 0.1 ptjla 9 100*F)
Total
AH

All
All
Hydrocarbon
Hydrogen
Total

235

208

102
1"1
~645a

-

6( 9)

4( 5)
10(14)a
24°

2743°
6C
0(0)
3(6)
3(6)a

	 auui
CounLu or Estimates Euui;
From PES Study Facti
226 - 389 0.

378 - 648 0.

0 0.
1B1 - 312 0.
785 - 1349C

17 - 29b 0.

B(ll)-16<22) 0.

0 0.
8(ll)-16(22f>
0.

2585 - 4465C 0.
0.
0(0) 1.
3(6) 0.
3(6)*

:»:si
iuloil
>r, Ib/hr
059

024

0005
018


005

25

046

070

00056
19
4
11


Estimated Total
13.

4.

0.
1.
20.

0.

2.

0.
2.


1.




27.
3 -

99 -

0 -
82 -
1 -

085-

25 -

0 -
25 -
1.

44 -
1.
0.
0.
0.
4 -
23

15

0
5
44

0

5

0
5
68

2
14
0
66
66
56
.0

.6

.051
.62
.3

.145

.50

.23
.73


.50




.0
               thyaically Counted
               Counted From Flnu Dlugramu
               Estimated
               Ktfereuca  49

-------
                                     TABLE 7-29.   ESTIMATED COMPOSITION OF  FUGITIVE  EMISSIONS
                                                     FROM A HYDROTREATING  UNIT*
00
00
Stream

Estimated percentage of emissions
attributed to each stream - %
VJeightcd contribution, of each
component to unit emissions - pprow
Benzene
Toluene
Ethylbe.nzene
Xylenes
Other Alkylhenzenes
Naphthalene
Anthracene
Biphenyl
Other Polynuclsar Aronatics
n-llexane
Othar Alkanes
Olcfins
Cyr.lo Alkanes
Hydrogen
Straight Run
Naphtha
47

119
1232
417
763
7792
683
2
295
7042
18254
23/i817
0
198579
0
TJesulf urized
Naphtha
47

119
1232
417
763
7792
538
2
295
7042
18254
234817
0
198579
0
Ha Recycle
Gas
6

0
0
0
0
0
0
0
0
0
0
39000
0
0
21000
Totals
100%

238
2464
834
1526
15584
1376
4
590
14084
36508
508634
0
397158
21000
1000000
               3Hased on GC-MS analysis of liquid stream samples (and  some vapor samples).
                Estimates based on the assumption rh.it  fugitive emission compositions from
                sources in liquid stream service is  the same composition a a that of Lhe
                liquid contained in the emission sourc.n.

               bCorapositions are estimated to 2-3 s iy.nif Jcaut figures.  Additional significant
                figures ate a result  ot calculational procedures, and  they should not be given
                any importance.

-------
  TABLE  7-30.  TYPICAL OPERATING  CONDITIONS  FOR ALKYLATION  OPERATIONS
                                                        Process
Condition
Reactor Temperature, °F
Acid Strength, Wt. %
Acid in Emulsion, Wt. %
Olefin Space Velocity, v/hr/v
Isobutane Concentration, Vol %
Steam, lb/bbl alkylate
Power, kWh/bbl alkylate
Fuel, 106 Btu/bbl alkylate
Alkylation
35 -
88 -
40 -
0.1 -
40 -
300 -
2.5 -
	
60
95
60
0.6
80
400
5

HF
Alkylation
60
83
25

30

3
0.3
- 120
- 92
- 80
	
- 80
	
- 7
- 1.1
Source:  References 38,50,51,61.

          Po tentially Hazardous _Atmo_sphe_r_ic___Emisslons—The alkylation process-
is a closed system; therefore, the only emissions are those associated with
process heating and fugitive emissions.  These emissions are summarized in
Tables 7-31, 7-32 and 7-33.

7.1.5.2   Isomerization

          Isomerization processes convert normal paraffins into isopar-
afflns.  In general, octane numbers are much higher for isoparafflns than
for normal paraffins.  The process is also used to produce isobutane for
use in alkylation units.

          Process Conditions—Temperature is a critical factor in isomeri-
zation reactions.  In general, equilibrium concentrations of isoparaffins
are increased by reducing the reaction temperature.  Typica.1 process condi-
tions and utility requirements for both the vapor phase-solid catalyst
system described earlier and the liquid phase system are given in Table 7-34.
                                   289

-------
TABLE  7-31.   TYPICAL  EMISSIONS FROM ALKYLAT10N
               UNIT PROCESS HEATERS
                        EPA Emission Factor
                       (lb/103 gal-oil fired)
                       (lb/10E scf-gas fired)
Total Emissions
(lb/103 bbl of
total alkylste)
                                7
                               10
                               10(S)+3
                              142(S)
                              157(5)
                                2(S)
                                5
                                1
   5.1
  18
  26
  26(S)+7.7
 3G5(S)
 404 (S)
  13
   2.6
Oil Fired Heaters
    Particulates
     - Distillate oil
     - Residual oil
          Grade 4
          Grade 5
          Grade 6
    Sulfur Dioxide
     - Distillate oil
     - Residual oil
    Sulfur Trioxide0
    Carbon Monoxide
    Hydrocarbons (as CH^)
    Nitrogen Oxides
    (as K02)
     - Distillate oil
     - Residual oil6
Gas Fired Heaters
    Particulates
    Sulfur Oxides (as S02)
    Carbon Monoxide
    Hydrocarbons (as CK^)
    Nitrogen Oxides (as  N02)

 Soxirce:   Reference  7.
 Based on a heat input of  360,000  Btu/bbl of total alkylatc with the following
 fuel  heating values:  Oil  -  140,000  Btu/pal; Gas - 1050 Btu/scf
 S " wt % eulfur in the  oil
 Improper combustion may cause  a significant increase in emissions
 Use this emission  factor for residual oils with less than 0,5% 0?<.5) nitro-
 gen content.   For  oil with higher nitrogen content (>!>0,5), use emission
 factor of 120 lb/103 gal
 Based  on sulfxir content of 2000 gr/10G scf
22
22+400 (N)
5-15
0.6
17
3
120-230
57
5 7-1-1030 (N)'
1.7-5.1
0.21
5.8
1.0
41.1-78.9
                          290

-------
               TABLE 7-32.   ESTIMATED FUGITIVE NONMET11ANE  HYDROCARBON EMISSIONS
                             FROM A TYPICAL  SULFURIC ACID ALKYLATION UNIT
Emiuaioiio
Source Type
Va 1 vea


Open- End
(Sample)
Vulvea
Pumps (Pump
Sea lu)

Drains
Flanges &
Fltlings
Relief Valves
Compressors
(Compressor
Sicily )
Process
Stream Service
Classl Clcatlon
Gae/Vapor
LlgliC Liquid
(Vf > 0.1 pala 9 lUO'F)
Heavy Liquid
(VP < 0.1 pats 9 100'F)
Hydrogen Service
Total
All

Light Liquid
(VF > 0.1 pa It If 100'i)
Heavy Liquid
(VP < 0.1 v,i» it 100'F)
Total
All
All
All
Hydrocarbon
Hydrogen
Total
Number of Sources in
Ciumlti or Estimate;!
From Uadlan Study
274
40!
0
0
	 ~677a
_

13(18)
°L°)
I3(18)a
41"
2407a
6C
0
0
0
Process Unit
Counta or Estimates
From PES Study
429 - 719
636 - 1067
0
0
1065 - 1786C
26 - 30b

13(18)-23(32)
o{ P> o{pi
13(ia)-23(32)"b
-
3525 - 5875C
-
0(0) - 2(4)
0(0) - 0(0)
0(0) - 2(4>1>
Source
Emlotilon
Factor, II) /hr
0.059
0.024
0.0005
0.018
0.005

0.25
0.046
0.070
0.00056
0.19
1.4
0.11
Estimated Total
Eml uuluna,
Ibyiir
16.2 - 42.4
9.67 - 25.6
0.0
0.0
25.9 - 68.0
0.13 - 0.15

4.50 - a. oo
0.0
4.50 - 8. 00
2.87
1.35 - 3.29
1.14
0.0 - 5.60
0.0
0.0 - 5.60
J5.9 - 89.1
 i'hyjlcally Counted

 Counted From Flow Dlagramu
£
 Estimated

' Kuftueuce  49

-------
                 TABLE 7-33.   ESTIMATED  COMPOSITION OF FUGITIVE EMISSIONS
                                 FROM AN ALKYLATION  UNIT3


Olefinn
S t re am
LPG
H2SOi,
Alky late
Totals
Estimnted percentage of emissions
a
ttributed to each stream - %
24
35
0
41

Weighted contribution of each ,
component to unit emissions — ppinw














Benzene
Toluene
Ethylbetxzene
Xy lanes
Other Alkylbenzenes
Naphthalene
Anthracene
Biphenyl
Other Polynuclear Arcmatics
n-Hex?.ne
Other Alkan.es
Olefins
Cvclo Alkar.es

0
0
0
0
0
0
0
0
0
0
96000
144000
0

0
0
0
0
0
0
0
0
0
0
350000
0
0

0
0
0
0
0
0
0
0
0
0
0
0
0

0
0
0
1
1
0
0
0
1
39
409572
381
5

0
0
0
1
1
0
0
0
1
39
855572
144381
5
1000000
Rased  on Cfl-MS analysis of liquid stream samples (and some vapor samples).
Estimates based on the assumption that fugitive emission  compositions froTT,
sources in liquid stream  service is the same composition  as  that of the
liquid contained in the emission source.

Compositions are estimated to 2—3 significant figures.  Additional significant
figures are a result of calculations!  procedures, and they .should not be given
any importance.

-------
       TABLE  7-34.  OPERATING CONDITIONS AND UTILITY REQUIREMENTS
                    FOR PARAFFINS  ISOMERIZATION PROCESSES
Solid Bed
Systems
Reactor Temperature, °F
Reactor Pressure, psig
Liquid Space Velocity, v/hr/v
Fuel, 10 3 Btu/bbl feed
Electricity, kWh/bbl feed
200
200
1
10
1
- 600
- 1,000
- 4
- 50
- 2
Liquid Phase
Systems
150 - 250
300 - 500
2-3
NA3
NA3
Source:  References 38,50,51,61,62,63.
o
 NA = not available

          Atmospheric Emissions—An isomerization unit is a closed system.
The emission sources for this process are process heater flue gas and fugi-
tive emissions.  Emissions from process heaters are summarized in Table
7-35.  Fugitive emissions are estimated in Table 7-36.

7 .1.5.3   Catalytic Reforming

          Catalytic reforming is one of the most important of all refinery
processes.   In catalytic reforming, relatively low octane naphthas are con-
verted to highly aromatic, high octane gasoline blending stocks.  The
reforming operation consists basically of contacting oil and hydrogen with
a catalyst  in a series of three to six reactors.  Because the overall
reaction is endothermic, the mixture must be heated before it is charged to
each reactor.

          A number of reactions occur simultaneously during the reforming
process including dehydrogenation, isomerization, and hydrocracking.
Dehydrogenation reactions which result in the formation of aromatics  are
the most important.
                                    293

-------
         TABLE 7-35.   TYPICAL EMISSIONS  FROM ISOMERIZATION
                        UNIT PROCESS HEATERS
                                EPA Emission Factor
                                (lb/103 gal-oil fired)
                                (lb/106 scf-gas fired)
                    Total Emissions
                    (lb/103 bbl of
                      fresh  feed)
 Oil  Fired Heaters
     Particulates
      - Distillate oil
      - Residual oil
          Grade A
          Grade 5
          Grade 6
     Sulfur Dioxide
      - Distillate oil
      - Residual oil
     Sulfur Trioxidec
     Carbon Monoxide
     Hydrocarbons (as CHi,)
     Kitrogen Oxides
     (as N02)
      - Distillate oil
      - Residual oile
  7
 10
 10(S)+3
   (S)
157 (S)
  2(S)
  5
  1
 22
 22+400(N)'
 0.71
 2.5
 3.6
 3.6(5)41.1
50.7(S)
56.1(S)
 0.71(5)
 1.8
 0.36
 7.9
 7. 9-KL43 (N)'
Gas Fired Heaters
Particulates
Sulfur Oxides (as S02)
Carbon Monoxide
Hydrocarbons (as CH;t)
Kitrogen Oxides (as N02)

5-15
0.6
17
3
120-230

0.24-0.71
0.029
0.81
0.14
5.71-11.0
 Source:  Reference  7.
 Based on a heat input of 50,000  Btu/bbl of fresh feed with the following
 fuel heating values:  Oil - 140.000 btu/gal;  Gas - 1050 Btu/ccf
°S •= v-t % sulfur in the oil
 Improper combustion nay cause a significant increase in emissions
eUse this emission factor for residual oils vvi th .less than  0.5%  Q^.5) nitro-
 gen content.  For oil with higher nitrogen conte.nt (N>C,3).,  use emission
 factor of 120 lb/103 gal
fBased on sulfur content of 2000 gr/106 scf
                                    294

-------
             TABLE 7-36.  ESTIMATED  FUGITIVE NONMETHANE HYDROCARBON EMISSIONS
                          FROM A TYPICAL BUTANE ISOMER1ZAT10N UNIT
Emissions
Source Type
Valves






Open- End
(Sample)
Vulvee
Pura|>o (Pump
Seals)



Drains
Flangee &
Fittings
Relief Valvee
Compressors
(Compressor
Seala)
• Proceaa
Stream Service
Classification
Caa/Vapor
Llglit Liquid
 Q.I pala 6 100'f)
Heavy Liquid
(VP < 0.1 p»la 4 100'F)
Hydrogen Service
Total

All

Llglit Liquid
(VP > 0.1 pain 8 IQO'F)
lluavy Liquid
(V? < 0.1 t>aln H 100T)
Total
All

All
All
Hydrocarbon
Hydrogen
Total
Number of Sources in Proceoa Unit
238

310

0
102
650a

_


10(14)

0( 0)
10(14)a
26°

2321a
6a
0(0)
2(4)
2<4)a
Source
Einioalan
Factor, Ib/hr
0.059

0.024

O.OOQ5
0.010


0.005


0.25

0.046

0.070

0.00056
0.19
1.4
0.11

Eutimated Total
Kmlualona ,
Ib/hr
14.0

7.44

0.0
1.B4
23.3

-


3.50

0.0
3C f\
. JU
1.82

1.30
1.14
0.0
0.44

0.44
                                                                                       31.5
I'titluvat ed

-------
          Catalytic reforming processes are categorized by the method or
 frequency of catalyst regeneration.  Catalyst beds may be regenerated
 continuously, all at once at the end of a 3 to 24-month cycle (semi-
 regeneration) , or one at a time while an alternate "swing" reactor is in
 use  (cyclic regeneration).  The method of regeneration affects the choice
 of catalyst and the product yie.l ds obtainable.

          Process Conditions—A summary of typical operating conditions and
 utility requirements for catalytic reforming is given below.3S>5°»5 1

          •    Reactor temperature:  850 to 1,000°F.

          •    Reactor pressures
                  Serai-regeneration:  150 to 500 psig.
                  Cyclic regeneration:  90 to 200 psig.
                  Continuous regeneration:  90 to 200 psig.

          •    Space velocity:   1.5 to 3.0 v/hr/v.

          •    Power:  5 to 7 kWh/bbl.

          •    Fuel:  0.15 to 0.32 x 106 Btu/bbl feed.

          Atmospheric Emissions—Emissions from catalytic reforming include
emissions from catalyst regeneration, process beater flue gas, and Fugitive
emissions.  During the reforming operation,  coke is deposited on the
catalyst.  The rate of coke formation is a function of the type of feed-
stock and the severity of the operating conditions.  During regeneration
a flue gas stream is generated  which contains carbon monoxide and low con-
centrations of  sulfur and nitrogen oxides.

          Total averaged emissions from catalyst regeneration are. quite, low
because only -small, amounts of coke are produced and the frequency of
                                   296

-------
regeneration may be low.  These emissions are highest for continuous
operations because more severe operating conditions can be used.  Carbon
monoxide emissions from continuous reformers have been estimated at 0.002
to 0.02 pounds per barrel of fresh feed, a relatively small amount.

          Emissions from process heaters and fugitive emissions are
summarized in Tables 7-37, 7-38, and 7-39.

7.1.5.4   Hy d r o d e aIky1a t i on

          Hydrodealkylation removes alky] groups from aromatic rings at
elevated temperatures in the presence of hydrogen.  The reaction can be
conducted either thermally or in the presence of a catalyst.

          Since hydrodealkylation is a closed process, the only emissions
are fugitive emissions and emissions from process heaters.  These emissions
are summarized in Tables 7-40 and 7-41.

7.1-6     GasJProcessing. <"*,65,66, 67,68,69

          Gas processing recovers various hydrocarbons as pure products or
as mixtures of specified compositions.  The products of gas processing may
be fuel gas, methane,  ethane, propane, propylene, normal  and isobutane,
butylencs, normal and isopentane, amylene, and/or a light naphtha.

          The feed to gas processing units comes from crude distillation,
catalytic reforming,  catalytic cracking, hydrocracking,  thermal cracking,
and to a lesser extent,  hydrodesulfurination.  Major units include acid
gas removal, dehydration, and separation.
                                   297

-------
            TABLE  7-37.   TYPICAL  EMISSIONS FROM  CATALYTIC
                           REFORMING UNIT  PROCESS  HEATERS
                                EPA Emission Factor
                               (lb/103 gal-oil fired)
                               (lb/106 scf-gas fired)
                    Total Emissions
                    (lb/103 bbl  of
                      fresh feed)
Oil Fired Heaters
    Participates
     - Distillate oil
     - Residual oil
          Grade 4
          Grade 5
          Grade 6
    Sulfur Dioxide0
     - Distillate oil
     - Residual oil
    Sulfur Trioxide0
    Carbon Monoxide
    Hydrocarbons (as
    Nitrogen Oxides
    (as N02)
     - Distillate oil
     - Residual oile
  7
 10
 10(S)+3
157(S)
  2(S)
  5
  1
 22
 22+400(N)'
  2.9

 10
 14
 14(S)+4.3
203(S)
224(S)
  2.9(S)
  7.1  .
  1.4
 31
 31+571 (N)'
Gas Fired Heaters
Particulates
Sulfur Oxides (as S02)
Carbon Monoxide
Hydrocarbons (as CHi^)
Nitrogen Oxides (as N02)

5-15
0.6
17
3
120-230

0.95-2.9
0.11
3.2
0.57
22.9-43.8
 Source:   Reference  7.

 Based on a heat  input  of  200,000 Btu/bbl of fresh feed with the following
 fuel heating values:   Oil - 140,OCO Btu/gal; Gas - 1050 Btu/scf.

 S = wt % sulfur  in  the oil

 Improper combustion may cause a significant increase in emissions
ri
"Use this emission factor  for residual oils vith less than 0.5% (N<.5)  nitre*-
 gen content.   For oil  with higher nitrogen content 0^0-5), use emission
 factor of 120 lb/103 gal

 Based on sulfur  content of 2000 gr/lO6 scfr
                                    298

-------
                           TABLE  7-38.   ESTIMATED  FUGITIVE NONMETHANE HYDROCARBON  EMISSIONS
                                         FROM A TYPICAL CATALYTIC  REFORMING UNIT
VD
VD
Cuilaslons
Source Type
Valvea






Open-End
(Sample)
Valves
Pump a (Pump
Seals)



Draina
Klangeu &
Fittings
Relief Valvea
Compressors
(Compressor
Seals)

Proceun
Stream Service
Classification
Gas/Vapor
Light Liquid
(VP > 0.1 pala S 100'F)
Heavy Liquid
(Vf < 0.1 pala 8 IQO'1?)

Total

All

I-JgllL Liquid
(VP > 0.1 pala S 100'k')
Heavy Liquid
(VP < 0.1 pale 9 100T)
Total
All

All
All
Hydrocarbon
Hydrogen
Total

Number of Sources in
Count a or Kat inmtea
From Radian Study
100

391

4'J
77
691a

-


13(18)

K 2)
14(20)a
49a .

2961a
fic
0(0)
3(6)
3(6)"

Process Unit
County or Estimates
From PKS Study
15/i - 291

493 - 938

0
139 - 263
786 - 1492C

16 - 30»>


8(11)-17(24)

0
8(ll)-17(24)b
-

2585 - 4935C
-
0(0)
3(6)
3(6)

Source
Emliittion
Factor, Ib/hr
0.059

0.024

0.0005
0.018


0.005


0.25

0.046

0.070

0.00056
0.19
1.4
0.11


Estimated Total
Emissions ,
Ib/lir
9.09 -

9.38 -

11. 2

22.5

0.0
1.39 -
19.9

0.080 -


2.75 -

0.0 -
2.75 -
3.

1.45 -
1.
0.
0.
0.
29.4
4.7i
44.4

0.15


6.00

0.092
6.09
43

2.76
14
0
66
66
58.6
              Physically Counted
              Counted  Front Flow Diagrams
              Estimated
              ^Reference  49

-------
                                   TABLE 7-39.   ESTIMATED COMPOSITION  OF FUGITIVE EMISSIONS
                                                   FROM A CATALYTIC  REFORMING  UNITa
o
o
Stream

Estimated percentage of emissions
attributed to each stream - 7,
Weighted contribution of each
component to unit emissions - ppmwb
Benzene
Toluene •
Ethylbenrene
J'ylcnes
Other Alkylbenzenes
Naphthalene
Anthracene
Biphenyl
Other Po.lynuclear Aroma tics
n-Kexane
Other Alkanes
Olefins
Cycle Alkanes
Kydrogo.n
Desulfurized
Naphtha
47

119
1232
417
763
7792
688
2
295
7042
18254
234817'
0
198579
0
He formate
47

2538
36519
15745
80323
152468
3478
0
0
329
11280
s
167320
0
0
0
H2 Recycle
Gas
6

0
0
0
0
0
0
0
0
0
0
39000
0
0
21000
Totals
100%

2657
37751
16162
81086
160260
4166
2
295
7371
29534
441137
0
198579
21000
1000000'
                Based on GC-MS analysis of liquid stream samples (and  some vapor samples).
                Estimates based on the assumption that  fugitive emission compositions  irora
                sources in liquid stream service is the same composition as that of the
                liquid contained in the emission source.

                Compositions are estimated to 2-3 significant figures.  Additional significant
                figures are a result of calcuiational procedures, arid  they should not  be  given
                any Importance.

-------
       TABLE  7-40.  TYPICAL EMISSIONS  FROM HYDRODEALKYLATION
                     UNIT PROCESS HEATERS
                                EPA Emission Factor

                               (lb/103 gal-oil fired)
                               (lb/105 scf-gas fired)
                    Total Emissions

                    (lb/103  bbl  of
                      fresh  feed)
Oil Fired Heaters
    Participates
     - Distillate oil
     - Residual oil
          Grade 4
          Grade 5
          Grade 6
    Sulfur Dioxide0

     - Distillate oil
     - Residual oil

    Sulfur TrioxideC

    Carbon Monoxide

    Hydrocarbons (as CHt,)

    Nitrogen Oxides .....
    (as N02)
     - Distillate oil
     - Residual oile
  7
 10
 10(S)+3
142(S)
157(S)
  2(S)
  5
  1
 22
 22+40000'
  4.1

 15
 21
 21(S)+6.2
294(5)
325(S)
 10
  2.1
 46
 46+829(N)"
Gas Fired Heaters
Particulates
Sulfur Oxides (as S02)f
Carbon Monoxide
Hydrocarbons (as CH^)
Nitrogen Oxides (as K02)

5-15
0.6
17
3
120-230

1.4-4.1
0.17
4.7
0.83
33.1-63.5
 Source:   Reference 7.

 Based on a heat  input  of  290,000  Btu/bbl  of  fresh  feed with the following
 fuel heating values:  Oil -  140,000  Btu/gal; Gas - 1050 Btu/scf.

CS =• wt 7. sulfur  in the oil
j
 Improper combustion  may cause  a significant  increase in emissions
2
 Use this emission factor  for residua]  oils with less than 0,5%  QJ<.5) nitro-
 gen content.   For oil  with higher nitrogen content (N>0,5)_, use emission
 factor of 120 lb/103 gal

 Based  on sulfur  content of 2.000 gr/10G scf
                                   301

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                          TABLE 7-41.  ESTIMATED FUGITIVE NONMETHANE HYDROCARBON  EMISSIONS

                                       FROM A TYPICAL HYDRODEALKYLATION UNIT
OJ
O
ho

Emlaaionu
Source Type
Vulveu




0|ieii-Knd
(Sample)
Valves
Furapu (Pump
Seals)


Drains
Flanges &
KlLLlngu
Relief Valves
Coniircauura
(Coiup resbur
Seals)

Counted from
Estimated

Strenm Service
Classification
Oas/Vapor
Liylit Liquid
(VP > 0.1 psia « lOO'F)
Heavy Liquid
(vr < o.i p.ia « IOO'F)
Hydrogen Service
Total

All

LiBlit Liquid
(VP > o.i pou g locT)
Heavy Liquid
(VP < 0 1 pal a g lOQ'F)
Total
All
All
All
Hydrocarbon
Hydrogen
Total

Flow Diagrams

Number of Sources in
Conntu or Estimates
From Radian Study
179
391
43
	 22.
690b

-

.' 13(18)
K 2)

36b
2463*
6b
0(0)
3(6^
3(6)



Procesa Unit
Counts or EaClmatea
From PES Study C
116
352
0
inn
560TJ

10a

6(8)
0(0)

-
18BOh
-
0(0)
2(4)
2(4)a




Emission
Factor, Ib/ltr
0.059
0.024
0.0005
0.010


0.005

0.25
0.046

0.070
0.00056
0.19
1.4
0.11





Emissions ,
Ib/l.i
6.84 - 10.6
8.45 - 9.38
0.0 - 0.022
1.39 - 1.80
16.7 - 21.8

0.05

2.00 - 4.50
0.0 - 0.092
2.00 - 4.59
2.52
1.05 - 1.38
1.14
0.0
0.44 - 0.66
0.44 - 0.66
23.9 - 32.1


             C
             |teference

-------
 7.1.6.1   Acid Gas Removal

          The acid gas removal unit removes hydrogen sulfide from hydro-
 carbon gases, usually by absorption in an aqueous, regenerative sorbent.
 C02 and/or mercaptans may also be removed, depending on the process used.

          A number of acid gas removal processes are available, distin-
 guished primarily by the regenerative sorbent used.  Ainine-based sorbents
 are most commonly used.

          The. feed to a typical unit is contacted with the sorbent, such
 as diethanolamine, in an absorption column to selectively absorb H2S from
 the hydrocarbon gases.  Hydrogen sulfide is then removed from the sorbent
 in a regeneration step.  The products are a sweet hydrocarbon gas and a
 concentrated hydrogen sulfide stream.  The hydrogen sulfide stream is
normally routed to a sulfur plant for recovery of its sulfur content.
Alternatively, the sulfide gas may be flared to produce the less toxic
 sulfur oxides.

          Process Conditions—A typical absorber operates at a pressure of
about 150 psi and a temperature of about 100°F.  Pressure, and temperature
may, in some instances, be significantly higher.

          Atrnospheric Emi s s i o n s—If a regenerative sorbent system is used
in conjunction with a sulfur recovery unit, only fugitive emissions are
produced.  If the hydrogen sulfide stream is flared,  sulfur oxide emissions
are produced.

7.1.6.2   Dehydration

          Dehydration removes water from the gas after the acid gas removal
step.   Excess water may be removed by refrigeration,  absorption, or
                                  303

-------
adsorption.  Refrigeration processes decrease the temperature to below the
required dew point; condensed moisture is collected for disposal.

          Absorption processes allow the moist gas to flow over a hygro-
scopic material such as di- or triethylene glycol.  Solid dissicants such
as silica gel or alumina are used in adsorption processes.  Beds are
regenerated with hot gas.

          Process Conditio ns—Temperature and pressure are interdependent
in condensation processes.  For example, if the required dew point is 50°F
at 135 psig and the best available cooling is 90°F, the pressure will be
460 psig.

          For absorption processes using di- or triethylene. glycol, absorp-
tion temperatures must be kept below the glycol's decomposition temperature
(327°F for DEC, 405°F for TEG).  Temperatures in the regenerator, where
water is separated from the glycol,  usually range from 375° to 400°F.

          Regeneration temperatures  for solid dessicants are 480° to 500°F.

          Utilities—A glycol absorption process requires about 0.1 percent
of the fuel produced.

          A tmo sp h e r i c Etn i s s i o n s—An estimated 0.1 gallon of triethylene
glycol per 10 ft3 of gas processed is emitted by a glycol absorption unit
in vented water vapor.   Water contaminated with glycol may be vented as
steam or it may be disposed of as a  liquid.   Hydrocarbons may also be
emitted from fugitive sources.

7.1.6.3   Product Separation/TPG Production

          Refinery gas  is often separated into its components in a gas
separation plant.   This separation is usually accomplished by contacting
                                  304

-------
the gas with an absorber oil.  Refrigerated absorption, refrigeration, or
adsorption may be used when a separate methane stream is desired.

          In the oil absorption process, the gas is contacted with an
absorber oil in a packed or bubble tray column.  Propane and heavier hydro-
carbons are absorbed by the oil while most of the methane and ethane pass
through the absorber.  The enriched absorber oil is then taken to a stripper
where the absorbed propane and heavier compounds are stripped Erom the oil.

          In the refrigeration process, the gas is first dried with molecu-
lar sieve beds.  It is then cooled in a heat exchanger to - 25°F.  Condensed
hydrocarbons are removed in a gas-]icuid separator.  The gas from this
separator is passed through a second separator at - 135°F.   Liquids from
the separators arc fed to a series of distillation columns  where methane,
ethane, propane, butane, and other products are recovered.

          An activated carbon bed adsorbs all hydrocarbons  except methane.
The bed is regenerated with heat and steam; the resulting hydrocarbon vapor
is condensed and the water separated.  The resulting hydrocarbon product is
then fractionated into its various components.

          Process Conditions—Pressure in an oil absorber may be as high as
400 psi, but is usually lower.  Inlet gas and oil temperatures are 90° to
100°F.

          Emissions--Fug111ve emissions from leaking pumps,  valves, com-
pressors,  and other fittings are the only emissions from product separation.
                                  305

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7.1.7     Other Processes

7.1.7.1.  Asphalt Proc.es sing /Product ion

          Asphalt is produced as the bottoms from vacuum distillation,
discussed in Section 7.1.1.2.  The removal of lube oil by deasphalting
is discussed in Section 7.1.7.A.

          The quality of asphalt is improved by blowing a:i r through it  (air-
bHowing) to increase its melting temperature and hardness.  Both batch  and
continuous processes are used.  Catalysts such as ferric chloride or
phosphorus pentoxide arc sometimes used.

          Because asphalt is distilled before it reaches the air-blowing
process, hydrocarbon emissions from tVic process are relatively minor.
Available data indicate that uncontrolled emissions from air-blowing of
asphalt are about 60 pounds per ton of asphalt.    The operating conditions
are favorable for the production of extremely undesirable polynuclear
aromatics.

          In some refineries, air-blown units have been replaced with
vessels packed with solid absorbents.   These vessels have no emissions
other than fugitive, emissions.

7.1.7.2   Blending

          Products with desired characteristics are often made by the mix-
ing of various components.  The most common blending operation in petroleum
refining is the manufacture of gasoline.

          Blending may be by batch or  in-line.   Batch blending takes place
in a blending tank to which components are added individually.  Agitation
                                   306

-------
may be either by an external circulation loop or by internal impellers
powered by external motors.

          In-line blending may be partial or continuous.  Partial blending
involves simultaneous combination of stock components in a mixing manifold.
Final additions are made downstream or in a storage tank.  Continuous
blending is  the simultaneous blending of all components in a mixing
manifold.

          Fugitive emissions from batch blending tanks are often more than
from similar storage tanks because of the agitation.  Fugitive emissions
from in-line blending are limited to fugitive leaks from valves, flanges,
and other process equipment.

          Control technology for batch blending operations includes float-
ing roofs on blending tanks and replacement of batch operations with in-
line blending operations.

7.1.7.3   Hydrogen Production

          A refinery with a large distillate hydrotreater or gas oil hydro-
cracker requires more high-purity hydrogen than is supplied by other
refinery processes.   It is estimated that by 1980, slightly less than 40
percent of the hydrogen used in refineries will be manufactured within the
refineries.7'

          Steam-hydrocarbon reforming is commonly used for hydrogen pro-
duction,  but because it uses valuable light hydrocarbons, it will probably
be gradually replaced by partial oxidation of heavy oils.  The choice
between the  two processes depends on the cost and availability of raw
materials.72
                                   307

-------
          Emissions from steam-hydrocarbon reforming are limited to  those
from process heaters and fugitive emissions.  No specific, information was
available on emissions from partial oxidation.  It is assumed they are con-
fined to process heater emissions and fugitive emissions.  Emissions from
.steam-hydrocarbon reforming are summarized in Tables 7-42 and 7-43.  These
emissions are more appropriate for units using liquid feedstocks.  Those
units utilizing natural gas as feed should have low emissions of nonmethane
hydrocarbons.

7.1.7.4   Lube. Oil Processing/Production

          Lube oil stock is produced as the 700 to 1,000°F fraction of the
residuum from vacuum distillation.  Procedures for processing the. lube oil
stock into specific products vary greatly, but they can be divided into four
groups:  deasphalting, treating, dewaxing, and finishing.

          Each of these processes is closed to the atmosphere.  Except for
hydrotreating, there are no emissions except for fugitive emissions and
emissions from process heaters.  With hydrotreating, there are emissions,
particularly CO, associated with periodic catalyst regeneration.

          Deasphalting—A very heavy oil (brightstock) can be produced from
vacuum residues by extraction with propane at temperatures from 104 to "UiO°F.
At these temperatures, paraffins are quite soluble in propane, but high
molecular weight asphaltic and resinous compounds precipitate.

          Propane can also be used to separate a lighter oil fraction (SAE
50), a very heavy oil, and hard asphalt by fractionation.

          Treating—Several methods  are used to improve the viscosity index,
the color,  and the carbon residue content of lube oil.  The two most common
treating methods arc phase extraction and furfural treating.  Hydrotreating
has also been used.
                                   308

-------
               TABLE 7-42.  ESTIMATED FUGITIVE NONMETTIANE HYDROCARBON  EMISSIONS
                            FROM A TYPICAL HYDROGEN PRODUCTION UNITe
Eraieaiona
Source Typo
Valvea






Open-End
(Sample)
Valvea
Purapfl (Puop
oj Seula)
o
^o


Drains
Flanges &
Fittings
Relief Valvea
Compreaaora
(Compreaaor
Sealu)

Process
Stream Service
Classification
Gaa/Vapor
Light Liquid
(VP > 0.1 p*la 8 tGQ'f)
Heavy Liquid
(VF < 0.1 pals 3 100'F)
Hydrogen Service
Total

All

Light Liquid
(VP > a. I pst" « IUO'K)
Heavy Liquid
(VP < 0.1 pals 
-------
                            TABLE 7-43.   ESTIMATED  COMPOSITION OF  FUGITIVE EMISSIONS FROM A
                                           HYDROGEN PRODUCTION UNIT  UTILIZING NAPHTHA AS  FEEDSTOCK3
                                                                Streams
U)
H-•
o
                                               Fuel
                                               Gas
        Straight Run
        Naphtha	
                          Hz Recycle
                          Gas
               Estimated percentage of
               emissions attributed to each
               stream - wt %

               Weighted contribution of each
               component to unit emissions
               ppmw
38
19
19
                                         24
               aRased on GC-MS  analysis of liquid stream samples  (and some vapor samples).
                Etttiii'rttes biisad on  the. assumption that fugitive £!iiii.r,sion compositions from
                sources in liquid stream service is the sane  composition as that of the
                Jiquid contained in the emission source.

               bCouipositior.s are estlmred to 2-3 significant figures.  Additional significant:
                figures are a result  of calculations!, procedures,  and they should not be given
                any importance.
                             Totals
100%
Benzene
Toluene
Ethylbenzene
Xylenes
Other Alkylbenzen.es
Naphthalene
Anthracene
Biphenyl
Other Polynuclear Aroma t
n-Hcx.ine
Other Alkanes
Clef in
Cycloalhanes
Hydrogen

0
0
0
0
0
0
0
0
ics 0
0
349600
22800
0
7600

48
498
16S
308
3150
278
i
_i_
119
2847
7379
94926
0
80277
0

0
0
0
0
0
0
0
0
0
0
190000
0
0
0

0
0
0
0
0
0
0
0
0
0
156000
0
0
84000

48
490
169
308
3150
278
1
119
2847
7379
790526
22800
80277
91600
1,000,000

-------
          Dewaxing—Dewaxing is the most difficult part of lube oil
manufacture.  The oil is contacted with solvent and chilled, causing the
wax  to precipitate.  The precipitated wax is separated from the mixture
by filtration or centrifugation.  The dewaxed oil and solvent are separated
by distillation and steam stripping.  The wax is solvent treated again under
different conditions to obtain a deoiled wax product.

          Finishing—Finishing processes remove traces of resinous materials
and  chemically active, compounds which can deteriorate the color of the
product.  The compounds can be absorbed by contacting the oil with various
types of clay, activated earth, or artificial absorbents.  Hydrotreating
(hydrofinishing) can also be used to effectively remove nitrogen compounds
which cause the oil to darken and become unstable.  Sulfur and oxygen con-
tent are also effectively reduced by hydrofinishing.

7.1.7.5   Sulfur Recovery

          A sulfur recovery plant converts hydrogen sulfide to elemental
sulfur.  The Clans process is assumed to be used for sulfur recovery by all
major refiners.

          Process types and process flow diagrams for the Glaus process are
given in Appendix E (Volume 4).  The amount of sulfur reaching the sulfur
recovery unit varies with the percent sulfur in the crude and the extent of
desulfurization.  Typically, 60 percent of the sulfur in the crude reaches
the sulfur recovery plant.

          Process Conditions—A Glaus plant operates at about 470°F and one
to two atmospheres.   About  20 Btu of heat are required per pound of sulfur
produced.  However,  approximately four pounds of steam per pound of sulfur
are produced in  a waste heat boiler.  This  steam can provide from five to
thirty percent of the total refining steam requirements.
                                   311

-------
          Atmospheric Rm1ssions—Process emissions from Glaus plants are
discussed in Appendix E (Volume 4).   A 100,000 bpd refinery with a one
percent sulfur crude and a 95 percent efficient sulfur plant will produce
5-6 tons/day of sulfur emissions.   Sulfur is emitted as SO?.,  H2S,  COS,
CS2, and mercaptans.

          It  is  estimated that there are 200 valves,  800 flanges,  nine
pump seals, 20 drains, and four  relief valves  on a typical  Claus unit.
These can be  sources of fugitive emissions of  various sulfur compounds
from the Claus unit.  However, because sulfur  compounds such as H2S are
present in streams, safety practices dictate careful  attention to
maintenance.

7.1.8     Waste  Treatment

7.1.8.1   Slowdown/Flare

          Blowdown/flare systems are common to all crude oil refineries.
A blowdown system consists of pressure relief  devices, manual bypass valves,
blowdown headers, knockout vessels, and holding tanks.  Compressors and
vapor surge vessels may also be included.  A flare is used  for final
disposal of noncondensable combustible gases.

          A pressure relief valve is an automatic pressure-relieving device
activated by the static pressure upstream of the valve.  There are three
types of pressure relief valves:   relief valves, safety valves and safety-
relief valves.  Relief valves, used primarily for liquid service, open in
proportion to the increase in pressure.  Safety valves, used in the
petroleum industry primarily for  steam or air service, pop fully open at a
set pressure.   Safety-relief valves may be used as either safety valves or
relief valves, depending on application.
                                   312

-------
          Another pressure  relief  device,  the  rupture  disk,  consists of  a
 thin metal  diaphragm held between  flanges.  Rupture disks are sometimes
 installed upstream of pressure  relief valves to prevent hydrocarbon leakage
 from valve  seals.

          Flares may be. designed for emergency or routine use.  These may
 be burning  pits, elevated flares,  or ground-level flares.

          Burning pits are  normally used only  for emergency  burning of
 large quantities of gases.  A typical pit  is simply an excavation 4 to 6
 feet deep and 30 to 40 feet square with burners mounted on one wall.
 These are not commonly used in modern refineries.  Elevated  flares allow
 gases to be burned safely from  the top of  a stack.  Ground flares are
 installed in a large open area  for safety  and  fire protection.4

          Smoke emissions from flares are  avoided whenever possible.  For
 smokeless operation, three  combustion principles are followed:  maintenance
 of critical combustion temperatures, adequate  combustion air, and adequate
mixing of air and fuel.  Steam is often injected to provide,  turbulence
which promotes mixing.  Air and water have also been used.   Further dis-
 cussion of  the use of steam in flares is provided in Appendix E (Volume 4)
 and Appendix F (Volume 5).  Emissions from blowdown/flares include:

          •    Combustion products from flares.

          •    Fugitive emissions.

Emission factors for smokeless flares are given in Table 7-44.  It  should
be noted that these  flare  emission factors  may  not  be  applicable to  specific
flares due to variations  in  off-gas composition,  flow  rate,  and  design
configuration.
                                   313

-------
              TABLE 7-44.  EMISSIONS FROM SMOKELESS FLARES
                                                    Emissions
  Component                            (lb/103 bbl total refinery capacity)

Participates                                        Negligible
SoJ°                                                   26.9
  X
CO                                                      4.3
Hydrocarbons                                            0.8
N0x                                                    18.9
NH3                                                 Negligible
Aldehydes                                           Negligible
o
 Source:  Reference 7.

 Varies with fuel sulfur content.
7.1.8.2   Wastewater Treatment

          A tremendous quantity of water is used in a refinery.  A substan-
tial portion of this water is reused before discharge.  However, it must
normally be treated to remove contaminants before discharge.

          Refinery wastewater treatment is of two types:  inplant treatment
(pretreatment) and end-of-pipc treatment.   Inplant treatment is the use of
procedures which can (1) reduce the amount of pollutants sent to the waste-
water system, (2) reduce the amount of water discharged, and (3) make sub-
sequent end-of-pipe treatment more effective.  End-of-pipe treatment
processes are classified as primary, intermediate, secondary, or tertiary
processes, depending on their function.
                                   314

-------
          High concentrations of hydrogen sulfide and ammonia are often
 reduced by steam-stripping before water is sent to the wastewater system.
 Phenol may be removed by using phenolic waters as desalter water:  a portion
 of the phenol is absorbed by the crude oil.1*6  Any technique which limits
 contact between oil and water also reduces the waste load.

          A number of procedures have been developed to reduce the amount
 of wastewater.  Among these are recirculation, use of air coolers and cool-
 ing towers to eliminate once-through cooling, and chemical treatment to
 prevent corrosion or scaling.

          Pretreatment techniques which improve the efficiency of end-of-
 pipe treatment include stream segregation, preaeration of the water to meet
 immediate, oxygen demand, and surge ponds to smooth the flow of wastewater.
 An example of refinery stream segregation in a modern refinery is given in
 Appendix F (Volume 5).  Older refineries may be able to segregate only
 sanitary wast es.

          A classification of end-of-pipe wastewater treatment processes is
 given in Table 7-45.   Each refinery has its own particular scheme based on
 the type of refinery,  the water use pattern, and applicable pollution
 regulations.

          Primary treatment is often the only treatment required of a
 refinery.   API separators remove oil which floats and coalesces on the
 surface of the water and sludge which settles to the bottom of the separa-
 tor.   Parallel plate separators are a relatively new method for removing
 oil and sludge which reduce the distance the oil droplets must travel
before collection.

          Intermediate treatment removes materials such as emulsions and
 suspended or colloidal solids,  which neither float nor settle within the
                                   315

-------
            TABLE 7-45.   CLASSIFICATION OF END-OF-PIPE REFINERY
                         WASTEWATER TREATMENT PROCESSES
    Treatment
     Objectives
     Processes
Primary
   Treatment
Free. Oil and Suspended
Solids Removal
API Separators
Parallel Plate
  Separators
Intermediate
   Treatment
Emulsified Oil, Suspended
Solids, and Colloidal
Solids Removal
Dissolved Air
  Flotation
Coagulation-Flotation
Coagulation-Precipita-
  tion
Filtration
Equalization
Secondary
   Treatment
Dissolved Organics
Removal Reduction in
BOD and COD
Activated Sludge
Trickling Filters
Aerated Lagoons
Oxidation Ponds
Rotating Biological
  Discs
Tertiary
   Treatment
Variable. Objectives
Filtration
Air Flotation
Coagulation
Activated Carbon
                                    316

-------
 residence  time  provided in primary  treatment.  Removal may be by dissolved
 air  flotation  (DAF),  chemical coagulation and sedimentation, or filtration.

           Secondary treatment involves physical, biological, or chemical
 treatment  for  the  removal of dissolved organics.  Physical and cherair.al
 treatments are  considered advanced  treatment processes which follow
 biological treatment.

          All of the  biological methods for secondary wastewater treatment
 involve oxidative  decomposition by micro-organisms.  These processes—
 activated sludge,  trickling filters, aerated lagoons, oxidation ponds, and
 rotating biological discs - are discussed in Appendix F (Volume 5).

          Some  refineries provide additional tertiary treatment downstream
 of biological treatment units.  This polishing treatment may be necessitated
by changes in refinery effluent water quality or by government regulations
on effluent quality.  Tertiary treatment commonly involves the reduction of
suspended solids and  carbon adsorption for removal of organic pollutants.

          Fugitive emissions are released from all of the above operations.
The extent of these emissions is a function of the amount and volatility
of hydrocarbons entering a unit, emission controls used, and other factors.
The greatest opportunities for emissions are at the front end of the waste-
water system, i.e., severs, open ditches, holding ponds prior to the API
separator, and  the APT separator itself.  Since the APT separator removes
most of the hydrocarbons with the skimmed oil, units downstream of it
re.lea.se substantially fewer fugitive hydrocarbons.   Emission factors for
API separators are given in Table 7-46.  Emission rates could not be. deter-
mined accurately enough to warrant the development of emission factors in
this study.  Data to update these factors will be collected as part of an
EPA research program on petroleum refinery wastewater system emissions.
                                    317

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              TABLE  7-46.  API  SEPARATOR EMISSION FACTORS
                                                   Emissions
                                      lb/103 gal                lb/103 bbl
                                      Wastewater              Refinery Feed
APT separators
    (uncontrolled)                         5                       200
APT separators
    (controlled by fixed
    or floating roof)                    0.2                        10
Source:  Reference 7.


7.1.8.3   Sludge/Solids Treat ing/Disposal

          Many of the solid wastes generated by petroleum refineries con-
tain toxic hydrocarbons or metallic compounds.  The wastes may be generated
continuously or intermittently.

          Solid wastes have historically been sent directly to landfills
or open pits for disposal.  Oily wastes, although sometimes incinerated,
have usually been sent to an oily waste disposal pit.

          More stringent solid waste disposal regulations have forced the
adoption of more advanced disposal practices.  Landfilling is still the
most commonly used method, but landfills must now be constructed to allow
no direct contact between the waste and surface or groundwater.

          Landfarming involves the use of soil bacteria to biodegrade
organic materials in sol:id waste.s.  Little is known about the nature of
the degradation products or about the fate of heavy metals or toxic organic
compounds in the waste.
                                  318

-------
          Incineration is a relatively expensive method for solid waste-
treatment.  Supplemental fuel, pollution controls, and dewatering of the
waste, may be required.  And, although the waste volume is reduced, the
incinerator ash must still he disposed.

          Chemical fixation involves the addition of certain chemicals to a
waste to form an insoluble solid which can be landfilled.  Little leaching
of heavy metals and organic, compounds results from chemically fixed waste.

7 • 2       Con t r o1 Technplog y

          Refinery control technology includes all types of equipment,
processes, operating practices, monitoring, maintenance, and raw material/
fuel modifications which result in a net decrease in air emissions within
the reasonable and practical constraints imposed by capital, operating and
energy costs.  This section includes discussions of the state-of-the-art of
petroleum refinery fugitive and process emission controls; the need for
additional controls for some sources; emission control technology used in
related industries and its applicability to refining; and the economics
of control.

          Detailed descriptions of emission sources and control technologies
are presented in Appendix E (Volume 4).  Emissions from transfer facilities/
operations, storage vessels, or other auxiliary processes are not included.

          Controls for fugitive emissions are discussed in Section 7.2.1.
Included in this discussion are work practice, and equipment controls.
Equipment controls for process (stack/vent) emissions are described in
Section 7.2.2.   Section 7.2.3 includes  discussions of process,  fuel,  and
feedstock controls for process emissions.

          Controls for fugitive emission sources are generally applicable
to a particular source type (valve, puir.p, etc..)  and are not unicue to any
                                    319

-------
type of process unit.  Fugitive emission controls are, therefore, discussed
by source type.  Process emission controls are discussed on the. basis of
the type of process unit, because of the differences in emissions and con-
trols between processes.

7.2.1     Control of Fugitive Emissions

          In this section the descriptions of fugitive emission control
technology are presented for each type of emission source (valve, pump,
etc.).  The order of presentation is such that sources with similar types
of controls are discussed in sequence.  The relative contribution of source
types for a hypothetical refinery is presented in Section 2.7.3 of Appendix
B (Volume 3) of this report.

          Three levels of control are described for most sources.  Existing
controls are those in general refinery use, although the extent of appli-
cation may be variable.  Available control technology may be used in some
areas of the refining industry due to regulatory or other requirements.
Control technology transfer includes any types of emission controls that
have been applied to similar types of emission sources in other industries.

7.2.1.1   Valves

          Valves can leak hydrocarbons through the junction where the
activating stem penetrates the valve body.   Excessive leakage from this
junction is generally prevented by a packing gland or a pressurized grease
seal.   If a valve is operated with one side of the valve seat open to the
atmosphere, such as for draining or sampling operations,  hydrocarbons may
also leak through the valve seat.

          Table 7-47 contains the approximate distribution of refinery
valves screened by Radian within the battery limits of major process units
during the thirteen refinery sampling programs.   The distribution of each
                                   320

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         TABLE 7-47.  APPROXIMATE DISTRIBUTION OF REFINERY PROCESS
                      VALVES3 BY TYPE AND SERVICE
Type
Valve
Gate
Globe
Plug
Butterfly
Diaphragm
Total
Valve Type Distribution
by Service, %


Manual
64
3
5
0
0
74
.7
.8
.7
.6
.0
.8


Control
0
23
0
I
0
25
.0
.3
.0
.8
.1
.2
Total
Type
Distribution, %
64
27
5
2
0
100
.7
.0
.7
. 5
.1
.0
Check and sample system valves excluded.  No dry-servir.e slide valves were
surveyed.
                                    321

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type of valve is shown for manually operated and automatically controlled
service categories.  Approximate]y 88 perc-.ent of all the screened refinery
valves were either manual gate valves (65 percent) or control globe valves
(23 percent).

          Existing Controls for Valves—These controls include the. valve
stem seal, inspection and maintenance practices, and closure of the
atmospheric side of open-ended valves.

          Valve StemSeals—The valve stem seal is designed to prevent
leakage of the contained fluid and is therefore a fugitive emission control.
All gate,  globe, and butterfly valves screened by Radian had a packed gland
stem seal.  These packed stem valves represent approximately 94 percent of
all refinery valves.   Plug valves typically have a grease-lubricated,
tapered plug to prevent leakage.   Grease may be added periodically to pre-
vent leakage and to assure proper operation of the plug valve.
          Packed stem seals consist of a stuffing box that surrounds the
stem, rings of compliant packing material in the annular space,  and a gland
or follower that is used to compress the packing against the stem to form
a seal.   Figure 7-1 is a simplified diagram of the type of packed seal used
in valve stems.
                               Stuffing
                               Box
                                                   Packing
                                                    Gland
           Working
           Fluid
"\seal facex*
                         or
                       Follower

                    Figure  7-1.
      Packing
     Simple Packed Seal
                                                 ~_ Valve
                                                     Stem
                                                 Possible
                                                 Leak
                                                 Areas
                                   322

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           The  fluid may be  fvirther prevented  from diffusing through  standard
 type  packing by  dispersion  of  lubricant  through  the packing.   The lubricant
 also  alleviates  galling, heating, and  scoring of Che stem or  shaft.   In
 most  cases, a  lubricant must be  compatible with  the packing and the  working
 fluid.   In refining,  this lubricant might be  a. silicone oil,  a petroleum
 grease,  or a TFE or graphite dispersion  in an oil or grease.

           Lubricants may be present in the coils or rings of  packing  as
 received.   They  may also be introduced Into the gland through a "grease"
 fitting which  passes  lubricant into the  stuffing box.

           Table  7-48  shows  the diversity of valve packing materials  used
 alone or in combination.    Most of these materials may be purchased  in
 coils or in preformed rings.  They may be. solid or stranded and may have
 a round, square,  "U," or chevron cross-section.

           All  refineries have operating practices that require repair of
 any detected leaks.  These practices arc primarily aimed at preventing
 fires or other safety ha/.ards that could result from large amounts of hydro-
 carbon leakage.  Visual methods or odor arc generally relied upon to detect
 leaks.  However, many leaks from valves and other sources may not be.
 detected by sight, hearing,  or smell.   It is  also a common refinery
                                                                     76  77
 practice to lubricate valves and tighten packing glands periodically.  '

          Open-ended valves  may be used for draining,  venting, or sampling
 operations.  In addition to  fugitive emissions from the stem seal, the
 valve seat may be a source of fugitive emissions.  To  prevent emissions
 through the seat, the open-end can be  sealed with a cap,  plug, blind
 flange,  or a second valve.   Two valves in series (double block and bleed)
can also be installed on sampling connection.   This provides a second valve
seat to  resist  emissions of  the process fluid to the atmosphere.
                                    323

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                          TABLE 7-48.   PACKING MATERIALS - PROCESS VALVES
        Packing Material
        r orm
                               Use
                    Temperature
Flexible, all metallic
Flexible metallic packing
(aluminum).
Flexible metallic packing (copper)
   ft-f iber puro .nsbof.tos ami fine
lubricating graphite  (nonmo.tal.11c).

Closely braided asbestos yarn;  top
jacket reinforced with Inconel
wire; core: long fiber asbestos.

Pure asbestos yarn witb an Inconel
wire insert around a  resilient
asbestos core impregnated with
graphite.

Twisted long fiber Canadian
asbestos.
Spiral wrapping.   Thin
ribbons of soft babbit
foil.

Spiral wrapping.   Thin
ribbons of soft annealed
aluminum foil loosely
around a small core of
pure dry asbestos.

Soft annealed copper
foil loosely around a
small core of pure dry
asbestos.

Graphite special loug-
fibor asbestos binder.

Spools, die-formed
rings. .
Spool form, die formed.
Spool form, die formed.
Valve stem
packing
Hot oil valves,
diphenyl valves,
Up to 450°F.
Up to 1000CF.
Hot oil valves,    Up to 1000°F.
diphenyl valves.
Extreme
resilience.

High-temperature
valves.
Up  to 750°F.
Up to 1200°F.
Valve  stem  for      Stuffing  box
air, water,  steam  temperature up
and mineral  oil.    to 1200°F.
Valves  handling,
high and  low
pressure  steam.
Up  to  500°F.
                                                                                     (Continued)

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                                              TABLE 7-48.   (Continued)
               Packing Material
                                              Form
                               Use
 Temperature
1-0
Ul
       Asbestos,  graphite and oilproof
       binder.

       Solid,  braided  TFE.
        Braided  asbestos with  complete
        impregnation  of TFE.
Braided of high quality wire-
inserted asbestos over a loose
core of graphite and asbestos.

Braided of high quality wire-
inserted asbestos over a loose
core of graphite.

Braided of long-fiber Canadian
asbestos yarn each strand Impreg-
nated with heat-resistant lubricant

Long-fiber Canadian asbestos yarn,
each strand treated with a synthe-
tic oilproof binder and impreg-
nated with dry graphite.
Spool form, die formed.


Coil, spool, ring.



Coil, spool, ring.



Coils, spools.



Coils, spools.



Coils, spools.



Coils, spools.
                                                                 Shutoff valves.     Up to 550°F.
                                                                 Valve shaft for    100°F to 500°F.
                                                                 highly corrosive
                                                                 service.
                                                                                 g

                                                                 Valve stems in     100°F to 600°F.
                                                                 mild chemical or
                                                                 solvent service.
                                                                        Valve  stems,
                                                                        steam,  air,
                                                                        mineral oil.
Up to 1200°F.
                                                                         Stainless-steel     Up  to  1200"F.
                                                                         valve stems,  air,
                                                                         steam,  water.

                                                                         Valves for steam,   Up  to  550°F.
                                                                         air,  gas and  mild
                                                                         chemicals.

                                                                         Refinery valves.    To  750°F.
                                                                                            (Continued)

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                                     TABLE 7-48.   (Continued)
       Packing Material
Braided/overbraided, wire-
inserted, white asbestos packing
impregnated with.a heat-resistant
lubricant.

Braided white asbestos yarn
impregnated with TFE suspensoid.

Braided or bleached TFE multi-
filament yarn.
Braided TFE multifilament yarn
impregnated with TFE suspensoid.
Asbestos jacket, braided over a
dry-lubricated plastic core of
asbestos graphite and elastomers.
        Form
Coils, spools.
Coils, spools.


Spools, coils.



Spools, coils.
Spools ana coils,
                                Use
                    Temperature
Valve stems, for
valves handling
steam, air, gas,
cresylic acid.

Valve stems.
Up to 750°F.
100°F to 600°F.
Valve stems for    12°F to 500°F.
highly corrosive
liquids.

Valve stems for    120°F to 600°F.
corrosive chemi-
cals, solvents,
gases.

Valve stems, for   Up to S50°F.
valves handling
superheated steam,
hot gases.
Source:  Preference 75.

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           Effectiveness  of  Existing  Controls—The  overall  effectiveness  of
 existing  controls  is  reflected  in  the  emission  factors  given  in  Section  5
 of  this report.  These emission factors were  derived  from  test data  collec-
 ted from  a broad cross-section  of  thirteen  refineries.   All levels of  the
 types  of  control existing at  the time  of  the  field sampling (1977-1979)
 were included.  The effectiveness  of individual types of existing controls
 (type  of  packing,  maintenance schedule) could not  be  determined  from the
 available  data.

           Available Control Technology for  Valves—Leak detection and  repair
 programs  are  the available  controls  for valves.  Programs  of  this type are
 already a  regulatory  requirement in  some  areas.  They will prohably  become
 more, common as additional regulatory requirements  are promulgated and  value
 of  the products lost  as  fugitive emissions  increases.

           Leak detection and  leak  repair  programs  consist  of  strategies to
 Identify  significant  fugitive hydrocarbon emission sources combined  with
 methods to  reduce  or  eliminate  the leakage.   At a  specified interval,  each
 valve would be checked with a portable hydrocarbon detector.  If a pre-
 determined  hydrocarbon concentration limit  (action level)  were exceeded,
 the  valve would be repaired.  The  repair  could  consist  of  tightening the
 packing, injecting grease,  replacing the packing,  or replacing the valve.
 During repairs such as tightening or greasing,  the hydrocarbon detector
 should be used to permit assessment of the  effect  of the repair attempt.
 This type of repair is called "directed" maintenance.

          Effectiveness — In the limited valve, repair study conducted by
 Radian, the average weight percent emission reduction immediately after
 "directed" maintenance was 91 percent.   The detailed results  of the main-
 tenance study are shown in Section 6 of Appendix B  (Volume 3).  They are-
 summarized  in Section 5 of  this report.  Data on the long-term effects of
maintenance are not available.
                                    327

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           In some cases injection of sealing fluids into the packing area
of the valve may be used to reduce fugitive emissions.  The effects on
emission reduction and valve operability have not been reported.  For some
control valves, operating procedures may prohibit excessive in-service
adjustment to prevent malfunction of vital process control valves.

          The required frequency of leak detection is dependent on the
rate of recurrence of repaired leaks and the rate of occurrence of new
leaks.  The selection of an appropriate action level is dependent on the
demonstrated ability to repair leaks of a given magnitude.  Radian test
results indicated that the smaller the initial leak rate, the more likely
it is that repair efforts will be ineffective.

          Because of the sparseness of data on long-term effectiveness of
leak repair, frequency of occurrence of leaks, and the fraction of leaking
valves which are unrepairable while in service, no quantitative estimate of
the overall emission reduction can be defined.

          The major costs for leak detection and repair are for labor
expenses.  The hydrocarbon detector can cost up to $4,250 per instrument,
and if leak surveys were conducted as frequently as once per month each
process unit would probably need one instrument.  Actual  labor costs are
dependent on the wage rate of the persons performing the leak survey and
leak repairs.  Estimates have been made for the time, needed to conduct
leak surveys.  One petroleum refining company has estimated that one minute
                                                          7 ^
per valve is the average time required for leak detection.  "   The time
needed to repair a leak will be dependent on the type of repair attempted.
Simple tightening of packing by refinery employees would obviously be much
cheaper than injection of a sealing fluid by leak repair contractors.   The
total cost  of a leak detection and repair program would be reduced by the
value of the product that was prevented from leaving the process as an
emission.   The emission reduction would also represent an energy saving.
                                    326

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          Control Technology Transfer for Valves—Fugitive emissions of
some process fluids may be hazardous or toxic.  In industries with these
constraints, valves with isolated stem seals may be used.  The diaphragm
and bellows-sealed valve are two types of these, valves.  Because the
process fluid is prevented from contacting the stem/body junction by a
bellows or diaphragm, the potential for fugitive leakage is reduced.  These
valves are not generally applicable to refinery use, however, because of
several limitations.

          The diaphragm material in the diaphragm valve limits operation to
about 50 psi pressure differential.flu  This type valve has definite limita-
tions in refinery use.  It can fail catastrophically upon overheating of
the elastomer diaphragm, so it should not be used in hydrocarbon service.
where a fire could be fed by its failure.  The bellows-sealed valve,
because of the corrosion and fatigue failure potential of the bellows,  is
subject to combined temperature-pressure-corrosivity stress.   Its usage is
best defined by the valve manufacturer.  Bellows-sealed valves should have
stem seal packing as back-up protection against bellows failure.

          Because use of these special valve stem seals will  probably be
limited, the impact of their use on emission control should also  be limited,
as would any economic impact.  No primary energy cost would result from
substitution of a very limited number of packless valves for  conventional
packed-stem, bonnet-sealed valves.

          Diaphragm and bellows valves are approximately 1.5  to 3.7 times as
                                                      a i
expensive as gate valves according  to the GARB report.     Another source
estimated that bellows valves might cost 10 to 20 times as much as packed-
                                                                         8 £
stem valves, but  would have a lower cost multiple if purchased in volume.
                                    329

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 7.2.1.2    Flanges

           Flanges are paired junctions between sections of pipe and pieces
 of  equipment.  They are sealed against leakage by the tightening of bolts
 or  studs which compress a flat gasket between the flat faces of the mating
 flanges, or  compress an "o" ring set in the grooved faces of special
 flanges.   The most common flanges have raised faces to accommodate tighten-
 ing of the bolt and centering of the gasket.  TypJca.l gasket materials are
 asbestos composition or spiral, metal strip-reinforced asbestos or TFE.
 "0" rings  may be made of neoprene, TFE or soft metals, depending upon
 temperature  and pressure limits.

           The results of the refinery sampling program showed that flanges
 have a very  low emission factor, and even though there are many of them,
 their overall contribution is small.  The only real controls available for
 flanges are  leak detection and repair programs.   If a leak Is found, the
 only repair  options are tightening the flange bolts or injection of a seal-
 ing fluid, since most flanges cannot be isolated from the process in order
 to permit  gasket replacement.

           A  large amount of time would be required to inspect all flanges
with hydrocarbon detectors.  The expenditure of  this time and manpower dues
not appear justified given the low average emission rate for flanges.

 7.2.1.3    Pump Seals

           Pump seals prevent the escape of process liquid from the area
between the rotating pump shaft and the stationary pump housing.   There are
two basic  types  of seals, the. packed seal and the mechanical seal.   The
packed seal can  be used on pumps  with reciprocating or rotating shaft
motion, and mechanical seals are  applicable only to rotating shafts.
                                    330

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          Existing. Control Technology—'This study indicated refinery
pump-seal combinations fall almost exclusively into one of three broad
categories:  centrifugal pump - mechanical seal  (82.1 percent), centri-
fugal pump - packed seal (11.5 percent), and reciprocating pump - packed
seal  (6.4 percent).

          The tvjo types of existing controls for pumps are the pump seal
itself, and inspection and maintenance of the pump seal.  The packed seal
and mechanical seal resist leakage of the pumped fluid by different
mechanisms, and are described separately.

          The packed seal is used to seal both rotary and reciprocating
shafts against leakage of liquid from the "working fluid" end of the shafts
to the atmosphere.  Compressed packing in the stuffing box forms a contact
seal against the moving drive shaft.  Friction resulting from this contact
requires that either the working fluid be allowed to leak from the stuffing
box housing the packed shaft, or a supplementary liquid be introduced to
remove fractional heat.

          Packings for the compression-type packed seals may be solid or
braided, twisted or ribbon-form (the latter form in graphite only).   They
may be obtained in continuous rolls or preformed rings.   Packing materials
include asbestos/TFE,  TFE (lubed), asbestos/graphite,  graphite-fiber,
graphite-ribbon, lead, aluminum,  and Inc.onel-reinforced asbestos over
resilient case.

          Under moderate conditions, the trend in braided backings is away
from asbestos and toward TFE because of the latter's  low coefficient  of
friction and its chemical inertness.

          The mechanical seal in  its tr.any forms is the predominant pump  seal
today.  Contrary to the broader application of packed  seals  to both  rotating
and reciprocating shafts,  however,  mechanical  seals  are  used only  on  rotary
                                    331

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 shafts.  Mechanical seals may be used to seal both pump and compressor
 shafts, but are more universally applied to pumps, specifically centrifugal
 p ump s.

          Mechanical seals are prefabricated assemblies which shift the
 point of wear from the drive shaft, as with packed seals, to easily
 replaced pairs of rings.  One of the. rings is attached to the pump shaft,
 and the other to the gland plate or its equivalent.  Seal faces are per-
 pendicular to the shaft and are typically lapped to a flatness of two light
 bands.  This precise flatness accounts for their typically low leak rate
 when carefully installed and started up.

          Single mechanical seals will generally serve to limit emissions
 in the majority of applications, but double mechanical seals provide an
 added margin of protection against seal failure.  Double seals normally
 have a barrier liquid circulating between the seals.  If the inner seal
 should fall, the outer seal will prevent escaping fluid from reaching the
 atmosphere.

          Mechanical seals are used in the majority of refinery pumps.  The
 American Petroleum Institute (API)  recommends mechanical seals as particu-
 larly advantageous for hydrocarbon emission control in the following cases:
 (1) ". . .more—or-less continuous pumping of products having a Reid Vapor
 Pressure of five pounds [per square inch (author's note)]  or greater.  . ."
 and (2) ".  . .when fluids are under substantial  pressure and when the pump
 or compressor is in continuous service.   For pumps operating on stand-by
 service either packed or mechanical seals may be used."'6

          At the time of the Los Angeles County, California,  study twenty
years ago,  mechanical seals made up only 42 percent of the seals in the use
      H 1
 there.    In the current refinery stud}7, the percentage was 82 percent.
The Radian  survey showed this  percentage to be  further subdivided into
                                   332

-------
approximately 67 percent single mechanical seals and 15 percent double
mechanical seals.

          Visual inspections are generally used to detect significant pump
emissions.  In some cases pressure gauges/alarms are used to detect build-
up of pressure in barrier fluids of double mechanical seals.  Such a pres-
sure buildup indicates failure of the inner seal.

          Packed seal emissions can generally be reduced by tightening the
packing gland.  This can be accomplished while the pump is in service.
Emissions from a mechanical seal, however, indicate a mechanical failure
in the seal assembly.  The pump must be taken out of service, and the
mechanical seal can then be replaced.

          frequency o_f_ App 1 ication_,^_Ef feetiveness , and Cost of Pump Seals—
Application of the types of pump seals is relatively uniform within the
refining industry.  This may be the result of a greater uniformity of
feedstocks and products in the refining industry than in the chemical
industry.  The application of standards published by the American Petroleum
Institute (API) has also undoubtedly led to uniformity among devices used
to control fugitive emissions, not only from pumps, but also from some of
the other devices tested in this program.

          The frequency of application of types of pump seals that was
observed in the Radian sampling program is shown in Table 7-49.  Sufficient
data are not available to compare the relative control effectiveness of
the. various types of seals.
                                   333

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    TABLE  7-49.  DISTRIBUTION OP PUMP SEALS IN RADIAN REFINERY STUDY
                                                                Percent of
               Pump Type                                        Population
A.  Centrifugal Pump - Mechanical Seal                             82.1
B.  Centrifugal Pump - Packed seal                                 11.5
C.  Reciprocating Pump - Packed Seal                                6.4
                         TOTAL                                    100.0
          Table 7-50 presents a cost breakdown of pump system elements for
systems rated at 3 - 200 horsepower.  May, 1980 costs were rolled back to
mid-1979.  Cost estimates of packed and mechanical seals are shown in part
(5) of the table in mid-1979 dollars, and in part (6) as percentage add-on
costs to bare, uninstailed pump costs [Subtotal (4)].  These add-on costs
for seals range from 1.2 to 3.0 percent for packed seals to 14.2 to 36.4
percent for double mechanical seals for the most common shaft size of
1.875 inches diameter.

          Table 7-51 contains a comparison of seal friction losses and
hydrocarbon leak estimates for packed seals and three basic types of
mechanical seals.   Friction losses and hydrocarbon losses are known to
vary widely with the fluid properties of the sealed liquid, the seal face
materials, the condition of the seal, bearings and shaft, and seal design,
so these figures are presented only as approximations of expected
performance.

          Inspection and Maintenance—All refineries practice inspection
and maintenance of pump seals to prevent fire hazards resulting from
complete seal failure.  Pump seals are usually inspected visually once
per day or per shift.   Packed seals can be adjusted while in service to
reduce leakage, but mechanical seals usually require, removal for repair.
                                    334

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 TABLE 7-50.   CENTRIFUGAL  PUMP  SEALS -  COST CONTRIBUTION TO  TOTAL
                PUMP  COST*
     Pump Horsepower                     3.0       100.       100.       200.
     Shaft Diameter, Inches              1.875     1.875     2.375      2.375

1.  Pump, including shaft, coupling,
    bore plate, seal/bush hardware as
    required.  (Installation costs
    not included)3                       2830      4670       4810       6370

2.  Switchgear - Switch, enclosure

3.
4.
5.



lighted push botton."
Driver - Electric
Subtotal
Seal Alternatives
a. Packed Seal
b. Single Mechanical Seal
c. Double Mechanical Seal
620
230
3680

110
860
1340
1940
2850
9460

110
860
1340
1940
2850
9600

130
1000
—
4110
8750
19230

130
1000
—
6.  Seal Costs - Percentage of Subtotal  (4)

    a.  Packed Seal                       3.0        1.2        1.4       0.68

    b.  Single Mechanical Seal           23.4        9.1       10.4       5.2

    c.  Double Mechanical Seal           36.4       14.2


*Mid-1979 Costs = May,  1980 Dollars  x  0.921
liases:
a                                                  85
 Reference 84.   Pump  built to  API  Specification  610,   and  upon  the following
 conditions:   1)  Low  corrosion—steel  puir.p casing,  cast  iron/steel inpeller
              2)  Seal gland pressure—200 psig  (-1/3 of  discharge pressure
                 maximum)
              3)  Pur.ped  Fluid—light gasoline
              4)  Pu:rpcd  Fluid  Temperature— £ 350°F
              5)  Shaft  Speed —3500 RPM
 Reference 86.   Switch  gear—explosion-proof, locally-mounted  push button
 stop-start with  red  light for "Oji"  indication.
 Reference 84.   Electric  Driver—Three phase, 400 volt,  explosion proof.

 Reference 87.   Packed  Seal—Cost  of packing materials approximate.

 Referer.ze 88.  Single Mechanical  Seal—Crane Packing Co. )?8-B-l with throttle
 bushing as hack-up.

 Reference 87.   Double Mechanical  Seal—Chesterton Seal No.  241.
                                      335

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              TABLE 7-51.   ESTIMATED  ENERGY LOSSES - PUMP SEALS
Hydrocarbon Leak Estimates, Ib/hr
Seal Power Open ,
Seal Type Consumption, kW Literature This Study
Packed 1.16 0.264°
Single mechanical,
unbalanced 0.422 X).0044e
Single mechanical,
balanced 0.194 >0.0044e
Double mechanical,
balanced 0.287 =0.00
0.16-0. 37, d
all pumps
 Reference 89.

 See Appendix B  (Volume 3), p. 2-263, pumps, light liquids.
r*
 Based upon 60 drops/min of hexane @ 20 drops/mA.  Reference 90.

 Range based upon 95% confidence interval.

 Based upon as little as 1 drop/min. of hexane @ 20 drops/mfc.  Reference 91-

 Reference 91.

Bases:  Pump shaft dia.—1.875 in.; stuffing box pressure—200 psig; barrier
        fluid pressure—175 psig (double mechanical seal only);  pump speed—
        3500 rpm; pump horsepower range (typical)—3-100 h.p.
                                    336

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The effectiveness of these inspection and maintenance programs is reflected
in the emission factors presented in Section 5 of this report.

          Available Control Technology for Pumps—Leak detection and repair
strategies are the available controls for pumps.  The procedures for find-
ing leaks requiring repair are the sane as those described previously for
valves.

          No data are available to quantify the effectiveness or cost of
leak detection and repair for pumps.  Effectiveness would be dependent on
initial leak rates, the ability to repair the leaks, and the length of
time before the leaks reoccurred.  Costs would be dependent on labor rates,
labor requirements, and the value of the product saved.  Average leak
detection time required for pumps has been estimated to be five minutes
per seal, and the average leak repair time has been estimated to be 80
hours per seal.

          Technology Transfer for Pumps—Sealless pumps are used in other
industries in cases where the pumped fluid is toxic or otherwise hazardous
and leakage cannot be tolerated.  Sealless pumps include diaphragm pumps,
hermetically sealed "canned" pumps, and magnetically coupled pumps.   Since
these pumps do not have a shaft/casing seal, their emission potential is
much lower.  Emissions may result from diaphragm failure or case failure.

                                                            p c
          Sealless pumps are not covered by API Standard 610 '  for pumps,
which may explain why no sealless pumps were found in the 13 refinery
survey.  If sealless pumps are to be used in the refining industry,  they
must be proven performers in terms of leak-tightness, reliability,  main-
tainability,  useful life and safety.
          The original cost of a "canned" pump may be approximately 110 to
                                                                      o o
.115 percent of the cost, of a centrifugal pump with conventional seals/'
No data are available to discern differences among the other true costs of
                                   3.37

-------
 running  conventionally-sealed versus  sealless pumps.   Sealless pumps  also
 have  a more  limited range of applicability  due  to  limitations on  tempera-
 ture, throughput, and horsepower.

 7.2.1.4   Compressor Seals

          A  number of types of compressor seals reduce emissions  of the
 compressed gas  from the.  compressor housing.  The five  basic types are
 packed (reciprocating shaft), labyrinth  (rotating  shaft), restrictive ring
 (rotating shaft), liquid film/bushing  (rotating shaft), and mechanical
 contact  (rotating shaft).

          The basic principle of packed  compressor seals is similar to
 packed pump  seals.  However, cooling of  friction-type  compressor  seals
 differs  from cooling of pump seals of  similar construction in that the
 gaseous  compressor working fluid provides negligible lubrication  and has
 a lower  heat capacity than does liquid.  For these reasons most,  but not
 all, contact-type compressor seals use some form of liquid seal coolant
which may also  serve to reduce gas emissions.

          The various types of non.pac.ked seals differ substantially from
 each other and  from mechanical pump seals.  Both the packed and mechanical
 types of compressor seals are described in detail in Appendix E (Volume 4).

          Existing Control Technology—The five basic types of compressor
 seals are applied in refinery service.  The API has estimated that 60- 70
percent  of refinery compressors have, packed seals, 10 percent have
                                                                      93  9 '*
mechanical contact seals, and about, five percent have labyrinth seals.

          Radian found that approximately 80 percent of the compressors
surveyed in the current study had reciprocating shafts with packed seals.
About 60 percent of the compressors process gas which contains less than
                                   338

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 50 percent hydrogen.  The remaining 40 percent compress streams which are
 predominantly hydrogen.

          The various types of compressor seals cannot be universally
 applied in any or all refinery operations.  Because of lubrication and
 cooling limitations, packed seals are rarely used around rotating shafts.
                                                                 q 5
 The labyrinth seal allows some gas to continually escape.  Nelson'  states
 that the  loss rate or recycle rate from this type of seal is not generally
 acceptable today for energy and environmental reasons.  For this reason,
 labyrinths are now more often seen in outboard seals in combination with
 other sealing devices.

          The restrictive ring seal is superior to the labyrinth seal
 alone, but is limited to about 200 psi and relatively clean gas service.y3>9
 Sealing and scavenging ports may be used for labyrinth seals and for
 restrictive ring seals.

          The liquid-film seal is relatively simple, and is not subject
 to significant wear.  It is capable of operating at pressures of up to
 5,000 psi in a multiple, seal configuration, but has, in all configurations,
                                                   9 5
 a relatively complicated piping and control system.

          The mechanical contact seal differs significantly from a mechani-
 cal pump seal, but utilizes the identical concept of zero clearance at
 closely-lapped wear surfaces to limit leakage.   This type of seal is
 limited to pressures of about 500 psi.  Its leak rate  is the lowest for
 the seals described, but,  like mechanical seals for pumps,  mechanical
 contact seals are subject  to catastrophic failure.   Their oil supply
systems, where used, are simpler than oil supply systems for liquid-film
      9 5
seals.     Mechanical contact seals form a nearly perfect seal when at
    9 5
rest "  in contrast to pump mechanical seals which are  believed to seal
better when the faces are  rotating.
                                   339

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          Many  compressors have enclosed seal areas which are vented to
 the  atmosphere  from  "high-point" vents for safety reasons.  Compressors
 are  often housed in  semi-enclosed or completely enclosed buildings.  Many
 handle gases which contain toxic or hazardous components such as hydrogen
 sulfide.  Venting the seal area to a high-point vent reduces the potential
 for  a buildup of toxic or explosive gases in the compressor area.

          Sealant or lubricating oil is circulated through and around com-
 pressor seal mechanisms.  This oil is under pressure and will contain the
 components of the compressed gas.  The oil must be depressured and/or
 treated to remove these gases.  The vapor from the degassing of the seal
 oil  is generally vented to a blovdown/flare system.

          Gases from the seal enclosures or seal oil degassing are some-
 times drawn off by vacuum educators and sent to flare/blowdown systems.

          Effectiven&ss of Compressor Seals—Table 7-52 shows a comparison
 of seal leakage.  The worst, the straight pass labyrinth, is given a gas
 leakage index of 1.00.  It is not clear from the table, which includes both
 dry and lubricated seals, where the oil film seal fits in according to the
 gas leakage index.  The liquid film seal is shown, however, to lose more
 lubricant than the lubricated mechanical contact seal by a factor of 55.
 It is not clear if this refers to oil loss into the compressed gas stream
 or if it refers to loss of oil (and dissolved gas) to the atmosphere.

          The packed seal is the only seal available for a reciprocating
 compressor application.   The mechanical contact seal, wet or dry depending
upon design needs, would appear to rank the best among centrifugal com-
pressor seals for pressures up to about 500 psi.   However,  these vseals  are
said to be fragile and prone to failure,  as well  as complex and difficult
to install correctly.
                                   340

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                   TABLE 7-52.  COMPRESSOR SEAL LEAKAGE
      Compressor Seal
Dry Types                                            Gas Leakage Index
   Straight Pass Labyrinth                                  100

   Staggered Labyrinth                                       56

   Honeycomb Labyrinth                                       40

   Restrictive Ring                                          20

   Mechanical Contact (Running Dry)                           2


Oil Types                                                  OilLoss
   Mechanical Contact                                     0.03 gal/hr
    63/i» in. Face Diameter
    30 psi Differential
    500 rpm
                                                       Lu b r icajit Lo s s

   Liquid Film or Bushing                              1.75 gal/hr or
    5Vz in. Bore Diameter                              55 times the
    0.007 in. Clearance                                contact type
    5000 rpm
    60°F Oil Rise
  Source:  Reference 95.
                                   341

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          A more flexible device in terras of broad pressure range
application (to 5,000 psi) and suitability for dirty gas service is the
.liquid film seal.  The complexity of its external circulation and control
system would be perhaps its most costly feature.  Acid gas stripping from
circulating seal oil is a must with the use of liquid f.i 1m seals if the
working gas is sour.  The oil reservoir degassing vent may be a source of
hydrocarbon emissions.

          Seal Energy Requirementsand Cost—Compressor seal design is
traditionally an integral part of overall compressor design.  As a result,
data are not available, to allow independent seal energy usage and cost
analysis.

          Inspection an d Ma int e n am: e—Existing inspection and maintenance
procedures for compressors are similar to those described for pumps.  Leak-
age may be more difficult to detect because some compressors have enclosed
seal areas that transport leakage to an elevated vent pipe.  The effective-
ness of these procedures is reflected in the emission factors for com-
pressors shown in Section 5 of this report.

          Available Controls for Compressors—Closed vent systems and leak
detection and repair programs are the available controls for compressors.
A closed vent system consists of piping and, if necessary, flow inducing
devices that transport compressor seal leakage to a control device.  Con-
trol devices could include fired heaters or boilers, incinerators, flares,
or vapor recovery systems.   For compressors with seal oil systems, the
closed vent system can be connected to the seal oil reservoir degassing
unit.  For other compressor seals,  the seal area itself could be enclosed
and connected to the closed vent system.

          Leak detection and repair for compressors is similar to the
program described for pumps.  A hydrocarbon detector can he used to detect
seal leaks.   These areas would include the seal itself (if accessible),
                                   342

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 Lhe  seal vent: pipe, and the seal oil reservoir vent depending on the
 physical configuration of  the compressor.  No data are available to
 quantify effectiveness of  the leak detection and repair for compressors.
 Effectiveness and cost would be dependent on the same factors discussed
 for  pumps.  Average leak detection time required for compressors has been
 estimated as 10 minutes per seal, and repair time has been estimated as 40
 hours per seal.61 One major difference between repair of pump and compressor
 seals is that most refinery pumps have spares, but many compressors do not.
 Therefore,any repair that required compressor shutdown might also require
 shutdown of the process unit.  Depending on the type of process unit, the
 unit shutdown could cause more emissions than allowing the compressor seal
 to leak until repair can be effected during the next turnaround or shutdown.

          Technology Transfer for Compressors—No other controls were
 identified for compressor seal leakage.  Sealless compressors are not
 available in the capacity range that would be required in almost any
 refinery application.

 7.2.1.5   Agitators

          Agitators may leak hydrocarbons at the junction of the vessel and
 the rotating agitator  shaft.   The. agitator seal may be in liquid service if
 the agitator is located at the side of a storage tank,  or the seal may be
 in vapor service if the agitator is located at the top of reactor vessels.
 In some types of refinery operations,  in-line blending has replaced the
use of agitated mixing vessels.

          Existing Controls for  Agitators—The four basic types  of  agitator
seals are listed in Table 7-53.   Some  of the seals are similar to pump seals
 (packed and  mechanical).   The limitations of the four  seal types are shown
in Table 7-53.   No data are available  to establish the magnitude of leakage
from agitator seals.   The seals  are listed in Table 7-53  in order of
increasing cost.
                                    343

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                    TABLE 7-53.   BASIC AGITATOR SEALS
     Seal Type
   Limitations
         Comments
a.  Hydraulic


b.  Lip



c.  Packing Gland



d.  Mechanical Face
Low pressure and
temperature

2-3 psi;
unlubricated
150 psi
0 psia to 5,000 psia
if housed and
pressured to working
fluid pressure
Least-used agitator seal.
Dust or vapor seal only;
temperature limited by
elastomer lip melting point.

Six packing rings and lantern
ring required for 150 psi
capability.

Externally lubricated so as to
leak in if inboard seal fails
(double seal configuration).
Single seals also used.
Source:  Reference 96.
                                  344

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           Available_Controls  for Agitators—Leak  detection  and  repair
 strategies  for  agitators should be similar  to  those  described for pumps
 and  compressors.  The  time  required  to  detect  leaks  is probably about  the
 same  as  for pumps and  compressors.   The time requirements for repair are
 not  quantified.

 7.2.1.6    Safety Relief Valves

           Safety relief valves (SRV) are installed on any refinery equip-
 ment  that  could be subjected  to overpressuring with  subsequent  safety
 hazards  and equipment  damage.  The various  types  of  SRV's in hydrocarbon
 service  are described  in detail in Appendix E  (Volume 4).   Emissions to
 the atmosphere occur through  the valve  seat due to improper seating, which
 can be a result of wear, corrosion,  or  foreign matter.

          Existing Control^ for Safety  Rel_i_ef_ Valves—Inspection and main-
 tenance  is one existing control for  SRV's.  The main objective  of most
 inspection and maintenance programs  is  to make sure  the  SRV will provide
 proper over-pressure protection.   Some  companies  remove  and test SRV's
 after every over-pressure release.61  This  procedure requires that a means
 be provided to install a spare SRV while the other one is tested.  Although
 this testing is primarily to  check the  set  pressure  of the SRV, it may
 also detect fugitive leakage.  The other existing control for SRV's is
 discharge header systems that transport over-pressure releases  (and fugi-
 tive leakage)  to a flare.

          Available Controls  for Pressure Relief Devices—Leak detection
 and repair programs and upstream rupture disks are the available controls
 for SRV's,   Leak detection would require periodic testing of SRV's that
 discharge to the atmosphere.  A hydrocarbon detector can be used to detect
 hydrocarbon concentrations at the exit of the discharge  "horn" or at the
weep hole at the bottom of the "horn."  Repair of the SRV would probably
 require removal  of the SRV,  and therefore a means of replacing the SRV
                                    345

-------
while the process unit was operating would be needed.  Data on costs and
effectiveness of leak detection and repair for SRV's are not available.

          Although most SRV's are. used alone or in pressure-stepped com-
binations, some are used with rupture disks mounted under them (i.e.,
between the. process fluid and the SRV).  Rupture disks (RD's) are somewhat
prone to age-induced fatigue or corrosion failure, and therefore are not
ordinarily used alone except where complete loss of process fluid is
acceptable economically and environmentally.  Such acceptable cases
probably no longer exist in any organic chemicals or fuels manufacturing
facility.

          Alternatively, rupture disks may be positioned downstream of SRV's
to protect working parts from weather or other corrosive atmosphere, as
when connected to a relief header.

          Rupture disk leaks may be detected by "tell-tale" bubblers or
pressure gauges, and by excess flow valves connected to the inside piping
space between the RD and the SRV.   This arrangement is covered by ASME
     n "7
code.    If small RD leaks are not monitored, there is a chance that the
pressure between the RD and SRV might build to system pressure.  Then,
with a rapid rise in pressure, as in an emergency, working pressure would
almost double before the disk and SRV would release, depending upon the
rate of increase and size of the RD leak.

          As long as the integrity of the  rupture disk is maintained,
fugitive emissions are completely  eliminated.  The disk would require
replacement after over-pressure release,  and therefore a means for replac-
ing it while the process unit was  in service would be needed.   Although
there is controversy within the industry  concerning the use of rupture
disk-safety relief valve combinations,  some feel that the combination may
                   Q 7
be operated safely.     Others consider RD  use upstream or downstream of
the SRV only as  necessary for either (1)  added isolation  of particularly
                                   346

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toxic materials from the air, or  (2) as a means of isolating  the SRV  from
a corrosive atmosphere.  This atmosphere might be, for example, a header
                                                                 9 g
with sulfur compounds present, or simply salt air near the ocean.
          Costs—The addition of an inlet or outlet side  rupture  disk  to
an SRV adds between three percent and 50 percent to the materials cost of
the SRV, depending on size and service.  Materials costs  for SRV  and RD
assemblies  (excluding piping) are shown in Table 7-54.  The net cost of
the system would take into account a value for the product saved  by
eliminating fugitive emissions.

          Technology Transfer for Pressure Relief Devices—Fugitive leakage
caused by improper reseating after over-pressure release may be minimized
by using pilot operated SRV'a with resilient (0-ring) seats.  No  data are
available to quantify the effectiveness of this type of control.  Another
potential improvement in SRV design would be to install parallel  SRV's
in all applications.  This would allow an SRV to be in service with the
other blocked off as a spare.  The SRV could then be removed for  testing
and rupture disk replacement after over-pressure releases.

7.2.1.7   _S_ainp_ling Connections

          Fugitive emissions from sampling connections are primarily due to
purging the sample line to obtain a representative sample.  Atmospheric
exposure of the purged fluid can result, in evaporative hydrocarbon
emissions.

          Exj-sting Controls for Samp 1 ing Connections—Existing practices
for obtaining process samples vary considerably.   They may range  from
draining process fluid onto the ground to collection of the purge in slop
oil systems.  All existing practices result in some atmospheric exposure
and emissions,  but the magnitude has not been quantified.
                                   347

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            TABLE 7-54.  SAFETY RELIEF VALVE (SRV) AND RUPTURE
                         DISK (RD) ASSEMBLY COSTS
System
Inlet x
diameter
1 x
3 x
8 x
Basis :


May 1980 Dollars
Size, SRV RD Assembly
Outlet
, inches 150 psi flanges
2 650
4 1,050
10 5,900
300 psi flanges inlet Outlet
700 320 120
1,150 520 160
7,800 1,100 220a
Materials only; piping excluded. May, 1980 prices.
RD assembly includes cost, of safety head and one disk.
 Interpolated from 4 inch and 12 inch diameter RD costs.

Source:  Reference 99.
                                    348

-------
          Available Controls for Sampling Connections—Closed loop sampling
 systems are  the primary control available to reduce sample purge emissions.
 A closed  loop sampling system consists of a network of piping and valves
 that either  returns the purged material directly to the process, or that.
 transports the purge to a closed collection system for recycle.

          Technology Transfer for Sampling Connections—The main innova-
 tions that are likely to reduce sample purge emissions are the increasing
 availability of on-line continuous analytical instruments that do not
 require discrete samples.

 7.2.1.8   Wastewater Systems

          Refinery wastewater systems have evolved over the years as
 awareness of water pollution problems has grown, and as various treatment
 systems have been developed.  There are four basic treatment steps.100 The
 first is primary separation, where oil is removed by gravity separation.
Normally, an API or a CPI-type separator is used.  These separators
 effectively remove free oil from water, but will not separate substances
                                  10'
 in solution or break up emulsions.   *  The second step is intermediate
 separation where suspended solids and additional oil are removed by
 chemical sedimentation or air flotation.  Secondary treatment is the third
step.  It involved the reduction of the biological oxygen demand (BOD)
with some type of biochemical oxidation.  Finally, in the tertiary treat-
ment step, dissolved organics which will not degrade with biological
treatment methods arc removed.   Carbon adsorption is the most common form
of tertiary treatment.

          The treatment processes for these steps are shown below.102

          •    Primary—API Separators, Tilted-Plate Separators
               (CPI.) ,  Filtration for Oil Removal, pH control,
               and Stripping Processes.
                                   349

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          •     Intermediate—Dissolved Air  Flotation,  Coagulation-
                Precipitation, and  Equalization.

          •     Secondary-Tertiary—Carbon Adsorption,  Activated
                Sludge, Aerated Lagoons, Trickling Filters,
                Waste  Stabilization Ponds, Cooling Tower Oxida-
                tion,  Chemical Oxidation, and Filtration.

 In addition, there is a waste-water collection system which consists of
 process drains, sewers, holding basin, and  pumps.

          Existing Controls for Wastewater  Systems—Tab]e 7-55 gives an
 estimate of the degree of adoption of various wastewater treatment pro-
 cesses for 1950, 1963, 1967, 1972, and 1977.  While this table utilizes
 the. author's judgment, in many areas due to  the "dearth of usable informa-
 tion," the data on API separators are reliable and confirm that by 1977
 nearly all refineries had an oil and water  separator of the API or the
 CPI type.103 The table also shows an increasing use of intermediate,
 secondary and tertiary treatment methods.   This trend  is a result, in
 part, of governmental scrutiny and control  in the area of water pollution.

          Covered oil/water separators and  trapped drain systems are two
 types of emission controls used in some refineries.   Some state regulations
 require covers for separators.   As of January 1977,  80 percent of the U.S.
 refining capacity was located in states where covers are required.10"*  The
 extent of application of trapped drain systems is not known.   Because, of
 the lack of emission data, effectiveness of those controls cannot be
 assessed.  Costs would vary widely, depending on site specific conditions.

          The current AP-42 emission factors for drains and oil/water
separators,  uncovered versus covered,  imply a 95 percent fugitive hydro-
carbon emission reduction.  The original data upon which the AP-42 emis-
sions are based are no longer available.     Thus, the validity of the
                                   350

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            TABLE 7-55.  DEGREE OF ADOPTION OF VARIOUS WASTEWATER
                         TREATMENT PROCESSES
Processes and Subprocesses
API Separators
Earthen Basin Separators
Evaporation
Air Flotation
Neutralization (Total Wastewater)
Chemical Coagulation and Precipitation
Activated Sludge
Aerated Lagoons
Trickling Filters
Oxidation Ponds
Activated Carbon
Ozonation
Ballast Water Treatment - Physical
Ballast Water Treatment - Chemical
Slop Oil - Vacuua Filtration
Slop Oil - Centrifugation
Slop Oil - Separation
Sour Water - Steam Stripping .
- Flue Gas Strippers
- Natural Gas
Sour Water - Air Oxidation
Sour Water - Vaporization
Sour Water - Incineration3
Neutralization of Spent Caustics
Flue Gas
Spent Acid (including
springing and stripping)
Oxidation
Incineration
Percent of Refineries Using the Processes
1950 1963 1967 1972 1977
40
60
0-1
0-1
0-1
1-5
0
0
1-2
10
0
0
9
1
0
0
100
60
0
1
35-40

20
15
0
25
50
50
0-1
10
0-1
1-5
5
5
7
25
0.5
1
9
1
5
2
93
70
3
1-2
40

30
25
3
40
60
40
1
15
0-1
5-10
10
10
10
25
0.5
1
8
2
7
3
90
85
3-5
1
50

35
30
5
50
70
30
1-2
18
0-1
10-15
40
25
10
25
3
3
5
5
12
10
80
90
7
0
30

20
25
5
20
80
20
2-5
20
0-1
10-15
55
30
10
20
5
5
5
5
15
15
70
90
10
0
20

20
20
5
15
 Incineration includes flaring, boiler furnaces, and separate incinerators
 uoed <:mly in conjunction with stripping and vaporization.

Source;   Reference 103.
                                      351

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.Indicated effectiveness cannot be assessed.  In a laboratory study using
a simulated API separator, the covered separator provided 89 percent
emission reduction.
          The data from Radian's oil-water separator emission measurements
are discussed in Appendix B (Volume 3).  The results are poor and cannot be
used to develop emission factors for oil-water separators.

          It is evident that further study of evaporative .losses from
oil-water separators is needed and justified.  Actual emission rates for
uncovered separators probably fall between 13 and 200 lb/1,000 bbl refinery
feed.  Similarly, average losses froir. covered separators can be expected
to be between .1.5 and 20 ]b/l ,000 bbl refinery feed.

          Available Controls for the^Wasjie water System—In general, avail-
able controls for reducing fugitive emissions from existing process and
storm sewers and collection systems consist of minor modifications such
as sealing open sewer systems,  altering pump bases, recurbing some process
areas,  and improving housekeeping.

          Changes which involve substantial capital outlays (or which may
be nearly infeasible from a construction standpoint), such as major
revisions to existing underground sewer systems or installation of vapor
recovery systems may not be practical.  Techniques which can be used to
reduce  emissions from the collection system are listed below.

          •     Open drains, sewers, or holding basins (which
               regularly receive water containing significant
               quantities of volatile  organic compounds) up-
               stream of the oil and water separator should be
               eliminated where practical.   These sources of
               emissions in the U.S. refining industry are now
               fairly rare.   The evaporation of significant
                                   352

-------
     volumes of oil at current world scale prices is
     a readily apparent financial burden.  Process
     drains and sewers should be covered or vented
     through liquid seals wherever safe and practical.

•    Pump bases which co not drain completely by
     gravity should be altered.  Many pump bases
     are designed so that a slight level of oil
     (from a leaking seal) must build up before the
     base drains to the sewer.  When new pumps are
     to be installed, bases should be selected which
     allow proper drainage.  Existing pump bases
     can be modified.

*    Segregation of process water from storm water and
     minimization of oily water volumes should be
     practiced wherever practical.  Curbing should
     be installed so that only those areas which are
     subject to oil spills drain into the oily water
     sewer system.  Storm sewers should be sized so that
     overflow into process sewers during peak runoff is
     avoided.  in many cases, however,  substantial revi-
     sions to the sewer systems of older plants can be very
     expensive.

•    General housekeeping can be improved.  An undefined
     but, in some cases,  significant source of emissions
     is the lack of good  housekeeping practices concern-
     ing oil  spills and leaks.  A quantitative control
     technique in the area of oil spills and leaks could
     probably not be formulated, but an awareness of the
     problem would be beneficial.
                         353

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          Adequate data are not available for a definitive evaluation of
 the effectiveness of covers on oil-water separators for reducing atmospheric
 emissions.  It seems reasonable to presume that covers will reduce, emissions
 to some degree.  The cost-effectiveness of this control option can only
 be determined after its control efficiency has been defined through test-
 ing.  There can be safety and operational problems associated with cover-
 ing the separators.  These must be evaluated on an individual basis.

          API separators can be covered by a number of methods including
 floating pontoons or double-deck-type covers which are sealed against the
 outer walls of each bay.  A CPI separator normally has a fixed roof
      1 C'f
 cover.

          Cost, of Controls—The cost of installing covers on API separators
 can be substantial.  The area of required coverage has been variously
 estimated at 0.028 ft2 per bpd wastewater flow and at 0.050 ft2 per bpd
 crude oil to the refinery. " '    These same sources have cited costs for
 covers of $lA.40/ft2 (mid-1978) and $12.50/ft2 (mid-1977), respectively.
 These costs can be escalated to current prices by using the M&S equipment
                                            " f\ p
 cost index reported in Chemical Engineering.'    The current cost of covers
 then becomes $15.8A/ft2 and $14.85/ft2, respectively.  If a cost of
 $16.00/ft2 and a cover size of 0.050 ft2/bpd crude oil charge are used,
 the capital cost alone is $265,000 for covers for the 330,000 bpd hypo-
 thetical refinery.

 7.2.1.9   Cooling Towers

          Hydrocarbons can be found at very low levels in nearly all water
used for refinery process cooling.   If significant leaks occur in process
heat exchanges, the level of hydrocarbons present in the circulating
cooling water can increase substantially.  Some of these hydrocarbons can
be vaporized and emitted to the atmosphere in the cooling tower.
                                   354

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          Existing  Control Technology—Existing  controls of hydrocarbon
 emissions from cooling  towers consist primarily  of heat exchanger inspec-
 tion and maintenance.   These practices minimize  the .leakage of hydrocarbons
 into the cooling water.  Monitoring for total organic carbon  (TOC) in cool-
 ing water is commonly practiced in refineries.   This procedure detects
 small increases in  the  hydrocarbon concentration and provides an early
 indication of small leaks.  These leaks can often be found and repaired
 before  they become  large and while the air emissions are still small.

          Emission  factors determined, during this study were based on two
 analytical methods:  Total Organic Carbon (TOC)  analysis and a purging
 technique.  These emission factors are shown in  Table 7-56.  The emission
 factor  for uncontrolled cooling tower emissions  currently included In
 AP-427  is 6 lb/106 gallon of circulating cooling water.  In Radian's
 study of cooling tower  emissions, the purge method of analysis was found
 to be much more precise than the TOC technique.  Therefore, the emission
 factor  of O.li Ib.  no nine thane hydrocarbons per 10s gallon cooling water
 is recommended for  controlled emission,

      TABLE 7-56.  RADIAN-GENERATED COOLING TOWER EMISSION FACTORS
                                                         Emission Factor,
Analytical Technique                                    Ib HC/106 gal C.W.
         TOC                                                    12.4

        Purge                                                    0.11
          Available Controls for CoolingTowers—The best control for cool-
ing towers is to minimize the amount of hydrocarbons entering the tower.
One method to achieve this goal is to eliminate the use of contaminated
process water as cooling tower make-up.  This may be difficult, since
efforts to reduce water discharges may require the use of process water
                                   355

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 for  cooling towers.  Another control option is to monitor the hydrocarbon
 content of the cooling tower input.  If elevated concentrations are
 detected, a leak in the process equipment is indicated.  The problem then
 is to identify the specific leak and to repair it.

 7.2.1.10  Solid Waste Svstem Alternatives
          Petroleum refineries generate numerous solid waste streams.
These streams may contain many substances, including volatile hydrocarbons.
Nonmethane hydrocarbons may be emitted to the air during disposal operations,

          Most solid wastes are residuals from wastewater treatment.  The
exceptions to this are some spent catalysts which are recovered in segre-
gated containers, spent acids and caustic, and other spills and sediments
which can be segregated.  Normally these exceptions arc handled separately
from other solid wastes.

          The five general categories of solid waste disposal alternatives
are landfarming, incineration (with landfilling of the ash), landfilling,
deep-well injection, solidification (producing relatively inert sub-
stances which chemically or physically isolate the pollutant),  or surround-
ing the pollutant by encapsulation.109 Landfarming, incineration, and
landfilling,  which are the most common methods of disposal for  refinery
solid wastes, can create emissions to the atmosphere.

          Existing Controls and Their Effectiveness—There are  no specif-
ically recommended emission control technologies for application in land-
farming and landfilling.   The disposal problems are individualized and
depend on the type of solid waste, the solids content, and the  properties
of the earth  at the disposal sites.   In general, solid wastes in landfills
should be dewatered and/or contained if necessary,  and covered  with a
quantity of earth sufficient to minimize vapor loss and odor problems.
Landfarmed materials should be covered or plowed into the. earth
                                   356

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 as  soon as possible  after application.  The  solid waste  loading capacity
 of  the particular  disposal areas should not  be exceeded.

          A number of  types of incineration  systems, including multiple-
 hearth and fluidized bed systems, are available to burn  refinery sludges.
 Control devices will generally be required to reduce particulate emissions
 from incinerators.  Effective part.ir.ulate controls are venturi scrubbers,
 impingement scrubbers, bag filters and ESP's, but these  devices are much
 more expensive than scrubbers.

          Landfarming and landfilling are economically attractive alter-
 natives to incineration.

 7.2.2     Control_of Stack and Other^Process Emissions

          In general, the major sources of atmospheric process emissions
 are sulfur recovery, fluid catalytic cracking catalyst regeneration, and
 process heaters/boilers.  Other sources include vacuum distillation, coking,
 air blowing, chemical sweetening, acid treating,  blowdown systems, and com-
pressor engine exhaust.

 7.2.2.1   Sulfur Recovery

          Any crude oil with more than 0.5 weight percent sulfur is
generally considered sour and its products are subjected to sulfur removal
processing.51  If not removed, the sulfur can cause corrosion, pollution,
and catalysis problems during refining or when the products are used as
 fuel or as petrochemical feedstocks.

          Sulfur removal from whole crude is not  generally economical.
Various intermediate stock streams  are,  however,  routinely subjected to
sulfur removal.   The sulfur  components in these streams are converted to
hydrogen sulfide by contact  with hydrogen over a  nickel-molybdenum catalyst
                                   357

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 at  an  elevated  temperature.  The resulting H2S may be removed from the
 stream and concentrated by one of several means, the most common of which
 is  absorption.

          At one  time this H2S was simply burned with other light gases as
 refinery fuel.  In recent years, to minimize SO  emissions and to produce
 elemental sulfur  for sale to other industries, the Glaus process has been
 used.  The tail gas from a Glaus un.lt is the main source of SO.  emissions
 in  a refinery today; it contains H2S, S02, CS2) COS, S , and also CO formed
 from small amounts of hydrocarbons and C02 in the feed stream.

          The Glaus Process—Because of its economic advantages, a Glaus
 unit for the conversion of H2S to elemental sulfur is often considered as
 simply part of normal refining operations.  However, because the process
 by  itself is not  totally efficient in producing elemental sulfur, the tail
 gas from the unit can be a major source of emissions.  But it must be
 recognized as a very effective control device.

          The Glaus process works best, for gas streams containing greater
 than 20 volume percent II2S and less than 5 volume percent hydrocarbons.
 There are several flow schemes available according to the H2S content of
 the feed stream to the unit.  In any case, the overall Glaus reaction is
 as  follows:
               H2S + -^ 02 - - S  + H20
                     2      n  n
where n represents the various molecular forms of sulfur vapor.
          GS2 and COS are produced in side reactions, and usually pass
unchanged to the tail gas.  They can account for 0.25 to 2.5 percent of
the sulfur content of the tail gas.  "  However, with proper design,
                                   358

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 including the use of  the cobalt molybdenum catalyst and  a  higher  inlet
 temperature  in the first reactor, the CS2 and  the COS concentrations  in
                               1 1 o
 the  tail gas can be minimized.

          A  Glaus unit with one catalytic reactor can convert 80  to 86
 percent of the H2S to elemental sulfur.51'113  This efficiency can be  greatly
 enhanced by  repeating the catalylic stage one  or more times.  Conversion
 is ultimately limited by the reverse reaction.  Recovery rates for various
 feed compositions are given in Table 7-57.

          These efficiencies, once considered  sufficient,  do not meet new
 regulations.  Further treatment of the Glaus unit tail gas is required.

          Glaus plant costs are sensitive to the flow rate and composition
 of the input stream as well as the sulfur removal efficiency.  It Is diffi-
 cult to generalize the costs.  As an example,  however, the capital Invest-
 ment costs for a Glaus plant having a capacity of 250 x 106 ft3/day of gas
 are $14 x 106 (construction period is 4th quarter 1979 through 4th quarter
 1980).  This plant has a sulfur removal efficiency of about 95 percent.

          Existing Contro1_ Technology for Sulfur Recovery—The tail gas
 from the Glaus unit is often incinerated before it passes  to the atmosphere.
 Some tail gas treating processes require that  the tail gas be incinerated
 prior to treatment.

          More than 70 methods have been proposed for treatment of the
 ClaviK unit tail gas.11"*  These methods may be continuations of the Glaus
 reaction or add-on processes with chemistry quite different from that of
 the Glaus reaction.   The six tail  gas clean-up methods listed in Table
 7-58 are those considered the most viable at present  in  light of energy
 demands,  economics,  and effectiveness.   Amoco's CBA Process,  the Sulfrccn
Process,  and the IFF Process are continuations of the Glaus reaction under
                                   359

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            TABLE 7-57.   TYPICAL COMPOSITIONS OF FEED STREAM AND
                         TAIL GAS FOR A  94 PERCENT EFFICIENT
                         GLAUS UNIT
Component
h
H2S
S02
Sa vapor
SB aerosol
COS
CSZ
CO
CO 2
02
N2
H2
H20
H.C.
Temperature, °F
Pressure, psig
Total Gas Volume
Sour Gas Feed
Volume %
89.9
0.0
0.0
0.0
0.0
0.0
0.0
4.6
0.0
0.0
0.0
5.5
0.0
100.0
104
6.6
—
Glaus Tail Gas
Volume I
0.85
0.42b
0.10 as Si
0.30 as SL
0.05
0.05
0.22
2.37
0.00
61.04
1.60
33.00
0.00
100.00
284
1.5
3.0 x feed
gas volume
 Gas volumes compared at standard conditions.

 NSPS requires an emission of less than 250 ppmv (0.025%) S02, zero percent
 02, dry basis if Glaus Unit Tail Gas is oxidized as the last control step,
 or, 300 ppmv S02 equivalent reduced compounds (H2S, COS, CS2) and only
 10 ppm HZS as S02, zero percent Oz, dry basis, if the Tail Gas is reduced
 as the last control step.

Source:  Reference  48.
                                     360

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TABLE  7-58.  EXISTING METHODS FOR  REMOVAL OF  SULFUR  FROM GLAUS TAIL GAS
Name
CBA
Sulfreen
IFP-1500
BSRP
SCOT
Wellman-
Lord
Developer
Amoco
SNPA/Lurgi
Ins ti Cut
Francals
du Petrole
Ralph M. Parsons
& Union Oil Co.
of California
Shell
Wellman Power
Gas
Final Tail Gas
Description S Concentration
Claus reaction continued
at low temperature; re-
moval of condensed sul- 1500 ppmv S
fur drives reaction.
Bed regenerated with hot
gas from Claus unit.
Claus reaction continued
at low temperature as in
CBA. Bed regenerated with 1500-2000 ppm S
hot nitrogen.
Claus reaction occurs In 1000-2000 ppm S
a solvent.
All sulfur compounds re- 250 ppm S
duccd to HjS which is Or less
processed in a Stretford
unit.
All sulfur compounds re- 200-500 ppmv HiS
duced to HzS which Is
recycled to Glaus
SO? in incinerator gas <200 ppmv SOj
contacted with HajS03 to
Coit
Product (Z Cost of Clau«)
S. 50-150*
t
S. 50-150Z
So variable
S. 100Z
Feed 75-100Z
to
Claus
NazSOs/NajSOj 130-1501
crystals
                     form NallSOj. NazSOs  regen-
                     erated in evaporator/
                     crystallizer.

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more favorable conditions, while the Beavon Process, the  SCOT Process, and
the Wellman-Lord Process are add-on units with higher efficiencies than  the
first three.

          Additional tail gas treatment methods are described in detail  in
Appendix E  (Volume 4).

          Alternate Tail-Gas Treatment Methods—An alternate to the Glaus
unit and a modification of the unit are also being tested.  The alternate,
the UOP Sulfox Process, would produce no objectionable  tail gas stream.
The Mineral and Chemical Resource Company (MCRC)  ''is a modified improve-
ment of the Glaus process.

          The UOP Sulfox Process '-—The UOP Sulfox process is an alterna-
tive to the Claus process.  In this process, aqueous ammonia, instead of
an amine solution, is used to scrub H2S from refinery streams.  Ammonia
is then scrubbed from the gas with purified water.

          Hydrogen sulfide content, in the treated gas is 10 to 100 ppm.  It
is possible, at increased cost,  to design a Sulfox unit which can achieve
1 ppm H2S in the tail gas.  However, NSPS requires less than 250 ppmv S02
from a final oxidizing step,  which in this case would probably be inter-
preted as "S02 or its equivalent as reduced sulfur compounds."

          It may be possible to  convert an existing Claus system to a
Sulfox System with a minimum of  expense.  It is probable that the existing
amine absorber could be used as  the ammonia absorber and that the existing
amine stripper could be. used in  the Sulfox unit proper.

          Cost of a Sulfox system is considered about equal to that of a
Claus unit,  not including the. cost  of tail-gas cleaning.  Utility costs
are estimated to be about 60  percent of those of a Claus unit.
                                   362

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          The Mineral and  Chemical Resource Company  (MCRC)'[ --Tine MCRC
 Sulfur Recovery process is actually a modified improvement  of  the Claus
 process.  A proprietary scrubber is used to improve  sulfur  recovery and
 also  to remove any ammonium sulfate which forms in a Glaus  unit if the
 feed  contains ammonia.  A  98 percent sulfur recovery efficiency can be
 obtained with a three converter design; greater than 99 percent efficiency
 can be obtained with four  converters.  Two MCRC sulfur recovery plants
 have  been operating since  1976.

          Control Technology for S u 1 f u r Re cove r y in  Other  Indus tries—Some
 FGD processes developed by the electric utility industry may be applicable
 to  the flue gas from a Claus incinerator.  These processes  are summarized
 in  Table 7-59.

 7.2.2.2   Cat alys t Regoneration

          Catalysts are used in several petroleum refining  operations,
 namely, fluid catalytic cracking (FCC), moving bed catalytic cracking
 (TCC), catalytic hydrocracking, reforming, and various oil  desulfuriza-
 tions.  These catalysts become coated with carbon and metals and must be
 regenerated to restore their activity.   During regeneration, the carbon
 is oxidized to CO and C02.   Hydrocarbons may be Incompletely burned.

          In most applications, a catalyst must be regenerated only a few
 times a year.  Emissions during these episodes may include,  catalyst fumes,
 oil mist,  hydrocarbons,  ammonia, SO,,  chlorides,  cyanides, NO , CO,  and
 aerosols.   Though there may be significant emissions during the regenera-
 tion of some of these catalysts, the total emissions over the course of a
year are probably not significant.

          Catalytic cracking catalyst  regeneration is a continuous process.
 Uncontrolled cracking catalyst regeneration can be a major source of air
                                   363

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        TABLE 7-59.   FLUE GAS DESULFURIZATION PROCESS
Kane
The r o ugr.br e d
101 Process
Developer
Chiy:>d.u Choir,. F.ng .
and Construction
Description
Tr.il gas incinccrstion
followed by Absorption
Number of
Commercial
Units
9
Efficiency
of SO 2 Removal
or S02
Concentration
in flue gas
oOCpprav SO 2
Approximate
Cost ,
% Coat o£
Product Claus Unit
Gypsum
Citrate Process




Townsend Process




Lurgi-Clans-Abgas-

     (LUCAS)



Takahak Process
Company,  Ltd.
U.S.  Bureau of Mines
P.M. Townsend
Lurgi
of SO2 in dilute sxilfuric
acid.

Absorption of S02 in aqueous   Xone
sodium cl.rrf.tc solution.
Absorber liquor is
regenerated with H2S

Claus reaction t.-iucs placp.    Mone
in an organic solvent,  such
as mcthylcnc p;ylcol, at an
elevated temperature.

Incineration + hot coke to     One
convert sulfur compounds to
SO2.  SO 2 racicved with
aqueous alkali phosphate
solutior. which is regenerable.

Tail gas contacted with
sodium carbonate and
redox catalyst.
                                                                95-99%
       99%
  (<2CO?T>r. SOZ,
<150pp.T.' COS/CSj)
                                                                 99.9%
                                                                                           250
75-30

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 pollution  in a petroleum refinery.  ?lue gases  from  catalytic  cracker
 regenerators contain participates,  SO. , carbon  monoxide, hydrocarbons,
                                      )\
 NO  ,  aldehydes and  ammonia,
  x

           Existing  Control Technology for  Catalyst Regeneration—The
 existing method  for controlling CO  emissions from catalyst  regeneration
 in catalytic cracking units is combustion  in CO boilers.  The  CO in the
 regenerator flue gas is burned to C02, and  the  heat  is recovered as steam
 in a  waste heat  boiler.  Particulate  emissions  can be controlled by
 cyclones followed by either electrostatic precipitators or  scrubbers.

          The effectiveness of combined CO  combustion and particulate
 removal in controlling emissions from catalyst  regeneration are presented
 in Section 7.1.  The amount of CO is reduced, of course.  However, another
 noticeable result is the substantial reduction  in emissions of hydrocarbons,
 ammonia, and aldehydes.  The exiting flue gas temperature is much lower
 after passing through the CO boiler.

          Control Technology in_Other Industries for Cat aly stReg ene r a t i on—
 Several FGD methods used by the utility industry have been proposed for use
 on FCC regenerators.117 They are discussed below.  In addition, some of the
 regenerable processes discussed in  this section for  treatment of the Claus
 unit  tail gas may also be applicable.  One of the processes described
 below simultaneously removes SO  and particulates from the flue gas.

          The Lime/Limestone FGDJProcess11--L.ime or  limestone FGD processes
 are the most widely used FGD systems.  The systems are very similar; they
 consume large quantities of feed material and produce large quantities of
waste sludge, but have relatively low operating costs and are highly
 reliable.   An SOZ removal  efficiency of greater than 90 percent has been
 demonstrated.
                                   365

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          A major design option is the choice of lime or limestone.
Limestone is less expensive than lime, but it is not used as efficiently
by the process; therefore, there is more feed material consumption and more
waste sludge production.  Procedures which improve limestone utilization
also increase capital and operating costs.

          Lime systems are usually more expensive to operate, however,
because of the high cost of lime.  Lime systems may be preferred where
space is limited for feed material processing and/or waste sludge disposal.
Capital and utility costs are also lower for a lime system.  The choice
between lime and limestone is also influenced by the availability of raw
materials.

          Costs of raw materials and utilities for lime/limestone systems
are generally lower than for regenerable processes, although more raw
materials are required.   Annual operating costs of a lime system are
about seven percent higher than those of a limestone system.

          The Dual Alkali FGD Process1l--The dual alkali (or double alkali)
FGD process can be used to overcome the scaling problem inherent in lime/
limestone FGD systems, while retaining the convenience of solid waste
disposal.  There are 53 operating dual alkali systems in the United States
and Japan; several more are under construction.

          These systems can achieve S02 removal efficiencies of greater
than 90 percent.  The. capability for more than 99 percent removal of S02
has been demonstrated.  The dual alkali process itself is capable of
greater than 98 percent particle removal.

          Absorption of  S02 from the flue gas takes place in a tray tower,
or a venturi scrubber if simultaneous particle removal is desired.   The
S02 in the flue gas reacts primarily with sodium sulfite (Na2S03) to form
sodium bisulfite (NaHS03).  Some sulfite and bisulfite oxidize to sulfate.
                                   366

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The desulfurized flue gas is reheated if necessary and released to a stack.
A bleed stream of the scrubbing liquor is withdrawn continuously from the
absorber and regenerated.

          Loss of soluble sodium and nonsulfur calcium salts can create
water pollution problems and also a loss of raw materials.  Therefore,
water can be added to the system only to replace that lost through evapor-
ation or in the. solid waste product.  Also, retention of soluble salts by
the solid waste must be minimized.

          Sludge from the dual alkali process must be fixed chemically to
decrease its permeability and leachability, or it must be disposed of in
well-designed lined ponds.  The thixotropic nature of the calcium sulfite
may make land reclamation difficult.  A larger disposal area will be
required then for a lime/limestone system.

          Dual alkali systems are economically competitive with lime/
limestone systems.

7.2.2.3   B£ilers__and_ Process Heaters12 °

          Most refineries use steam boilers to provide steam for direct
use in various processes, for heating and for driving steam turbines.
Process heaters are used extensively in refining operations.   They are the
largest combustion source of hydrocarbons in a refinery.   Refinery boilers
and heaters are fired with most available fuel.
                   Control Technology for Heaters and Eoilers—Emissions
from boilers and process heaters depend on the operating parameters of the
unit and the fuel burned.  Emission factors for burning natural gas and
residual fuel oil are given in Section 7.1.
                                   367

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          In addition to the combustion emissions, there are also emissions
associated with the decoking of the heaters.  At intervals of about six
months to three years, each heater must be flushed with a steam-air mixture
to remove interior coke deposits.  Emissions are similar to those from
decoking the delayed coking unit, but they are smaller and more infrequent.

          Control TechnologiesAvailablein Refineries for Heaters and
Boilers—Emissions of SO  from boilers and process heaters can be minimized
by routing the flue gas to an integrated sulfur removal facility such as
Lhe IFP-150 and the Aquaclaus.  However, there are substantial problems to
this approach.  This is discussed further in Appendix E (Volume 4).
          NO  Removal—NO  emissions can be reduced by several tail-gas
          	X	    X
cleaning methods, but this is inherently more difficult than controlling
NO  by combustion modification techniques.  The principal difficulties are
  X
the large amount of hot gas to be handled, the dilute concentration of NO
                                                                         X
interferences by other pollutants and the high power consumption.  Three
methods for removal of NO  from stack gases are gas scrubbing, catalytic
reduction and thermal reduction with added ammonia.  Because of economic
considerations, only thermal reduction with added ammonia appears promising.
This process is more expensive than combustion modifications but can
supplement these modifications when stricter control of NO  is required.

          As with SO  controls, substantial problems associated with flue
gas collection exist in refineries.
          Con fro 1 Technology Avaj 1 abj.e_in_ Other Industries for Heaters and
Boilers—Processes described previously in Section 7.2.2.2 for control of
S02 emissions from FCCU regenerators may also be applicable to the flue
gases from boilers and process heaters.  Another process, the Shell Flue
Gas Uesulfurization process (SFGD) can be used to simultaneously remove
SO  and NO.  from process heater flue gas, fluid catalytic cracking regenera-
  XX
tion, and Glaus units.  However, these flue gases would have to be
                                   368

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 collected and sent to one or two SFGD units.  There are serious safety and
 economic obstacles to such a collection system.

          The SFGD process has demonstrated S02 and NO  removal efficiencies
                                                      X
 of greater than 90 percent.  The efficiency of the system is not affected
 by variations in the S02 or NO  concentration.  The primary product, of the
                              X
 process is S02, which may be. sold, processed into elemental sulfur or
 sulfuric acid, or routed to the front of the Glaus unit.  The primary waste
 from the process is water generated during the recycle step.  It generally
 contains 30 to 50 ppm dissolved S02.  The SFGD process requires approxi-
 mately two moles of hydrogen per mole of SO-2 removed and one mole of
 ammonia per mole of NO  removed.  A heat credit may be realized by the
                      X
 process.  Actual costs for an integrated SFGD system are not available.
 because such a system has not yet been built at a U.S. installation.  Due
 to the complexity of the process, space requirements are expected to be
 high.  Retrofit application of the SFGD process might be difficult because
 of the duct work required.

 7.2.2.4   Vacuum Gistiliation

          Certain control methods can virtually eliminate the process
 emissions from vacuum distillation.  Emissions of noncondensable vapors
are controlled by venting into a blowdown system or by incineration.  The
vapors may be used as supplemental fuel in process heaters and boilers.
Oi]y condensate emissions can be eliminated by the use of mechanical
vacuum pumps or surface condensers which discharge to a closed drainage
system.  Both noncondensable and condensable emissions can be minimized
by the installation of a lean-oil absorption unit between the vacuum tower
and the first stage vacuum jet.
                                   369

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  7.2.2.5    Coking

            There are two accepted methods for coking:  f]uid coking and
  delayed  coking.  Delayed coking is the more widely used method.

            In the delayed coking process, the feed stream is heated and
  transferred to a coke drum which provides the proper residence time,
  pressure,  and temperature for coking.  When the coke drum has been filled
  to capacity, the coke is cut from the walls with high-pressure water;
  hydrocarbons and particulates are emitted when coke is removed.

           Particulate emissions from the delayed coking process can be
 minimized by wetting down the coke during the removal procedure.  Hydro-
  carbon emissions can be minimized by venting the quenching steam to a
 vapor recovery or blowdown system.  Once the drum has cooled to 212°F,
  the steam purge can be replaced by a water flood.  Further cooling will
 minimize steam and hydrocarbon vaporization when the drum is opened.

           Fluid coking is a continuous process in which the feed is
 injected into a fluidized bed of hot coke particles.  Approximately 30
 pounds of carbon monoxide and about 520 pounds of particulates per 1,000
 barrels of feed are emitted from an uncontrolled fluid coking unit.7'121
 There arc often additional pollutants from coke combustion.  Emissions
 can be controlled by the use of a scrubber or electrostatic precipitator
 and a CO boiler (either a separate one or the boiler which serves the
 catalytic cracking unit).

          Significant particulate emissions  often occur during the loading
of coke into rail cars  or trucks.  An induced draft  particulate control
system using bag filters could reduce these,  emissions,  but  would be expen-
sive to design,  install,  and maintain.   A more reasonable  approach is to
spray the coke with a small amount of heavy  crude oil or coker gas oil as
it leaves the coker.
                                    370

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 7.2.2.6   Air Blowing

          Blowing air through a material may serve to oxidize, remove
moisture, strip spent chemicals or mix the material.  The amount of emis-
 sions produced by air blowing depends on the amount of air used per ton
of charge, the volatility of the charge, and the temperature of the
operation.  In all of its uses, uncontrolled air blowing produces noxious
odors.

          Air is sometimes blown through asphalt to oxidize it and there-
fore increase its melting temperature and its hardness.  Emissions from
asphalt blowing are lessened by the fact that asphalt material is distilled
at high temperatures before it is subjected to asphalt blowing.  Available
data indicate uncontrolled emissions from asphalt blowing to be 40 to 80
                                                  7 0
pounds of hydrocarbons per ton of asphalt treated.

          Emissions from asphalt blowing can be reduced by vapor scrubbing,
incineration, or a combination of both.   Vapor scrubbers condense steam,
aerosols, and essentially all of the hydrocarbon vapors.  Incineration may
be accomplished in process heaters, boilers, or flares.  Hydrocarbon
                                                                1 22
emissions from a controlled asphalt-blowing unit are negligible.

          Air blowing of gas oil products to remove moisture takes place
in a packed tower or vessel.  The exhausted air does contain some lighter
hydrocarbon components of the gas oil.
          In many refineries, air-blown brightening units have been replaced
          d vessels containing solid adsorbei
potential for process hydrocarbon emissions.
with packed vessels containing solid adsorbents.'"   These units have slight
                                   371

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 7.2.2.7    Chcmica1  Swect en ing

           Chemical  sweetening rids hydrocarbons of odorous mercaptans.
 Only  low-sulfur  (sweet) materials are  subjected to this treatment; more
 drastic sulfur removal methods  such as hydrodesulfurization are used for
 high  sulfur (sour)  materials.

           In extractive sweetening, an aqueous NaOH or K.OH solution
 extracts the sulfur.  Before disposal, hydrocarbons are removed from the
 aqueous solution by inert-gas stripping, which may be a source of hydro-
 carbon emissions.

           Catalysts are used to promote oxidative sweetening.  Air is the
 oxidizing  agent and is also used to regenerate the catalyst.  Hydrocarbon
 emissions  may result from both  the oxidation and the. regeneration steps.

           Emissions from the inert gas stripping of spent caustic can be
 prevented  by venting the gases  to a flare or a furnace firebox.

           Emissions from air blowing regeneration of spent oxidative
 sweetening solutions can be reduced by steam-stripping the spent solutions
 to recover hydrocarbons before air-blowing.  The gaseouvs effluent from air
blowing can then be incinerated to dispose of residual hydrocarbons.

 7.2.2.8   AcidTreating

          Hydrocarbon streams may be treated with acid to remove or dis-
solve undesirable materials.  The use of sulfuric acid results in a
hydrocarbon/acid sludge which is removed by clay filtration.   To recover
the acid,  the sludge may  be incinerated and the resultant S02 used to
produce more sulfuric acid.   Alternatively the hydrolysis-concentration
process may be used; hot  gases from the combustion of oil or gas are
                                   372

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bubbled through the sludge to volatilize the hydrocarbon diluent and to
concentrate the acid.  Off-gases pass through a mist eliminator to the
atmosphere.  These gases may contain hydrocarbons and S02.

          If the acid concentration process is used, the off-gases from
the mist eliminator can be vented to caustic scrubbers for S02 and odorant
removal, and then to an incinerator or a flare.

          Hydrocarbons escaping from acid recovery operations can be
eliminated by using acid regeneration.  Regeneration involves sludge
incineration to produce S02, which can be converted to H2SOz..  Control
methods are available for control of S02 emissions from acid sludge
incineration.

7.2.2.9   Slowdown Systems

          All units and equipment subject to shutdowns,  upsets, emergency
venting, or purging are manifolded into a multi-pressure collection system.
Because the blowdown system receives materials from all processing units
within the plant,  any volatile material found in any process stream may
be emitted frotn an uncontrolled blowdown system.  It is estimated that 580
pounds of hydrocarbons per 1,000 barrels of refinery feed are emitted from
an uncontrolled blowdown system.

          Blowdown emissions can be effectively controlled by venting into
an integrated vapor-liquid recovery system.  A series of flash drums and
condensers arranged in descending operating pressures separate the blowdown
into vapor pressure cuts.   The liquid cuts are recycled to the refinery;
the gaseous cuts are recycled or flared.

          Emissions from a controlled blowdown system have been estimated
to be 0.8 Ib per 1,000 barrels of refinery feed, compared to 580 Ib per
                                   373

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 1,000 barrels  for  uncontrolled.   The  control  is  estimated  to  be  99.9
 percent  effective.

 7.2.2.10  Co mp res s o r E ng i ne s

          Reciprocating and gas  turbine  engines  fired with natural gas or
 refinery fuel  gas  are often used  in older refineries to run high-pressure
 compressors.   Their use is expected to dec.line.120

          The  exhaust emissions  from  these engines include carbon monoxide,
 hydrocarbons,  nitrogen oxides, aldehydes, and depending on the sulfur con-
 tent of  the fuel,  sulfur compounds.   Emission factors for  reciprocating and
 gas turbine compressor engines fired  with natural gas are  given  in Table
 7-60.  Particulate values were not available.

          No pollution control devices for refinery compressor engines are
 in current use.    Combustion modification is discussed in the following
 section.

 7.2.3     Emission Reduction Through  Process Modifi cation

          A reduction in emissions can sometimes be achieved  as  a result of
 process modifications made in the refinery.  Changes in operating practices,
 the use of alternate fuels, and the hydroprocessn'ng of refinery  feedstocks
 can result in net reductions in emissions.

 7.2.3.1   A1_Le_rnatiye_ Operating ^Practices and Conditions

                        £„,.,,,.   „   ,    123   1 2 it  125 126 127
          Regeneration of Catalytic Cracking Catalysts   »     '   '    '
 Older FCC regenerators were designed  for operation at temperatures up to
 1150°F; the introduction of newer, more coke-sensitive catalysts necessi-
 tated higher temperatures.   By 1976,  30 percent of all FCC regenerators
were operating at 1300°F.   High-temperature conversion of  CO  to  C02
                                   374

-------
        TABLE 7-60.  EMISSION FACTORS FOR RECIPROCATING AND GAS TURBINE
                    COMPRESSOR FUELED WITH NATURAL CAS
Engine Type
Reciprocating
Gas Turbine

NOX as N02a
3.4
0.3
Pollutant,
CO
0.43
0.12
lb/10s ft3 gas
HC as cb
1.4
0.02
burned
SOX as S02C
2S
2S
 At rated load.  In general, NO  emissions increase with increasing load and
 intake air temperature.  They generally decrease with  increasing air-fuel
 ratios and absolute humidity.
 Overall less than one percent by weight is methane.
cS=Refinery gas sulfur content (lb/1000 SCF):   factors  based on 100% combus-
 tion of
 Source:  Reference 1 27.

-------
generally occurs at 1,400 to  1,500°F.  With high-temperature regeneration,
the CO level in the exit gas  from  the regenerator can be reduced  to well
below 500 ppm.  Thus, a CO boiler  is no longer necessary for CO emission
control.

          Complete combustion of CO within the regenerator offers other
emissions benefits in addition to  reducing CO to less than 500 ppni:  for
example, elimination of the need for CO boiler reduces other emissions
since auxiliary fuel burning  is not required and NO -producing CO boiler
                                                   X
temperatures are avoided.  Recovery of additional heat in the regenerator
reduces  (and in some cases eliminates) the need for a FCC preheater and
its associated emissions.

          Several new catalysts, or promoters, have been introduced in the
last several years to promote the  combustion of CO to C02.  A promoter may
be chosen to promote complete combustion or partial combustion where
metallurgy cannot withstand the higher temperatures.

          Tn 1975, the cost of converting a relatively modern FCCU with
stainless steel cyclones to high-temperature regeneration was 350,000 to
$300,000.  Cost of a CO boiler for the unit was perhaps S2 million to $3
million.

          Other FCC operations which affect regenerator emissions are the
amount of recycle and the stripping steam rate.   Higher recycle rates
produce more flue gas,  but the net effect is negligible when compared to
the impact of recycle on yields and operating costs.   Similarly,  insuffi-
cient stripping steam allows hydrocarbons to enter the regenerator to pro-
duce more flue gas and  possible unstable operation.   In this case, the
impact of stripping steam rate on the entire unit's performance provides
incentives for the reduction of emissions.
                                   376

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           SO  Removal  in_ the FCC Regenerators18 >11--Amoco has developed a
 catalyst wh.ich reduces  the amount of sulfur leaving the regenerator as S02 ,
 The  catalyst holds  the  sulfur until it  is returned to the reactor, where.
 it is released and  converted to K2S.  The H2S leaves the reactor with the
 cracked product and  is  later converted  to sulfur  in the Glaus plant; the
 regenerated catalyst returns to the regenerator.

           Cost for  the  60 to 75 percent reduction in SO  emissions with
                                                       X
 this method in a new facility is estimated at 3c/bbl, compared to 22c to
 24c/bbl for stack-gas scrubbing and up  to 27c/bbl for feed hydrosulfuriza-
 tion.  The use of the catalyst for SO   control  is also less expensive than
 other methods of retrofit applications.

           Combustion Modification for Control of NO   > '   >   ;—In combus-
 tion sources, KO may be produced either by the  fixation of atmospheric
 nitrogen in the flame (thermal NOX) or by the oxidation of a portion of
 the nitrogen in the fuel  (fuel NO ).  N02 from  combustion sources is pro-
 duced as the NO combines with oxygen in the atmosphere.

          Boi_le_rs_1_ Furnaces, and Process Heaters—Combustion modifications
 for N0x control on boilers,  furnaces,  and process heaters are of three
 general types:   lowering the flame temperature,  limiting the amount of
 excess air, and limiting the residence time within the flame.  Control of
 N0x is often counter to a high thermal efficiency and contributes to the
 emission of other undesirable substances.  As a result,  compromises must
 often be made.

          A number of specific combustion modifications  for NO  control
have been devised.   The effectiveness  of some of the individual methods
and some combinations at different boiler loads  are shown in Table 7-61.

          Internal Combustion Engines—There are several modifications for
 controlling NO   emissions from internal combustion engines.   The percent
             X
                                   377

-------
                     TABLE  7-61.  REDUCTIONS  OF  NOX  EMISSIONS WITH COMBUSTION MODIFICATIONS AT

                                  VARIOUS  BOILER LOADS
OJ
•^j
oo
PERCENT REDUCTION IB NO^ EMISSIOHS WITH
Conbuatlon
Modification
Lov Exceaa Air Staging
(Percent
Full
Fired

Csi


Oil

Full Load) 85/105 60/85 50/60 85/105 60/85
Burner
Arrangement
Front Wall 13 24 7 37 30
Horizontally
Opposed 17 15 32 54 35
Tangential -
Average IS 19 26 45 31
Front vail 27 20 2B 29 20
Horizontally
Opposed 10 E6 12 34 34
Tangential 28 22 - - 17
Average 19 19 18 30 . 22
Loo Exeeta Air Flue Gas Possible* Combined
and Staging Reclrculatlon Hodlf icatlona
50/60 85/105 60/85 50/60 85/105 60/85 50/60 85/105 60/85 50/60
30 4B (2 3S 43 42 35
59 61 48 68 - 20 73 52 72
- - 60 - 66 65
52 54 44 52 - 60 20 64 51 60
20 39 32 21 4ft 31 - 50 SI 21
47 35 44 42 - - 38 35 55
- - 45 - 10 13 59 -
34 38 37 37 28 23 - 47 41 38
•Possible combination of nod If lection* on the boiler* tetted.
             Source:  Reference 46.

-------
 NO   reduction and  the  limitations for each of  these modifications are given
 in  Table  7-62.  These  methods are described in more detail in Appendix E
 (Volume 4).

 7.2.3.2   Alternative  Fuels 7

          Refiners traditionally have had a choice of natural gas, refinery
 gas, or distillate or  residual fuel oils as- fuel for refinery boilers and
 process heaters.  The  present trend is toward  Lhe heavier oils, both for
 economic  reasons and because lighter oils are  being reserved for smaller
 consumers with fewer emissions controls.  This trend, however, results in
 higher emissions from  refinery boilers and heaters.

          Emissions factors for the use of natural gas and fuel oils in
 industrial boilers have been presented previously in Section 7.1.  Accord-
 ing  to these factors, particulate emissions from natural gas and No. 2 oil
 are  independent of sulfur content, but increased with sulfur content for
 No.  4 oil and heavier  oil.  Sulfur dioxide emissions are, of course,
 directly related to sulfur content of the fuel gas or oil.

          Table 7-63 presents comparative emissions Tor natural gas and
 fuel oils for Id6 Btu heat release.   The AP-42-based "average" natural
 gas  contains only about 22 percent of the sulfur equivalent allowed by
 NSPS (0.10 grain/10 ft3 gas)  (Column 1).  Fuel oils containing 0.3 to 2.0
weight percent sulfur,  which represent the broad range of sulfur levels
 in fuels,  emit from 500 to 3,600 times as much SO  as the "average" natural
 gas.

          Overall,  the  substitution  of fuel oils for natural gas without
 instituting additional  controls will have a detrimental impact on the
 envi ronment.
                                    379

-------
                     TABLE 7-62.  ENGINE MODIFICATIONS WHICH REDUCE NOX EMISSIONS EKOM INTERNAL

                                  COMBUSTION ENGINES
CO
o
DIESELS SPARK IGNITION
ENGINE
MODIFICATION
Combustion chamber
design
Fuel propertied
Air/fuel ratio
Exhaust recycle
Fuel injection
timing
Stenm or wnter
injection
Variable compression
ratio
NOx NOX
REDUCTION PENALTIES i REDUCTION
(Percent) LIMITATIONS (Percent)
40 Increased first -
cost
Variable Availability of Variable
low nitrogen
fuels; higher
operating cost
Not applicable 30
50 Increased fuel; 50
decreased power
40 Increased fuel;
decreased power
50 Corrosion ' 50
problems
Under development -
PENALTIES (,
LIMITATIONS
Not applicable
Availability of
low nitrogen fuels;
higher operating
costs
Backfiring; reduced
power
Increased fuel;
decreased power
Not applicable
Corrosion
problems
Not applicable
CAS TURBINES
NOX
REDUCTION PENALTIES &
(Percent) LIMITATIONS
Under development
Variable Availability o£
low nitrogen fuels;
higher operating
costs
50 Increased fuel;
decreased power
Under development
- Not applicable
71 Need delonlzed
water; costly
- Not npplicable
              Source:   Reference 45.

-------
             TABLE 7-63.  REFINERY FUEL EMISSIONS AT  EQUIVALENT
                          HEAT RELEASE
         Fuel Type
Natural Gas'
#2 F.O.
                                                                   #6 F.O.
Gross Heating Value
Specific Gravity
Amount Equivalent to
 IO6 Btu heat release
Emissions Ib per
Btu:
   S02: NSPS
   S0?: (av)
   Particulat
   CO
   HC
   NO  (av)
            1
Sulfur Wt%  I
 (oils only)|
                          1012 Btu/ft3°
                          0.55/Air

                          988 ft3
                  19,460 Btu/lb'
                  0.856/water

                  7.20 gal
 Reference 7.
 Accepted value for pure methane.

                                0.1 gr H2S
                 18,200 Btu/lb'
                 0.972/watera

                 6.78 gal
2.66 x 10 d
5.9 x IQ~^
(av) 9.9 x IO"3
1.68 x 10~3
3.0 x 1Q~3
0.17


0.306
0.014
0.036
7.2 x ].0~3
0.16
0,3
(typical)

2.13
0.16
0.034
6.8 x io~3
0.41
2.0 ,
(high)
      emission limit of SO2 =
                    x 64 Ib S02    1 Ib
    10 ft3  nat.  gas   34 Ib H2S~ X 7000 gr
                            = 2.69 x 10
                                             Ib S02
                                          ft3 nat. gas
Tlesidual  fuel  oil sulfur levels range from 0.3 Wt.  percent (N.Y. City)
 to  2.0  percent (Midwest) according to sales data as regularly published
 iu  Oil  and  Gas Journal
                                     381

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 7.2.3.3   Hydroprocessing as Fe_edstock_ Pretreatment

          Hydroprocessing includes those processes in which hydrogen is
 combined with a feedstock and passed over a catalyst at elevated tempera-
 ture and pressure.  Some examples are:

          •    Eydrodesulfurization of residual feedstock to
               be used in fuel oil production or catalytic
               cracking.

          •    Hydrodesulfurization of heavy gas oils and middle
               distillates to be used in the production of jet
               fuels, diesel fuels, and heating oils.

          •    Hydrodesulfurization of heavy gas oils to be used
               as high-quality catalytic cracking feed.

          •    Hydrodesulfurization and hydrodenitrogenation of
               naphtha and straight-run crude distillate streams to
               be used as primary feeds for the isomerization and
               catalytic reforming units.

These and other uses of hydroprocessing are discussed more thoroughly in
Section 4.4 of Appendix F (volume 5).

          Hydroprocessing removes sulfur and nitrogen-containing compounds,
the heavy metals,  oxygen, and halides.   Hydrotreating also stabilizes
unsaturated hydrocarbons by saturating the double bonds.

          The overall impact of hydroprocessing is  generally beneficial
for reducing emissions.   Removal  of objectionable materials, besides reduc-
ing emissions from subsequent processes,  can significantly reduce catalyst
                                   382

-------
poisoning and equipment corrosion and can also increase yields.   Hydro-
desulfurization of catalytic cracking unit feeds is a very effective method
for reducing sulfur emissions from catalytic cracking catalyst regeneration.
                                  383

-------
8.0       ENVIRONMENTAL ASSESSMENT

          An environmental assessment was performed to examine the effects
of refinery emissions on the surrounding atmosphere.  The large volumes
of emission rate data generated in this program were used to predict
ambient pollutant levels.  Environmental and public health effects of the
predicted pollutant concentrations were also examined.  Finally, a brief
survey of the effects of existing and potential regulatory policies and
developing technology was made.

          The primary objective of the environmental assessment is to
provide guidance in identifying potential problem areas.  For instance,
it can provide insight into which sources and which pollutants appear to
pose potential hazards.  The results are semi-quantitative in nature, which
allows a relative ranking of such problem areas.  This can help to focus
attention on those areas needing further research.  The environmental
assessment is only a tool to aid in the relative evaluation of potential
environmental impacts, not a method for making precise and accurate
predictions of such impacts.  The results should not be regarded as an
absolute value which can be used to predict violations of standards,
public health hazards, requirements for additional pollution control
technology, or regulatory requirements.

          The complete environmental assessment of petroleum refineries is
presented in Appendix D (Volume 4) of this report.  The methodology used in
performing the environmental assessment is described in Sections 8.1
through 8.3.   Section 8.1 describes the hypothetical refinery model used
in the assessment.   The calculations used are shown in Section 8.2.  The
workings of the atmospheric dispersion model are described in Section 8.3.
Section 8.4 conveys the predictive results of the model applied to the air
quality surrounding the hypothetical refinery.   Effects of existing and
potential environmental regulations and policies on refineries and their
surrounding environments are discussed in Section 8.5.

-------
          The environmental assessment performed in this study included
the following steps:

          •    Definition of a model refinery.

          •    Calculation of emissions from the model refinery.

          •    Calculation of ground level concentrations outside the
               boundaries of the refinery using atmospheric dispersion
               modeling.

          •    Comparison of those ground level concentrations to some.
               acceptable concentration.

          The parameter which is used to quantify environmental impacts is
called source severity.  This concept was developed by Monsanto Research
Corporation under contract to the EPA.
          A source severity factor is defined as the ratio of the maximum
ground level concentration of a pollutant in a "standard receiving
atmosphere" to the "acceptable pollutant concentration," as shown below:
                              S -
where
                     S    = the source severity factor,

                     Y    = the maximum ground level concentration of the
                      max
                            pollutant, and

                     F    = the acceptable pollutant concentration.
                                  385

-------
This acceptable concentration is derived from either National Ambient Air
Quality Standards  (NAAQS) or from Threshold Limit Values  (TLV's).  If the
resulting ratio is greater than 1.0, then emission reduction is probably
needed.  If the ratio is below about 0.01, then further reduction is
probably not needed.  Emission reduction requirements for pollutants with
source severity factors between 0.01 and 1.0 are uncertain.

8.1       Definition of the Refinery Model

          The first element to be examined is the development of the
model refinery.  Both the refinery processing arrangement and its physical
configuration must be characterized.  There is ample documentation of the
difficulties involved in trying to synthesize a "typical representative
refinery."  Refineries are very diverse, and only a very rough approxi-
mation can be achieved with a single model.  Therefore, it should be noted
throughout this discussion that this is not a model that attempts to
represent the total industry, but rather a model of one hypothetical
refinery that reflects the "real world" as much as possible.

          The source for the model refinery is an EPA report prepared by
Pacific Environmental Services. 9  The "Large Existing Refinery" case
was chosen as the model for this study because it is essentially a worst
case.  If the results show minimal environmental impact for this type
of refinery, then smaller, less complex, or more efficient grass roots
refineries should create, an even lesser impact.

8.1.1     Refinery Process Configuration

          Figure 8-1 shows the basic processing configuration of the
model refinery.  All of the normal refinery unit operations are represented.
Approximately 350,000 barrels per day of crude can be processed in the model
refinery.   It is a reasonable example of a modern fuels refinery supplying
low sulfur products.
                                   386

-------
                                                                                                         Fuel Caa and LPG
CO
                    ITC  and Cns
                                                                                          Aroma tj.ce
                                                                                          Extraction
                       Middle Distillates
                                                                                                                   Fuels
                                                                                                                  Diesels
Heavy Atm. Gas Oil
                                                                               Cycle  Gas  Oils
                                Treating  |
                                   	4	1
                                                                                           llcntlng Oils
                                           To
                                        llydrotrenters
                                                                                                                  Petrochemical
                                                                                                                  Feedstocks
                                 Vac. Cos OIL
                                                                                                                    Fuels
                                                                                                                  Refinery
                                                                      Gasoline. Naphtha,  Middle Distillates ..
                                    Figure 8-1.   Block  Flow Diagram of Model Refinery

-------
8.1.2     Refinery Layout

          The plot plan of the refinery is shown in Figure 8-2.  The
functions of the various refinery modules arc detailed in Table 8-1.
This environmental assessment does not include the effects of emissions
from storage tanks (This is discussed further in Section 8.4.3).  It
includes only emissions from the refinery processes.  The process areas
tend to form two clusters, probably the result of a stage-wise expansion
over a period of many years.  Considerable detail has been included in
the physical model.  All of the appropriate vital functions have been
accounted for and distributed in a realistic manner.

8.2       Emission Calculations

          This section describes the estimation of losses using emission
factors and fitting counts.  Also included are the hydrocarbon emissions
broken down into their component compounds.

8.2.1     Emission Factors and Fitting Counts

          The emission factors required for the calculations were derived
primarily from the results of testing on this program, but they were
supplemented by emission factors from other sources (such as AP-42') as
needed.  Fugitive emission factors for valves, pumps, compressors, flanges,
relief valves, drains, and cooling towers were developed in this program.
Estimated fitting counts and emission factors for fugitive sources in
the model refinery are presented in Table 8-2.  Emission factors for
process sources and the corresponding source capacities are given in
Table 8-3.

          The estimate of the population of each type of fitting is as
important as the emission factor in determining total emissions.  The
PES model contained estimates of fitting populations, but they were not
                                  388

-------
                      LARGE CAPACITY
                      W -  1865 m
 e
u-i

ts
      22,
z:
   24
   20
      25
      30
45
     46
58
5C
          26
         31
         47
      60
      68
             32
             51
                 33
                62
                             10
                      36
                       39
                                 38
                              40
                        41       42
                  6364.
                69
     70
     71
                 72
                        65
                           G6
                         67
                    73
                                54
                                         11
                                         13
                                         14
                                         15
                                                       12
                                                 16
                                                 17
                                                 IB
                                                   21   .
                                            43
                                           55
                                    T4
                                              76
                                                          44
                                                          56
                                                          57
                                                        75
                                                                         N
                                  126
       Figure 8-2.   Model Refinery Layout
                           389

-------
TABU1".  8-1.   LARGE  CAPACITY  EXISTING  REFINERY /MODULE  KEY
Module No.
LI
L2
13
IA
L5
It
17

IB

19

L10
L1I
112
L13

114


115
L16

U7
U8
LI 9
L20
L21
122

L23
124
L25
L26
L27
L28
L29
L3D

L31
L32
133


134
L35
Lsa

169
L70
171
L72
173
L74
L75
176

Description
Buffer Zone
Feedstock Storage
Crude Oil Storage
feedstock Storage
Feedstock. Storage
Crude Oil Storage
Feedstock .and Product
Storage
Crude, Feedstock, and
Product Storage
Crude, Feedstock, and
Product Storage
Oil-Water Separator
Produce Storage
Product Storage
Distillation and Gas
Recovery Unit
Jet Hydrofiner/Catalytic
Reformer

Naphtha Hydrotreater
Hydrotreater (It Cycle
Oil)
Hydrogen Manufacturing
Partial Oxidation Unit
Future Expansion
Cooling lover
Flares
Feedstock and Product
' " Storage
Naphtha Bydrotreater
Vacuum Gas Oil licit
Benzene Fractlonation
St*ui Rerun Stills
Future Expansion
Crude Distillation
Catalytic Refoner
Vacuum Residua De-
sulfurizer
Hydrogen Manufacturing
AlkylaticD
Distillate Hydrodesul-
forlzatlon (Hvy Cat
Oil)
Sulfur Recovery
Tanks /Cooling lovers
Vapor Recovery/Gasoline
Rectifier /Tanks
Main Pumy House
Produce Storage
Uaetevacer Tre^cicenC
Building
Product Storage
Shops and Warehouse
Crude Oil Storage
Crude, Feedstock, and
Product Storage
Module No.
L36
L37
L38
L39
L60
L41
L42
L43
L44

L45
U6

L47

L4S

L49
L50
L51

L52

L53
L54
L55
L56
L57
L58
L59
L60

L61

162

L63


164

165


L66
167











Description
Catalytic Reformer
Aromatic 6 Extraction
Catalytic Cracking
Para-Xylene Plant
Delayed Coker
Sorrel Storage
Barrel Reconditioning
Feedstock Storage
Stern Water Impound
Basin
Warehouse ''
Cas Hclder/Blcvcovn
Stack
Cas Holder/Slowdown
Stack
Fire Prevention Train-
ing Facility
Oil-Water Separator
Asphalt Plant
Solvent Treating Plant/
Boiler House
SO; Treating Plaat/
Tanks
lube Oil Packaging
Coke Storage
Crude Oil Storage
Feedstock. Storage.
Tanks/Impound Basin
Adaiais t rat ion
Oil-l'ater Separator
Gasoline Sweetener/
Crude Distillation
Crude Distillation/
Crude D*£aicer
Specialty Crude
Distillation
Speciality Crude Dis-
tillation/Condenser
Box
Gasoline Fractionating
unit
Tank loading/Truck
loading/Vapor Re
covery
Buildings
LFG Storage and Blending











    The oil/vater separator In hodule 110 treats  aqueous discharge from
    Modules L1-L21.
    The c-parator located In Module 159  treats aqueous streams from Modules
    L58-L60, L70, 171, and L73-L76.
    The vastevater separator in Module 149 treats discharges from the remain-
    ing nodulei.
                                   390

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             TABLE 8-2,  FUGITIVE SOURCES AND EMISSION FACTORS
SOURCE
Pumo Seals1

Valves '



Compressor Seals

Flanges1
Relief Valves1

Process Drains1
Cooling Towers1
Oil/Water Separators2

Dissolved Air
Flotation1
ESTIMATED POPULATION
(OR CAPACITY)
313
340
1714
4198
7422
8442
82
48
84346
171

1105
(10,668 x 103 gal/hr)
(160.3 x 103 gal/hr)
(1719 x 1C3 gal/hr)
(220.5 x 1C3 gal/hr)
SERVICE
CATEGORY
Light Liquid
Heavy Liquid
Hydrogen
HC Gas
Light Liquid
Heavy Liquid
Hydrogen
HC Gas
NA
HA

NA
NA
Uncontrolled
Controlled
NA
NOfi-METKANE HYDROCARBON
(NMHC) EMISSION FACTORS
0.25 Ib/hr. /source
0.046
0.018
0.059
0.024
0.0005
0.11
1.40
0.00056
0.19
\
0.070 |









t

0.006 lb/103 gal.
5.0 lb/103 gal.
0.2 lb/103 gal.
(0.01 lb/103 gal)3
  Emission factors based on Radian testing.

2 Emission factors based on AP-42.
3
  This value is a rough average of a very few test results.
  It should not be construed as an emission factor for broad application.
                                     391

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                                          TABLE  8-3,   PROCESS  SOURCES  AND  EMISSION F'ACTORS
                    SOURCE
                                          CAPACITY
                                                         PAKTICULATES
                                                                                    EMISSION FACTORS
                                                                              SO,
                                                           NOV
                                                                                                                CO
                                                                                                                         KM HYDROCARBONS
            Proceaa Heatera/Boilera
             - oil fired
             -  gas -fired'
36.7 x 103  gal/hr     6  lb/101 gal    47.7 lb/101 gal    60 lb/10J  Kal   5 lb/10J  gal   1  lb/101  gal
 2.27 x 10' Et'/hr    5  lb/10' ft1     0.6 lb/106 £tj   120 lb/10'  ft3  17 Ib/lO6  ft3   3  lb/10*-  ft'
            Fluid Cncnlytic
            Cracker CO Boiler'
 2.086 x 103Dbl/hr    45  lb/103Bbl.    493 lb/103Bbl.     71 lb/105Bbl .  Negligible     13.3 lb/lo'Bbl.
LJ
sO
M
Sulfur Recovery  Complex1*

 - Clans plants  plua
   Wellman-Lord  Tall
   Gaa Treating  Unit
                                         long tons/day
                                         (l.TPD)
             - Sulfurlc Acid Plant   179 LTPD
                                      3.6 Ib/LT


                                     U.6 Ib/LT
            Flarcu5
 350 x 103Bbl/day    Negligible
                                                             26.9 lb/10!Bbl    18.9 lb/10Jbbl  /..3  lb/10JUbl   0.6  Ib/lO'bbl
              1  Based on AP-427 faccors for No. 6 fuel Oil with 0.3 wt .  X  sulfur.

                Based on AP-A2  factors for natural gaa.

              1  Baaed on AP-42  factors for a Fluid Catalytic Cracker with un  El uct roaLat ic Precipl tator and n CO Boiler,
                except the NKHC taccor was taken from Radian tenting.

              11  Based on sulfur recovery «f f icleiiclea taken from Hydrocarbon Procenulng;'' 2-scngc Glaus - 92X, Wcllman-Lord
                TGTU - 99X, SulfurJc Acid Plant - 99Z
                 Based un AF
                                (acturu for blowHown flyutema with vapor recovery  and vents  to flares,

-------
broken down into the service categories corresponding to the emission
factors.  Radian data on fitting counts were generated during the field
testing phase (see Tables 5-16 and 5-17 in Section 5).  These unit
configurations did not necessarily match those from the model refinery.
The detailed procedure developed to generate fitting counts compatible
with emission factor service classes and to represent the model refinery
as closely as possible is described in Appendix D (Volume 4).

          Although emissions from storage tanks were not within the scope
of this study, they were estimated to provide a basis of comparison to
other hydrocarbon emission sources.  The PES report " contained a detailed
breakdown of the storage facilities, their service, capacities, and
annual turnover.  Emission factors were taken from AP-42  and applied to
these facilities to estimate total emissions.  The PES data indicated
the use of floating roofs to control emissions on all tanks containing
liquids with Reid vapor pressures greater than 0.5 psia.

8.2.2     Emissions of Criteria Pollutants and Total Hydrocarbons

          Applying all of these factors, a slate of refinery emissions
was generated.  Table 8-4 is a summary of those emissions by pollutant type.

8.2.3     Emissions ^f Selected Hydrocarbon Components

          The emissions estimates given in Table 8-4 are sufficient to
estimate the ambient concentrations of criteria pollutants, but a species
breakdown is necessary to evaluate individual hydrocarbon concentrations.
Analyses of the components in various process streams were made in this
program and supplemented by literature sources.  The application of these
stream analyses is not straightforward, however, since the emissions were
                                  393

-------
        TABLE 8-4.  SUMMARY OF EMISSIONS FROM THE MODEL REFINERY

Pollutant
Particulatcs
SO
X
CO
NO
X
Norune thane
Hydrocarbons
Emissions in Tons/Year
Point Sources1 Fugitives2 Storage
1,425
14,650
1,247
12,693
364 8,767 3,308

Total
1,425
14,650
1,247
12,693
12,439
1 Includes combustion sources, fluid catalytic cracker, CO boiler,
  sulfur recovery complex, and flares.

2 Includes process fittings (pumps, valves, flanges, compressors,
  drains, and relief valves),  cooling towers, oil/water separators, and
  other wastewater treating units.
                                   394

-------
calculated on a unit basis.  The necessary approach involves three
steps:

          (1)   Identification of the major product and intermediate
                streams in each unit.  Total unit emissions were
                distributed among each stream.

          (2)   Application of stream analyses to estimate component
                emissions for each stream.  Component analyses were
                obtained from samples taken during this program and were
                supplemented where necessary with data from a previous
                Radian literature survey,13'an API medical research
                report1,32 and engineering estimates.

          (3)   Summation of the stream component emissions to get unit
                component emissions.  In this assessment, some components
                were consolidated into groups if either discrete con-
                centration data or quantifiable toxicity data were
                unavailable.

          An example of the distribution of emissions between each process
stream for valves in an FCC unit is given in Table 8-5.  The estimated
percentage of fittings on each stream is multiplied by the weighted
average emission factor for fittings in that service.  The result is the
percentage of the total unit fugitive emissions attributed to each process
stream.  The weighted average emissions factor used in Table 8-5 may be
a combination of the gas-light liquid, or the gas-heavy liquid emission
factors if the particular process stream is present in the unit as both
a gas and a liquid.

          A summary of stream quality data is given in Table 8-6.  This
table shows the estimated component analysis for numerous refinery
streams.
                                  395

-------
                            TABLE 8-5.   DISTRIBUTION OF UNIT FUGITIVE EMISSIONS  BY STREAM
MD

-------
TABLE 8-6,  SUMMARY OF STREAM QUALITY DATA  (PPMWJ
Conpound or
Funct tonal Family
Benzene
Toluenp'
tthylbentcnt
Xyleiies
Other Alkylbenzenes
Naphthalene
Anthracene
Bipheuy 1
Other PNA's
n-Hexane
Other Alkalies
Olcf Ins
Cyuloalkanes
Other Compounds
Indicated Present






Cnidt
Oil
60
680
220
880
3,739
PSO
140
320
7.8HU
18,000
87/.240
0
58,300
Carbonyl
~ 500 ppm
Thlols
~ 25,000 ppm
Sulf Ides
~ 6,000 ppra
Qulnollnes
~ 200 ppm
Pyrldln*s
Straight
Rim
Naphtlia
253
2,621
887
1,623
•16.578
1,463
5
628
14,983
38,838
499,613
0
422,508
Pyrldines
Thlola
Sulfldes





Middle
Distillate
0
5
9
52
835
100
56
0
5,507
0
842,536
0
100,000
Pyrldlr.es
Thiols
Snlfldea
~ 51,000 ppra
Qulnollnes




Atmospheric
Gas & Oil
0
8
6
16
61
4
3
0
220
0
949,573
0
50,000
Pyrldlnes
Thioln
Snl fides
Qulnollnes
^ 9 pirn




Vacuum
Gas & Oil
0
5
6
22
36S
28
12
9
663
0
948,887
0
50,000
Pyrldlnea
Thlols
Suicides
Qulnolines





Refornate
5 , 400
77,700
33,500
170,900
324,400
7,400
0
0
700
24,000
356,000
0
0
Hj







Hi Recycle
Gas
0
0
0
0
0
0
0
0
0
0
650,000
0
0
~ 350,000







Deaulfurized
Naphtha
253
2,621
887
1,623
16,578
1,463
5
628
14,983
38,838
499,613
0
422,508








                                                        Continued

-------
                                               TABLE 8-6.  (Continued.)
VO
03
Compound or
Functional Family
Benzene
loluene
EChy Ibenzene
Xylenes
Othrr Alkylbenzenes
Naphthalene
Anthracene
Biphenyl
Other FNA'a
n-llex«no
Other Alkanes
Olefins
Cycloalkanes
Other Compound*!
Indicated Present
Hydrotrca ted
Mtdillo
Distillate
0
3
9
52
835
100
56
0
5,507
0
887, 436
0
IDO.WXI
Siilfldcs
t 6,000 ppm
Refinery
Fuel
CaE
0
0
0
0
0
0
0
0
0
0
920,000
60,000
0
HJ : 20,000
Thlola
Sulfldei
Liquefied
Petrolcura
Gas (L?C)
0
0
0
0
0
0
0
0
0
0
1,000,000
0
0
Thiols
SulElde*
Raffinate
30
750
300
1,500
2,300
50
0
0
50
63,000
932,000
0
0

Aroma tics
Extract
17, 840
256,700
110,670
564,590
48,000
100
0
0
100
100
1,900
0
0

Benzene
993,000
2,000
0
0
0
0
0
0
0
5,000
0
0
0

Toluene
1,000
992,800
4,000
1,000
0
0
0
0
0
0
1,200
0
0

Xylcncs
0
1,000
162,420
828,580
5,000
100
0
C
100
0
2,800
0
0

                                                                                           (Continued)

-------
                                      TABLE  8-6.   (Continued)
Compound or
Functional Family
Benzene
Toluene
Ethylbenzene
Xylenes
Other Aikylbenzenes
Naphthalene
Anthracene
Blphenyl
Other PKA's
n-Hcxane
Other Alkane8
Oleflns
Cycloalkanes
Other Compounds
Indicated Present




LPC
Oleflns
0
0
0
0
0
f)
0
0
0
0
400,000
600,000
0
ThiolB





Alkylate
0.1
0,3
C.I
1.1
3.3
0.3
0
0
2.2
96
998,956
930
11






Cracked
Naphtha
2,880
89,780
21,430
171,450
243,470
10,950
0
0
6,480
11,830
204,110
170,740
68,880
PyrlUlnee
ThiolB
Sulfldes
Qulnaltnes


FCC
Light Cycle
Gas & Oil
0
40
0
610
26,670
59,000
10,270
10,180
624.480
0
190,800
36.750
41,200
Phenols
Carbonyla
Pyrldlnes
Thlola
Sulfldea
Qul no lines
FCC
Heavy Cycle
Gas & Clt
740
10,000
1,200
11,800
38,200
14.000
0
0
22,500
0
701,560
50.000
150,000
Pyrldinea
Csrbonyls
Thiols
Sul Fid en
Qulnolln«a

Heavy
Aromatica
Extract
(SOj Plant)
0
0
0
0
750.000
0
0
0
200,000
0
45,000
0
5,000






Asphalt
0
0
0
0
•ch
0
2
0
200
0
999,798
i.
i






API
Separator
Skin Oil
87
1,713
661
2,510
12,751
990
457
2,351
29,700
4.
948,780
i.
i






Vacuum
Resld
0
0
0
0
i
0
2
0
200
0
999,798








1 Compositions are estimated to 2 or 3 significant figures.   Additional
 significant figures are a result of calculational procedures,  and they
 should not be given any importance.

 The symbol -L means that the component has been indicated to be present, but
 the exact concentration is unknown.

-------
          The stream breakdown is  combined with  the  stream analyses  to
get a component analysis of unit emissions.  An  example  of this process
is shown for an estimate of fugitive emissions from  an FCC unit in
Table 8-7.

          A similar operation was  performed separately on relief valves,
since they arc not distributed uniformly across  the  streams.  Relief
valves are usually  placed at the  top of a fractionating column or
reactor vessel, and, thus, are exposed primarily to  lighter  streams.
Table 8-8 shows the allocation of  relief valves  for  the  Aromatics
Fractionation unit.  The number of relief valves in  each stream service
was totaled, and the stream analyses were applied to the emissions,
as shown in Table 8-9.  All relief valves in the model refinery were
assumed to vent to the atmosphere.

          Still a different procedure was required to characterize the
hydrocarbons emitted from the API  separators.  Analyses  were available
for the inlet oil to the separator and for the recovered oil.  A hydro-
carbon material balance was made to estimate the composition of the
evaporative emissions from the separator, as shown in Table 8-10.  The
available analyses showed only the aromatics components, so the balance
of the oil was assumed to fall in  the alkane family.

          This material balance approach assumes that any component lost
from the oil phase, is lost as evaporative emissions.  This neglects the
slight solubility of certain components which could result in mass transfer
to the water phase (or eventually even the sludge phase).  Thus, this
approach results in a conservatively high, worst case assumption of the
emission rate of individual species from the API separators.

          Summary of Hydrocarbon Species Emissions—The  emissions of
selected hydrocarbon species were calculated by the above methods.   The
results are summarized in Table 8-11.   These figures represent only
                                   400

-------
                  TABLE 8-7.   FLUID CATALYTIC  CRACKING  -  FUGITIVE  EMISSION CHARACTERIZATION
     Stream
LPC Olcfliis

Crocked Naphtha

Lt. Cycle Can Oil

Hvy.  Cycle Uas Oil
                                   7
                                 Weighted Contribution of  each Component to Unit Emissions, III ]>pmu
Aluus. Gas Oil
Fuel Cos
1
30
0
0
0
0
0
0
0
0
1
0
0
0
'.5

 1

 0
                   Kate
                   Ib/hr
  0

1296

  0
000

    9644    77153

006
                                           9644
                                                  7715*
    0

J.09562

   267



109830
         0


         0

   0      0

4928

 590    103
                                                                   5518
                                                                          103
                                                      102
                                                                                  102
   0

   0

2916

6245



9163
   0

   0

5324

   0



5324
  9'.95

276000

 92000

 9185(1

  1906



'•71251
 18000

138000

 76833

   368



233201
   0

   0

31)09 b

  412
                                                                                                                                   H !
                                                                                                                                    0
fiOOO

   0

   0

   0
                                                                                                                         31008   6000
                    59.8
                            .078
                                    2.42
                                           .577
                                                   4.6)
                                                            6.57
                                                                    .31
                                                                          .006
                                                                                 .OOfi
                                                                                         .54B
                                                                                                .118
                                                                                                        28.18
                                                                                                                 13.95
                                                                                                                          1.85
                                                                                                                                  .359

-------
         TABLE 8-8.  RELIEF VALVE DISTRIBUTION
        Example:  Aromatics Fractionation Unit







Total Relief Valves = 6




      Steam                          No. of Relief Valves




    Benzene                                   4




    Toluene                                   2




    Xylenes                                   0
                           402

-------
•P-
O
                                  TABLE  8-9.    RELIEF VALVE SUMMARY  -  FUGITIVE  EMISSION  CHARACTERIZATION
                                                                       Weighted Contribution of mch Conponirit to Unit Enlaslons,  In ppav
II, Recycle Cos
Fuel Gas
  LFG
  LFG Olefins
S.R. Naphtha
Cracked Naphtha
  Reformate
  Extract
  Rafflnate
                                                                                                                  0     9828
                                                                                                                9^99   663492
                    TOTALS
                    Normalized
                    Total.
                    1.1      0
                  100.0   2253J

                         23040
                                                    24421
                                                            4439
                                                                    2A458
                                                                            35247
                                                                                    1345
                                                                                                  113
                                                                                                         3256
9713   678416
                29703
                         1100      0
                        80143  S0050

                        81946  81850

-------
             TABLE 8-10.  ESTIMATED COMPOSITION OF INLET OIL,
                          HYDROCARBON VAPOR, AND OUTLET OIL
                          STREAMS AROUND AN API SEPARATOR

Component
Benzene
Toluene
Ethylbenzene
Xylen.es
Alkylbenzenes
Naphthalene
Anthracene
Biphenyl
Polyrmclear Aroraatics (PNA's)
Alkanes

Estimated
Inlet
Oil
0.03
0.22
0.06
0.21
0.80
0.29
0.04
0.18
2.04
96.13
100.00
Composition of
Vapor
Fro-
Separacor
0.07
0.22
0.06
0.21
0.80
0.29
0.04
0.18
0.15
97.98
100.00
Streams (Wt %)
Outlet
(Skinned)
Oil
0.01
0.22
0.06
0.21
0.80
0.29
0.04
0.18
2.98
9.5.21
100.00
Skimmed Oil Rate = 667 Ib./lOOO Ib.  inlet oil
Vapor Lost from Separator = 333 Ib./lOOQ Ib. inlet oil
                                    404

-------
                   TABLE 8-11,   SUMMARY OF HYDROCARBON SPECIES EMISSIONS FROM
                                FUGITIVE SOURCES
Source
Component

Benzene
Tolurnc
Ethy Ibcnzene
Xyleneo
Other Alkylbenzenes
Naphthalene
Anthracene
Biphenyl
Other PNA's
n-Hexane
Other Alkanea
OlefJns
Cycloalkanes
Hydrogen
TOTALS
V, P. C, F,
ppmu
7,200
21.000
5.600
31,000
42,000
1,700
20
230
7,700
16,000
654,000
'i6,000
135,000
31 ,000

D, CT*
kg/hr
2.8
8.2
2.2
12.1
16.6
0.7
0.01
O.i
3.0
6.3
255.9
18.1
52.9
12.3
391.2
Relief Valvofl
ppmu
23,000
2 '.,000
4,500
26,000
35,000
1,400
1
110
3,300
9,700
676,000
30,000
82,000
82,000

kg/hr
0.4
0.4
0.1
0.4
0.6
0.02
0.0
0.0
0.05
0.2
11.3
0.5
1.4
1.4
16.8
APT Scpnrntarti
ppnrw kg/hr
700 0.4
2,200 1.1
590 0.3
2,100 1.1
7,900 4.1
2,900 1.5
390 0.2
1,800 0.9
1,500 0.8
•i.** 4,.
980,000 502.4
•i -i
•i 4.
•i i.
512.8
Totals
ppmu
3,900
11, GOO
2,800
15,000
23,000
2.400
220
1,100
4,200
7,100
640,000
20,000
59,000
15.000

kg/hr
3.6
9.7
2.6
13.6
21.3
2.2
0.2
1.0
3.9
6.5
769.6
18.6
54.3
13.7
920.8
* Kl
•  fugitive emissions from valves, pumps, compressors, flanges, drains, and cooling towers.

  Components marked with "•£" are indicated present, but no quantifiable concentration data
  were available.

-------
fugitive hydrocarbon emissions and not the point source emissions from
sources such as process heaters and fluid catalytic cracking regeneration.
The stack hydrocarbon emissions did not significantly affect any of the
critical emission points for hydrocarbon species because of the effects
of height of release and plume rise.

8.3       Atmospheric Dispersion Modeling

          Ground level concentrations of the various pollutants can be
estimated using any one of a large variety of computer modeling techniques.
The choice of the model and the details of its application to the refinery
model are discussed in the following sections.

8.3.1     Choice of the Dispersion Model

          There were several guidelines considered in choosing a model.
First it should be an established, well accepted model.  It should have
the capacity to handle a large number of both point sources and area
sources.  It must be able to give not only the total concentration of the
pollutant at any given point, but also the relative contribution of each
source to that total.

          Although not alone in satisfying these requirements, the EPA
guideline model RAM '   is certainly the most well-known.  It has been
extensively used and, at the time of this study, was accepted by regulatory
agencies for flat terrain modeling.   There are two versions of RAM,  the
rural and urban versions.  The urban version has slightly higher dispersion
coefficients to account for the numerous heat sources typical of an urban
environment.  As with other unconstrained choices, the worst case was
chosen, which means the. rural version of RAM.

          The RAM model was not calibrated in this study.   Raw predictions
were used in evaluating the refinery impact.  The use of raw predictions
                                  406

-------
can result in ambient concentrations that arc overestimated by as much
as a factor of two.

8.3.2     Application of the Dispersion Model to the Hypothetical Refinery

          The RAM dispersion model133 is capable of predicting a 1- to
24-hour average concentration of relatively unreactive pollutants.
A maximum of 250 point and 100 area sources can be modeled.  Concentrations
are predicted at a maximum of 150 selected locations (receptors).

          RAM uses Gaussian steady-state dispersion algorithms for areas
where one wind vector for each hour is a good approximation.  Concentrations
are calculated hour by hour as if the atmosphere had achieved a steady-
state condition.

          Meteorological parameters utilized by the model include wind
speed,  wind direction, temperature, atmospheric stability class, and
mixing height.  The parameters are set by the "standard receiving
atmosphere" as defined by Monsanto in their source severity work.130
The worst case wind direction was determined by comparing the results of
modeling for wind blowing for one hour from each of 16 different directions.
After determining the worst case wind direction, a repeating sequence
of 3 wind directions (1 hour from the worst case direction and 1 hour
each from 5 degrees on either side of the worst case direction) was used
to obtain mean concentrations for short averaging times.   It is
recognized that the persistance of these conditions for a 24-hour period
is quite improbable.  This assumption again results in a worst case
approximation of  "real world" conditions.  The source severity methodology
is specific in requiring that these conditions be used, and no provisions
are given to incorporate variations when modeling for longer averaging
times.
                                  407

-------
          Annual concentrations  (for comparison with N02 NAAQS) can be
                                 134
predicted with Larsen statistics.   Using empirically determined ratios,
the maximum annual concentration can be determined from mean concentrations
for shorter averaging times.  These ratios are functions of the standard
geometric means (SGM) of the shorter averaging times.
          The dispersion coefficients are empirically-determined as
functions of atmospheric turbulence, distance from the source and the
concentration  averaging time.  Thus, the spread of the plume is dependent
on these three factors.  The atmospheric turbulence is defined by stability
classes.  These classes, which range from very unstable to neutral to
very stable atmospheres, are determined by wind speed and insolation
during the day, or wind speed and cloud cover during the night.  The most
unstable class is A.  Class F the most stable.  The C stability class
used here is considered neutral.

          RAM can accept both point source and area source inputs.  The
data required to characterize a point source includes source coordinate,
emission rate, physical height, stack diameter, stack gas exit velocity,
and stack gas temperature.   Area source parameters consist of coordinates
of the southwest corner, side length, total area emission rate, and
effective height.

          Stacks,  flares, etc., were modeled as point sources.  Fugitive
emissions were modeled by three different methods.

          (1)   As a. single point source originating in the center
                of the process unit plot.

          (2)  As  a pseudo-area source (where the single point source
               was divided  into three point sources distributed across
               the unit in  a plane perpendicular to the worst-case
               wind direction).
                                   408

-------
           (3)   As area sources.

The point  source approach gave very unrealistic boundary line conditions
with large concentration peaks directly downwind of the unit centerlines
and very low concentrations elsewhere.  The pseudo-area approach had
some smoothing effect, but only the rigorous area source approach gave
satisfactory results.

           Concentrations from the point sources are a function of the
distance downwind and crosswind from the source to the receptor.
Concentrations due to area sources are calculated using the narrow
plume approximation.  This neglects diffusion in the crosswind direction
and assumes that an area source consists of many narrow plumed point
sources.  As a result, any receptor that has no area sources directly
upwind receives no contribution to its predicted concentration from area
sources.  This approximation is good when modeling large urban area
sources.136 The five degree variation in wind persistence did add some
dispersion outside the worst-case wind direction streamline.

          The locations of a series of permanent receptor sites were also
input to the model.  The locations consisted of a grid placed in the area
of greatest impact as predicted by the worst case wind direction.  The
model then calculated the 24-hour average concentration at each receptor.
From these data,  maximum concentrations were determined.  Also, isopleths
(lines of equal concentration) were plotted.  Not only were the total
ambient concentrations displayed for each receptor, but these concentrations
were broken up into their component contributions from each of the sources.
                                   409

-------
 8.4        Impacts on Ambient Air Quality

 8.4.1      Criteria Pollutants  and Total Hydrocarbons

           The modeling results for criteria pollutants and total hydro-
 carbons are summarized  In Table 8-12.  Four of the predicted pollutant
 concentrations do not exceed the NAAQS, those being particulatcs, oxides
 of sulfur, oxides of nitrogen, and carbon monoxide.  The maximum
 ground level concentration of  particulates was 68 yg/m3 as compared to
 the NAAQS  of 260 yg/m3.  These values include only process particulates
which result primarily from the FCC and oil fired heaters, and do not
 include fugitive dust from unpaved roads, construction activities, or
 coke handling.  The point of maximum concentration occurred due west of
 the refinery center at a distance of 1.5 kilometers from the fence line.

           The maximum concentrations of GO  was found to be 233 yg/m3 as
 compared to the NAAQS of 365 yg/m3.  The maximum point was due west of
 the sulfur recovery complex and occurred at one-half kilometer from the
 refinery boundary.

           The maximum 1-hour concentration of CO was predicted to be
 17 yg/in3 as compared to an NAAQS of 10,000 yg/m3.  The maximum point
occurred due west of the refinery center and at a distance of 1.25
kilometers from the boundary line.

          The maximum 24-hour average N02 concentration was estimated to
be 269 jjg/m3.   By applying Larsen statistics as discussed in Appendix D
 (Volume 4), the. predicted annual average N02 concentration at the point of
maximum concentration was estimated to be 55 /Jg/m3.  This figure is well
below the NAAQS value of 100 /Jg/m3 as a maximum annual average.  This pre-
dictive estimate has been based on the assumption that all of the NO  is
                                                                    X
emitted as N02.  Actual N02 concentrations are likely to be significantly
lower than the predicted value.
                                  410

-------
              TABLE 8-12.  SOURCE SEVERITY FACTORS FOR CRITERIA
                           POLLUTANTS
Pollutant
Particulates
S02
CO
NO 2
Nonme thane hydro-
V -i-
max
ug/m3
68
288
16
55
9644
Ftf
yg/m3
260
365
10,000
100
160
s+tt
0.26
0.78
0.0016
0.55
60.3
     carbons*

   X    is the maximum ground level concentration.
    max

  'F is the acceptable pollutant concentration  (which is the NAAQS for
   criteria pollutants).
-!•-;•-j-
   S is the source severity, with the following decision levels.

   if S >_ 1:   Additional Emission Reduction Probably Required

   if 0.1** <. S < 1.0:  May or May Not Require Additional Emission Reduction

   if S < 0.1**:  Additional Emission Reduction Probably Not Required
 * The nonmethanc hydrocarbon standard is a guideline standard based on the
   estimated contributions of hydrocarbons to oxidant formation.

** The lower critical value may need to be as low as 0.01 where large
   uncertainties arc involved.
                                      411

-------
          An analysis of the source severity factors indicates that none
of the criteria pollutants has a high probability of causing a public
hazard (as indicated by S > 1).  On the other hand, only CO has a source
severity factor low enough to have confidence that it does not create a
hazard.  The others are in the area of uncertainty where no clear decision
can be made.

          The total hydrocarbon concentration was found to exceed the
federal guideline for 3-hour maximum (6-9 AM) nonmethane hydrocarbon
concentration of 160 pg/m3, with a maximum concentration of 9644 yg/m3.
The point of maximum concentration was located on the refinery boundary,
due west of the main processing area.  Although the concentrations fell
off rapidly from the maximum, the 160 yg/m3 isopleth extends about 3.5
kilometers downwind and encompasses about four square kilometers, as
shown in Figure 8-3.  The source severity factor for total hydrocarbons
is quite high.  However, the NAAQS guideline for hydrocarbons is based
on the prevention of the formation of photochemical oxidants rather than
on primary toxicity data.  It should be noted that this guideline is
no longer widely accepted or used because the relationship between ozone
formation and ambient hydrocarbon concentrations is not adequately defined.

8.4.2     Selected Hydrocarbon Components

          The ambient concentration of any given hydrocarbon species can
be determined by summing the contribution of the component from all
modeled sources.  The RAM model is capable of performing this analysis
with the assumption that all species will disperse at the same rate; that
is, atmospheric turbulence outweighs any differences in molecular diffusion
between species.

          The first point of interest is the receptor showing the largest
total hydrocarbon concentration.   Table 8-13 shows the component breakdown
at that point.   This maximum point is located directly downwind of the. API
                                    412

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Pollutant:   HC
NAAQS Guidelines:   .160
Aroa in Excess of  NAAQS  Guidelines:  4.05 km2 (1.57 mi2)

                                Figure 8-3.  Hydrocarbon Isopleth
       East
South

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      TABLE 8-13.   HYDROCARBON  SPECIES AMBIENT CONCENTRATION AT THE
                   POINT  OF MAXIMUM TOTAL HYDROCARBON CONCENTRATION
Location:  On the west boundary  line  at a point  1650 meters from the north-
           west corner;  directly downwind of source L49  (an API separator).
         Component
Concentration, yg/m;
Concentration,  ppmv
Benzene
Toluene
Ethylbenzene
Xylenes
Other Alkylbenzenes
          6.6
         21.2
          5.7
         19.8
        102.2
      0.0019
      0.0051
      0.0012
      0.004
      0.017
Naphthalene
Anthracene
Biphenyl
Other Polynuclear Aromatics
         27.5
          3.6
         16.5
         22.7
      0.0047
      0.0005
      0.0025
      0.0030
n-Hexane
Other Alkanes
          2.8
       9380.0
      0.0007
      1.876
Olefins
Cycloalkanes
H2
          0.0
         33.7
          1.8
      0.0
      0.009
      0.020
Total Hydrocarbons
       9644.0 yg/m:
      1.95 ppmv
                                     414

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 separator  (Source L-49), and 97.8 percent of  the hydrocarbon species at
 that point came from the separator.  The bulk of the hydrocarbons are
 from the alkane family  (9380 Pg/m3 or 1.9 ppmv), but both the aromatics
 and polynuclear aromatics species are present at the part per billion
 level  (PPB).

          It is also desirable  to find the point of maximum concentration
 Tor each hazardous component.   A limited search was carried out to find
 these  species maximum points by finding the maximum points for units
 with high concentrations of the subject species.  Resulting maximum
 concentrations are summarized in Table 8-14.

          All of the species maximum concentrations were found at the
 two points having the highest concentration of total hydrocarbons.  Five
 species (including benzene, naphthalene, anthracene, biphenyl, and the
 general polynuclear aromatics family) had maximum concentrations adjacent
 to the API separator.  The maximum concentrations of other species were
 found  at a receptor on the west boundary about 1380 meters from the
 northwest corner.  The largest  contributor to this point was the crude
 distillation unit (L28-1).   Other significant contributing units included
 the two catalytic reformers (L36-1 and 29-1), aromatics extraction (L37-1),
 alkylation (L32-1),  fluid catalytic cracking  (L38-1), delayed coking
 (L40-1), hydrogen plant (L31-1), and resid hydrodesulfurization (L30-1).
 The largest concentration for any single component examined was found to
 be hexane at a concentration of 15 ppbv.

          To assess the impact of a given concentration of a pollutant
 species, quantifiable toxicity data must be available.   The Monsanto
approach uses the term "acceptable pollutant concentration" as the level
at which there is a very low probability of adverse impacts on the general
public.  For criteria pollutants, the Primary Ambient Air Quality
 Standards (PAAQS) were used as the acceptable pollutant concentrations.
                                  415

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         TABLE 8-14.   MAXIMUM AMBIENT CONCENTRATION OF SELECTED HYDROCARBON SPECIES
Ambient Concentration
Component
Benzene
Toluene
Ethylbenzene
Xylenes
Other Alkylbenzenes
Naphthalene
Anthracene
Biphenyl
Other Polynuclear Aromatics
ug/m3
6.6
26.3
10.7
53.6
105.5
27.5
3.6
16.5
22.7
ppmv
0.0019
0.0063
0.0022
0.0092
0.0179
0.0047
0.0005
0.0025
0.0030
Location
On the West Boundary,
XXXX meters from the
Northwest Corner
1650
1380
1380
1380
1380
1650
1650
1650
1650
n-Hexane
 58.5
0.0152
1380
Olefins
 37.6
0.010
1380
Cycloalkanes
365.8
0.099
1380

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For other species, the acceptable concentration can be defined from  the
Threshold Limit Value  (TLV) as  shown below:

                                F = TLV(G)
where
                      G =  (8/24)  (1/100) = 1/300,
so
                               F = TLV/300.

The factor "G" is defined as a conversion factor to express TLV values as
"equivalent PAAQS."  G is defined as 1/300.  This comes from two factors:

          •  The ratio (8/24) converts the TLV from an 8-hour per day
             basis to a 24-hour basis.

          •  The factor (1/100) is a safety factor to account for the
             fact that the general public is more susceptible to illness
             than the industrial work force (for whom the TLV was set).

          Table 8-15 shows a summary of the acceptable pollutant
concentrations that result from this operation.  The values in parentheses
are values arbitrarily assigned to a family of chemicals, some of whose
members have TLV's that average out to the assigned value.  These values
should be used with caution.  Not all of the members of such a family are
equally toxic, nor is it certain that their effects would be additive.
If the source severity factors based on these values are low, then it can
be said with some confidence that no damage will be done by those com-
pounds.  If the values are high,  however, no conclusions can be drawn.
                                   417

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                    TABLE 8-15.  SUMMARY OF "F" VALUES
Pollutant
Benzene
Toluene
Ethylbenzene
Xy.lenes
Other Alkylbenzenes
Naphthalene
Anthracene
Biphenyl
Other Polynuclcar Aromatics
n-Hexane
Other Alkanes
Olefins
Cyloalkanes
F yg/m3
114
1,388
1,586
1,586
(488)**
194
0.66
4.4
(25)
1,281
(16,665)
(12,344)
(.4,937)
Based on
TLV =
TLV =
TLV =
TLV =
TLV =
TLV =
TLV =
TLV =
TLV =
TLV =
TLV =
TLV =
TLV =
10 PPM
100 PPM
100 PPM
100 PPM
(25 PPM)
10 PPM
200 yg/m3*
0.2 PPM
(1 PPM)
100 PPM
(1,000 PPM)
(1,000 PPM)
(400 PPM)
* Based on "Coal Tar Pitch Volatiles" which anthracene is a major component.
" TLV values arbitrarily assigned to a family of chemicals.
                                    418

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          The whole process of basing an acceptable pollutant concentration
on TLV's should be critically appraised.  These values were set for use
in industrial hygiene studies within plant boundaries, and the American
Conference of Governmental Industrial Hygienists  (ACGIH) specifically
warns against their use:

          •  as a relative index of hazard or toxicity,

          •  in the evaluation of community air pollution, or

          *  in estimating the toxic potential of continuous,
             uninterrupted exposure.

While such usage is discouraged, the fact remains that no other source of
quantifiable toxicity levels is available.  Therefore, the use of TLV's
to estimate acceptable pollutant concentrations is used here in accordance
with the source severity methodology.  It is felt that this comparison,
however tenuous it might be, is better than ignoring the problem.  This is
especially true as long as the proper qualifications and limitations on
the results are explicitly stated.

          Taking the maximum ambient concentrations presented in Table 8-14
and the acceptable pollutant concentrations shown in Table 8-15, it is
straightforward to calculate source severity factors for each component.
These factors are shown in Table 8-16.

          Using Monsanto1s recommended decision levels, it can be said that
there is a significant probability that anthracene and biphenyl need
further application of control technology.  Several things should be noted
in the context:

          •  The high concentrations of these species were contributed
             by a covered API separator.
                                  419

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              TABLE 8-16.  SOURCE SEVERITY FACTORS FOR  SELECTED
                           HYDROCARBON SPECIES
Component
Benzene
Toluene
Ethylbenzene
Xylenes
Other Alkylbenzenes
Naphthalene
Anthracene
Blphenyl
Other Polynuclear Aromatics
X
max
yg/ma
6.6
26.3
10.7
53.6
105.5
27.5
3.6
16.5
22.7
F
Vg/m3
114
1388
1586
1586
(488)*
194
(0.66)
4.4
(25)
S
0.06
0.02
0.007
0.03
(0.22)
0.14
(5.5)
3.8
(0.9)
n-Hexane
 58.5
  1281
 0.05
Olefins
 37.6
(12344)
(0.003)
Cycloalkanes
365.8
 (4937)
(0.07)
^Values in parentheses are an average of the F values for several selected
 members of the family group, and are not true F values for the entire
 family.
                                    420

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          •  That separator was located right on the plant boundary
             line, which is quite unusual.

          •  There is a great deal of uncertainty in the emission  factor
             for separators.  No conclusive results were obtained  from
             limited testing of separators on this program, so AP-427
             factors were used in this analysis.  The EPA has since
             begun a program to improve these factors.

          •  The emissions from an API separator are highly variable in
             component breakdown (much more so than process unit emissions),
             and the species breakdown for that unit is based on several
             grab samples which may well not be reflective of "typical"
             operation.

          •  These component emissions (calculated by an oil-phase volatile
             hydrocarbon balance) may be overstated due to solubility
             effects.

          It can also be stated that there is a very low probability of
the need for further control of ethylbenzene and the olefin family.  All
other species fall into the range where no clear decision can be made.
The uncertainties involved in the calculation of these source severity
factors make it impossible to make clean cut decisions for the range
from. 0.01 to 0.99.

          It should also be noted here that all of the quoted hydrocarbon
species maximum points occurred on the refinery boundary.   Because they are
released close to the ground and with little velocity or thermal buoyancy,
the vapors tend to stay at ground level.   Dispersion does proceed at a
relatively rapid pace when moving downwind.  This establishes two inter-
esting points:
                                    421

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          •  The sphere of influence for hydrocarbon species that were
             noted as potential problems at the boundary line does not
             extend more than a few hundred -meters.

          •  This further suggests that buffering areas with a high
             potential for fugitive emissions could be effective in
             reducing or eliminating high source severities.

8.4.3     Discussion of Re suits

          The sensitivity of the source severity values to a number of
variables was estimated.  The most significant variables include refinery
processing configuration, refinery layout, calculated emissions, type of
atmospheric dispersion model, meteorological conditions, hydrocarbon
component breakdown, and toxicity values.

          Several of these variables can be considered in a group.   A
change in the calculated emission rates will produce a proportional change
in the predicted maximum concentrations.  These emissions will vary with
a change in refinery processing configuration, emission factors, or fitting
count.

          Another point of uncertainty is the potential contribution of
storage emissions to the impacts predicted for the refinery process area.
Total storage tank emissions were estimated to contribute about 27  percent
of all nonmethane hydrocarbon emissions.  Since no layout information
within the module was available, each storage module was treated as an
area source.   The specific emission rates (lb/hr/ft2) were calculated for
each module and compared to the API separator and the process area  which
contributed to the two highest points of nonmethane hydrocarbon concentra-
tion.  The following conclusions can be drawn:
                                   422

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          •  The worst storage tank module  (L-22) had a specific emission
             rate of 85.4 lb/hr/106 ft2.  This figure is much lower  than
             either the covered API separator  (L-49) with 1169 lb/hr/106 ft2
             or the worst process area  (near L-28) with 320 lb/hr/106 ft2.

          •  Since all of these sources are directly adjacent to the west
             boundary line, the predicted impacts should be roughly
             proportional to the specific emission rates.  This is
             actually somewhat conservative, since the height of release
             of the storage tank emissions would be considerably higher
             than for a separator or for process fugitives.  Therefore,
             it can be concluded that the specific impact of the worst
             storage module would be significantly less severe than  the
             two worst points cited in this assessment.

          •  By examining the relative contributions of adjacent process
             sources to the predicted maximum and applying similar ratios
             to adjacent storage modules, it was determined that the      :
             inclusion of storage emissions in the modeling would not
             have, significantly increased the  estimated maximum concentra-
             tion.  It would, however, have greatly increased the area of
             impact in which relatively high concentrations of nonraethane
             hydrocarbons would occur.

          The refinery layout may be even more critical than the complexity
and the resulting overall  emission rate, especially for the predicted
hydrocarbon species.  Fugitive emissions are released near ground level,
and, thus, are subject to much less dispersion than stack emissions.  A
refinery layout with process units right on the boundary line (such as the
model used here) will show much higher hydrocarbon concentrations outside
the refinery boundaries than one with a buffer zone around the processing
area.
                                    423

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          The choice of dispersion model type could affect the predicted
pollutant concentrations significantly.  None of the available models is
perfect, and predicted maximum concentrations may vary from half to
ten times (or more) the actual concentrations measured from a source.  The
use of the rural version of RAM to model a refinery is a conservative
choice since the heat island effect of a refinery will tend to increase
atmospheric diffusion.

          The predicted impacts will vary with meteorological conditions
as illustrated by sensitivity runs on the model.  A 22 percent decrease
in wind speed resulted in a 28 percent increase in predicted maximum
ground level concentrations for total hydrocarbons.  Use of the more
stable atmospheric stability class D resulted in 3 percent higher predicted
concentrations.

          The hydrocarbon component breakdown is quite critical.  Individual
component source severity factors will vary in direct proportion with the
predicted concentration of that component in the emitting source.  There
are fairly wide confidence intervals that should be applied to those
component breakdowns.   Component concentrations will vary from day to
day with changes in such things as feedstocks and operating conditions.
This effect is amplified by several orders of magnitude when discussing
API separator emissions.  The small number of samples on which the
component analyses are based is insufficient to confidently average out
such process variations.

          There is a shortage of quantifiable toxicity data for the many
organic compounds present in refinery processing.   This makes it
difficult to prepare a comprehensive environmental assessment.  The
accuracy of existing toxicity data is also questionable,  and this effect
is compounded by the transformation from TLV to an "acceptable pollutant
concentration."   Dividing the TLV by three to account for the difference
between eight hours per day and continuous exposure assumes that the
                                    424

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toxic effects are cumulative.  For some compounds that is certainly
true, but others require some critical concentration to be harmful and
are easily assimilated by the body below that concentration.  The safety
factor of one hundred used to account for the greater susceptibility
of the general public is obviously arbitrary and therefore questionable.
Any of these changes in the acceptable pollutant concentration will
produce an inversely proportional change in the calculated source severity.

          Recognizing the high degree of uncertainty in the results, the
following conclusions can be drawn:

          •  There is no certainty of public hazard resulting from the
             emissions of this hypothetical refinery.

          •  Conversely, there is no certainty that it does not create
             a hazard.

          •  If any hazard exists due to hydrocarbon species, the most
             likely species to cause problems would be the polynuclear
             aromatics.

          •  This approach to an environmental assessment of a generalized
             source is of limited value in providing specific information
             on whether  steps need to be taken to further reduce emissions
             of a given  pollutant.

          •  The results can be useful in indicating the relative impacts
             of various  emission sources and species.  For instance, API
             separators  appear to pose more of a potential hazard than
             fluid catalytic crackers; polynuclear aromatics emissions
             appear to be more troublesome than benzene.   Such relative
             ranking of  emission sources and species can be useful in
             directing emphasis towards potential  problem areas.
                                   425

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          •   If  this approach were  used  to assess  the  impact  of  a
              specific plant, it might yield more useful results.   The
              range  of uncertainty would  be much narrower because the input
              factors could be more  firmly defined.

 8.5       Effects of Existing and Potential Regulations and Policies

          This section contains an  examination of  the  effects of environ-
 mental regulations  and permit policies on the emissions from petroleum
 refining.  The first two subsections deal with state and federal regula-
 tions, respectively.  The final section  addresses  the  effects of potential
 new regulations.

 8.5.1     State Regulations

          Existing  refineries are regulated by the states, rather  than
 by federal standards.  Standards for the South Coast and Bay Area
 regions of California are considered here with the state regulations.
 Though some state regulations were  amended as late as  1979, most were
 adopted in the early 1970's.

          There is  disparity among  the regulations in  some categories;
 the general trends which could be discerned are presented here along
with notable exceptions.  No attempt is made to describe the regulations
 of the individual states per ^e.

          All states are included even if they presently have no refineries,
 This should not be  interpreted, however,  to mean that  all. states have
 specific regulations for all the pollutant categories  included here.  Some
 states have regulations only for specific existing facilities; others have
no regulations except those supporting federal standards.
                                   426

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          jParticulate and Visible Emissions—Most states have specific
standards for the maximum opacity and darkness of emissions.  The
strictest standard, and by far the most common, calls for a maximum
opacity of 20 percent and a maximum darkness of No. 1 on the Ringlemann
Chart.  In some states these stricter standards apply only to new sources,
while existing sources are allowed an opacity of 40 percent and a darkness
of No. 2 Ringlemann.  In other states these more lenient standards
apply to new and existing sources.  One state allows 40 percent opacity
for new sources and 60 percent for existing sources.

          Some state standards specify either opacity or darkness, but
not both.   Exception to the above standards is sometimes allowed for the
flue gases from catalytic cracking catalyst regeneration and fluid
coking:  these gases may be allowed 25 to 40 percent opacity where other
gases are limited to 20 percent.   In all states with visibility standards,
provision is made for varying amounts of upset time.

          Participates are generally regulated by source.  For process
emissions in general, many state regulations incorporate a chart with
pounds per hour allowable emissions versus tons per hour process weight,
with all stacks being considered collectively.

          Again, catalytic cracking catalyst regeneration is sometimes
considered separately,  although no exact comparison of the various
regulations can be made because of widely varying formats.  A one pound
per ton of coke burn-off regulation found in two states appears to be
the most stringent.   When a CO boiler is installed on the regenerator,
an allowance is usually made for the added emissions from fuel-burning.

          Particulate emissions from fuel-burning are also often considered
separately.   The stipulation is generally made that all  fuel-burning at
the facility is considered collectively.   Regulations range from 0.1 to
2.5 pounds of particulates per million Btu of heat input; many of the
                                  427

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regulations stipulate a maximum of 0.6 lb/106 Btu or less.  Some
regulations have varying maximums for different size units.  One state
regulation specifies that afterburners must be used.

          Sulfur Emissions — Several states limit S02 emissions from any
source in a refinery to 500 ppmv; a common maximum is 2000 ppmv.  One
state limits total S02 emissions from the refinery to 10 percent of the
sulfur in the crude; another limits total S02 emissions to 0.3 pounds per
barrel of oil processed.  Many states, however, consider separately the
sulfur emissions from fuel burning and sulfur recovery.  One state limits
emissions of mercaptans specifically to 0.25 pounds per hour.

          Most regulations for S02 emissions from fuel burning are of
two types.  Some states limit the sulfur content of the fuel burned
while others specify a maximum amount of S02 that may be emitted per
million Btu of heat input.  When the sulfur content of the fuel is limited,
allowance is usually made for equivalent alternate means of SO^ emission
control.

          Where the sulfur content of the fuel is limited, state
regulations stipulate maximums of up to 2.5 weight percent sulfur.
Most maximums are 1.0 weight percent sulfur or less.  Sulfur content
of gaseous fuels (often specifically fuel gas) is expressed in grains of
H2S per dry standard cubic fool (gr/dscf ) .   In this case the common
maximum is 0.1 gr/dscf.
          Allowable SOp emissions from sulfur recovery units are some-
times expressed in pounds of 862 per pound of sulfur processed.  These
allowances range from 0.004 to 0.12 lb S02/lb S.  Several state
regulations contain a chart of allowable emissions versus sulfur
input.  One state allows up to 1000 pounds of SO? per hour.  Limits of
500 to 2000 ppmv S02 are in some instances set specifically for sulfur
recovery units.
                                  428

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          Hydrogen sulfide emissions from sulfur recovery units are
addressed by a few states.  One state allows 0.3 pounds of H?S per hour.
One state allows 0.1 ppm I^S and two others allow 10 ppra
          NO  Emissions — State regulations for the control of NO  emissions
from fuel burning arc quite consistent.  These regulations, which normally
apply only to units larger than 250 million Btu, allow gas-fueled units
to emit 0.20 pounds per million Btu and liquid-fueled units to emit 0.3
pounds per million Btu.  Solid-fueled units are allowed 0.7 pounds per
million Btu.  When different fuels are burned simultaneously, the
applicable regulation is determined by proration.

          Carbon Monoxide Emissions — One state limits carbon monoxide
to 200 ppmv in fuel-burning units larger than 107 Btu.  All other CO
regulations are for catalytic cracking catalyst regeneration and for
fluid coking.   Some states limit CO emissions from these sources to
500 ppmv; in some instances this limit applies only to new sources.  One
state allows existing sources to emit 20,000 ppmv CO; another allows the
emission of 5  tons of CO per year.

          The  control method for CO emissions from catalyst regeneration
and fluid coking is expressed specifically in several regulations as
combustion at  1300°F for 0.3 second in a direct flame afterburner or
boiler with an indicating pyrometer located at eye level.  Some, but
not all, states with this stipulation allow the use of equivalent control
measures.  One state allows alternative control methods which remove at
least 93 percent of the GO in the exiting gas.

          Hydrocarbon Mmis sions — Some regulations stipulate, that
oil-water separators must be pressurized, have floating or double-deck
roofs,  have vapor recovery, or have an equivalent vapor control method.
One state regulation specified 85 percent control for wastewater
separators,  another 95 percent.
                                    429

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          Most  standards  for pumps  and  compressors  state  simply  that  these
must be equipped with mechanical  seals  or an equivalent control.  Several
states specify  mechanical seals for rotating pumps  and compressors and
packing glands  for reciprocating.   Two  states  limit emissions  from each
pump and compressor to 2  cubic inches of liquid per 15 minutes;  one limits
leakage to 3 drops per minute.

          A number of states specify that hydrocarbon waste from the  vapor
blowdown system be smokelessly flared or disposed of in an equivalent
manner.  One state specifies that these emissions be controlled  if they
are more than 10 percent  equivalent methane; another state sets  a limit
of 50 pounds per day.

          Hydrocarbon emissions from catalytic crackers and fluid cokers
are required by several states to be incinerated in a direct flame after-
burner or boiler.  One state allows 100 ppra equivalent methane or 8 pounds
of hydrocarbons per hour  before controls must be applied; another state
allows 5 tons of hydrocarbons per year.

          Other sources of hydrocarbon emissions are mentioned infrequently
in state regulations.  Several regulations specify that hydrocarbon
emissions from  condensers, hot wells and accumulators be  incinerated,
compressed, or  equivalently controlled.  One standard allows no  hydro-
carbon emissions from fuel burning; another specifies 95  percent control
of hydrocarbons from vacuum systems and from process unit turnarounds.
One regulation  states that relief valves in pipes over one inch  in
diameter must be vented to vapor recovery or disposal, be protected by a
rupture disc, or be maintained by an approved inspection  system.  In one
regulation, emissions from air blowing must be incinerated at 1400°F for
0.3 second or equivalently controlled.

          Effects of State Regulations  on the Environmental Impacts of
Refineries—It  is difficult to assess the effects of state regulations
                                    430

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because of this great variety.  There is no doubt  that significant
emission reductions have been achieved over the last ten to fifteen
years by virtue of these regulations.  The model refinery used in this
environmental assessment, however, already reflects the control technology
required by the consensus of regulations for existing sources.  Some
reduction of the impacts could be expected if the  refinery was located
in one of the stricter states.

8.5.2     Federal Regulations and Policies

          Federal regulations apply primarily to new or modified sources.
These take the form of New Source Performance Standards (NSPS) and New
Source Reviews required for permitting.

          New Source Performance Standards—NSPS specific to refineries are
contained in 40 CFR Part 60, Subpart J.  These standards apply to fluid
catalytic cracking unit regenerators, fluid cokers, sulfur recovery units,
and fuel sulfur levels.  Subpart D contains standards for fossil-fuel fired
steam generators with a heat input greater than 250 million Btu.
Subpart K includes standards for storage vessels containing petroleum
liquids, but these are outside the scope of this study.

          Particulate and Visible Emissions—Federal standards state that
gases from fossil-fuel fired steam generators may not exhibit more than
20 percent opacity except for one 20-Tninute period per hour of not more
than 27 percent opacity.   These gases also may not contain more than 0.1
pound of particulate matter per million Btu of heat input from the
fossil-fuel.

          Gases from fluid catalytic cracking catalyst regeneration may
not exhibit more than 30 percent opacity, except for one six-minute
average reading per hour.  These gases also may not contain more than
1.0 pound of particulate matter per 1000 pounds of coke burn off.
                                    431

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           If the gases from the regenerator pass through an incinerator
 or waste heat boiler in which auxiliary or supplemental liquid or solid
 fuel is burned,  excess particulatc emissions may be allowed.  These
 excess emissions may be 0.1 pound or less per million Btu of heat input
 attributable to  the added fuel.

           Sulfur Emissions—When liquid fuels are used for steam generation,
 sulfur dioxide emissions must be no more than 0.8 pounds per million Btu
 of heat input.   Any fuel gas which is burned in a combustion device must
 contain no more  than 0.10 grain of l^S per dry standard cubic foot or the
 sulfur dioxide emissions from the combustion device must be controlled
 in an equivalent manner.   Flares for the combustion of process upset
 gas or fuel gas  from relief valve, leakage are exempt from this standard.
 Sulfur dioxide emissions from Claus plants must be limited to 0.025
 percent (250 ppm)  by volume on a dry basis at zero percent oxygen if
 emissions are controlled by an oxidation system (one which converts
 emissions to hydrogen sulfide) followed by incineration.  If emissions
 are controlled by a reduction system not followed by incineration,
 emissions from the unit may be 0.030 percent (300 ppm) reduced sulfur
 compounds and 0.0010 percent (10 ppm) hydrogen sulfide calculated
 as sulfur dioxide at zero percent oxygen on a dry basis.  Reduced sulfur
 compounds include hydrogen sulfide, carbonyl sulfide,  and carbon disulfide.

           Carbon Monoxide Emissions—The standards for carbon monoxide
 states simply that no gases which contain more than 0.050 percent by volume
 (500 ppmv)  carbon monoxide may be discharged to the atmosphere from a
 fluid catalytic  cracking catalyst regenerator.
!*••'
           NO  Emissions—Allowable NO  emissions from fossil-fueled steam
          	x	              x
 generators  vary  with the type of fuel used.   When gaseous fuel is used,
 emissions are limited to 0.2 pounds per million Btu of heat input.   For
 liquid fuels the limit is 0.3 lb/106 Btu and for solid fuels 0.7 lb/106  Btu.
                                      432

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When different fuels are burned simultaneously, the applicable standard  is
determined by proration.

          New Source Review—The 1977 Amendments to the Clean Air Act
emphasize the control of atmospheric pollutants from new or modified
facilities by establishing a New Source Review  (NSR) process.  This is
essentially a federal permit to construct any major emission source.  The
review process can take one of two paths depending on whether or not the
source is to be built in an area in attainment of the National Ambient
Air Quality Standards GMAAQS).  If so, the Prevention of Significant
Deterioration (PSD) regulations apply.  If not, then nonattainment
regulations apply.  Frequently both paths must be followed, since attain-
ment is judged on a pollutant-by-pollutant basis.

          prevention of Significant Deterioratiori—The PSD review process
is a multilevel examination of the emission levels and air impacts of the
new source.   The overall process can best be illustrated by the flowchart
shown in Figure 8-4.  It would not be pertinent here to examine in detail
the many applicability criteria which determine the level of review
required.  Suffice it to say that if a new or modified refinery (which
is one of the 28 major industry categories) has the potential to emit
more than 100 tons per year of any given atmospheric pollutant, and that
represents a net increase in emissions since 8/7/77, the new or modified
section must demonstrate the use of Best Available Control Technology (BACT)

          BACT is defined as the level of emission control which gives the
lowest emissions while taking into consideration the cost of control,
energy efficiency, and technical feasibility.  BACT must, therefore, be
determined on a case-by-case basis to evaluate these effects.  When an
NSPS is available, this usually forms the minimum criteria for BACT.  When
no NSPS exists,  then all possible methods of emission reduction must be
catalogued.   When one of these methods has been proposed as BACT for the
                                     433

-------
  WES D*Mnnln«liflri
                                    Modified Stationary Sources in PSD Areas
                                     According to Alabama Power Decision
                                 Modfilcntioji
                                                                                                  56 Ion E*empi ois
AHHKCVI&flOISi CODE



IU£! - M
olvfl-v
         Pifb
-------
new source, all methods giving lower emissions must be shown to be
inappropriate in terms of cost, energy impact, or technical feasibility.

          Nonattainment Requirements—The requirements for permitting a
source which will emit significant levels of a pollutant for which the
area Is not in attainment of the NAAQS are quite stringent.  First, the
source must use the Lowest Achievable Emission Rate (LAER).  It must then
offset the resulting emissions by reducing emissions from another source
in the area by a more than equivalent amount.  There are additional
requirements relating to the other sources owned by the applicant and to
assuring a net positive air quality improvement, but these are not
pertinent to this discussion.

          LAER is defined as the strictest control technology required
for this type of source by any State Implementation Plan (SIP), or the
lowest emissions achieved by any operating source of the same type,
whichever is more stringent unless the owner or operator of the proposed
source demonstrates that such limitations are not achievable.  This does
not take cost or any other side effects into account.   It also recognizes
the transfer of control technology from one type of source to another, if
technically feasible.

          The resulting emissions after LAER must be offset on a
pollutant-by-pollutant basis by reducing emissions from other sources in
the area.   For nonreactive pollutants the offset must be from another
source in the immediate vicinity.  For NO  and hydrocarbons, however,
offsets can be obtained over a broader area.   The offsetting emission
reduction must be greater than the emissions from the new source, thus
causing a net positive air quality improvement.

          Effects of New Source Reviews on the Environmental Impacts of
Refineries—The effects of the New Source Review process on the environ-
mental impacts of refineries should be significant.   Any new refinery
                                    435

-------
permitted under this system should have much lower emissions than existing
refineries.  This would be particularly true in the area of hydrocarbon
emissions, but it would also occur for NO  and SC^.

          The NSR process will also discourage expansion in nonattainment
areas, where the combined impacts of a heavily industrialized area have
already caused a deterioration in air quality.  If an expansion were to
be made in such an area, it could only be done by achieving a greater
than equivalent offset.  Thus, the impetus to build new facilities can
provide the impetus to clean up older facilities.  The net effect of
these policies should be an improvement in existing air quality.

8.5.3     Potential Regulations and Policies

          There are many standards and regulations currently under
consideration that would have a significant impact on refinery emissions.
It would be quite difficult to document all of these since many have not
even been published as proposals at this time.  Several examples will be
discussed in this section to illustrate regulatory trends.  Caution should
be used in interpreting or applying these regulations since they are only
proposed at this point, and they may be significantly -modified before
being adopted.

          State Regulations — Only the new and developing standards for
the Bay Area (San Francisco) and the South Coast (Los Angeles) regions of
California are summarized here.  Other regulatory agencies may be similarly
updating their standards.  Most of these new and proposed standards are
concerned with the emission of hydrocarbons from refineries.

          Two levels of control for SO  emissions from catalytic cracker
                                      X                     "
catalyst regeneration are being considered by the South Coast Region, one
of which is expected to become a standard by .1982.   One proposed standard
                                     436

-------
 calls  for replacement of  the conventional catalyst with a newly developed
 catalyst which can reduce SO  emissions by 80 percent without additional
 controls; the other proposed the addition of alkaline scrubbers for  90
 percent control of SO .   The South  Coast Region  also proposes that the
 allowable sulfur content  of fuels be  halved by 1982.

          Many of the proposed standards for the Bay Area and South  Coast
 Regions are concerned with fugitive emissions, an area not emphasized by
 present standards.  The South Coast Region proposes that by 1980, leak
 rates, maintenance schedules, etc.  for random hydrocarbon emissions  be
 established.  Pumps and compressors within 3 miles of the control center
 would be inspected every  eight hours, all others every 24 hours.

          The South Coast Region also proposes that natural, gas-fired
 control devices such as afterburners must have a stand-by fuel system for
 use during natural gas curtailment.   By 1980, all relief valves would be
 vented to vapor recovery or disposal.  By 1982, combustion modification
 and/or ammonia injection for control of NO  would be required on heaters
 and boilers.

          A Bay Area Region standard which went into effect in December 1979,
 limits valve leakage to 10,000 ppm VOC measured one centimeter from  the
 leak.  It is proposed that this standard be applied also to flanges.

          By March 1980, emissions  from condensers or vacuum-producing
 systems must be incinerated,  compressed and added to fuel gas, or controlled
 equivalently.   It is proposed that emissions from steam ejectors be
 similarly controlled.

          Also by March 1980,  hot wells and/or accumulators associated
with contact (barometric) condensers must be covered and the organic vapors
 either incinerated or contained and  treated.   It is proposed that this stan-
dard apply to  the hot  wells and/or accumulators associated with all condensers.
                                    437

-------
          Emissions from process vessel depressurizing must, by 1980, be
passed through a knockout pot to remove condensable hydrocarbons, then
incinerated, flared, or compressed and added to the fuel gas.  It is
proposed that emissions from process vessel purging be similarly controlled.

          Another Bay Area Region standard effective March 1980, is similar
to those in several other states:  oil/water separators must have a
solid cover, a floating pontoon or double-deck cover, 90 percent effective
vapor recovery, or other approved control equipment.

          Federal Standards—Petroleum refineries are among those
industries for which New Source Performance Standards (NSPS) will be
formulated or updated in the near future.   It is expected that within
2-3 years additional standards will be added to Subpart J of 40 CFR
Part 60 and parts of the existing Subpart J may be revised.  Additional
standards may concern such emissions as SO  from catalytic cracking
                                          A
catalyst regeneration and fugitive emissions.

          Effects of Potential Regulations and Policies on the Environmental
Impacts of Refineries—These proposed regulations will tend to bring more
uniformity to the determination of BACT.   They do not generally increase
the stringency of measures already required through the New Source Review
process.   If other states follow California lead in upgrading their
SIP's, however, the allowable emissions from existing refineries could be
greatly reduced,  with a corresponding reduction in the environmental
impacts of those  refineries.   Such stringency in state regulations may
or may not be warranted, depending on the magnitude of any air quality
problems in the specific state.
                                    438

-------
8.6       Effects of New and Developing Technology

          Although petroleum refining is considered a mature technology
area, it is constantly undergoing a process of improvements.  The
environmental impacts of refineries will be reduced in the future through
new developments in both process technology and emission control technology.

8.6.1     Process Technology

          Process technology in petroleum refining has continually evolved
to meet the demands of the end-use sector.  Some of the current evolutionary
trends in refining include the shift to produce lead-free gasoline,
increased use of hydrodesulfurization to achieve lower fuel sulfur
contents, and a push for greater energy efficiency.  Some of these trends
will tend to aggravate emissions while others will reduce them.

          The production of lead-free gasoline requires significantly
more processing in units like catalytic reformers, alkylation units, and
isoincrization units.  While the units are not major emitters, they do
contribute to fugitive emissions and emissions from combustion sources.
Since there is a decrease in gasoline range yields with this type of
processing, more crude must be charged to maintain the same gasoline
production.  This will cause slight increases in emissions across the
board.   Much of this effect is now behind us, but a phase-down of gaso.l Ine
pool lead content will cause continued emissions increases.

          Sulfur levels in many fuels are being regulated downward.  This
will require an increased use of hydrodesulfurization to achieve these low
sulfur levels, which will, in turn, increase the load on Glaus plants and
tail gas treating units.   The hydrogen demand will also begin to exceed
that provided by catalytic reforming, and thus require construction of
hydrogen plants.  Both of these effects will tend to cause an Increase in
refinery emissions unless countered by more effective control technology.
                                   439

-------
          The trend toward greater use of energy conservation will tend
to reduce the emissions from combustion sources.  The recovery of process
heat and the use of intrinsically more efficient processes will reduce the
heat required from process heaters and steam boilers.  Since the emissions
from combustion equipment are proportional to the fuel burning rate, this
should result in an emission reduction.


8.6,2     Emission Control Technology

          New and improved emission control technology will continue to
appear in petroleum refining.  Significant reductions may be achieved by
application of technology, such as covers for API separators, scrubbers
for flue gas from fluid catalytic cracking, and combustion modifications
to reduce NO .   These effects could be complemented by progress on
developing technologies like the fluid cracking catalyst which adsorbs
SO,  from the regenerator.
  X

          One area with great potential for improved technology is in
fugitive emission control.  The manufacturers of seals, packing, and
gaskets for process equipment  have designed their products to meet the
users needs.  Up until now, those needs have been to limit product loss
and maintain safe operation.  No one was aware or concerned about "low
level" fugitive vapor leaks which could not be detected visibly.  Fugitive
emission regulations will provide the incentive to develop more effective
seals, packing, etc., and will result In lower emissions and lower costs
for monitoring and maintenance programs.
                                    440

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1.  Los Angeles County Air Pollution Control District.  Joint  District,
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-------
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                                    444

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36. Dooley, J. E., et al.  Analyzing Heavy Ends of Crude.  Hydrocarbon Proc.,
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                                    445

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                                   446

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                                   448

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    100 h.p. pumps with 1.875  - 2.375 inch diameter shafts.

85. American Petroleum Institute,  Refining Dept.  Centrifugal Pumps for General
    Refining Services,  5th Edition.   API  Standard 610.  Washington,  D.G.,
    March 1971.
                                   449

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86. Voden, James, Allen-Bradley Co., Houston, Texas.  Private  Communication
    with W. R. Phillips, Radian Corporation, Austin, Texas, May 15,  1980.
    Regarding electric switchgear for pump motors.

87. Adams, C. S., Gulf Coast Packing and Seal Co., Inc., Houston, Texas.
    Private communication with W. R. Phillips, Radian Corporation, Austin,
    Texas, May 1980.  Regarding A. W. Chesterton pump seals and packings.

88. Fadner, D. U., Crane Packing Co., Houston, Texas.  Private communication
    with W. R. Phillips, Radian Corporation, Austin, Texas, May 1980.
    Regarding costs and applications of John Crane mechanical  seals.

89. Center for Professional Advancement.  Mechanical Seal Technology for the
    Process Industries.  East Brunswick, New Jersey, March 1978.

90. Hoyle, R.   How to Select and Use Mechanical  Packing.  Chem. Eng., 85(22):
    103, 1978.

91. Ramsden,  J.  H.  How to Choose, and install Mechanical Seals.  Chem. Eng.,
    85(22):102,  1978.

92. Potter, Charles,  Crane-Doming Pump Co., Houston, Texas.  Telephone
    conversation with W.  R. Phillips, Radian Corporation, Austin, Texas,
    September 27, 1979.

93. American Petroleum Institute,  Refining Dept.  Centrifugal Compressors for
    General Refinery Service, 3rd   Edition.   API  Standard 617.   Washington,
    B.C.,  October, 1973.

94. American Petroleum Institute,  Refining Dcpt.   Reciprocating Compressors
    for General  Refinery  Service,  2nd Edition.   APT Standard 6.1.8.  Washington,
    D.C.,  July 1974.
                                   450

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  95.  Nelson, W.  E.  Compressor  Seal Fundamentals.  Hydrocarbon  Processing,
      56(12):91,  1977.

  96.  Ramsey, W.  D. and G. C. Zoller.  How  the Design of  Shafts,  Seals and
      Tmpellors Affects Agitator Performance.  Che.m. Eng. ,  83(18):101, 1976.

  97.  Kayser, D.  S.  Rupture Disk Selection.  CEP,  68(5):61, 1972.

  98.  Isaacs, M.  Pressure Relief Systems.  Chera. Eng., 78(5):113, 1971.

  99.  Britton, Stephen, Groth Equipment Corporation, Houston, Texas.  Private
      communication with W. R. Phillips, Radian Corporation, Austin, Texas,
      May 19, 1980.

100.  Beychok, Milton R.  Wastewatcr Treatment.  Hydrocarbon Processing,
      50(12):110, 1971.

101.  Environmental Protection Agency, Effluent Guidelines Division.  Development
      Document for Effluent Limitations Guidelines and New Source Performance
      Standards for the Petroleum Refining Point Source. Category, final report.
      EPA 440/l-74-01.4a, PP. 238 612.  Washington, D.C.,  April 1974.

102. Azad, H. S., ed.   Industrial Wastewater Management Handbook.  McGraw-Hill,
     New York,  1976.

103. Jones, H.  R.  Pollution Control in the Petroleum Industry.   Pollution
     Technology Review No. 4.   Noyes Data Corporation,  Park R:idge, New Jersey,
     1973.

104. Hustvedt,  K. C.  and R.  A.  Quaney.   Control of Refinery Vacuum Producing
     Systems, Wastewater Separators and Process Unit  Turnarounds.  EPA 450/2-
     77-025, OAQPS No.  1.2-081,  Environmental Protection Agency, Office of Air
     Quality Planning  and Standards, Office of Air and  Waste Management,
     Research Triangle Park,  North Carolina,  October  1977.
                                    451

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105. Shaffer, N. R. and C. J. Seymour.  Emissions of Hydrocarbons  from
     Refineries in Los Angeles County.  Los Angeles County Air Pollution
     Control District, Los Angeles, California, April 1957.

106. Litchfie.ld, D. K.  Controlling Odors and Vapors from APT Separators.
     Oil and Gas Journal, 69(44):60-62, November 1971.

107. Air Pollution Control Association, ed.  Emission Factors and  Inventories,
     Anaheim, California, November 1978.  In:  Proceedings of the  Specialty
     Conference, Pittsburgh, Pennsylvania, 1978.

108. M & S Equipment Cost Index.  Chem. Eng., 87(9):7, May 5, 1980.

109. Pojacek, R. R.  Solid Waste Disposal-Solidification.  Chem. Eng., 86(17):
     141-145, 1979.

110. Elkin, H. F., and R. A. Constable.  Source/Control of Air Emissions.
     Hydrocarbon Proe., 51(10):113, 1972.

111. Beavon, D.  K., and R. P. Vaell.  The Beavon Sulfur Removal Process for
     Purifying Claus Plant Tail Gas.  API, Division of Refining, 267, 1972.

1.1.2. Bryant, H.  S.  Environmental Needs Guide to Refinery Sulfur Recovery.
     Oil and Gas J. , 71(13):70-76,  1973.

113. Valdcz, A.  R.  New Look at Sulfur Plants.   Hydrocarbon Proc., Petrol.
     Refining, 43(3):104-108, 1964.

114. Laengrich,  A. R., and W. L.  Cameron.  Tail-Gas Cleaning Addition May
     Solve Sulfur-Plant Compliance  Problem.   Oil and Gas J., 76(13):159-162,
     1978.

115. Hydroprocessing is Lively Topic.   Oil and  Gas J.,  75(28):153, 1977.
                                     452

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116. Conser, R. E.  Here's a New Way to Clean Process Gases.  Oil and Gas J.,
     72(13):67-68, 70, 1974.

117. Vasolos, i. A., et al.  New Cracking Process Controls 1'CCU  SOX.  Oil and
     Gas J., 75 (26):141-148, 1977.

118. Hulroan, P. B., and J. M. Burke.  The Lime/Limestone Flue Gas Desulfuriza-
     tion Processes.  DCN 78-200-187-03-17s.  Radian Corporation, Austin,
     Texas, 1978.

.119. Gibson, E. D., T. G. Sipes, and J. G. Lacy.  The Dual Alkali Flue Gas
     Desulfurization Process.  DCN 78-200-187-03-19, Radian Corporation,
     Austin, Texas, 1978.

120. Radian Corporation.  Control Technologies for Volatile Organic Emissions
     from Stationary Sources.  DCN 77-200-187-23-08.  Austin, Texas, 1978.

121. Laster, L. L.  Atmospheric Emissions from the Petroleum Refining Industry.
     EPA 650/2-73-017, PB 225 040, Control Systems Lab., Research Triangle
     Park, North Carolina, 1973.

122. Atmospheric Emissions from Petroleum Refineries.  A Guide for Measurement
     and Control.   PHS No. 763, Public Health Service, 1960.

123. Stover, R.  D.  Control of Carbon Monoxide Emissions from FCC Units by
     Ultrar.at Regeneration.   In:  Ind.  Process Ses.  for Poll. Control, Proe. of
     the AIChE Workshop,  6:80-85,  1975.

124. Rheumc, L., ct al.   Two New Carbon Monoxide Oxidation Catalysts Get
     Commercial Tests.   Oil  and Gas J., 74(21):66-70, 1976.

125. Rhcume, L., et al.   New FCC Catalysts Cut Energy and Increase Activity.
     Oil and Gas Journal, 74(20) :.l 03-110,  1976.
                                     453

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126. Davis, J. D.  FCC Units Get Crack Catalysts.  Chem. Enp,., 84 (12) : 77-79,
     1977.

]27. American Petroleum Institute, Refining Department, Proceedings of the
     41st Mid-Year Meeting, Am. Pet. Inst. Ref. Dept., Washington, B.C., 1976.
128. lya, K. S.  Reduce NO  in Stack Gases.  Hydrocarbon Process., 51(11):
                          X
     163-164, 1972.
129. Reed, R. D.  How to Cut Combustion-Produced NO.  Oil and Gas J., 72(3):
     63-64, 1974.

130. Serth, R. W.,  et al.  Source Assessment:  Analysis of Uncertainty, Vol. II:
     Application to Air Source Assessment Program.  KPA-600/2-77-107, Monsanto
     Research Corp., Dayton, Ohio, 1977.

131. Bombaugh, K. J., et al.  Sampling and Analytical Strategies for Compounds
     in Petroleum Refinery Streams, Vol. II.  Radian Corporation, Austin, Texas,
     September 1975.

132. American Petroleum Institute, Medical Research Report //EA-7103, Petroleum
     Asphalt and Health.  Reinhold Publishing Company, 1966.

133. Environmental  Protection Agency, Office of Air and Waste Management.
     Guideline on Air Quality Models.  Research Triangle Park, North Carolina,
     1978.

134. Larsen, R.   A Mathematical Kodel for Relating Air Quality Measurements
     to Air Quality Standards.   F.nvironmental Protection Agency,  Office, of Air
     Programs, Research Triangle Park, North Carolina, 1971.

135. Turner, B.   Workbook of Atmospheric Dispersion Estimates.  Publication
     No.  AP-26,  Environmental Protection Agency,  Office of Air Programs, 1972.
                                     454

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136.  Gifford, F. and S. Hanna.  Urban Air Pollution Modeling.  In:  Proceedings
     of the Second International Clean Air Congress, H. Englund and W. Beery,
     eds.   Academic Press, New York,  pp. 1146-1151.

137.  Arthur D. Little, Inc.  The Impact of Lead Additive Regulations on the
     Petroleum Refining Industry.  Final Report.  EPA/450/3-76/016 a&b.
     Cambridge, Mass., May, 1976.
                                     455

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10.0
CONVERSION FACTORS
To Convert From
Btu
bbl
gal
ton
Ihs
cm
ft3
psi
g/gal
Btu/bbl
kWh/bbl
]b/bbl
lb/10G Btu
grain/ft3
gal/1.0Gft3
gpm
lb/100n gal
To
kcal
I
I
kg
kg
in
m3
kg/cm?
8 ^
kcal/il
kWh/£
kg/£
g/Mcal
g/IT.3
Jt/106m3
raVhr
mg/£
Multiple By
0.252
159.0
3.785
907.2
0.454
0.394
0.0283
14.223
0.264
0.0016
0.0063
0.0285
18.0
2.29
133.7
0.227
119.8
                                   456

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                                TECHNICAL REPORT DATA
                         (Please read Instruction! on the reverse before completing!
 1. REPORT NO.
  EPA-600/2-80-075a
                                 3. RECIPIENT'S ACCESSION-NO.
                                             22525  3
 4. TITLE AND SUBTITLE
 Assessment of Atmospheric Emissions from
  Petroleum Refining: Volume 1.  Technical Report
                                 B. REPORT DATE
                                  April 1980
                                 6. PERFORMING ORGANIZATION CODE
 7. AUTHOFttS)

 R.G.Wetherold and D. D. Rosebrook
                                                     B. PERFORMING ORGANIZATION REPORT NO
9. PERFORMING ORGANIZATION NAME AND ADDRESS
                                                     10. PROGRAM ELEMENT NO.
 Radian Corporation
 P.O.  Box 9948
 Austin,  Texas  78766
                                 1AB604
                                 11. CONTRACT/GRANT NO.

                                 68-02-2147, Exhibit B
 12. SPONSORING AGENCY NAME AND ADDRESS
 EPA, Office of Research and Development
 Industrial Environmental Research Laboratory
 Research Triangle Park, NC  27711
                                 13. TYPE OF REPORT AND PERIOD COVERED
                                 Final; 3/76-6/79	
                                 14. SPONSORING AGENCY CODE
                                  EPA/600/13
 is. SUPPLEMENTARY NOTES IERL_RTP project officer is Bruce A.  Tichenor, Mail Drop 62,
 919/541-2547.
 6. ABSTRACT
              rep0rt gives results of a 3-year program to assess the environmental
 impact of petroleum refining atmospheric emissions. Fugitive and process emissions
 were extensively sampled at 13 refineries in the U.S.  Nonmethane hydrocarbon
 emission rates were measured from valves, flanges, pump and compressor seals,
 process drains, relief valves,  cooling towers, and wastewater treating units. Flue
 gases were sampled from fluid catalytic  cracking units, sulfur recovery processes,
 process heaters, and other process units.  Their compositions were determined. .
 Organic species in liquid streams and emitted vapor were identified and quantified.
 Sampling and analytical methods are described. Emission factors  for major fugitive
 emission sources were calculated. Nomographs were developed showing the relation-
 ship of hydrocarbon concentrations at leaking sources  (screening values) with the
 leak rates from the sources. Existing and available emission control technologies
 for refinery emissions sources are evaluated.  Control methodologies are recommen-
 ded for individual emission sources. The impact of refineries on the surrounding
 atmosphere  and population is estimated.
 7.
                            KEY WORDS AND DOCUMENT ANALYSIS
                DESCRIPTORS
                                         b. IDENTIFIERS/OPEN ENDED TERMS
                                             c. COSATi Field/Group
 Pollution
 Petroleum Refining
 Assessments
 Hydrocarbons
 Organic Compounds
 Sampling
Analyzing
Pollution Control
Stationary Sources
Nonmethane Hydro-
 carbons
13B
13H
14B
07C
 3, DISTRIBUTION STATEMENT

 Release to Public
                     19 SECURITY CLASS (TMs Report)
                     Unclassified
                                                                 21. NO. OF PAGES
                     20 SECURITY CLASS 
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