Acknowledaements · Acknowledaements We appreciate all the assistance that was given to our effort...

Acknowledaements

We appreciate all the assistance that was given to our effort in developing this manual by those within industry and governmental agencies. A special thank you to the following for their comments and special effort:

Karen Brooks San Luis Obispo County APCD Kerby Zozula Ventura County APCD Mark Shemaria Tidelands Oil Production Company Mike Amundson San Joaquin Unified APCD - Kern County Desert Zone Mukasa Kezala Santa Barbara APCD

Princioal Authors Carl M. Brown Eric Patton

Contnbutina ARB Staff Ravindra Ramalingam

TABLE OF CONTENTS

100 INTRODUCTION “..” I.. ........ . ..“““““. ......... I”” . ...... . . .. . . “I .. . ... .” .. . .. . ............. 100-l

200 CATEGORY DESCRIPTION __..__“. ......... _..“““-_-“-““..““-“---..- -. ........... 200-l 201 Origin and Accumulation of Oil and Gas ..“” .. . ...... “““. ... “.. ..“. ... . .......... 200-l

201.1 Migration of Oil and Gas ....... “.... . .......... ““““..” . ....................... 200-l 201.2 Oil and Natural Gas Reservoirs .““. .. .” ..“. ..... ..“. ....... . ...... ..” ...... 200-2

202 Oil Production in California .““. ..... . “....“..“““““.. ..“. ... “I.“. . ..“. ............. 200-7 203 Emissions from Oil Field Gas Production “....““““. ... “......“..I I.. .. “I.. ..... 20018 204 Impact of Oil Production Emiasionson Air Quality ..UU..l_l..” .._. ... “. .... 200-10 205 Control of Emissions from Oil Field Production .... “““““. ........... . ..... .” .. 200-12

205.1 Inspection and Maintenance .“” . .... “..““..“..“.... . ...... . ............... 200-12 205.2 Regulations ... . . . . . . .................................... “” ..“. ..................... . .. 200-14

2052.1 District Permitting Process .... . ...... ..“. .......................... 200-14 205.22 Prohibitory Rules .......... . .......... ““.... . ........................... 200.16 2052.3 Enforcement .............. . ........ . ......................................... 200-17

PROCESS AND CGNTROL .... “” ..“. ... . ........ . ... . . . . . . ....................................... 300-l 301 Onshore Oil Production ........................ “..“.,.. . .. ..“. ............. . ..................... 300-l

301.1 Drilling .................. .” ..“. ............... . .... ..“. ........................................ 300-l 301.2 Well Construction .. . ...................................................................... 300-4

301.2.1 The Wellhead .............. ..“. “....,. . ...................................... 300-7 301.3 Primary Oil Recovery .............. . .................. ..“. ............................ 300-11

301.3.1 Artiticiai Lift ...... . . ..“““. ........... ..“...... ............................ 300.11 Rod-beam Pumping .” ..“. ... . .................. ““. ..................... 300-11 Hydraulic-Powered Rod-beam Pumping . . ........ . .......... 300-12 Electrical Submersible Pumping ...... ..Y . .......... ..“. . ..“. ... 300-14 Subsurface Hydraulic Pumping ... .._..“. ........... “. ............ 300-14 Gas Lift ..““..““-..--__-I”-” I. . ..“. ................. . .... . .......... 300-15 Plunger Lift “““. ......... ..“. ............. “..““““. ...... .” . ............. 300-16

301.4 Enhanced Oil Recovery . . .. . . .. ..____..__........“...... ..................... 300-16 301.4.1 Secondary Recovery ... ..“. ............................................... 300-16

Waterflooding ........... . .. . l.... . .............. ““. ....................... 300-17 Immiscible Gas Injection . . .................. ““. ........... . .... . .... 300-18

301.4.2 Tertiary Recovery “““. ... ..““. ....... . ................................ 300-19 Tertiary Miscible Methods ........... . .... . ........................... 300-19 Tertiary Thermal Methods . . . . . ........................ . . ....... 300-23

3015 Separation and Treatment .... ..“. ... . .......... . .. . . .......................... 300-33 3015.1 Separators .“““..“““““““........ . ........ I .. . ........................ 300-37 301.52 Free Water Knockout Vessels ““. ....................... . .......... 300-39 301.53 Heater Treaters “. . ..“. ... ““““” . .... ..“. ............................. 300-41 301.54 Heaters I........ . .......... ““I”. ... Y..“..” ..“. ............. . ...... . .... 300-44

Direct Heaters ... . .. ..” . .... “““. ... ..“. ............... . .................. 300-44 Indirect Heaters ..... . .... I”. ......... ““““..““..” . ........ . ......... 300-47

July 1992 i

301.55 Wash Tanks . . . . . ..I_ -..- -__-___..-_I.......... . . . . . . . . . . . 300-49 3015.6 Wastewater Separators .““““““““” . . . . ..I” . . . . . . . . . . . . . . . . . . 300-51 3015.7 Pits, Ponds, and Sumps ““““““““_““..I..“““_““” . . . . . . . 300-52

301.6 Storage .““-“-..-“““--““-““-“--“~--“~“““..””””-- . . . . .a.... . . . . . . 300-54 302 Offshore Oil Production l___l_l_..ll_l._____~~~“~-..~~--..”~-”--.... 300-56

302.1 Drilling Vessels . ..I.... I.................._ . “I---I--..----“-......“....- 300-57 302.2 Production platforms -“-““““““““““““““_--------~..-..~-... 300-59

400 INSPECTION PROCEDURES _~~~~~~--~~~~~~~~~~~~~~~~-..~ ti . . . . . . . . . . . . . . . . 400-l 401 Pre-Inspection Procedures ““““..“““““_-“-“..__~““--” . ...” . . . ...” . . . . . . . . . . 400-l

401.1 File Review .“_“_“-“---“_-““““““““--------..---....... 400-l 401.2 Regulation Review --..-. -..-... -.. . . ..- - ....---......I.: . . . . 400-l 401.3 Equipment Check ..~-...~~.-~ .-- -....-......“.... . . . ...” . . . . . . . . . . 400-2 401.4 Pre-Entry and Entry “---.“-“-““-.“-““I”..~“-..” . . . . . . “......... 400-2 401.5 Pre-Inspection Meeting -....-.. - _l--__l--““-_“.................. 400-2

402 Facility Inspection Procedures --...-. .-- -..-----....-.. . . . . -.. 400-3 402.1 Leak Detection Methods .-- ~.~~-~~ -.. -....--.............-. 400-3 402.2 Components ..- - -.------....- -.. ---.................-. 400-4

402.2-l .valves ” . . . . . . ““......“..“..............“..” . . . . “““....“..” . . . . . . . 400-4 402.2.2 Fianges -“-“-“““-“..“-“---------“~---..“- . . . . . . “.. 400-S 402.23 Pumps and Compressors .__I_..__I___..____..-....~-. 400-S 402.2.4 Other Equipment .---.--....- . . . . . . - . ...-..” . . . . . . . . 400-6

402.3 Fired Equipment ___.._______.............. . .--...........-..-.... . . . . 400-6 402.4 Fixed Roof Tanks .““..“..“““..“““” . . . . . . . . “..” . . . . . . . . . . . . . . . ..a . . . . . . . . . . . . . 400-7 402.5 Oil Water Separators --“---..---“““““““_“- . . . . ““..” . . . . ““” . . . . . 400-9 402.6 Sumps “““..I....“““.._ . . . . . . . . . . . . . . ..“......“....“““........ . . . . . . . . “.. . . . . . ...” 400-9 402.7 Vapor Recovery Systems ..“....““““..““..“” . . . . I . . . ...” . . . . . . . . . . . . . . . . . . . 400-9

402.7.1 Tank Vapor Recovery Systems .I”““..““....“..“” . . . . . . . . . . 400-10 402.8 Offshore Platforms ““““““““““““““...“...““..“““” . . . . “” . . . . . . -... 400-11 402.9 Inspection Checklist ._“......... i ..-.._.._ ..-.. -. . ..__-....._.........-.-- 400-12

403 Post-Inspection Procedures ” . . . . “.... . . . . . . . . . . . . . ...““.. . . . . . ...” . . . . . . . ...” . . . . . . . . . . . . . 400-14 404 Recordkeeping .____1....1_..111......“..“......””””-..-””......“...................... 400-15 405 Sampling . . . . “““““.... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...” . . . . . . “.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 400-16 406 Inspector Safety -.-.-.- . ___.._____________....“....““-..”””-..”....-”. 400-19

500 LEGAL REQUIREMENTS ..“..“....“_..__........““..“..“..........””..”..........”........... 500-l 501 Health and Safety Code .“..“_-------..-..--..-..----..-..” . . . . . . . . . . . . . . . . . . “.. 500-l

501.1 Locai and State Agency Responsibilities - 39002 .-.-.-..-.- 500-l 501.2 ARR Responsibilities - 39003 “-“----“-“..-“-..---..” . . . . . . . . . . . . 500-2 501.3 LocaFState Responsibilities - 40000 ..-...-.... --...-.. -....-.. 500-2 501.4 District Powers - 40701 .__l_..ll________l_l-----......--....-- 500-2 501.5 District Rules and Regulations - 40716 ““..“““““..“” . . . . . . . . . . . . . . . . 500-3 501.6 Right of Entry with Inspection Warrant - 41510 ..-.-..-.--. 500-3 501.7 Cogeneration Technology - 41515 I............“““........” . . . . . . . . . . . . . . . . 500-3 501.8 Mitigation for &generation and Resource Projects - 41517 . . . . 500-4 501.9 District Permit System - 42300 . ..-.--..-...---..-............ 500-4 501.10 Requirements for Permit Issuance - 42301 . . . . . . . . . . . . . . . . . . . . . . . . 500-S

July 1992

501.11 Permit Approval: Powers and Duties of Air Pollution Control Officer . 42301.6 .................... . ...................................... 500.6

501.12 False Statements in Permit Applications . 42303.5 .................. 500-7 5Ol.W Applications for Variance . 42350 ............................................. 500.7 501.14 Interhn Variance Applications - 42351 ....... . ............................ 500.8 501.15 Emergency Variances . 42359.5 ................................................. 500-s 501.16 General Violations, CrimhtaI . 42400 ..... . .. . ............................ 500-s 501.17 Negligence, Criminai . 42480.1. ........... ..“. .................................. 500.9 501.18 Generai Violations, Civil . 42402 ............................................... 500.10 501.19 Negligence or Actual Injury, Civil . 42402.1 ............................ 500-10 501.20 General Violations, Administrative Civil . 42402.5 ................. 500-11 501.21 Recovery of Civil Penalties . 42403 ........................................... 500.11 501.22 Statute of Limitations for Civil Actions . 424045 ................... 500-12

502 Summary of District Oil Field Production Rules ..................................... 500-12 503 ARB Control Strategies ............................. . .... ..“. ...................................... 500.15 504 Department of Conservation Division of Oil and Gas ............................ 500.15

504.1 The Role of the Division of Oil and Gas .................................... 500-15 504.2 California Code of Regulations Safety and Pollution

Control Equipment Requirements . 1747.1 .............................. 500.16 505 District Regulations ..... ..“. ... . ..................................................................... 500-18

GLOSSARY ......... . .. . .......... ..“. ............................... ..“. .................................................. Gloss-l

APPENDICES A EPA Method 21 Determination of Volatile Organic Compound Leaks . . . . . A-l B South Coast AQMD Rule 1173 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-l C ASTM 4057 . . . . . . . . . . . . . . ...” . ...” . . . . . . . . . . . . . . . . . . . . . . . . * . . ...” . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-l

INDEX . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Index-l

LIST OF FIGURES

201.1 Dissolved-Gas Drive ............................................................................................ 200.3 201.2 Geological Types of Oil and Gas Reservoirs .................................................... 200-4 201.3 Gas-Cap Drive .. . .......... . .... . .. . .............. . ........................................................... 200-5 201.4 Water Drive .......................... ..- ........................................................................... 200.5 301.1 Drilling Rig ............... . ................ ..“. .................................................................... 300.2 301.2 A Typical Well ......................... . .......................................................................... 300.5 301.3 A Typical Wellhead Assembly ........... . .. . .......................................................... 300-8 301.4 Artificial Lift Pumping Unit ............................................................................... 300-13 301.5 Steam Drive Well Arrangements ....................................................................... 300.25 301.6 Steam Drive Process . . . .” . ........ ..“. ..................................................................... 300.26 301.7 Schematic of Well Vent Control System .... ..“. ....... . ............ ..“. ....................... 300-29 301.8 Air Cooled (Fin Fan) Heat Exchanger .._ .......................................................... 300-30 301.9 Schematic of Modified Steam Generator Burner ..... . ..................................... 300-32 301.10 Flow Diagram of a Light Crude Oil Treatment Plant ..................................... 300.34 301.11 Flow Diagram of a Heavey Crude Oil Treatment Plant .................................. 300-35

July 1992 . 111

301.12 A Typical Separator ... .._..........__ ....................................................................... 300-38 301.13 Free Water Knockout Vessel . .._......_ .... “.. ...... -“_.-“_. ....... -. ............... .._ ....... 300-40 301.14 Typical Vertical Heater Treater ___ .... - ..-. ........... __I .._.........._ ....................... 300-42 301.15 internal Firebox Heater .... ..__..___-....-..............................--“” ....................... 300-46 301.16 Typical Indirect Heater .._.. . ______..__......_.._“~~“..--~............-..-............~ .. 300-48 301.17 Typical Wash Tank (Gun Barrel) .__..__““““..__..-_” ..” .... ..“...._ .................... 300-50 301.18 Fixed Roof Storage Tank --___lll__..--...._..-“-..-- ....................................... 300-55 405.1 Tank Sample Locations ““...._.._..........“....--..“““....”..”..- ................................. 400-17

LIST OF TABLES

204.1 Oil and Gas Extraction 1989 Emission Inventory . . . . . ..“..................................... 200-10

iv July 1992

( 100 INTRODUCTION Oil Field

Production

This manual provides descriptive information on processes, equipment, and controls associated with air pollution from oil field production. It also provides information for district inspectors and industry operators on how to determine and maintain compliance with regulatory requirements.

Purpose

Section 200 of the manual describes what oil field production is, how oil field production impacts air pollution , and how air pollution is controlled at oil field production sites. Section 300 describes the processes and controls that are involved in onshore and offshore oil field production. Section 400 discusses compliance inspection procedures and techniques. Section 500 discusses air pollution control regulations, policies, and procedures associated with oil field production. References used in each section are placed at the end of each section.

Organization

A glossary, which contains important terms used in the manual, and appendices, which contain supplemental information are included in this manual. An index tit the end of the manual provides easy access to informatton.

The manual basically focuses on operational descriptions of processes and equipment used in oil field production from the well site to transfer of custody. It does not cover transport to refineries or refinery operations.

Scope

The manual was written for district inspectors and site operators. It can be used as a reference manual and user’s guide. It is designed for easy referencing, reading, and updating. Additionally, it contains numerous graphics and illustra- dons to enhance understanding.

Audience

The Compliance Assiitance Program (CAP) welcomes your comments concerning this manual. A colored comment sheet has been placed in the back of this manual to encourage your input. Your comments and corrections, changes in legal requirements, and new information on equipment and processes will be collected and periodically distributed in an upgrade packet. Only the manual users who return the tracking card located in the very front of the manual will receive an upgrade packet, so be sure to fill out your card and send it in as soon as you receive the manual.

Feedback

The Compliance Assistance Program (CAP) is an effort by the California Air Resources Board to provide assistance to local districts in conducting more comprehensive, consistent, and accurate compliance inspections and to provide

CAP Description

July 1992 Page 100 - 1

Oil Field Production 100 INTRODUCTION

industry with information and tools to help them become aware of how to stay in compliance with air pollution regulations. This effort is to promote greater awareness for continuous compliance with district rules and to encourage coop- eration between regulators and industry to reduce excess emissions.

The program produces district inspection manuals and industry self inspection handbooks and informational pamphlets. The district inspection manual is designed to provide rule specific inspection procedures and reference materials in a readable and understandable format. The manual is intended to encourage complete compliance inspections including comprehensive compliance determinations.

A separate industry handbook or pamphlet is designed to help operators and management understand the air pollution rule requirements, to inform them about district inspections, and to show them how to conduct self-inspections at their facility.

Page 100 - 2 July 1992

200 CATEGORY DESCRIPTION Oil Field Production

Oil field production involves bringing crude oil from the subsurface to the surface and preparing it for shipment to the refmery. This process involves drilling, well construction, treatment, separation, and storage. In the oil field production process, air pollution control districts usually become concerned with volatile organic compound emissions at the point where the oil reaches the surface (wellhead) and ends where the oil is transported from the production site.

201 ORIGIN AND ACCUMULATION OF OIL AND GAS

There are many theories explaining the origin of petroleum or oil and natural gas. However, it has not been possible to identify the exact place or materials from which any particular oil accumulation originated.’

There are two,generally accepted theorles to explain the origin of oil, the organic and inorganic theories. The inorganic theory holds that hydrogen and carbon were brought together under great pressure and temperature deep in the earth to form oil and gas, which then found its way through porous rocks to collect in natural traps in the underground formations of the earth.’

The organic theory, on the other hand, presumes that both the hydrogen and carbon that make up petroleum came from plants and animals living on land and in the sea It is thought that this organic material probably was mostly former sea and swamp lie rather than true land life. Also, it possibly was mostly the wry small, rather than the larger forms of life.’

It is believed that some time after these remains collect in the sediments, parts of them are converted into minute oil droplets. The exact process by which the organic material becomes oil is not known, but bacteria, heat, and pressure are all believed to play important roles. *

201.1 MIGRATION OF OIL AND GAS

Migration is the movement of oil droplets through pore spaces. How oil droplets migrate with accumulations is not fully known, but migration may occur through the following combination of forces and actions:

Theories

Pore Spaces

July 1992 Page 200 - 1

Oil Field Production 200 CATEGORY DESCRIPTION

Oil Pools

Salt And Water

Dissolved Gas Drive

1. Gravity. Oil, lighter than water, will rise through water until an obstruction is encountered, prohibiting additional upward progress. Oil may move a considerable distance laterally at the same time it is moving upward

2. Water currents. Movement of the water through sands may push oil along for considerable distances.

3. Crustal movements. Beds bending and folding undoubtedly play an important part in the migration of oil. Tilting strata that have been lying relatively flat accelerate the separation of oil and water, concentrating the oil in the highest accessible place.*

Oil pools are formed when the proper combination of conditions are present. Oil and natural gas migrate until they reach a trap~past which they cannot move. At this point, they accumulate, forming an oil or natural gas reservoir?

201.2 OIL AND NATURAL GAS RESERVOIRS

It is convenient to classify oil and gas reservoirs or traps in terms of the type of natural energy and forces available to produce the oil and gas. At the time oil was forming and accumulating in reservoirs, pressure and energy in the gas and salt water associated with the oil were also being stored- The salt and water would later be available to assist in producing the oil and gas from the underground reservoir to the surface. Oil cannot move and lift itself from reservoirs through wells to the surface. It is largely the energy in the gas or the salt water (a tJw occurring under high pressures with the oil that furnishes the force to drive or displace the oil through and from the pores of the reservoir into the wells.’

In nearly all cases, oil in an underground reservoir has dissolved in it varying quantities of gas that emerges and expands as the pressure in the reservoir is reduced. As the gas escapes from the oil and expands, it drives oil through the reservoir toward the wells and assists in lifting it to the surface. Reservoirs in which the oil is produced by dissolved gas escaping and expanding from within the oil are called dissolved-gas-drive reservoirs1 See Figure 201.1.

Often more gas exists with the oil in a reservoir than the oil can hold dissolved in it, under the existing conditions of pressure and temperature in the reservoir. This extra gas, being lighter than the oil, occurs in the form of a cap of gas over the oil. This condition is illustrated in Figure 201.2c, 201.2e, and 201.3. Such

Page 200 - 2 July 1992


IMPERVIOUS ROCK OIL WITH

DISSOLVED GAS

IMPERVIOUS ROCK

Figure 201.1 Dissolved-Gas Drive

a gas cap is an important additional source of energy because, as production of oil and gas proceeds and as the reservoir pressure is lowered, the gas cap expands to help fill the pore spaces formerly occupied by the oil and gas producec Where conditions are favorable, some of the gas coming out of the oil is conserved by moving upward into the gas cap to further enlarge the gas cap. As compared with the dissolved-gas drive, the gas-cap drive is more effective, yielding indicated oil recoveries ranging from 25 to 50 percent.’

The gas-drive processes just described are typically found with the discontinu- ous, limited, or essentially closed reservoirs of the types shown in Figure 201.2 201.2g, 201.3.’

Where the formation containing an oil reservoir is uniformly porous and continuous over a large area, as compared with the size of the oil reservoir, very huge quantities of salt water exist in surrounding parts of the same formation, often directly in contact with the oil snd gas reservoir. This condition is demon strated by Figure 201.2a through e. These large quantities of salt water occur under pressure and provide a large additional store of energy to assist in produc ing oil and gas.’ A situation like this is termed a water-drive reservoir and is shown in Figure 201.4.

Gas Cap

Water Drive

July 1992 Page 200 - 3


Figure 201.2 Geological Types of Oil And Gas Reservoirs

Page 200 - 4 July 1992

-


IMPERVKXIS

FREE GAS ’ CAP

OIL WITH DISSOLVED GAS

Figure 201.3 Gas-Cap Drive

n

IMPERVIOUS ROCK

OIL WITH DISSLOVED GAS

WATER

IMPERVIOUS ROCK

Figure 201.4 Water Drive

July 1992 Page 200 - 5

200 CATEGORY DESCRIPTION

Expanding Water

Recovery Efficiency

The energy supplied by the salt water comes from expansion of the water as pressure in the petroleum reservoir is reduced by production of oil and gas. Water will come into the reservoir to the extent of about one part in 2500 per 100 psi change in pressure.

Although this effect is slight with reference to small quantities, the phenomenon becomes important when changes in reservoir pressure. affect large volumes of salt water that are often contained in the same porous formation adjoining or surmmding a petroleum reservoir1

The expanding water moves into the r&ions of lowered pressure in the oil and gas saturated portions of the reservoir caused by production of oil and gas, and retards the decline in pressure. In this way, the expansive energy in the oil and gas is conserved As shown by Figure 201.4, the expanding water also moves and displaces oil and gas in an upward direction out of the lower parts of the reservoir. By this namral process, the pore spaces vacated by oil and gas produced are filled with water, and oil and gas are progressively moved toward the wells.’

Ihe water drive is generally the most efficient oil production process. Oil fields in which water drive is effective are capable of yielding recoveries ranging up to 50 percent of the oil originally in place, (1) if the physical nature of the reservoir rock and of the oil are conducive to the process, (2) care is exercised in completing and producing the wells, and (3) depending on the rate of oil and gas production from the field or reservoir as a whole.’

llese factors also affect the oil recovery efficiency in gas-cap-drive reservoirs. However, rate of prcduction seems to exert only minor effects on oil recoveries obtainable 6-om dissolved gas drive type fields except where conditions are ravorable for gas caps to form. In mauy instances, reservoirs may possess the potential for either water drive or gas drive. Then the kind of operation and total rate of production will determine which type. of drive will be most effective, and accordingly will affect the oil recovery.’

l

Page 200 - 6 July 1992


202 OIL PRODUCTION IN CALIFORNIA

California ranks fourth among oil producing states behind Texas, Alaska, and Louisiana, respectively. The first year of commercial oil and gas production in California occurred in 1876. Today, twenty-nine counties are involved in oil and gas production; seventeen of these counties produce crude 0il.s

During 1990, California’s crude-oil production decreased for the fifth year in a row. production totaled 350.7 million barrels in 1990, compared with 364.3 million barrels in 1989. Production decreased in both the federal and state offshore areas. The total state production continued to decline during the year, largely due to low crude-oil prices.3

The state total includes 297.2 million barrels of oil produced from onshore fields (down 8.6 million barrels) and 53.4 million barrels from offshore fields (down 5.0 million barrels). production from federal offshore fields (29.9 million barrels) decreased by 3.2 million, while production from state offshore (tide- land) leases (23.6 million barrels) dropped by 1.8 million barrels.3

In spite of the overall decline in both onshore and offshore fields, significant production increases were posted in four California onshore fields: Midway- Sunset (2.4 million barrels), Coalinga (902,ooO barrels), Kern (622,000 barrels), and Lost Hills (608,ooO barrels). Most of the production increases were due to enhanced, heavy-oil recovery operations using steam injectionP

In December 1990, California’s oil was produced from 232 fields at a rate just over 946,000 barrels per day compared with 983,000 batrels per day at the end of 1989. There were 44,506 producing wells at the end of 1990, an increase of 428 wells over 1989. These figures include 77,300 barrels per day produced from 378 wells in 8 fields on federal offshore leaseas

fin 1990, incremental oil production from all types of enhanced oil recovery accounted for about 229.7 million barrels, or about 66 percent of California’s total oil production. Steam stimulation was credited with about 180.8 million barrels, or about 79 percent of all incremental oil production. Waterflooding accounted for about 48.9 million barrels, or about 21 percent of the incremental production total. However, the total figure should actually be higher, as figures are unavailable for the incremental oil production from the waterflood projects in federal offshore fields3

Crude Oil Production

Enhanced Oil Recovery

July 1992 Page 200 - 7


Recoverable Oil

Drilling

California’s Production

Page 200 - 8 July 1992

As of December 31,1990, California’s estimated recoverable (proved) oil reserves totaled 4.2 billion barrels. Included in the total were 3.4 biion barrels in onshore fields and 705 million barrels in offshore fields (332 million barrels of which were in federal offshore fields). At the same time, proved gas reserves iu the state were estimated at 4.1 trillion cubic feet3

The number of new oil, gas, service, and prospect (exploratory) wells drilled iucreased from 2,080 wells in 1989 to 2,476 wells in 1990. In addition, the number of new wells completed to production increased from 1,482 in 1989 to 1,638 in 1990.9

The drilling increase resulted in an increase of new-well footage drilled, from 5,183,767 feet in 1989 to 5.595,610 feet in 1990. Footage drilled while mdrihing or deepening existing wells increased from 119,867 feet in 1989 to 153,185 in 1990.9

The number of exploratory (prospect) wells drilled decreased from 155 in 1989 to 133 in 1990. During the year, no new fields or areas were discovered, 2 new pools in oil fields were discovered, and the productive limits were extended in 5 oil fields. In 1990,3,064 wells were plugged and abandoned3

In 1990 California produced 350.7 million barrels of crude oil (includes federal outer continental shelf - OCS). Seventeen counties produced this oil from 234 active oil fields with 44,506 producing wells. The average daily crude oil production per well on 12/31/90 was 21.3 barrelsr

According to the U.S. Department of Energy’s 1990 Petroleum Supply Annuals,- crude oil production for the U.S. was 2684.7 million barrels/day and California was 350.9, thus, California produced 13.1% of the total U.S. production.

For continued update of oil production data in California, contact the California Department of Conservation Division of Gil & Gas. This agency publishes an annual report on oil and gas production in California.

203 EMISSIONS FROM OIL FIELD PRODUCTION

The recovery of oil and natural gas from Califomia’s natural underground reservoirs both onshore and offshore requires a vast assortment of equipment: (pumps and compressors), vessels, (tanks and separators), heat sources, (heater

,s.

C -

I


treaters, power and stesm generators, and flares), piping components, (valves, connections, flanges, and other components). In the course of recovering and transporting the petroleum and gas, some of the contained liquid and gas is leaked to the atmosphere at various points such as:

- Flanged and threaded connections - Valve stems - Compressor and pump seals - Hatches - Meters - Sight glasses - Pressure relief valves

The numbers of components are large. Although a leaking component may release somewhat small amounts of photochemically reactive organic compounds into the atmosphere, the cumulative emissions from all leaking components are 1argeP

Volatile Organic Compound (VOC) emissions from pressure/vacuum (PV) valves on oil production storage tanks can be significsnt if the PV valves are not maintained properly or equipment is not sixed or operated properly!

NOx emissions from the use of stationary internal combustion engines in oil field production can conttibute to oxone formation, visibility reducing particulates, and total suspended psrticulates (TSP) if not controlledP

Enhanced oil recovery (EOR) methods such as steam displacement and in-situ combustion can produce SOx and particulates from steam generators and hydrocarbons and carbon monoxide from producing wells. EOR methods such as micellar-polymer flooding can cause emissions problems if chemicals are manufactured onsite.

The major polhnants emitted t%om offshore platforms are: - Oxides of nitrogen (NOx) - Volatile organic compounds (VOCs) - Particulate matter (PM) - Sulfur dioxide (SO,) - Carbon monoxide (CO)

Components

NOx Emissions

Enhanced Oil Recovery

July 1992 Page 200 - 9

Oil Fkld Production 200 CATEGORY DESCRIPTION

0

Combustion Emissions

Leak Prone Components

The major sources of NOx, PM, and CO are combustion emissions from power generating equipment. If high sulfur content gas is discovered flaring this gas can be a major source of SO,. VOCs are emitted from the glycol regenerator, heater treaters, water treatment equipment, pump seals, and various process and storage vents6

All five of the above pollutants are also emitted from support vessels associated with offshore platforms (e.g., crew boats, supply boats, helicopters, oil tankers). Additionally, hydrogen sultide and mercaptans are sources of odor nuisance problems, emitted from fugitive sources or incomplete combustion.6

204 IMPACT OF OIL PRODUCTION EMISSIONS ON AIR QUALITY

Oil and gas production operations contain numerous components which can leak volatile organic compounds into the atmosphere. Leak-prone components include valves, connections, sight glasses, meters, hatches, seal packings, and diaphragms. Leakage from these components contributes to the formation of ozone and other oxidants in the atmosphere..

According to ARB’s latest emissions inventory (1989), 278 tons per day of VOCs or ROCs were emitted from oil and gas production (see Table 204.1). The sources of these emissions am concentrated in the San Joaquin Valley, South Coast, and the South Central Coast air basins.

VOC emissions fium oil field production contribute to violations of state and federal ambient air quality standards for oxidant and ozone in these air basins.

COUNTY

Alameda Butte Colusa Contra Costa Fresno Glenn

TABLE 294.1 OIL AND GAS EXTRACTION

1989 EMISSION INVENTORY EMISSIONS Avg. Annual (tons/day:

TOG ROG NOX .Ol Ml .oo .26 .09 .oo

6.61 2.04 .oo .99 .33 .oo

16.15 10.02 .oo 5.45 1.69 3.12

Page 200 - 10 July 1992


TABLE 204.1 OIL AND GAS EXTRACTION

1989 EMISSION INVENTORY (Cont’d)

COUNTY

Humboldt Kern Kings Los Angeles Madera Merced Monterey @awe Riverside (South Coast) Riverside (Southeast Desert) Sacramento San Benito (North Ctrl Coast) San Bernardino San Joaquin San Luis Obispo San Mated Santa Barbara Santa Barbara (OCS) Santa Clara Solano (Sac Valley) Solano (SF Bay Area) Sonoma (North Coast) Sonoma (SF Bay Area) Suttar Tehama TtllalX Ventura Ventura (OCS) Yolo

Total

July 1992

IONS Avg. An I

EMISS roci

.85 331.03

1.77 27.02

SO .04 .69

13.43 .05 .22

1.23 4.40 .lO

5.85 2.01

.OS 14.75 8.89

.Ol 10.37

83 .85 .Ol

6.25 1.37 .19

16.05 11.32 3.88

ROG .26

207.32 .73

15.05 .17 .02 .42

8.17 .02 .09 .50

1.86 .08

1.72 1.01 .03

7.79 3.60

.oo 3.15

.22

.26

.oo 1.94 .46 .08

7.53 4.54 1.20

.oo

.ll

.oo A0 .oo .oo .oo .03 .ocl .04l .oo .oo .oo .oo .oo .oo .oo .oo a0 .oo .oo .oo .oo .oo .oo .oo .oo .oo .oo

483.11 278.12 3.66

Page 200 - 11


Leak Detection

Detection Techniques

EPA Method 21

0 - 12

205 CONTROL OF EMISSIONS FROM OIL FIELD PRODUCTION

Fugitive VOC emissions and combustion emissions are the main emissions to be controlled from oil field production. These emissions are controlled through maintenance and inspection programs and regulations.

205.1 INSPECTION AND MAINTENANCE

The most effective control strategies to reduce fugitive VOC emissions from components consist of leak detection, repair programs, and equipment design. Preventing components from leaking or decreasing the frequency and magnitude of such leaks is the most effective means of controlling fugitive VOC emissions. This can be achieved by:

- Using components that are less prone to leaks - Conducting proper maintenance - Using double mechanical seals on compressors and pumps - Using vapor recovery on storage tanks and compressor and pump seals8

However, most connections or components in piping systems will eventually leak. Therefore, inspection programs are necessary to ensure leaks are routinely identified and repaired

Several leak detection techniques can be used to identify the sources of fugitive emissions. Leak detection can be performed using visual, audible or olfactory senses; or by using tools such as soap solutions or instrumentation. Any of these techniques can be used as a cursory check for leaks, but instrumentation such as a portable hydrocarbon detector must be used to adequately characterize emissions.8

For daily inspections, cursory or screening techniques, such as soap solutions, are used to reduce the number of components to be checked with a hydrocarbon analyzer. EPA Method 21, Determination of Volatile Organic Compound Leaks, specifies the procedures for instrument monitoring (see Appendix A)-8

Directly inspecting insulated components may be diEicult due to the insulating material that encases these components. However, EPA Method 21 provides procedures to inspect these components without removing the insulating mate- riaL8

July 1992

c

c

I -*;,


Once leaking components are identified, emissions from these sources are reduced by repairing the components. Repairs are made by adjusting or replacing the components. Leaking pump and compressor seals are initially repaired by tightening the packing gland, which usually corrects the leak. However, at some point, the packing may degrade to such a degree that no further leak reductions can be achieved. In such a case, the packing gland must be replaced, typically reqmring that the component (pump or compressor) be taken out of service.8

Leaking pressure relief valves must be removed in order to repair the leak. This may require the installation of block valves or a combination of block and pressure relief valves in order to avoid shutting down the process. Some pressure relief valves may be difficult to monitor because they are located in areas with limited accessibility.*

Most other valves have a packing gland that can be tightened while in service. For these valves, this procedure will reduce fugitive emissions from &valve seals. However, if the packing is old and brittle or if it has been overtightened, further tightening can result in an increase in VOC emissions. Another possible method to reduce leaks from process valves can be achieved by injecting a sealing fhrid into the source of ~the leak!

Leaks from flanges and connections can be reduced by replacing the flange gasket or in the case of threaded connections by placing synthetic tape or “pipe dope” on the threads before the connection is made. Repair of flanges normally requires the process line to be shut down or, if possible, redirected. However, emissions from flanges and connections can be reduced by tightening bolts or fittings, without shutting down.8

Onshore and offshore oil field production also produce combustion emissions from internal combustion engines used for cranes, emergency generators, and drilling; combustion emissions from gas turbines used for electrical power production or natural gas compression; and hydrogen and sulfur dioxide emissions from venting and flaring waste gases, respective1y.S

Combustion emissions from diesel and natural gas engines (principally NOx) are controlled, where practicable, by substituting diesel engines with electric motors connected to a utility power grid and using diesel engines as a backup only.

Repairs

Pressure Relief Valve

Combustion Emissions

July 1992 Page 200 - 13

Oil Field Produetion

l 200 CATEGORY DESCRIPTION

Gas Turbines

Flare System

“3 Emissions

Other ways that combustion emissions kom diesel engines are controlled include:

- Using only low NOx emitting diesel engines - Modifyiug the engine, such as retarding fuel injection - Using selective catalytic reduction (SCR) to reduce NOx in exhaust gas

Emissions (primarily NOx) from gas turbines used for power production can be eliminated by replacing them with electric motors connected to a utility power grid and only using the turbines for emergencies or during periodic testing. If turbines are used, use only low NOx emittiug gas turbines and water injection to reduce NOx. Additionally, the waste heat from mrbines can be used for processing, in which case the burners (and their emissions) can be eliminated.8

If hydrocarbons are emitted at a relatively constant rate during processing, a vapor recovery or flare system can be used to reduce such emissions. If these emissions are highly variable, or result from equipment malfunctions or upsets, then a flare system is generally used to control such emissions.8

In some fields, onshore or offshore, substantial quantities of hydrogen sulfide (H$) are present in the oil and gas. Generally, this HsS is separated from the gas. For safety purposes during offshore operations, l3$ is flared prior to venting to the atmosphere, which converts the H$ to SO,

These emissions can be virtually eliminated by shifting the processing, power production, and HsS removal to onshore sites, where efficient controls can be used to recover sulfur, such as the Claus and Stretford sulfur removal systems8

205.2 REGULATIONS

Local Air Pollution Control Districts (APCDs) use the permitting process, prohibitory rules, and enforcement to control emissions from oil production facilities. They set limits, require certain operating conditions, and conduct compliance inspections.

2052.1 District Permitting Process

Section 42300 of the California Health and Safety Code (HSC) allows every local air pollution control district to establish a permit system that requires any

Page 200 - 14 July 1992

c 200 CATEGORY DESCRIPTION Oil Field Production

person to obtain written permission to erect and operate any equipment or contrivance that may cause the issuance of air contaminants. The air pollution control permits are typically referred to as an Authority to Construct (AC or ATC) and a Permit to Operate (PO or PTO). These permits are required for equipment not specifically exempt by regulation, regardless of whether or not permits have been issued by other state and local agencies.

Specific district requirements may vary for the same equipment or process depending on the existing air quality of the district. The local APCD permitting process usually includes:

- Application Submittal - Preliminary Engineering evaluation - Engineering evaluation, Authority To Construct - Authorization for equipment start-up - Engineering evaluation, Permit To Operate - Annual permit renewal

For oil field production, APCDs require an AC prior to building, erecting, and installing and a PO before operating any article, machine, equipment, or other contrivance, the use of which may cause the issuance, reduction, control, or elimination of air contaminants.

The AC gives permission for construction and establishes the conditions under which the equipment is to be built. For example, the conditions may require a control device or may set an emissions limit. Upon completion, but prior to operation, the applicant must comply with all AC requirements before a PO is issued.

The PO usually lists the equipment that is permitted and the conditions under which it may operate.

In districts that have oil field production, permitting requirements for articles, machinery, equipment, or other contrivances vary. However, the following are usually candidates for permitting:

- Storage and process tanks - Process equipment - Internal combustion engines - Oil, gas, and injection wells - Sumps, pits, ponds

Authority To Construct

Permit To Operate

July 1992 Page 200 - 15

Oil Field Pmductlon 200 CATEGORY DESCRIPTION

Local APCD

Page 200 - 16

- Fii equipment and flares - Chemical storage tanks - Drilling rigs

266.2.2 Prohibitory Rules

Each local APCD has prohibitory rules that govern basic operations of any stationary source of air pollutants. Make sure you know the prohibitory rules iu your district that apply to oil field production. Regulations that local APCDs may have that limit emissions from oil field production include:

- Valves, Pressure Relief Valves, Flanges, Threaded Connections, And Process Drains at Petroleum Refineries And Chemical Plants

- Pump And Compressor Seals At Petroleum Refineries & Chemical Plants

- Storage of Organic Liquids - Steam-Enhanced Crude Oil Production -~ Wastewater Separators - Crude Qil Production Sumps - Steam Drive Crude Qil Production Wells - Oil Field Drilling Operations - Inorgauic Gaseous Pollutants - Hydrogen Sulfide - Gas Turbines - Fuel Burning Equipment - Emissions From Stationary Internal Combustion Engines

The South Coast Air Quality Management District’s (SCAQMD) Rule 1173 is an example of a model rule for control of fugitive emissions of volatile organic compounds from oil and gas production facilities. See Appendix B.

This rule includes leak control requirements, component identitication requirements, operator inspection requirements, and maintenance requirements.

See Section 500 for a brief description of this rule and other prohibitory rules that apply to oil field production in various districts.

July 1992


205.2.3 Enforcement

After a Permit to Operate is issued, the APCD enforcement staff will inspect the facility periodicalIy to determine compliance. A significant portion of the compliance de termination is usually based on comparing operating conditions included in the Permit to Operate with the status of the permitted equipment.

Such permit conditions are added by an APCD to ensure compliance with district rules and regulations. The inspections may be performed without prior notice and entry denial could result in having the permit revoked.

District enforcement staff may also perfotm a source test, without prior notice, to determine compliance with emission limitations. Deficiencies documented by enforcement staff may be subject to civil and criminal penalties and fmes of up to $25,000 per day (see Section 500).

If the APCD determines that the equipment cannot be operated in accordance with the Permit to Operate, the permit may be revoked or cancelled or an applicant may be required to modify equipment as necessary to maintain compliance.

It should be emphasized that specific requirements vary between districts. Under no circumstances should an equipment owner/operator assume that a permit issued by one district could be valid at another district. It is essential that an operation under permit give ample notice (60 to 90 days) prior to any relocation, whether it be to a location within the txxmdaries of the same district or to another district.

Compliance Determination

Source Test

Relocation

July 1992 Page 200 - 17


SECTlON 200 REFERENCES

1. m of Gil and Gas Production, Dallas, Texas, American Petroleum Insti- tute Production Department, 1976.

2. California Department of Conservation, Division of Gil And Gas, California @I. Gas and Gv Publication No. TR03, 1988.

3. California Department of Conservation, Division of Gil And Gas, 76th An- 011 and Gas SUD~MSQ 1990.

1. California Air Resources Board (CARB), The Control of Photochemicrdlv Reactive Wan

. . ic CoC bans and Gas Processine Plants, 1981.

5.L Energy Resources Company, 1976.

6. California Air Resources Board, Air Oualitv Asnects of the Develoument of Dffs ore Gil and Gas Resources, 1982. h

7. California Air Resources Board, Gil and Gas Extract ion. 1989 Emission hrventm.

3. California Air Resources Board, mblv Available Control Technolow for Control of Fuaitive Emissions of Volatile Graanic Comwunds From u Gas Production and Processinu Facilities. Chemical Plants. and Pipeline Transfer Stations, 1992.

Page 200 - 18 July 1992

300 PROCESS AND CONTROL Oil Field Production

Oil field production involves the bringing of crude oil from the subsurface to the surface and preparing it for shipment to the refmery. This process involves drilling, well construction, recovery, product separation, and product storage.

Oil field production occurs onshore and offshore. Although the production process for both onshore and offshore is basically the same, both onshore and offshore am discussed here to emphasize the air emissions differences due to the use of drilling vessels and production platforms in offshore production.

301 ONSHORE OIL PRODUCTION

Onshore oil production, lie offshore oil production involves drilling, well construction, recovery, separation and treatment, and storage.

301.1 DRILLING

In oil drilliig operations, two well types are commonly drill4 exploratory and development. Exploratory wells r&drilled into unknown formations in search of oil and gas. Once oil or gas is discovered in commercial quantity, development wells are drilled to recover as much of the oil or gas as possible.

Typically, wells are drilled with a drill bit having roller cones with chisel-type teeth (the rotary method). The rotary method of drilling requires the use of a large amount of expensive equipment which includes: a derrick, draw works, crown and traveling blocks, steel cables, mud pumps, rotary table, drill pipe, drill collar, and drill bit (see Figure 301.1).’

The well is drilled by chipping away the formation with the rotating cones. Drilling mud is pumped into the hole through the drill pipe to push the cuttings to the surface and to support the sides of the well’

Usually.two or three strings of casing of varying width and length are cemented in the drill hole to protect it from water and loose earth and to protect fresh water zones.’

Before drilling a well, the drill pipe, drill collar, and drilling bit are attached to a square or hexagonal pipe called the kelly, which passes through the kelly bushing. During drilling, the kelly bushing sits in and is turned by the rotary table. Lengths of drill pipe are added as the hole is deepened.’

July 1992 I

Well Types

Rotary Method

Casing

Kelly

Page 300 - 1

Oil Field Production 300 PROCESS AND CONTROL

Figure 301.1 Drilling Rig’

Drilling Mud During the drilling operation, drilling mud (generally a mixture of clay and water especially chosen for physical and chemical properties) is pumped down the drill pipe and out through the drilling bit The mud cools the drilling bit and, after jetting through holes in the bit, picks up the rock cuttings and returns to the surface through the space between the drill pipe and the wall of the hole, known as ihe atmulus. Upon reaching the surface, the mud travels through a screen that removes the cuttings and into a mud pit from which it is pumped and circulated back down the drill pipe to pick up more cuttings.’

Page 300 - 2 July 1992


Simultaneously, a mud cake forms on the wall of the hole. The mud cake prevents mud fluid from flowing into porous rock and, together with the weight of the column of mud, prevents the hole from caving in. The weight of the column of drilling mud also prevents high-pressure gas, oil, or salt water from flowing into the hole.’

Mud weight is controlled by using special weighting material, such as bat-he, salt, bentonite, etc. Different chemicals may be added to the mud from time to time to achieve desired mud properties.’

Occasionally, in areas where formations do not cave in easily and formation pressures are not very high, air is used as the circulating medium instead of mud. When this is done, air compressors are used to supply the volume of air needed to keep the bit cool and to remove the cuttings from the hole.’

When a drilling bit becomes dull, all drill pipe must be removed from the hole so the bit can be changed, a process called tripping. As drill pipe is tripped, it is stacked vertically against the derrick, usually in lengths of 60 to 90 feet, depending upon, the derrick size. Once the bit is replaced, the drill pipe is run back into the hole, and drilling is resumed’

Sometimes it is impossible to install dtilling equipment directly over the desired location. This occurs when the desired bottom-hole site is under a huge building, residential property, a river, or when a group of wells must all be drilled from one location. At such times, wells are directionally drilled with deviations as much as 80 degrees from vertical, and may be bottomed as much as a mile from the surface location.’

Many early wells blew out of control because drillers lacked the necessary equipment and dtilling mud technology to prevent blowouts. Gushers were looked on as natural indicators of discoveries. Often, such flows could not be stopped until reservoir pressures declined. Thus, not only ivere great quantities of oil and gas lost at the surface, but much oil was left unrecoverable in the reservoir because much of the reservoir energy was lost’

Today, the California Division of Oil and Gas requires the installation of blowout prevention equipment on wells during dtilling operations to prevent blowouts. Before such equipment can be installed, pipe called surface casing must be

July 1992

Mud Weight

Drill Pipe

Directional Drilling

Blowouts

Page 300 - 3

Oil Field Productlon 300 PROCESS AND CONTROL

Pipe Line

Surface String

Intermediate String

cemented in the hole to anchor the equipment The amount of surface casing used depends upon factors such as expected well pmssmes, the depth of fresh water, and the competence of the strata in which the well casing will be cemented. Thus, surface casing may be cemented at depths as shallow as 200 feet or as deep as 1,500 feet.’

Air pollution control districts may have rules that govern oil field drilling operations. For example, Ventura Comity Air Pollution Control District rules have requirements for drilling operations. These operations include activities powered by nonvehicular internal combustion engines for the purpose of drilling or redrilhg oil we&, injection wells, or gas wells. The Ventura County rule requires these operations to be powered by grid power or meet certain NOx emissions requirements.

301.2 WELL CONSTRUCTION

After the weIl has been drilled, it is constructed. An oil well may best be described as a pipe line reaching brn the top of the ground to the oil-producing formation. It is through this pipe line that oil is brought to the surface. This pipe line is a series of joints of a special kind of pipe (casing) screwed together to form a continuous tube or string for the oil and gas to flow through. A sketch of a well is shown in Figure 301.2.’

It is necessary to protect the hole from underground water and hole collapse. Also, the fresh water xones must be protected from produced fluids. To provide this protection, usually two or more strings of casing am cemented in the hole. The first and larger of the casings is called the surface string. This casing will extend from the surface to a depth great enough to keep surface waters and loose earth liom entering the well. The length of the surface string will vary from 200 ft. to 1,500 ft. depending upon the local conditions encountered.’

A second protective string may be used. This casing is called the intermediate string. These strings are sometimes run to allow higher mud weights or to avoid lost circulation when drilling into abnormally pressured zones.

0 - 4 July 1992

300 PROCESS AND CONTROL

I_ Oil Field

Pmduction

PACKER

WELLHEAD CONNECTIONS

aGROUND LEVEL

=‘ CEMENTED

NNUIARSPACE

?-OIL STRING CEMENTED

Figure 301.2 A Typical Well2

July 1992 Jage 300 - 5


Oil String

Liner

Cementing

Tubing

Because the casing and liner must remain in a well for a long time and their repair or replacement would be costly, another string of pipe is placed in the well through which the oil is produced This is called tubing and is used as the flow string. During the later life of the well, the same tubing may be used to support a pump or for other means of artificial lift Tubing sizes range from 1 l/4 to 4 l/2 inches in diameter. The tubing is suspended from the wellhead (surface) and usually reaches to within a few feet of the producing interval. Tubing is used as the flow string because casing is usually too large to permit

Page 300 - 6 July 1992

The final string of casing, called the oil string, will usually extend from the surface through the surface and intermediate pipe, to the top of and sometimes through the producing zone at total depths of 20,000 ft. or more. Because both strings of casing are subject to large pressures and forces, it is necessary that the casing string be carefully designed and properly run into the well.’

The methods of preparing an oil well to produce are many and are governed by the kind of oil reservoir. Jf the well is bottomed in hard formations, the oil producing zone may be left entirely open, with no perforated casing or liner used to protect the hole. In loose, soft sands it may be necessary to cement the oil string at the top of the producing zone and use a slotted or even a gravel-packed liner set through the oil sand This liner is a string of casing that does not reach to the surface and is usually suspended, or hung, from the bottom of the oil string.’

The purpose of the liner is to keep sand and solids out of the well, yet allow the passage of oil and gas into the well. In csse there are several oil producing zones at different depths, the oil string of casing may be run the entire depth of the well, then gun perforated or jet perforated opposite the horizon to be produced Gun perforating is done by shooting metal bullets through the casing so that holes are left in the casing at the desired depth. Jet perforating uses special shaped charges rather than bullets to perforate the casing.’

One of the most common types of completion consists of setting the oil string casing through the producing formation, cementing it in place, and then perforating both the casing and cement into the producing formation.’

Another type is multiple completion where production is possible from different pay zones through the same well bore. This affords a means of obtaining the maximum amount of oil with the minimum use of casing and time.’


the well to flow efficiently, or (in some cases) to maintain continuous flow. Tubing is also required in a pumping well to support the pump.’

Tubing packers are sometimes used in the tubing string to seal off the space between the tubing and the oil string of casing. This is done psrticularly in wells where there are high reservoir pressures. By sealing off this space the casing is not exposed to high pressure, and the chances of a casing failure are reduced. Tubing anchors and packers also support part of the weight of the tubing in the casing and prevent the tubing string from “working” or moving up and down.’

Sometimes it is both practical and economical to drill a small diameter hole and use conventional tubing~as casing in completing a well. This is called a tubingless completion since no retrievable inner string of tubing is used to conduct fluids to the surface. The casing is cemented from bottom to the top and perforated opposite the pay zone. The equipment used is essentially the same as a conventional well, including a float collar, guide shoe with back pressure valve, and landing nipple. Tubingless completions with pipe as small as 2 718 inches in outside diameter provide for well control, well stimulation, sand control, workover and an artificial lift system.’

301.2.1 The Wellhead

The wellhead is the equipment used to maintain surface control of the well. It is usually made of steel, cast or forged, and machined to a close tit; and it forms a seal to prevent well fluids from blowing or leaking at the surface. See Figure 301.3.

NOTE The wellhead contains many fittings and seals and is often a point where many air pollution control district inspectors search for emissions.

The wellhead is sometimes made up of many heavy fittings with certain psrts of the well head designed to hold pressures up to 20,000 psi. Other wellheads may be just a simple assembly to support the weight of the tubing in the well, and may not be built to hold pressure.*

Oil Field Production

Tubing Packers

Tubingless Completion

July 1992 Page 300 - 7

Oil Field Oil Field Production Production 300 PROCESS AND CONTROL 300 PROCESS AND CONTROL

Page 300 - 8

TUBING HANGER

TUBING HEAD

- CASING HANGER

CASING HEAD

TUBING

ilNG INNER CASING lNTERMEDlATE CP

SEALING MEDIUM

CASING HANGER

CASING HEAD

OUTER CASING

Figure 301.3 A Typical Well Head Assembly2

le kind of head and cotiguration to be used is determined by well conditions. le high-pressure wellhead is required where formation pressures are extremely gh. Pressures higher than 20,000 psi have been found in some fields,

July 1992


requiring the use of a heavy wellhead. In stripper fields, or where production and pressures are very low, the simple wellhead may be used if only small amounts of gas are produced with the oil2

The wellhead is formed of combinations of parts called the casing head, tubing head, Christmas tree, stuffing box, and pressure gauges.’

During the drilling of the well, as each string of casing is run into the hole it is necessary to install heavy fittings at the surface to which the casing is attached. Each part of the casing head is supported by a part of the casing head which was installed at the top of the next larger siring of casing when it was run2

Each part of the casing head usually provides for use of slips or gripping devices to hold the weight of the casing. The head provides a way of sealing between &casing strings to prevent flow of fluids. Openings are usually provided for reducing gas pressure which may collect between or within casing strings. Also, the openings (commonly called gas outlets) may sometimes be used for production of the well when oil is produced through the casing.”

The casing head is used during drilling and workover operations as an anchor ~for pressure-control equipment which may be necessary during such work.2

The tubing head is similar in design and use to the casing head. Its most important purposes are to:

1. Support the tubing string 2. Seal off pressures between the casing and inside of tubing 3. Provide connections at the surface with which the flowing

liquid or gas can be controlled

The tubing head is supported by the casing head, where casing heads are used.2

In many low-pressure or pumping wells that have only one string of casing, the casing head is not used and the tubing head is supported on the top of the casing at or near ground level. Tubing heads vary in construction depending upon pressure.2

The tubing head must be easily taken apart and put together to make well- servicing operations easier. Many different types have been developed for use

Casing Head

Tubing Head

July 1992 Page 300 - 9

011 Field PrOduction 300 PROCESS AND CONTROL

Christmas Tree

Choke

Fugitive Emissions

uuder high pressures, with different designs and pressure ratings to fit expected well conditions.*

Wells which are expected to have high pressures (or corrosive gases) are usually equipped with special heavy valves and control equipment above the casing head or tubing head before such wells are completed- This group of valves controls the flow of oil and gas from the well, and is called a Christmas tree because of its shape and the large number of fittings branching out above the well head?

Pressure gauges are usually used as a part of the well head and Christmas tree to measure the casing and tubing pressures. By knowing the pressures under various operating conditions, it is possible to have better well control.2

The cutting effect of very fine sand particles or high-speed liquid droplets in nigh-pressure wells may cut out valves, fittings, or chokes. Because the choke is the point at which well control is maintained, the pressure drop and cutting action are most damaging to the choke. When replacing the choke, the flow valve upstream of the choke is closed, the pressure in the line bled off, and the choke replaced- When sand production is anticipated, scrubbers or knockouts are often installed upstream from the choke to remove sand.’

When the flow valve becomes cut and needs replacement, the master gate is closed, the pressure bled off, and the flow valve replaced. Thus, by not opening and closing the flow valve and the master gate too often and by having most of the cutting action at the choke, it is usually possible to use the same flow valves and master gates for the life of the well. r

Because of the valves, flanges, and threaded connections on the wellhead, fugitive emissions from the oil, water, and gas flow are a possibility. This is why it is important for sources to have a routine program of inspection and repair of equipment to detect and eliminate conditions that may result in a breakdown. Most air pollution control districts have rules that control liquid and gaseous emissions. Inspectors use hydrocarbon detectors and soap solutions to detect gaseous emissions and liquid organic leaks. *

Page 300 - 10 July 1992

300 PROCESS AND CONTROL Oil Field z Production

301.3 PRIMARY OIL RECOVERY

The oil industry first develops oil-gas deposits from formations that have comparatively high porosity and sticient permeability. For example, formations with the capacity to be penetrated by liquids and gases. Rocks with such properties are called reservoirs. Oil reservoirs are sandstones, limestones, dolomites and other permeable rocks, which are isolated from the basic rock mass by such impermeable rocks as clay or shale. The oil deposit is bounded below, as a rule, by water-saturated rocks, and quite often gas accumulates above the deposit, forming a gas cap.”

When discovered, a crude oil reservoir contains a mixture of water, oil and gas in the small pore spaces in the reservoir rock. Initially, the reservoir holds these fluids under considerable pressure, caused by the hydrostatic pressure of the groundwater. At this pressure a large part of the gas is dissolved in the oil. These two fluids, the initial water and the gas in solution, combine to provide the driving force for moving the oil into the well where it is pushed by the underlying pressure. Producing naturally, a field may yield 20 to 30% of the original oil in place but usually much less.3

When pressures in the oil reservoir have fallen to the point where a well will not produce by natural energy, some method of artificial lift must be used.

301.3.1 Artificial Lilt

Common artiticial lift techniques include rod-beam pumping, gas lift, hydraulic pumping, and electrical submersible pumping, subsurface hydraulic pumping, and plunger lii

Rod-beam Pumping

Rod-beams (sucker rods) are solid high-grade steel rods that are run inside of the producing tubing string to connect a subsurface pump to the pumping unit or jack These sucker rods are made in various sixes (e.g., ln inch, 7/8 inch, and 1 l/8 inches) and are usually 25 to 30 feet long.2

The pumping unit is a complete set of surface equipment necessary to impart an up and down motion to the sucker-rod suing, to which is connected a bottom- hole pump. See Figure 301.4.2

July 1992 I

Reservoirs

Hydrostatic Pressure

Pumping Unit

Page 300 - 11


Prime Mover

Stuffing Box

Speed reduction between the prime mover (1) and the pitman crank (4) is accomplished by a combination of V-belt drive and gear reducer. With an engine speed of 600 revolutions per minute., a speed reduction ratio of 30 to 1 is necessary to operate the tit a 20 strokes per minute. The crank (3) is rotated by the slow-speed shaft of the speed reducer. with one end of the pitman coMected to the crauk and the other end to the walking beam (5). the rotation is changed to the up-and-down motion of the walking beam necessary to operate the pump.*

The power plant or prime mover may be either a gas engine or electric motor. The size depends upon the power necessary to lift the fluid to the surface.2

A set of weights, attached to the crank or to one end of the walking beam, counterbalances the weight of the rods and part of the weight of the fluid which is suspended from the opposite end of the walking beam and helps the power plant lift rods and fluid on the upstroke. The rod string is lifted by means of a cable looped over the horse head and connected to the carrier bar to support the polished-rod pum~.~

Pumping wells need a means of packing or sealing off the pressure inside the tubing to prevent leakage of liquid and gas outside the polished rod (12). Stuff- ing boxes (13) consist of flexible material or packing housed in a box which provides a method of compressing the packing. The stuffing-box packing is replaced by the field pumper when it becomes worn and loses its seal.2

Hydraulic-Powered Rod-beam Pumping

This method involves a means of pumping oil with sucker rods and a bottom- hole plunger-type pump where the rod movement is obtained from high-pressure fluid and a vertical piston. In general, this type of equipment uses a pump, an air balance tank, and a hydraulic cylinder. The polished rod is coupled directly to the hydraulic cylinder piston2

The operation of this equipment is as follows: The pump takes fluid from the air balance tank and discharges it at high pressure to the underside of the piston in the cylinder on the upstroke, and takes suction fluid from beneath the piston and discharges it into the air balance tank on the piston downstroke. This cycle of operation gives the rods the up-and-down motion needed to pump oil to the

Page 300 - 12 July 1992


Eli

Oil Field Pmduction

1 - Prime Mover or Power Plant 2 - Gear Reducer 3 - Crank And Counter Weight 4-pitman 5-WalkingBeam 6 - Horse Head 7 - Counter Weight 8 - Sampson Post 9 - Bridle 10 - carrier Bar 1 1 - Polished Rod Clamp 12 - Polished Rod 13 - Stuffmg Box 14-Tee 15 - Tubing Ring 16 - Casing Head 17 - Casing sllings 18 - Tubing String 19 - Sucker Rod 20 - Fluid Level 21- RodPump

Figure 301.4 Artificial Lift Pumping Unit

July 1992 Page 300 - 13


Sucker-Rod

Electricity

Bottom-hole

Hydraulic Lift

Page 300 - 14

surface. This type of lift is suited for long-stroke pumping and for depths in excess of 8,COO feet2

Pneumatic sucker-rod pumping is a method similar to hydraulic sucker-rod pumping except that compressed air is used in the lift cylinder to move the rod string.*

Electrical Submersible Pumping

This equipment consists essentially of a centrifugal pump, the shaft of which is directly connected to an electtic motor. The entire unit is of such a sire that it may be lowered to the bottom of the well together with an insulated cable from the surface, which supplies electricity to the motor. Operation is controlled by a control box at the surface. In operation, the motor causes the pump to revolve so that impellers in the pump apply pressure upon the liquid in it. The total pressure developed by the pump forces fluid through the mbing to the surface?

Subsurface Hydraulic Pumping

This is a method of pumping oil from wells using a bottom-hole pump without sucker rods. This method uses a bottom-hole production unit consisting of two principal parts: a hydraulic engine, and a pump directly connected to the engine. Surface power is supplied from a standard engine-driven pump.2

This system of hydraulic pumping uses two strings of tubing alongside one auother or a small string inside the other. Clean crude oil from the high pressure pump goes downward through the large size tubing to the engine and moves a power piston connected to the production plunger in the bottom-hole pump. Fluid from the well and the exhausted power oil become mixed and return to the surface storage through the smaller tubing. The power oil is drawn from the top of a settling tank at the surface storage-tank battery?

This type of pumping unit may be used to pump several wells from a central source. Hydraulic lift has been successfully used to lift oil from depths greater than 15,000 feet. Maximum capacity of such equipment is dependent upon well conditions (sire of tubing strings, ability of the well to produce).r

Another type of hydraulic pumping well system, called a casing type free pump, requires only one string of tubing set on a casing packer with power fluid going

July 1992

300 PROCESS AND CONTROL <,

Oil Field Pmduction

down the tubing string and power fluid and production being returned in the tubing casing annulus.*

Closed power fluid systems axe being used where. there is limited surface area, such as platforms, or where it is impractical to obtain consistently clean power fluid. This system requires an additional string of tubing to permit return of the power fluid separate from the produced well fluid.*

Gas Lilt

Gas lift is a method of producing oil, in which gas I@CT pressmc is used to lift the well fluids.

Gas lift is accomplished by one or a combination of the following processes:

1. Aeration (mixing of the gas and liquid) of the fluid column in the well 2. Expansion of compress&i gas 3. Displacement of fluid by the compressed gas I

Present gas lift practices include the use of specially designed gas lift valves which are installed on the tubing string. These valves are placed in openings spaced along the tubing string and are run to provide an opening between the casing and tubing. Gas lift valves can also be run in side pocket mandrels and pulled and replaced by means of a wire line unit.*

In operation, gas ‘under pressure is injected into the space between casing and tubing and enters the tubing through the gas lift valve.’ Fluid that is standing in the tubing above the gas inlet port is displaced, lightened by mixing with the gas, and is raised to the surface by the expanding gas. If the well is able to maintain a column of fluid above the point of injected gas, the well is said to be under continuous-flow gas lii. In a well where considerable time is needed for fluid to build up in the tubing, gas is injected into the well in batches which brings the fluid to the surface in slugs. This type of production is known as the intermittent-type gas lift system.*

Gas Lift Valves

Continuous Flow

July 1992 Page 300 - 15


Compressed Gas

Pressure Decline

Plunger Lift

This is a method of recovering oil using a steel plunger, or swab. The plunger is propelled from the lower end of the tubing string to the surface by compressed gas which enters the tubing through one or several gas inlet valves spaced at intervals in the suing. As it rises, a column of oil is lifted to the surface where it is discharged into the flow line. The force of gravity then pulls the plunger to the bottom for another load of oil. A simple valve mechanism controlling gas input to the casing makes the operation of the plunger entirely automatic. Plungers used in plunger lift systems usually have a valve in the plunger that is opened when the plunger bumps the top, and closed when the plunger bumps bottom The tool is also used for paraffin removal.2

301.4 ENHANCED OIL RECOVERY

Secondary and tertiary oil recovery is referred to as Enhanced Oil Recovery (EOR). EOR refers to a variety of methods and techniques which increase the recovery of oil above that which would be obtained through primary recovery. Secondary and tertiary oil recovery methods permit the recovery of a higher percentage of the original oil in place than would have been possible using only primary recovery methods. s

301.4.1 Secondary Recovery

A traditional step for increasing oil recovery is to inject gas or water into or near an oil reservoir to increase reservoir pressure to force oil into production wells3

Even after a decline in pressure has caused the oil recovery rate to become uneconomic, oil production can again be increased through a concentrated injection of fluid into the oil reservoir. Historically, these techniques have been called secondary recovery because the fluid injection results in a second crop of oil from the reservoir3

Essentially the secondary methods are aimed at maintaining reservoir pressure at levels adequate to prevent production cut off beyond the point at which the reservoir’s inherent driving forces cease to be effective.’

The major secondary recovery methods include: waterflooding and immiscible gas injection or combinations of both.

Page 300 - 16 July 1992

300 PROCESS AND CONTROL 011 Field Production

Waterflooding

After a decline in pressure from the water drive or pressure maintenance, production can be increased through a technique called waterflooding, which is the injection of water through injection wells to push crude oil toward producing wells.’

Water is pumped into the productive stratum in a volume equal to or greater than the volume of oil extracted. As a result the formation energy in the deposit is kept at the optimum level. The fountain time of the well is prolonged, which substantially reduces the volume of drilling operations and the cost of the oil.3

c.

In waterflooding, treated water is injected into the oil-bearing part of the rescr- voir to force oil to flow toward the production wells. Water, because of its high density, relatively efficient displacement characteristics and its nearly incom- pressible nature, can raise the reservoir pressure quickly. This is an important factor in rapidly restoring the oil productivity of older wells in advanced stages of depletion. Most waterfloods are designed so that incrcased,oil production ,$I older wells occurs within a period of six months to a year.’

Water, however, has two major problems that impede its efficiency. Fit, it does not flush all of the oil from the pore spaces as it moves through the reservoir rock. Because water and oil do not~mix, 25 to 50% of the oil is left behind in the form of small droplets held within the larger pores. Tbis problem may be prevented by the use of additives to reduce or eliminate the nonmixing nature of water and oil.3

The second limitation is that the advancing water front generally bypasses significant portions of the reservoir due to difficult well placements or unex- pected geological configurations. This lack of a perfect sweep efficiency is responsible for leaving behind additional crude oil in areas not reached by the waterflood. Altogether, 50 to 70% of the original oil in place remains after watet%oding.3

Injection Wells

Pore Spaces

Geological Configura- tions

July 1992 Page 300 - 17


Viscosity

Mobility Ratio

Capillary Forces

Immiscible Gas Injection

The secondary recovery technique of injecting natural gas into the reservoir has been employed since 1900. This low-pressure injection of gas is used to maintain reservoir pnxsure to prevent production cut-off and thereby increase the rate of production.’

In general, gas which is immiscible with the reservoir oil is not as efficient as water. The lower viscosity of the gas causes an increase in the by-passing of the oil, both within the individual pore space and in large sections of the reservoir3

For many years, gas reinjection methods had been widely utilized. The govem- ment practice of capping natural gas prices substantially below its energy equivalent value resulted in an economic situation where it paid the operator to reinject associated gas even when the increase in oil recovery was even rather marginal.3

A major problem with gas reinjection is its inefficiency. For typical gas solution drive fields, reinjection~ will only increase oil recovery from the neighborhood of 15 to 20% of the original oil in place to perhaps 25%, still leaving the great bulk of the oil in the ground This is due largely to the unfavorable mobility ratio. The mobility of a fluid in a reservoir is equal to the ratio of the permeability to viscosity of that fluid The mobility ratio, then, is equal to the ratio of the mobility of the displacing fluid to the fluid being di~placed.~

Occasionally, gas reinjection can be used in conjunction with waterflood where gas is injected into the cap with water. The gas prevents the oil kom pushing into the gas cap, thus wetting additional rock however, this technique is useful only in certaiu rather specialized cases. Even then, the differences with and without gas injection are not striking.3

Gas injection can also be used sequentially in conjunction with waterflood. In water wet reservoirs, capillary forces will tend to pull the water through the narrow passages, bypassing the wider passages. The opposite will tend to happen with gas. Thus, in some cases, extra production can be obtained by cycling gas and water injection.’

Page 300 - 18 July 1992


301.4.2 Tertiary Recovery

Tertiary recovery of crude oil refers to chemical and/or thermal treatment of oil reservoirs to increase the production of crude oil beyond those amounts tecover- able by natural reservoir energy or by artificial maintenance of reservoir energy. Such high recovery techniques seek to overcome the inefficiencies of conventional primary and secondary methods.

The presence of substantial quantities of oil in the reservoir, even after a suc- cessful waterflood, has prompted interest in tertiary recovery methods to recover a third crop of oil. These methods make use of substances added before or during fluid injection to increase the recovery efficiency of the injected water or g=

Tertiary oil recovery include miscible methods and thermal methods.

Tertiary Miscible Methods

The miscible methods are aimed at reducing the surface tension forces between the oil and the driving fluid and include:

- Hydrocarbon miscible displacement - carbon dioxide miscible displacement - Polymer-augmented miscible displacement - Miceller miscible displacement

The hydrocarbon miscible displacement process involves introduction of a fluid (solvent) that will completely dissolve the reservoir oil, eliminating the forces that cause oil retention in the rock matrix, and sweep the solvent-oil mixture to the producing well. This solvent can be alcohol, refined hydrocarbons, condensed hydrocarbon gases, carbon dioxide, liquefied petroleum gases or exhaust gas. 4

Fit a slug of solvent (miscible with the reservoir oil) is injected- This is followed by injection of a liquid or gas to force the solvent-oil mixture to the producing wells. Unfortunately the solvent (miscible slug) becomes concentrated with oil as it moves through the reservoir, changing its composition and diminishing its ability to dissolve oil; as a result, theoretical recoveries are never achievedP

Reservoir Energy

Solvent

July 1992 Page300-19

Oil Field Production 300 PROCESS AND CONTROL’

Enriched Gas

Lean Gas

Permeability Streaks

There are three different miscible hydrocarbon displacement processes for impmved oil recovery. The first method, known as the miscible slug process, consists of injecting a slug of liquid hydrocarbon followed by natural gas, or gas and water, in order to drive the slug through the reservoir?

The second technique, known as the enriched gas process, consists of injecting a slug of enriched natural gas followed by lean gas or lean gas and water. The slug is enriched with ethane through hexane.4

The third method, known as the high pressure lean gas process, consists of injecting lean gas at a high pressure in order to cause retrograde evaporation of the crude. oil and formation of a miscible phase, consisting of C, - C,, between the gas and oil. Thus, the main difference between enriched gas and high pressure lean gas processes is that in the former, C,-C, components are transferred from the oil to the gas?

Hydrocarbon miscible displacement suffers from several problems. Since high pressures are required, the method is limited to fairly deep fields both to avoid the cost of mpressuring and the threat of blowing through the overburden. The method is energy-intensive both because the siug is hydrocarbon and more importantIy because of the amount of compression required. Most important, however, the method suffers from a very poor mobility ratio. The mobility ratio is a measure of the ease with which the driving fluid moves through the formation relative to that with which the reservoir moves. 3

If this ratio is high, the driving fluid tends to finger the oil and channel through high permeability streaks. The net effect is that the driving fluid begins to recirculate rather than expulse oil. This is much the same problem that plagues waterflocd. The resultant implication is that miscible hydrocarbon displacement is limited to very high API oils where the mobility ratio is not so unfavorable.3

Carbon dioxide miscible displacement is the injection of CO, to dissolve in crude oil, swell it, reduce its viscosity, and vaporize it into the CO, phase, resulting in high displacement efficiency of the contacted oil. Banks of water ahernated with injected CO,may be used to drive the oil toward producing wells. When CO, begins to appear at the producing well it is recovered, cleaned of impurities, pressurized and reinjected.’

Page 300 - 20 July 1992


Though carbon dioxide is not completely miscible with most crude oils, it is soluble with both crude oil and water at twzrvoir temperatures and pressures. When carbon dioxide is injected and mixing occurs, the viscosity of the crude oil is reduced. The carbon dioxide increases the bulk and relative permeability of the oil, swelling it so that reservoir pressure is increased and the oil flows more readily toward the production welk3

Thxee variations of CO, miscible displacement are presently employed by the petroleum industry for tertky oil recovery:

1. Injection of carbon dioxide in a slug, followed by water or carbonated water

2. Injection of carbonated water directly 3. Injection of carbon dioxide at high pressure to achieve mixing directly with

the reservoir oil and-the formation of an oil-miscible slug in the formation

The major factors cOntributing to oil recovery in carbon dioxide displacement are formation of a miscible slug in in situ modification of viscosity and changes in oil density and compressibility of fractions. By maintaining the slug in a single dense phase, its solubiity with crude oil is increased considerably. Crude oil viscosities ranging from 5 to 90 centipoises can be reduced by a factor between 10 and 100 times under high injection pressures of carbon dioxide. After a carton dioxide displacement has been completed, the gas comes out of solution to some degree due to reduction in pressure, creating a further gas drive within the reserv~ir.~

Carbon dioxide miscible displacement is favored by high API gravity, requires a fair amount of pressure, and is relatively insensitive to permeability. A basic and continuing problem, however, has been mobility control, which indicates that CO, effectiveness is sharply dependent on reservoir homogeneity. The mobility ratio, while not as bad as that for high-prekre hydrocarbon, is still quite unfavorable for most reservoirs?

Poor mobility ratios lead to poor conformance and effectively confine the method to light crudes. Also, as gravity decreases, the pressure required to obtain miscibiity increases. Certainly, any oil which was not reached by the preceding waterflood due to limited sweep efficiency will not be reached by CO, in the absence of additional drilling.3

July 1992 I Page 300 - 21

Miscible c Displace- ment

Mobility Control


300 PROCESS AND CONTROL e

Thickened Water

Micellar Solution

Polymer-augmented waterflooding is the addition of high-molecular-weight chemicals (polymers) to thicken water in water-flooding, thus reducing the tendency of water to by-pass oil in less permeable portions of the reservoir3

This process employs an additive to the initial injection water to increase the viscosity of the displacing flmd. The influence of this thickened water on the efficiency of oil displacement is minimal at best since the thickened water pushes the connate water from the acmal displacing fluid It does, however, cause the reservoir conformance (the fmctiou of the reservoir swept by the invading fluid) to be increased. Thickened water can be used alone or it may be used as a following agent for any other miscible process3

Approximately 40% pore volume of a solution of polyacrylamide is usually injected for mobility control. The concentration of the polymer varies from 2,000 ppm initially to 100 ppm at the end of the injection.’

The technology of micellar-polymer flooding is similar in operation to a waterflood (although considerably more complicated), but it relies on chemical and physical forces to effect oil displacement3

Certain chemicals sre used which wash the oil out of the reservoir rock the same way that laundry detergent acts on greasy stains. Chemical techniques such as micellar-polymer flooding may produce about half of the recoverable tertiary oil. In a micellar flood, a slug containing a high concentration of surfactant is injected into the reservoir. The slug is called a micellar solution because the large concentration of surfactant causes the formation of micelles. One of the unique properties of an oil-external microemulsion is that it is miscible with the oil and, therefore, displaces the oil in the formation by dissolving it in the slug.3

A second displacement mechanism, common to low-tension floods (dilute surfactant) or to the leading edge of the micellar flood is related to the reduction of the interfacial tension between oil and water as a result of the presence of the smfactant in the micellar slug. As the interfacial tension is reduced, the capillary forces acting to hold the oil within the reservoir ate reduced. When the interfacial tension is reduced to a very low value, the capillary forces are no longer sufficient to retain the oil and, consequently, it flows freely out of the p-es.”

Page 300 - 22 July 1992


A typical micellar flood project proceeds in four distinct phases. They are: I

1. Rreflush, which is injected into the reservoir to adjust the salinity of the formation to be compatible with the optimum surfactant system.

2. Micellar solution (slug) including surfactant, cosurfactant, hydrocarbons, and electrolytes, which in combination accomplish the miscible displacement of oil from the formations.

3. Mobility control solution (buffer); a low salinity water/polymer solution used to uniformiy push the micellar slug through the formation in as close to a piston-like. flow as possible.

4. Water drive, which pushes the micellar slug and mobility buffer through the reservoir to the production well3

Tertiary Thermal Methods I

c

Thermal recovery pertains to oil recovery processes in which heat plays a principal role. The most widely used thermal techniques are cyclic steam injection, steam drive, and in situ combustion (fireflooding).. Because of the strong temperature dependence of oil viscosity, these thermal methods find greatest application in the recovery of extremely viscous, low API gravity crudes, for which the usual displacement methods such as water flooding are lmfnlitflll.’

Heat is applied to the crude to: - Reduce the viscosity of the crude - Activate a solution gas drive in some instances - Result in thermal expansion of the oil and hence increased relative

permeability - Create distillation and in some cases, thermal cracking of the oil

Much of the oil in California oil fields is very viscous at underground reservoir temperature and therefore will not flow readily into production wells. The recovery of this viscous crude oil is commonly aided by injecting steam into the reservoir. The steam is injected in two ways, cyclic steam injection and steam drive?

Cyclic steam injection (also called huff and puff and steam stimulation) is where steam is injected directly into the reservoir through the production wells to heat the surrounding area. The condensation and cooling of the steam heats

July 1992 Page 300 - 23


Oil Viscosity

Steam Stimulation

In-Situ Combustion

Geometric Patterns

Steam Saturated Zone

Page 300 - 24

the reservoir rock and oil, reducing the oil viscosity and thus increasing production rates. After two or three weeks, the steam injection is stopped and the heated oil is produced from these same wells. After the hot oil production has ended, a new cycle may be initiated. The time period of the cycles is on the order of six to twelve weeks or longer. These reservoirs are usually shallow and the producing wells are drilled on very close spacing because the head does not penetrate far from the wells.3

The primaxy benefits of the process are the reduction of oil viscosity near the well and the cleaning of the well bonz3

Steam stimulation is basically limited to shallow fields. Close well spacings are required and well costs rise rapidly with depth as do injection pressures. Much more importantly, however, the natural temperature gradient generally makes steam stimulation superfluous at depths of more than 3 or 4 thousand feet.’

Steam stimulation, by its very nature., is a limited process. Afterseveral cycles (perhaps over 2 to 3 years), &area in the immediate vicinity of a well has been flushed out and the wells fail to respond to further stimulation. It is rarely possible to recover more than 10% of the original oil-in-place via steam stimulation. Therefore, the real payoff via thermal methods will have to come f?om steam drive or in situ combustion. However, steam stimulation is almost univer- sally the first step in applying thermal measures to a field. It is common practice after a number of succeeding steam stimulation cycles to convert from this method to steam drive.3

In Steam drive or steam flood, high pressure steam is continuously injected into a reservoir through other wells arranged in geometric patterns near the steam injection wells. Most steam drive operations are developed on 2 l/2,5, or 10 acre patterns. Diagrams of various steam drive patterns are shown in Figure 301.5. A diagram of the steam drive process is shown in Figure 301.6.’

In steam drive, the injection of steam forms a steam-saturated zone in the reservoir. As the steam-saturated zone expands, steam distillation of the oil occurs. The temperature of the steam declines as it moves away from the injection well, and an advancing hot-water zone is formed. The advancing hot-water and steam-saturated zones increase the mobility of the oil by decreasing its viscosity; the steam thermally expands the oil and pushes it to the production wells.5

July 1992


TWO-SPOT THREE-SPOT

.SEVEN:SPOT

INVERTED NORMAL SEVEN-SPOT NINE-SPOT

o PRODUCTION WELL

A INJECTION WELL --- PAlTERN BOUNDARY

REGULAR FOUR-SPOT

DIRECT LINE DRIVE

Figure 301.5 Steam Drive Well Arrangements5

FIVE-SPOT

STAGGERED LINE DRIVE

INVERTED NINE-SPOT

July 1992 Page 300 - 25

Oil Field Production 300~ PROCESS AND CONTROL

Figure 301.6 Seam Drive Process’

Page 300 - 26 July 1992

-


Several critical parameters must be considered to ensure favorable results from a steam drive project:

- Reservoir depth should be less than 3,000 feet - Reservoir thickness should not be less thsn 30 feet - The oil gravity should be 12~ - 25 AFT, with viscosity about 1,000

centipoises at reservoir tempemmre -Steamshouldbeinjectednesrthebaseoftheoilxone - Formation permeability should be higher than one darcy

In practice, the performance of a steam drive operation is different from the theoretical situation. This difference exists because a uniform radial flow of steam and heat in the reservoir around the injection well does not usually occur. Instead, the steam forms channels in the reservoir and heats the oil next to each channel; oil displaced by and entrained in the flowing steam is brought out of the production well?

Steam usually breaks through near by production wells, within three to six months after the initiation of steaming. As steam is continuously injected, the finger-like steam channels widen, and steam reaches more production wells. Forty percent or more of the original oil in place may be recovered using steam drive. Conventional primary recovery techniques result in the recovery of only about 10 percent of the original oil in place.5

Steam enhanced methods are of particular importance in California. In 1990, incremental oil production from all types of enhanced oil recovery accounted for about 229.7 million barrels, or about 66 percent of California’s total oil production. Steam stimulation was credited with about 79 percent of all incremental oil production.6

Between cyclic steam injection and steam drive, steam drive causes the most hydrocarbon emissions. Hydrocarbon emissions from steam drive wells come from vents of the producing wells and components such as valves and connections that are subject to the release of fugitive emissions?

Hydrocarbons Tom producing well vents can be collected in a steam drive well vent vapor recovery system. A typical system schematic is shown in Figure 301.7. A typical system includes a gas gathering system, liquid/gas separators, water-cooled (shell and tube) or air cooled (fm-fan) heat exchangers, and liquid collection tanks5

Channels

Cyclic Steam Injection

July 1992 Page 300 - 27


Gas Gathering System

Air Cooled Heat Exchanger

Steam Generator

Combustion Air

Page 300 - 28

A gas gathering system is a system of piping that directs well vent vapors to a central manifold Hydrocarbons, especially those heavier than pentane, tend to condense in gas gathering lines and are transferred directly to a collection tank. Became about 50 percent of well vent vapors are condensed in gas gathering lines, gravity flow is provided to avoid liquid traps and the resulting back pressnre that could affect production rates5

Two-phased streams are dimcted to a separator vessel where further condensation occurs and where liquids are separated from gases. Uncondensed gases may then be dkxted to a shell and tube heat exchanger or to an air-cooled heat exchanger where additional condensatron occurs. A shell and tube heat exchanger is a water-cooled exchanger where gases are passed through a cylindrical NIX bundle.5

Water is circulated around the tubes, allowing heat transfer from the gas stream to the water. The gases are. cooled and partial condensation occurs. An air- cooled heat exchanger, or fin-fan cooler, is similar to an automobile radiator cooled by fan. A diagram of a fin-fan cooler is shown in Figure 301.8. Ambient air is forced by a fan across a bank of externally finned tubes. The well casing vapor stream is circulated through the system of finned tubes, and part of the stream is condensed.’

Collected liquids (oil and water) am transferred to a collection tank. The uncondensed gases are either discharged into the amrosphere or injected into a steam generator. If a steam generator is not near a vapor recovery system, a flax may be used to improve the efficiency of the vapor control system The vapor control efficiency of the above described system will vary with vapor composition and size of heat exchangers. A properly designed system can achieve an efficiency of 93 to 99 percem.S

The injection of well vent gases into steam generators is practiced by some oil companies. Most steam generators sre equipped with dual fuel burners that can combust liquid and gaseous fuels simultaneously. Most steam generators are equipped with instruments to measure the concentration of oxygen in the stack gas and thereby indicate the amount of excess air supplied to the steam genera- tclr.~

The combustion air supply to the steam generator would have to be adjusted to account for the oxygen requirements for the combustion of the vented hydrocar-

July 1992

l

I)

.., I


Figure 301.7 Schematic of Well Vent Control System5

I

July 1992 Page 300 - 29


bans. Some modification of piping would also be necessary. A compressor would usually be required to increase the gas stream pressure to 10 - 15 psig. The overall emission control efficiency of a vapor control system involving the combustion of gases in a steam generator would be greater than 99 percent. Some steam generator burners would have to be modified to allow the burning of well vent gases. A typical steam generator burner modified to allow the simultaneous combustion of liquid and gaseous fuels is shown in Figure 301.9:

The in situ combustion method (not used very much in California) introduces heat into a reservoir through the injection of air into the reservoir to burn some of the oil in place. Typically, air is injected into the reservoir to create a gas saturation high enough to allow the large air flows necessary to sustain combustion. When the air flow is large enough, spontaneous combustion may take place or a downhole heater is used in the injection well to initiate the combustion. The burning oil front should proceed slowly through the reservoir. Higher rates of air injection tend to burn excessive amounts of the oil in the reservoirs and may cause the burning front to oyerride the oil?

A number of zones exist in the reservoir undergoing a fireflood. In each of these zones, dynamic processes occur which determine the rate and amount of additional oil recovered. The burned region is composed primarily of clean, finely grained sand. The action takes place at the buming zone. Here, heat breaks down the oil into coke, which catches fire, and lighter oils are vaporized or move ahead of the burning region. Temperatures &I this zone range from 600 degrees to 1200 degrees F depending upon the reservoir’s physical characteristics and the operating conditions of the project?

Just ahead of the burning front is where coke is produced by cracking and distilling of CIude oil, which dissociates the lighter from the heavier hydrocarbons. The coke residual fractions are composed of high boiling point hydrocarbons containing oxygen, sulfur, nitrogen and trace metals. Molecular weights of these residual fractions range from 300 to 900 grams per mole. These tiactions can represent up to 20% of the crude oiL3

Another zone created in a flreflood consists of light hydrocarbons, which are vaporized by the buming front or other hot regions of the process. As the gases are driven through parts of the reservoir they displace some oil and improve the oil recovery. In situ combustion is sometimes subdivided into forward combustion and reverse combustion.3

SDontaneous Cbmbustion

Zones

Coke

July 1992 Page 300 - 31


I Figure 301.9 Schematic of Modified Steam Generator Burned

Page 300 - 32 July 1992

C 300 PROCESS AND CONTROL Oil Field Production

<1

The forward combustion process requires the drilling of air injection wells and oil production wells. Although ignition in the reservoir may occur spontane- ously at the injection wells, a heat source is usually employed to start combustion.’

The reverse combustion process resembles forward combustion, except that the reservoir oil is ignited at the production wells rather than at the injection wells. A possible use of the process is in the recovery of tars, since the high temperature of reverse combustion can produce thermal cracking which increases oil API gravity and drastically reduces oil viscosity. Furthermore, the forward combustion process is not readily adaptable to recovery of tars, since condensation of vaporized hydrocarbons may impede or completely stop the flow of combustion gases from the oxidation zone to the production well3

301.5 SEPARATION AND TREATMENT

After the well fluids and gas reach the wellhead they am transferred to a treatment plant At the treatment plant the crude oil, natural gas, produced water, and solid contaminsnts are separated and treated. A treatment plant may be simple or complex;and can take many different forms depending on treatment needs. See the flow diagram of onshore light crude oil treatment plant in Figure 301.10.

The onshore and offshore operations are essentially the same, except after the oil/water and gas separation (by using separators) the oil and water mixture is piped onshore for further separation and storage. Also, see the flow diagram of the onshore heavy oil treatment plant in Figure 301.11. Typically, the treatment plant includes a well flowline manifold and the following:

- Separators - Free water knockout vessel - Heater (if heavy crude) - Heater-treaters - Wash tanks (gun barrels) - Stock tanks - Wastewater separators or oil/water separators - Sumps, Pits, Ponds - Vapor recovery

Forward Combustion

Reverse Combustion

Tank Battery

July 1992 Page 300 - 33

n 2 ii Ei i 0

QLYCOL CONTACTOR AND HEATER

* Irl-“- I

-. SEAM PUMPER

I t t

TYPICAL GAS LIFT WELL

w QAS UFT COMPRESSOR

TO SALES PIPELINE


Test Separator

Stock Tank

Dehydration Unit

Water Treatment Facility

Gaseous Emissions

3asically, what happens at the treatment plant is as follows:

I. The well fluids and gas mixture flows to a well manifold that connects with each well in the field From the manifold the mixture is directed to either a test or a production separator. A test separator separates and measures the three phases separately and is used to determine the production of each well from the field Under normal conditions, the mixture flows to a production separator, where gas is separated tiom the mixture.

1. From there, the oil/water stream flows to a free water knockout, heater ue-ater, wash tank, and oil/water separation vessels where water is removed from the oil.

3. After suflicient reduction of the water content, the oil flows to an oil storage or stock tank. Upon sale, the oil flows through LAfl units for metering.

3ases removed from the oil during treatment may be vented to the atmosphere, xuned as fuel, or treated and sold Gas collected from separators and oil treat- us, along with vapors from storage tanks, may be processed through a dehydra- ion unit (usually glycol). This unit removes the water from the gas before it is xrt into a sales pipeline or used again in the dehydration process.

The oily water collected from the separators and oil treaters may flow directly to s sump or may flow to a water treatment facility prior to disposal. The water reatment facility reduces the oil content of the water with skimming tanks, dissolved air flotation units, pita filters or a combination of these. The water nay be used on-site, discharged to the surface, or injected back into water fluid injection wells or disposal wells.

Vapor recovery is usually on all of the separation vessels and is piped back to he gas pipeline for dehydration.

At the treatment plant, all of the valves, flanges, threaded connections, piping, and process drams that are on separation equipment or connect different pieces of separation equipment are potential sources of fugitive emissions from the Sl and water flow and separation process. This is why it is important for sources to have a routine program of inspection and repair of components to detect and eliminate conditions that may result in a breakdown. Most sir pollution control districts have rules that control liquid and gaseous emissions.

Page 300 - 36 July 1992

300 PROCESS AND CONTROL 011 Field Pmductlon

Inspectors use hydrocarbon detectors and soap solutions to detect gaseous emissions and usually note a rate of three drops a minute. to determine organic liquid leaks.

The major pieces of equipment and separation methods in the separation process include: separators, free water knockout vessels, heater tmaters, heaters, wash tanks, sumps, pits and ponds. These items are described below.

301.51 Separators

c

The separator or gas trap separates the liquids from the gases. The simplest form of an oil and gas separator is a small tank in which the force of gravity is used to separate the oil and gas. Gil, being heavy compared to the gas, falls to the bottom of the tank and then goes into storage tanks. Gas, being lighter, rises to the top of the tank and goes from there into a gas-gathering system. ’

In addition to using the force ofgravity, modem se.paratorS make use of other forces to get the best possible separation of oil and gas. The way in which each of these forces is used can be better understood by following the flow of a mixture of oil and gas through a separator.2

The mixture of oil and gas enters inlet (A), see Figure 301.12, where it is given a swirling motion by a spiral inlet baffle in the separator space or chamber (B). At this point there are two forces tending to separate me oil from the gas. The first is the effect of gravity; the second is the whirling action, which causes the heavy oil particles to collect on the walls of the separator.2

The gas, which still contains some oil in the form of small drops and spray, rises through chamber (B). As the gas enters the swirl cylinder (C), it moves faster and is again caused to whirl so that the oil is forced against the side of the deflector cone (E). This oil drains down through tubes (F) to the bottom of the separator. After passing through the swirl cylinder, the only oil remaining in the gas is in very small drops. These drops am taken out of the gas by the scrubber dome (G). The gas then passes thmugh another chamber (I-l) and then leaves the separator through the gas outlet (l)?

Oil leaves the separator at the oil outlet (J). The oil level is regulated by a float (L) and control valve, so that liquid covers the drain tubes (F) and the oil outlet

Gas Traps

Baffle

Drains

July 1992 Page 300 - 37

Oil Field Pmduction 300 PROCESS AND CONTROL

A - OIL AND GAS INLET

B-SEPARATOR SPACE OR CHAMBER

C - SWlRL CYLINDER

D -SWIRL-CYLINDER INLET PORTS

E - DEFLECTlON CONE

F - DRAIN TUBES

G-SCRUBBER DOME OR MIST EXTRACTOR

H - DRY GAS CHAMBER

I - GAS OUTLET

J - OIL OUTLET

K - DRAIN CONNNECTION

L - DRAIN-VALVE FLOAT

Figure 301.12 Typical Separator

Page 300 - 38 July 1992


(I). The separator can be cleaned through drain connection (K) in order to remove any sand, mud, or other materiak2

This kind of separator is normally referred to as a vertical-type separator. Sepa- rators of the horizontal type are also common; and, although of different design, they have the same uses as the vertical separator2

Two common symptoms of improper functioning of separators are:

1. The dump lever arm on the float valve leaks, causing gaseous or liquid leaks 2. The float valve has washed out and gas is being sent to the storage tank

instead of liquid. This causes overpressurization of the tank which can cause hatch and pressure vacuum valve blow outs.

These items should be frequently inspected and properly maintained to detect and control emissions.

301.52 Free Water Knockout Vessels

Free water is water produced with oil’that settles out within five minutes while the well fluids are stationary in a settling space within a vessel., Free water, then, is not part of the emulsion and may be readily separated by the force of gravity alone. Free water removal prevents overloading the heating and treating plant For instance, consider that it takes about three and a half times more heat energy to raise the temperature of water than oil. Therefore, if most or all of the free water is removed first, then substantial savings in fuel needed to fii the heater can be made.8

The free water knockout vessel (see Figure 301.13) is used to remove excessive amounts of free water in the flow lines ahead of the treating plant. The many different types of free water knockout vessels range from homemade units to vertical or horizontal units that are capable of either two-phase or three-phase operation. A two-phase free water knockout vessel is designed in such a way that only the free water separates from the oil or emulsion. A three-phase free

Vertical Type

Flow Lines

July 1992 Page 300 - 39


Figure 301.13 Free Water Knockout Vessel8

Page 300 - 40 July 1992


water knockout vessel qarates free water and gas from the oil or emulsion.* In general, a free water knockout is simply a vessel that provides a space for free water to settle out of an emulsion. Often filter material or excelsior is provided to remove particles of oil or emulsion that may be entrained in the water as it passes through the fdter. The free water is automatically drawn off out of the bottom of the unit, and the emulsion or oil passes out the top of the treating system. Thus, all water in a free state is removed, and only the emulsion is handled by the heating or treating systems

3015.3 Heater Treaters

A heater treater (also called a flow treater or emulsion treater) is a device that combines all the various pieces of equipment used to treat heavy or emulsified oil in one vessel. Thus, a heater treater is the vessel in which the effects of chemicals, heat, settling, and, often, electricity are applied to heavy or emulsified oil.’

The heater treater is designed to include in one unit any or all of the following elements: oil and gas separator, free water knockout, heater, water wash, filter section, stabilizing section, heat exchanger, and electrostatic field The basic pattern of a heater treater may be modified to emphasize one of the functions more than the other, depending on the service for which it is designed.8

In vertical heater treaters (Figure 301.14), the emulsion usually passes through a heat exchanger, where it is preheated by the outgoing clean oil. Then the emulsion enters the vessel, splashes over a pan, and falls downward through a downcomer tube. At the bottom, any free water in the emulsion falls out, and the emulsion flows upward through the water, which serves as a washing medium. The water is heated by a fire tube projecting into this compartment.8

After leaving the heated water wash, the emulsion rises into a settling space where water broken out of the emulsion settles out and falls back into the water wash. The clean oil rises and passes through the oil outlet, usually through a heat exchanger to heat incoming emulsion, and then to storage. The water in the bottom of the unit passes out a water outlet to the disposal system!

Horizontal heater treaters operate much like vertical treaters. Generally, horizontal treaters have a larger settling section than vertical treaters and therefore are often used to treat heavier oi1s.S

Flow Treater

Many Functions

Vertical Treaters

Horizontal Treaters

July 1992 Page 300 - 41


EhWLSlON

SIPHON

EMULSION OIL IN OUT

Figure 301.14 Typical Vertical Heater Treaters

Page 300 - 42 July 1992


Electrostatic treaters, often called chemelectric or electrochemical treaters, are similar to horizontal heater treaters except that high-voltage, alternating current, electric grids are add& Electricity is often an effective means of breaking emulsions. In the case of electrostatic tmaters, as the heated emulsion rises through the electric field, the water droplets are given an electric charge.’

When charged, the droplets move about rapidly, colliding with each other with enough force to coalesce into larger and larger drops until they settle out. The clean oil continues to rise to the top of the vessel, where it is collected and removed to the storage tanks.’

Heater treaters should be operated at the minimum temperature commensurate with proper treating. This reduces undue wear on the heating component, which is the part of the treater most susceptible to failure.’

Fireboxes and fire tubes should be inspected at periodic intervals, and a check should be made for accumulation of scale, rust, and corrosive materials. No pattern on the frequency of inspection can be set because the determimng factors are the conditions under which the heater operates. When scale or corrosive materials are noticed, the firebox should be removed and cleaned or replaced, depending on its condition. F’ractically ah oil that must be treated has a certain amount of sludge and entrained solids in it. A bottom drain is provided on most heater treaters that can be opened occasionally to permit removal of sludge and solids.~

The three symptoms of improper timctioning of a treater unit are (1) emulsion is carried over to the stock tanks, or (2) free water is carried over to the stock tanks, or (3) oil is carried into the water disposal tank or system Emulsion in the stock tank is usually an indication that the proper amount of chemical is not being applid*

When free water shows in the stock tank, the water outlet line end valve should be inspected for corrosion and proper operation. Oil showing up in the water disposal system may mean that the water valve is stuck open aud oil is draining out of it, or that the oil outlet on the treater is below the level of the stock tank inlet and the back pressure valve fails to hold a positive pressure on the treater and oil goes through the water outlet.’

Electrostatic ”

Fireboxes

Improper Functioning

Free Water

July 1992 Page 300 - 43


Heating

Tubular Heater

301.54 Heaters

At present, most treating plants do not employ heaters that are separate from other ueatiug vessels; the heater is usually an integral part of a single treating vessel in which heating and treating are both accomplished. However, separate heaters are sometimes used and should be discussed.

There are two types of heaters that are usually used at treating plants, direct heaters and indirect heaters.

Direct Heaters

In a direct heater, the emulsion comes in direct contact with the firebox, or heating element. In general, direct heaters are used to heat noncorrosive emulsions that are under comparatively low pressure. Direct heaters, when operating under proper conditions, are the most efficient type of heater. The efficiency of a heater is determined by figuring out how much gas the heater burned to heat up how many barrels of emulsion to the desired temperature. Four basic types of direct heaters am used in the field: (1) tubular heaters, (2) fluid-jacket heaters, (3) iutemal firebox heaters, and (4) volume or jug-type heaters.*

A tubular heater is similar in construction to a refinery pipe still. Straight tubes that carry the fluid to be heated are suspended within a firebox. The tubes are co~eqed to each other by means of return bends. One or more banks of tubes may be used, depending on the volume of fluid to be heated. The banks of tubes are enclosed within a shell so that the fire from the burner heats the tubes and the fluid flowing tbrough them.*

The pipe tubes should be inspected regularly for corrosion and scale. Directly applying fire to the tubes often causes hot spots that are more likely to corrode and scale up than other spots, especially if flow through a tubular heater is intermittent. During the periods when there is no flow and the fluid is motion- less within the heater, the fluid may be heated to the extent that some of it evaporates, leaving a scale within the tubes.’

Tubular heaters also get plugged up by scale formation from the water being passed through them. Scale deposits from both sources interfere with the transfer of heat from the fire to the fluid, thus lowering the efficiency of the heater,

Page 300 - 44 July 1992


long before the scale becomes thick enough to restrict fluid flow. Tubes can usually be inspected, cleaned, and replaced separately or in groups when neces- W.’

Tubular heaters am best used in systems where flow is steady, pressure is low, and the emulsion being produced has little tendency to deposit scale when heated?

Fluid-jacket heaters are manufactured in both horizontal and vertical models. Both models are very similar, consisting of a cylindrical shell with a large central flue in it The flue serves as a firebox and is surrounded by fluid The fluid to be heated ftlls the annular space between the shell and central flue. Emulsion enters the inlet near the bottom of the heater, is heated by the central flue, and is discharged at an outlet near the top of the heater?

(, Fluid-jacket heaters are susceptible to trouble with burnouts if not cleaned thoroughly at regular intervals. Sediment and sludge must not be allowed to accumulate in the lower, fluid-filled portion of the heater. These heaters are suitable only for light heating loads where the fluid to be handled is noncorrosive and not full of sediment or sltige.8

An internal fmbox heater is usually a horizontal pressure vessel with a removable internal fmbox. The fuebox is constructed so that the fire goes into the heater and the hot flue gases return ,&rough the same fire tubes. Thus, the exhaust stack is on the same end of the vessel as the heater, see Figure 301.15. The emulsion enters the heater through a distributor pipe beneath the firebox and flows out the outlet in the top of the heater shell?

The distributor pipe causes the emulsion to spread out to prevent uneven flow and the effects of hot spots caused by the emulsion standing still in parts of the heater. The Srebox should be removed and inspected periodically when using this type of heater because, although this firebox is not as badly affected by scale as other designs, corrosion is a very serious factor. Jnternal fvebox heaters should be used only where the well production is noncorrosive and flow is fairly constant.*

!. Jug heaters are similar to internal fuebox heaters, except that jug heaters have a short, vertical shell that is normally fIbed with hot water. The emulsion entering

July 1992 I ‘age 300 - 45

Fluid-jacket Heaters

Internal Firebox

Jug Heaters


300 PROCESS AND CONTROL l

- L DRAIN

Figure 301.15 Internal Firebox Heaters

Page 300 - 46 July 1992


the heater through the distributor pipe beneath the internal firebox must pass upward to the outlet in the top of the shelL*

Passing through the vessel, the emulsion is washed by a hot water bath that assists in breaking the emulsion and reducing the load on other parts of the treating system Any water that breaks out of the emulsion is carried out through the emulsion outlet.’

The water bath also helps smooth out temperature changes that occur when flow is intermittent. Jug beaters may be used with fluids that are mildly corrosive, especially when the corrosive material is in the oil rather than in the water. They should not be used with fluids that sre highly corrosive.8

indirect Heaters

An indirect heater, see Figure 301.16,~consists of three main parts: -thebody - the firebox - the flow-tube bundle

The firebox and flow-tube bundle may be built into the body but are usually removable for easy cleaning, inspection, and replacement. Heat from the firebox is transferred indirectly through a water bath in the bcdy of the vessel to the emulsion being heated in the flow-tube bundle.’

An indirect heater is less hazardous to operate than a direct heater because the fire does not touch the flow tubes. Because the flow-tube bundle is not warmed by direct heat, the temperature of any flow tube cannot be higher than the temperature of the water bath surrounding it*

Also, hot spots do not form in the flow-tube bundle and crack the tubes because the temperature of the water bath is controlled by a thermostat. The relatively low, even temperature of the water further minim&s salt and scale deposits. Tube faihue is not as likely as in direct heating because many deteriorating effects are held to a minimum. Also, the oil or emulsion is not in contact with the open flame in the fire box should a failure 0ccur.r

Fireboxes and fire tubes should be inspected at periodic intervals, and a check should be made for accumulation of scale, rust, and corrosive materials. No

Hot Water Bath

Hot Spots

July 1992 Page 300 - 47


Figure 301 .16 Typical Indirect Heaters

Page 300 - 48 July 1992

300 PROCESS AND CONTROL Oil Field Pmductlon

(.

pattern on the frequency of inspection can be set because the demrmining factors are the conditions under which the heater operates. When scale or corrosive materials are noticed, the fiibox should be removed and cleaned or replaced, depending on its condition. Practically all oil that must be treated has a certain amount of sludge and entrained solids in it. A bottom drain is provided on most heaters that can be opened occasionally to permit removal of sludge and solids.’

301.5.5 Wash Tanks

The action that occurs in a wash tank to separate oil and water is divided into two main parts, washing and settling. The washing is done in the free-water layer, and the settling occurs in the emulsion layer. Because all emulsions are not alike, no set pattern on the amount of free water that should be held in a wash tank can be established. For instance, washing has little or no effect on certain emulsions; therefore, in such cases a very small amount of free water in the tank is all that is necessary. On the other hand, some emulsions completely break down by washing; therefore, it is advantageous to have a large amount of free water in the wash tank.*

Basically, a wash tank or gun barrel (see Figure 301.17) is a settling tank that is fitted with an internal or external boot, or flume. In general, wash tanks are composed of five principal parts, each of which serves one or more specific purposes.8

1. The inlet line is the pipe that conducts the emulsion (or water and oil) from the oil and gas separator to the wash tank.

2. The conductor pipe (also known as the boot, flue, or stack) is the large pipe through which the emulsion passes before entering the bottom of the wash tank. The boot may be mounted either inside or outside the tank and serves three main purposes:

a. Gas separates from the emulsion inside the boot, and thus turbulence is reduced within the body of the wash tank.

b. It serves as a surge tank to prevent slugs of emulsion from being ejected into the wash tank, as would occur if the separator discharged directly into the bottom of the wash tank.

c. It spreads the emulsion more evenly throughout the water wash using a spreader, or apron, which is attached to the bottom of the boot.

Washing And Settling

Gun Barrel

July 1992 Page 300 - 49



GAS EQUALIZER.

EMULSION +

CONDUCTOR m p,pE .

WATER OUT

Figure 301.17 Typical Wash Tank (Gun Barrel)*

Page 300 - 50 July 1992


.-J 011 Field

Production

3. The body, or tauk, holds the water wash (or water layer), emulsion, and clean oil layers and allows time for the oil and water to separate.

4. The water outlet - also called the water leg, outside siphon, or grasshopper - serves two principal purposes:

a. It provides an outlet for the water that has separated from the emulsion.

b. It is used to regulate the amount of water held in the wasb tank.

5. The oil outlet line conducts the clean oil from the wash tank to the storage talllcs.

The majority of wash tanks have several other parts, such as gas equalizers between the tank and conductor pipes, gas lines, bleeder line, and gauge glasses. The oil and water interface may be seen through the gauge glasses.’

( Wash tanks are usually attached to a closed-type vapor recovery system. This system is capable of collecting all reactive organic compound vapors. It has a vapor return or disposal system capable of processing vapors to prevent their emission to the atmosphere at a vapor loss control efficiency of at least 95 percent by weight.

Gas Equalizers

Vapor Recovery

301.56 Wastewater Separators

A wastewater separator or oil/water separator is any device or piece of equipment that is used to remove oil and associated chemicals from water, or any device, such as a flocculation tank or claritier that removes petroleum-derived compounds from wastewater.’

A wastcwatcr separator separates minor amounts of oil from produced water prior to water injection or disposal. These separators are commonly known as dissolved gas flotation cells or induced gas “Wemco” units. Both types use natural gas to float solids and oil out of the produced water?

Wemco

Some air pollution control districts rcquirc a solid cover for separators with all openings sealed and totally enclosing the liquid contents of the separator com- partments, except for breathing vents. Additionally, any gauging and sampling device on the separator cover must be equipped with a cover or lid The cover must be in a closed position at all times, except when the device is in actual use.8

July 1992 Page 300 - 51


Forbay

Pits

Ponds Ponds am receptacles formed primarily of earthen materials, although they may be lined with artificial materials, used to contain produced water from petroleum production processes for disposal or m-use. Ponds are not used for oil/water separation or evaporation.8

Sumps Sumps are receptacles formed primarily of earthen materials, although they may be lined with artificial materials, in continuous use for separating oil, water, sand or other material in petroleum production operations. * In some air pollution control districts, sumps are defined in terms of first, second, and third stages. A first stage production sump receives a stream of petroleum material directly from wells or a field gathering system. A second stage production sump receives a stream from one or more upstream first stage

Page 300 - 52 July 1992

All wastewater separator forbays must be covered A forbay is that section of a gravity-type wastewater separator that receives the umreated oil-water waste from the prempamtor flm and acts as a header which distributes the influent to the separator channels?

Wastewater separators am usually attached to a closed-type vapor recovery system This system is capable of collecting all volatile organic compound vapors. It also has a vapor remm or disposal system capable of processing such vapors so as to prevent their emission to the atmosphere at a vapor loss control efficiency of at least 95 percent by weight.

Skimmed oil or tar that is removed from wastewater separators is either charged to process units with feed or transferred to a container with a control system.*

301.57 Pits, Ponds, And Sumps

Pits are receptacles formed primatily of earthen materials, although they may bc liued with artificial materials, used to receive intermittent flows of petroleum material from emergencies or from drilling and petroleum production processes.*

A skim pit is simply an earthen pit (nowadays often lined with concrete) into which large volumes of well fluids are produced. Only a fractional percentage of this well fluid is oil, which rises to the surface of the water and is skimmed off by a series of baffles as the water flows across the pit. Although the skim pit represents a final effort to extend the economic life of wells a little longer, sign&ant quantities of oil are recovered in this way. Even so, skim pits are much less used now than was fotmerly the caseP

-


:, ,.. Oil Field

Productlon

separation processes, including sumps, l%ee water knockout vessels, wash tanks, etc. A third stage production sump receives a stream from one or more up- stresm second stage sumps, or subsequent separation processes.

Smnps can be fatal to wildlife that mistake them for water holes. In 1971, the California Division of Gil and Gas identified over 4,ooO hazardous sumps in the oil-producing areas of the state. Today, these sumps have either been eliminated, screened, or cove&

Some air pollution control districts require pits, ponds, and sumps to be covered. The cover should use gasketsas seals along those parts of the perimeter of the cover that contact the sides of the sump, pit, or pond The covers should be maintained in good condition. Pressure-vacuum relief valves should be on the cover and hatches should be included and remain closed at all times except during sampling or maintenance operations.

If the VGC content of the liquid entering a sump, pit, or pond is less than a certain amount (around 5 milligrams per liter) the sump, pit, or pond is usually exempt from having to have a cover. Additionally, in some districts, Ventura for example, covers are not required for drilling operation pits, if clean-up procedures are implemented within 48 hours after the drill rig has been removed from the location, if clean-up procedures take no more than f&en calendar days, and if test production is routed to a closed top tank.

Ventura also exempts emergency pits and well cellars used in an emergency (maximum 30&y use), if clean-up procedures are implemented within 24 hours after each emergency occurrence and if clean-up procedures take no more than fifteen calendar days.

Because of then concern for soil and groundwater contamination, many operators sre removing sumps, pits, and ponds from service and replacing them with tanks.

Check with your district t!ules and regulations for specific requirements for sumps, pits, and ponds.

July 1992 Page 300 -,53

Stages

Covered

Specific Requirements

Oil Field Pmductlon 300 PROCESS AND CONTROL

Tank Battery

LACT Units

Drain Outlet

Thief Hatch

Page 300 - 54

301.6 STORAGE

After gas has been separated from the oil and the oil has been treated to remove water and sediment (if present), the oil goes to stock tanks which make up the tankbattety Thestocktanksinatankbanerywillvaryinnumberandinsize, depending upon the daily production of the lease and the fmquency of pipeline runs. The introduction of Lease Automatic Custody Transfer (L.AClJ units and their acceptance by pipelines and producers has reduced storage requirements.r

The total storage capacity of a tank battery is usually 3 to 7 days’ production; thatis,3to7timesthe maximum daily production or allowable of the wells connected to the tank battery. There are usually two or more tanks in a battery, so that while oil is being run from one tank the other tank can be filling.*

Most tanks are made of either bolted steel or welded steel. Stock tanks usually have a bottom drain outlet for draining off basic sediment and water. In some areas tanks must be cleaned frequently due to collection of paraffin and basic sediment, which cannot be removed through the drain outlet. Therefore, tanks are equipped with cleanout plates. Cleanout plates can be removed so that a workman can enter the tank. See l$gure 301.18?

Oil is drawn out of the stock tank one foot above the bottom of the tank for shipment via truck or pipeline. The space below the pipeline outlet provides room for the collection of basic sediment and water. The pipeline outlet valve is seakd closed with a metal seal when the tank is being filled and similarly locked in the open position when the tank is being emptied. This is to assure both the producer and the pipeline company that only oil in a particular tank will enter the pipeline company lines.2

Oil enters the tank at the top at an inlet opening. Usually a valve is on the inlet line so that it may be closed to prevent oil from entering the tank after the tank is full and ready for delivery to the pipeline company. Where oil storage is controlled manually the tank is fitted with a thief or gauge hatch in the tank roof so the amount of oil in the tank can be determined with a steel measuring line.2

The thief hatch is large enough so that a device which is called a “thief” can be lowered into the tank and samples of oil obtained to determine the basic sediment and water content of the oil, and its API gravity. When storage is done

July 1992


TulCC VACUUM I nucr

RECOVERY\ PRESSURE ..-

DEV’CE HATCH,&z

f

VR LINE GAS OUTLET

VAPOR

OUTLET VAPOR RECOVERY REGULATOR

-CONDENSATE CLEANOUT

- SUBMERGE FILL OR DRAIN

Figure 301.18 Fixed Roof Storage Tank

July 1992 Page 300 - 55


Vapor Recovery

Gas-Tight Cover

Page 300 - 56

automatically, devices called liquid level controllers signal when tanks are filled and valves open and close according to a prearmnged schedule.’

Storage tanks are usually attached to a closed-type vapor recovery system. This system is capable of collecting all reactive organic compound vapors. It also has a vapor return or disposal system capable of processing such vapors so as to prevent their emission to the atmosphere at a vapor loss control efficiency of at least 95 percent by weight2

Any tank gauging or sampling device on a tank vented to the vapor recovery system is equipped with a gas-tight cover which shall be closed at all times except during gauging and sampling.*

All equipment used in conjunction with the storage of crude oil should be gas tight and routinely maintained in a manner representative of good industry maintenance practices so as to minimize the release of air contaminants.

302 OFFSHORE OIL PRODUCTION

The search for oil and gas to satisfy the nation’s growing energy demand has moved increasingly, in recent years, offshore.. This is particularly true in Cali- fornia where offshore oil and gas development is either ongoing or contemplated along vhtually the entire coastline. The greatest activity has been in southern California, primarily in the Santa Barbara Channel and off the coast near Long Beach and Huntington Beach.9

The offshore oil production process is basically the same as onshore. The differences lie in the activities that are required for offshore oil production which include drilling vessels and production platforms. These activities have power requirements that generate combustion emission concerns as well as volatile organic compound emissions concems.9

This section discusses the technology and current practices of offshore exploratory drilling and production and the types of pollutants emitted by these activities.9

The development of offshore oil resources impact air quality through the exploration, development, and production phases of offshore petroleum resource recovery operations.g

July 1992

300 PROCESS AND CONTROL Oil Field PrOduction

During the exploration phase, emissions of NOx can approach one ton per day from a single drillship. During the production phase, unmitigated emissions of NOx from an outer continental shelf (OCS) platform can exceed one ton per day?

302.1 DRILLING VESSELS

An exploratory project involves drilling a number of test wells from a mobile dding vessel to delineate the oil and gas reserves and evaluate the economics of various production alternatives.9

There are three. types of drilling vessels used for offshore drilling. One is the jackup rig, which is towed to the location; the legs are lowered to the seabed, and the platform is jacked up to the necessary height. The maximum water depth in which jackup rigs are used is generally about 300 feet9

A second type of drilling vessel is known as a semi-submersible. The semi- submersible rig is towed to the location, where it is partially submerged and moored by anchors. Semi-submersibles can be used to drill in water depths up to about 2,000 feet9

The third type of drilling vessel is the drillship. A drillship is basically a self- propelled marine vessel equipped with a derrick, a drawworks (equipment to lift pipe in and out of the hole), a system for turning pipe (rouuy table), and a drilling fluids circulating system. Since a drillship must be totally self-contained, it must be equipped with storage racks for drilling pipes, drilling machinery, related facilities, fuel storage tanks, and living space for the crew?

Drillships are moored by anchors and use motor driven propellers (thrusters) to maintain their position. Some drillships can be used in water depths up to 5,ooO feet. Due in part to the water depths in which OCS drilling off California takes place, drillships are normally used for exploratory drilling?

The electrical power needed to operate a drillship is usually generated onboard by diesel engines using number two diesel oiL The installed diesel engine power capacity can be as high as 16,OCQ horsepower. These diesel engines and flaring during well testing are the major source of air pollutants from an exploratory project?

Exploratory project

Semi- Submersible

Drilling Equipment

July 1992 Page 300 - 57


NOx Emissions

voc Emissions

sox Emissions

Page 300 - 58

The major air pollutants emitted from exploratory drilling activities are: - oxides of nitrogen (NOx) - Volatile organic compounds (VOCs or hydrocarbons) - Pardculate matter (PM) - Oxides of sulfur (SOx) - Carbon monoxide (CO)

Oxides of nitrogen are emitted t?om the large diesel engines used to generate power onboard the drillship. Most of the NOx is emitted as NO (nitric oxide), which is formed by the high temperature. reaction between nitrogen and oxygen iu the combustion air. In the presence of sunlight oxides of nitrogen and VOCs are the primary pollutants necessary for the formation of oxidant (ozone).9

The total NOx emitted from a drillship during the drilling of one well (approximately 90 days) is estimated to be about 80 tons. During certain phases of the drilliug operation such as combined drilhng and drillship positioning, the NOx emission rate can be twice this value. Based on maximum energy usage during the dtilling cycle, the NOx emission rate may be as great as 150 pounds per hour?

Volatile organic compounds (ITICs) from drilling operations generally result from incomplete fuel combustion, evaporative emissions, and fugitive emissions from fuel storage equipment, pumps, and flanges. The average VOC emissions during drilling are estimated to be 9 pounds per hour or 10 tons per well.9

Particulate matter, which is emitted from the diesel engines on board a drillship, come from the incomplete fuel combustion and fuel contaminants. The average PM emissions during drilling are estimated to be 3.4 pounds per hour or 4 tons per well.9

Oxides of sulfur (SOx) come from the combustion of sulfur (a contaminant) in the diesel engine fuel which forms sulfur dioxide. The average estimated SOx emissions during drilling are 4 pounds per hour and 4 tons per well based on a fuel sulfur content of 0.2 percent9

Carbon monoxide (CO) is a product of incomplete fuel combustion. The average estimated emissions during drilling are 12 pounds per hour and 13 tons per welLg

July 1992


The emissions presented above are for a single drillship and do not include emissions from support vessels, drillship movement, or the flaring of high sulfur content natural gas. Support vessels are used to transport crew and materials to and from the drillship. Support vessels usually consist of crew and supply boats and helicopters. The amount of pollutants emitted by these vessels is dependent on the distance the drillship is from the shore and the number of trips which are required.~

Flaring of natural gas can emit substantial amounts of SO, if the sulfur content of the gas is high. For example, if 1.5 million cubic feet of natural gas containing 1% hydrogen sulfide f&S) is flared, SO? emissions would exceed one ton. However, it is diflicult to predict SO, emissrons from flaring due to uncertainties about the quantity of natural gas which will be flared and the sulfur content of that gas?

302.2 PRODUCTION PLATFORMS

If substantial reserves of oil or gas are delineated by exploratory drilling, a fixed production platform is usually established. Offshore platforms are large metal structnres which are placed in water 50 to 1000 feet deep and are attached to the ocean floor by rigid steel legs. For shallow waters, artificial islands have sometimes been used instead of platforms.9

A typical platform has the following types of equipment: - Power generating and fuel storage - Drilling - Gas processing - Oil processing -Water treatment

Power generating equipment is needed to supply electric power for drilling, processing, and pumping. Power is usually supplied by gas turbines, while emergency power is supplied by diesel engines. Some p1atform.s use electrical power supplied from onshore generating equipment through underwater electrical cables.9

c

Well drilling equipment used on a platform is identical to that used on a drillship. Platforms are designed so that 20 to 90 wells may be drilled either by

Flaring

Power Generating Equipment

July 1992 Page 300 - 59

011 Field Productlon 300 PROCESS AND CONTROL

Gas Compressors

Gas Dehydrators

Separators

Froth Flotation Units

Pumps are used to raise the oil (actually a mixture of gas, oil, and water) from the field, and to pump it onshore or into an oil tanker?

Water treating equipment includes oil/water separators and froth flotation units. This equipment is designed to recapture any residual hydrocarbons in the water.

Page 300 - 60 July 1992

directional or angular drilling. This allows a single platform to drill a network of wells extending over several thousand acres!

Gas processing equipment on a platform usually consists of gas compressors and dehydrators Gas compressors are used to raise the gas pressure from a few psi to 20 or more psi. If a platform does not pipe the gas to shore, the gas is usually compressed and reinjected into the field to maintain the natural reservoir pressure and thereby maximize oil production. In addition, a portion of the gas is generally used as fuel for the gas turbines and other combustion equipment used to generate electricity and process heat, respectively. When production is initiated, the gas cannot be reinjected or processed. In such a case, the gas will be flared.~

Gas dehydrators are used to remove water from the gas. Most dehydrators use n-i-ethylene glycol as a dehydration agent. Gas containing water is passed through a desorbcr where it comes in direct contact with glycol as a dehydrating agent, Gas containing water vapor is passed through a desorber where it comes in direct contact with glycol, which absorbs the water from the gas. The glycol is then sent to a &oiler where the water is removed and the glycol is then returned to the desorber9

If significant quantities of hydrogen sulfide @I$) are present in the gas, the H$ can be removed by treatment at the platform prior to use as fuel or being sent onshom9

Gil processing equipment used on a platform includes separators, heaters, treaters, and pumps. Separators are used to separate the gas, oil and water fractions of the well fluid. Separators remove about 75 percent of the water from the oil. The remainin g 25 percent is emulsified in the oil and heater treaters or chemical-electric units are needed to break up the oil/water emulsion, prior to transporting the oil by either pipeline or tanker. Some platforms pipe the oil and water to onshore treatment facilities after the oil/water/gas separation.p

a -

300 PROCESS AND CONTROL Oil Field Pmductlon

After treatment, the water is often reinjected into the field to maintain reservoir pressnre.9

The major pollutants emitted from offshore platforms are: Major - Oxides of nitrogen (NOx) Pollutants - Volatile organic compounds (WCs) - Particulate matter (PM) - Sulfur dioxide (SOJ - Carbon monoxide (CO)

The major source of NOx, PM, and CO is combustion emissions from power generating equipment. If high sulfur content gas is discovered, flaring this gas can be a major source of SO,. VOCs are emitted from the glycol regenerator, heater treaters, water treatment equipment, pump seals, and various process and storage vents9

All five of the above pollutants are also emitted from support vessels (e.g., crew boats, supply boats, helicopters, oil tankers). Additionally, hydrogen sulfide and mercaptans are sources of odor nuisance problems if such pollutants am emitted from fugitive sources or as a result of incomplete combustion?

(.,

July 1992 Page 300 - 61

Oil Field PVJdUCtiOll 300 PROCESS AND CONTROL

SECTION 300 REFERENCES

1. California Department of Conservation, Division of Oil and Gas, California Oil and Gas Geothermal Resourcea, Publication No. TRO3,1988.

2. m of Oil and Gas PJQ&&B, Dallas, Texas, American Petroleum Jnsti- tute Production Department, 1976.

3. MM Schumacher - editor, &&awed Oil Recoverv. Seco dary and Tertiary Park Ridge, New Jersey; Noyes Data Corporation,“l978. Methods;

4. H.K. Van Pollen And Associates, Inc., Enhanced Oil Recovers, Pennwell Books Division of PennWell Publishing Company, Tulsa, Oklahoma, 1981.

5. California Air Resources Board, eslbgeested Control Measure for Emissions pf Photo&@,&lv Reactive Organic Compounds From Vents of Steam Drive Qil Production Wells, 1982.

6. California Department of Conservation, Division of Oil And Gas, 76th An- nual Rewrt of the State 011 aud Gas Su~ervlsor. 1990.

7. California Air Resources Board, The Control of Fugitive Photochemicallv Reactive Oraanic Comwund Emissions From Oil and Gas Production Opem uons and Gas Processine Plants, 1981.

8. Treating Oil Field Emulsions, Third Edition; Da&s, Texas, Austin, Texas, American Petroleum Institute Division of Production and Petroleum Extension Service respectively, 1974.

9. California Air Resources Board, Ai Oualitv Asnects of the Develoument of Offshore Oil and Gas Resources, 1982.

Page 300 - 62 July 1992

c 400 INSPECTION

The following inspection procedures will give you a general description of how to inspect the equipment typically found on an oil field Remember, this section is only an outline to provide you with guidance on how to conduct the inspection and what to look for. A copy of your district rule should be placed in section 505 of this manual in the Legal Requirements. You should refer to your rule for specitic requirements for which compliance must be determined. It is important to remember that you represent your agency and have responsibilities and liabilities. Be sure to follow your agency’s policies.

401 PRE-INSPECTION PROCEDURES

The objective of an inspection is to determine a facility’s compliance with district regulations and permits to operate. It is important to prepare for the inspection prior to your visit to the site. This section is a discussion of some general guidelines on what steps to follow prior to the inspection.

401 .l FILE REVIEW

Prior to the site inspection, the inspector should review all information available in the district source files including: permit applications, approved permits, equipment lists, conditions for each permit, previous inspection reports, notices of violation, breakdown reports, enforcement actions taken, complaints, vat% ante histories, alternative emissions control plans, abatement orders, source tests, processes involved at the facility and emissions inventory.

The inspector may wish to complete some portions of the inspection documentation before arriving at the facility, as this will save time during the pre-inspcc- tion meeting. If your district has checklists or rule specific forms, use them

401.2 REGULATION REVIEW

You should review any references to the specific rule which ate noted in the source files. In particular be fsmiliar with each standard and exemption in the rule. Discuss the regulation with experienced personnel and review any policies your district may have. Make sure that you receive consistent interpretations on how to apply the reqrirements of the rule.

Review Data

Review Rules

July 1992 Page 400 - 1

Oil fleld PdllCtlO~ 400 INSPECTION

Inspection & Safety Equipment

Page 400 - 2

401.3 EQUIPMENT CHECK

Make sure that you have the following equipment available for use during the inspection: vision protection, hearing pmtection, safety shoes, hard hat, gloves, identification, business cards, pens, wipes, inspection forms, chain of custody forms, hydrocarbon analyzers, hydrogen sulfide detector, Scott air pack, sampling cans, can case, labels, soap solution, thermometer. and Ohm meter.

401.4 PRE-ENTRY AND ENTRY

When you arrive at an oil field, notice if them are any strong odors or visible emissions. Request to see the previous contact mentioned in the files. Depend- ing on the facility, it may be the environmental coordinator, production man- ager, supervisor, president, or maintenance worker. Always present your business credentials immediately to avoid confusion.

If the source is unfamiliar with your district’s authority, be prepared to cite and provide copies of California Health & Safety Code (CHSC) Section 41510: Right of Entry (a copy is available in Section 500). Know and follow your district’s policy when the facility refuses entry.

401.5 PRE-INSPECTION MEETING

Before the inspection begins, the inspector should meet with the source representative to obtain operating information. The inspector should state the purpose of the inspection and identify the equipment which will be inspected Facility information can be verified during this meeting, including: the facility name and ownership, address with city and rip code, contact name, contact title, phone number and area code. Discuss safety procedures and whether or not there have been any hydrogen sulfide problems in the past. Request a copy of any emission inventories, material safety data sheets (MSDS), and if necessary discuss sampling procednres. You should request to see a copy of the permit(s) for the facility and check to see if the permit(s) is current and valid Also, check existing permit conditions and ask if any changes have been made to then operation which are not reflected in the permit

July 1992

-

400 INSPECTION Oil Field Production

402 FACILITY INSPECTION PROCEDURES

The inspection is performed by checking the Permits to Operate for each permitted item and making sure the equipment runs in accordance with district regnla- tions. Permits must be posted on the equipment and they must be current. When you inspect the equipment make sure that it has not been altered since the last permit was issued If equipment has been mod&xl, look to see if there is an Authority to Construct. A Notice of Violation may have to be issued if procedures regarding permits are not followed.

Furthermore, see that the district rules am not being broken. Most district regulations generally apply to hydrocarbons leaking from oil field equipment, NOx emissions, SOx emissions and fuel requirements. Inspection procedures of various oil fields vary because of the different equipment oil fields have from the wide range of oil reservoirs and crude oil types encountered in oil production. A general description of inspecting various equipment typically found on

(‘1, p- an oil field follows.

402.1 LEAK DETECTION METHODS

Inspectors can detect leaks by using their sight, smell, and hearing senses. Inspectors can check components for leaks (valves, flanges, pumps, compressors, hatches, connections, sight glasses, meters, etc.) by using a hydrocarbon detector or by applying a soap solution on the component and looking for bubbles.

Another good way to detect leaks is to look for a distortion emanating from the equipment similar to the distortion seen from infmred radiation near the ground or on a roof on a hot day. Always look for liquid leaks from components. If more than three drops of liquid drip from a component in a minute and the liquid hasmorethantheminim urn allowable VOC (volatile organic compotmd) or ROC (reactive organic compound) content in your district, it may be considered to be a leak by your district.

When you am in an oil field note if there are any strong odors of petroleum. If there are any strong odors, find out where they are coming from. The odor could be from a leaking component. Make absolutely sure the odor is not hydrogen sulfide, since it is a lethal gas. At low concentrations hydrogen sulfide smells like rotten eggs but at lethal concentrations it is odorless. Inspec-

July 1992

Permit Compli- ante & . Reaulation

Page 400 - 3

Oil Field Production 400 INSPECTION

Page 400 - 4

ton can also detect leaks by hearing them Always investigate the source of any strauge unexplained hissing sounds.

It is important to use a hydrocarbon analyzer properly. Before you use a hydrocarbon analyzer to check equipment for leaks make sure the analyzer is cali- brate-d according to the manufacmrer’s directions. This is typically done by warming up the instrument, setting it to zero and introducing a zero gas to the probe inlet. When checking a device for a leak, move the probe along the joint where a leak may appear holding the probe one centimeter away (check your district regulations. Some districts may not use one centimeter). Move the probe slowly along the interface where a leak may be occurring and note the highest concentration found in the joint you are checking. Try to block the wind from the area you are checking so you will get better results. When a leak is found, subtract the background concentration measured one meter upwind.

402.2 COMPONENTS

The components are devices where hydrocarbons can escape into the atmosphere from an oil field production facility. Most companies check their valves and other components regularly for leaks. There may be hundreds or thousands of components at a facility and most inspectors don’t have time to check all of them for leaks. Check the company’s records to see which components are leaking, what percentage of them are leaking, and which ones have been fixed. Your district may allow a small percentage of leaking components and will allow a period of time for a facility to fix its leaking components. Check your district regulations for specific rules regarding the leakage and repair of valves, flanges and other components. Districts usually have an inspection schedule for inspecting components for leaks.

It is advantageous to know where leaks occur on components. Leaks usually occur between moving parts, joints, connections, and pressure relief devices. When leaks are found the components are tagged so the leaking area won’t be lost and can quickly be identifted. The leaking components can then be repaired later.

4022.1 Valves

Valves regulate the flow of fluid or gas from one place to another or isolate equipment from liquids and gases. Some of the typical types of valves found on

July 1992

c- 400 INSPECTION Oil Field PVJdUCtiO~

an oil field include gate, globe, plug and ball valves. Gate and plug valves are used to shut off a flow to equipment but, globe valves sre used to regulate flow. Valves often leak around the stem and housing interfaces; therefore, gate, globe, and ball valves have packed stem seals. The packed stem seals are filled with asbestos, fluorinated hydrocarbon plastics, or laminated graphite that. surrounds the stem. Plug valves are lubricated with grease. on their stems to help prevent leaks.

4022.2 Flanges

Flanges and other connections are also sources of hydmcarbon leaks. Planged connections ate found between pipe connections, pipe - valve connections and other connections. Planged connections have a gasket made of asbestos and/or metal between the connecting interfaces to help prevent leaks. Leaks will often occur at gaskets or at the tbreads of threaded connections.

c 402.2.3 Pumps and Compressors

Pumps mainly are in two categories: reciprocating and centrifugal. Reciprocat- ing pumps are often found at oil well rod pumps at an oil field. Leaks usually occur where the reciprocating polished rod goes into the wellhead. A stuffing box filled witb packing is put around the rod to help prevent leaks. Packing can be compressed by adjusting the packing gland as the packing wears down.

Centrifugal pumps have seals to prevent leaks around their rotating shafts. Mechanical seals may be used with centrifugal pumps. They typically have a washer that rotates with the shaft that presses and seals against the seal seat on the pump housing which doesn’t rotate. Pressure between the mating surfaces is supplied by a spring. Stuffmg boxes may also be used with centrifugal pumps.

Compressors are used to compress and transport a gas. They also typically fall into two categories: reciprocating and centrifugal. Reciprocating compressors usually leak hydrocarbons around their packing rings (packing rings are very similar to piston rings on an internal combustion engine). Centrifuga.l compressors use a number of different mechanical seals.

Reciprocatina Pumps -

Centrifugal Pumps

July 1992 Page 400 - 5

011 field Production 400 INSPECTION

Steam Generators

Scrubbers

Page 400 - 6

4022.4 Other Equipment

Sight glasses and meters are small sources of emissions relative to valves and flanges. Sight glasses usually leak where they co~ect to the device in which they are installed. Meters can leak where they co~ect to the device that they are measuring or the meter itself may leak hydrocarbons.

402.3 FIRED EQUIPMENT

Steam generators are natural gas or oil fired pieces of equipment, often found on an oil field with heavy oil, that am used to produce steam. The steam is injected into the ground to improve oil production. When inspecting steam generators, note first if there are any visible emissions coming from the stacks. There should be little or no visible emissions coming from steam generators.

NOx and SOx emissions are the emissions of greatest concern from steam generators. Some of the technologies used to reduce NOx emissions include oxygen trim systems, low - NOx burners, flue gas recirculation (PGR), selective non - catalytic reduction (SNCR), and selective catalytic reduction @CR). Some of these systems, such as flue gas recirculation, may increase the efficiency of steam generators. Small steam generators or steam generators built during the 1970’s or earlier may be exempt from most district regulations. Steam generators sixes are rated by their Bm (British Thermal Units) outputs; therefore, steam generators with small Btu outputs are not regulated by many diStliCtS.

Steam generatots that are natural gas fired may have controls for NOx. If a steam generator is covered by a permit, check the air fuel ratio and make sure it is within proper limits to reduce NOx emissions. The air fuel ratio may be automatically printed on a polar chart If it is, get copies of the charts to help verify compliance with the Permit to Operate.

Steam generatots that are oil fired or field gas tired may have controls for NOx and SOx emissions. A scrubber and soda ash tower are used to control the SOx emissions. A large steam plume may emanate from a stack of a scrubber but, there should be no lingering emissions beyond the steam plume. Check the gas to liquid ratio of the scrubber. If it is too low the scrubber could start to till with water. If it is too high the collection efficiency of the SOx may be poor. Make sure the solution coming from the soda ash tower has the proper pH in order to

July 1992

400 INSPECTION Oil Field FKlduotlon

neutraliae the acid from the SOx. Check compliance with NOx emissions in a mamm similar to natural gas tired steam generators.

Heater treaters are natural gas or oil fired equipment used to break oil from an emulsion. They combine all the different pieces of oil equipment into one vessel, applying heat, chemical and settling effects to an emulsion. They may have NOx controls if they bum natural gas and they may also have SOx controls if they sre oil fii or field gas fried. Heater treaters are also inspected by checking Permits to Operate, making sure air fuel ratios are within proper limits and scrubbers are working properly. When inspecting steam generators or heater treaters check to see that the equipment has the required control equipment to reduce emissions.

Natural gas is a by-product of many oil field production facilities. Facilities use flares to burn off natural gas when their compressors break down, are being serviced, or when there is another problem in the natural gas production system. Some opera&ons may flare all their natural gas if they do not recover it. Flares may also be used on a vapor recovery system at a loading rack or tank battery. Only a small amount of inspection is required for flaring units. Flares should not give off any visible emissions; only a flame should be emanating from the stack of a flating unit. They must also have a continuous ignition system. Records of flare usage should be kept by the facility.

402.4 FIXED ROOF TANKS

Most tanks on au oil field have Permits to Operate. Tanks that must be inspected for compliance with Permits to Operate and district regulations include:

-Oil wash tsnks -Oil storage tanks -Oil LACT (lease automated custody transfer) tanks -Oil gauge tanks -Producd water tanks -Produced water separator tanks -Portable tanks -Organic liquid (other than oil) tanks.

The top of a tank is an area where a large amount of hydrocarbon emissions can occur. Make sure there are no holes in the tops of tanks. Check the gaskets in the seams at the tops of the tanks, they should not be weathered or cracked and

Heater Treaters

Flares

Types of Tanks

July 1992 Page 400 - 7

011 Field Roductbn 400 INSPECTION

Rivets

Hatches

Pressure Relief Valves

Page 400 - 8 July 1992

they must be under gas tight or vapor tight conditions. Gas tight is defined in your district regulations.

If a tank is bolted or riveted together, make sure that there are no loose or missing rivets or bolts on the top or sides of the tank. Old tanks at oil fields often have nmerous rivets. The rivets in a tank can be a source of hydrocarbon emissions to the atmosphere. Look for any wet oil or stains emanating from rivets or seams.

Tank gauge hatches on top of the tanks should be closed and gas tight except during gauging and sampling. For water sealed hatches, verify that there is sufticient water to make a good seal. Check for water spots or discoloration around the hatch and tank side. This may be an indication of operationalupsets resulting in burping and me release of hydrocarbon vapors to the aanosphere.

Verify that there are no continuous hissing sounds from hatches or breather vents. Conventional gauge hatches (conservation vents) are designed to periodically relieve tank pressure or to let ambient air into the tank to maintain pressure in tanks. Venting often occurs when a tank is being filled, emptied or from vapor expansion from temperature increases during the day. Continuous venting through seal gaskets could indicate poor maintenance and potential violations.

It is also important to check pressure relief valves on the tops of tanks for leaks, since they are often sources of emissions 6-om tanks. FYessure relief valves should have a gas tight seal with the tanks and they should not vent continuously. The valves should be maintained in good condition and should not be left open.

Besides using the visual or audio senses, a properly calibrated hydrocarbon analyzer (OVA, TLV, etc.) should be required for inspections. Check gauge hatches, tank seams, bolts and rivets, pressure relief valves and other accessible areas for any hydrocarbon leaks. Check your district regulations for the cali- bration and use of an analyzer and allowable hydrocarbon emission limits from leaking tanks.

400 INSPECTION

c

402.5 OIL WATER SEPARATORS

Oil water separators or “Wemco units” are machines driven by electric motors used to separate out the last small amounts of oil left in produced water. They are also a source of hydrocarbon emissions on an oil field Oil water separators must have vapor control systems unless the liquid within them has less than the minimum amount of volatile organic compound (VOC) and hydrogen sulfide (H$) allowed by your district.

These machines have large sight glasses. Make sure they are not leaking any vapors. Check to see that there are no vapor leaks where the electric motor axles driving the machine enter the part of the machine containing the oil/water mixture. All the hatches, connections, and components of the unit should be gas tight. Looking for distortion above the surface of the device and leaking fluid stains are simple ways to detect leaks.

402.6 SUMPS

A sump is a lined or un-lined excavated depression used to continuously separate crude oil, produced water and solids. Sumps must be covered with a net to prevent birds and other wildlife from getting into them Some districts require sumps to have covers that are impermeable to VOCs. Check your district regulations for the type of cover and specific limitations regarding sumps.

402.7 VAPOR RECOVERY SYSTEMS

Oil wells in an oil field are usually connected to a casing gas vapor recovery system Vapors from volatile components of crude oil accumulate within the casing of each oil well and the vapors must be prevented from entering the atmosphere. A small pipe for vapors is connected to the Christmas tree of an oil well to carry away the vapors. In many oil fields vapors are collected and routed to casing gas vapor recovery units in order to condense and separate them. The condensed hydrocarbons may then be sent to pipelines, burned in steam generators or other equipment.

Storage and other tankage, closed wastewater treatment systems and various other oil field equipment may be connected to a vapor recovery system There are several types of vapor recovery systems. One type uses a compressor, where vapors are gathered using the suction side of a compressor. Liquids are condensed and gas sent to pipelines or other uses in the oil field

July 1992

011 Field Production

Page 400 - 9

Oil Pield PVJdWtlon 400 INSPECTION

Tank Farm Pressure

Page 400 - 10 July 1992

Some types of vapor recovery do not rely on a compressor but instead use pressure to route excess gas to an oil field combustion device such as a flare or heater fir&ox. These types are often used in remote locations where compressor vapor recovery is not practical.

Make sure compressors for the vapor recovery system are operating. Check that there are no leaks around compressor shafts and seals. Check to see that casing gas vapor recovery units are operating in accordance with their Permits to Oper- ate. Vapor recovery systems must also be gas tight.

4027.1 Tank Vapor Recovery Systems

Vapors from the components of crude oil that have low boiling points result from tank filling or from temperature increases from the sun heating tanks during the day. Natural gasoline is a component in crude oil that readily vaporizes. In the past vapors were allowed to vent to the atmosphere resulting in increased air pollution, fire hazsrds, releases of hydrogen sulfide, and production losses.

Tanks operate just above atmospheric pressure at about one inch of water column. If the pmsure in a tank gets too low, especially from emptying, it could collapse. If the pressure in a tank gets too high, it could explode but, the vapor recovery system and pressure relief valves help regulate the pressure in a tank.

In a tank battery, the tanks are co~e-cted with pressure. equalizing lines so that if the pressure in one tank increases, it can be taken up by the other tanks. When the pressure in all the tanks in a tank battery gets too high, the vapor recovery system draws some of the vapors out of the tanks, compresses them and mutes them to the gas gathering or disposal system When the tank farm pressure becomes lower than the set point, especially during oil shipping, make up gas, usnally from the fuel gas system, is introduced into the tank to maintain pressure (See Figure 301.18). Older vapor recovery systems shut off when the pressure within tanks is within operating limits. Newer vapor recovery systems run in a gas by-pass mode, preventing frequent equipment starting and stopping, decreasing wear and tear on the equipment.

Tanks must have vapor control systems unless the liquid in the tank has less than the minimum amount of reactive organic compound (ROC), volatile organic compound (VOC), and hydrogen sulfide (H.$) allowed by your district. Check- ing vapor recovery system components for good operation and any leaks must be

c 400 INSPECTION Oil Field Production

done on a regular basis. If a tank battery has a manometer for the vapor recovery system, check to see if it is operating correctly. The manometer indicates the gage pressure (pressure relative to atmospheric pressure) inside tankage in inches. Some vapor recovery systems have a chart recorder, indicating pressure and operation of the vapor recovery. If a tank has a chart mcorder, verity that the pressure has not exceeded the PV valve set point or rated pressure as this indicates venting through the PV valve. Check with field personnel to learn the vapor recovery systems used.

PV Valves

The tank vapor recovery system must be gas tight. If the tank vapor recovery system is equipped with a compressor, check to see if the compressor works properly. When the tank vapor recovery system is working properly, there should not be any frequent venting from breather valves or pressure relief valves on the tank and there should not be any hydrocarbon emissions from any other roof components. Check to see that vapors are handled properly. Vapors are often condensed and recombined with LACI (Lease Automated Custody Trans- fer) sales gas pipelines or used in field fuel fired equipment.

Safety is also an important concern while inspecting tanks. Never walk or put your weight on top of a tank. Some tanks are old and cannot support the weight of a person. Some companies may require you to wear a breathing apparatus before inspecting the tops of tanks. It is also always a good idea to have a hydrogen sulfide detector with you.

4028 OFFSHORE PLATFORMS

Inspecting offshore oil platforms is somewhat similar to inspecting a typical oil production facility onshore. All the oil platforms within three miles of the coast in state waters pump their crude oil to onshore facilities for separation. Some oil platforms in federal waters pump their wet oil onshore for separation but, some have oil dehydration facilities on the platform. The main areas of inspection required on a platform include compressors, pumps, backup engines, cranes, drilling engines, crew boats, process heaters, gas turbines, and the components (valves, flanges, connections, etc.).

(.

NOx controls are a major part of emission control on oil platforms because of the large internal combustion engines or gas turbines on them Offshore oil platforms in Caliiomia waters have gas lift wells where huge internal combustion engines are used to drive compressors to pump natural gas into oil wells to

July 1992 Page 400 - 11

011 Flold Production 400 INSPECTION

Components

Page 400 - 12

recover crude oil. Records such as the number of hours of usage and the cubic feet of natural gas used should be acquired tiom industry personnel. There should he no visible emissions coming from the stacks and required control devices must he working properly. These large engines also have a vapor recovery system known as crank case vapor recovery. It is an electric system that condenses hydrocarbon emissions into a liquid

There are also similar inspection procedures for backup engines, crane engines, and drilling engines. Get records showing the fuel used in the engines, the amount of fuel used, and the time they were running if the records are necessary to verify compliance with pemh to operate. If crew boats are used for transpor- tation between land and the oil platform note if there are any visible emissions from the boats. If there are a lot of visible emissions, find out what fuel they are using to see if it is accepted by your district. Check your district regulations regarding marine vessels. See also the technical manual and pamphlet for internal combustion engines created by the California Air Resources Board for more information about internal combustion engines.

Ihe components at an oil platform may also be sources of emissions. The iuspec- tion of components on an oil platform is very similar to inspecting components on m oil field on land. There should be no liquid leaks (three drops or more per minute of VOC) or gaseous leaks, but check your district regulations for specific tits allowed by your district. The oil company or an outside contractor will astrally check all the components. Make sure you obtain the records of the inspection done of the components including the name, location, type, date of letection, level of leak (ppm), and method of detection. Records for repair and e-check of leaking components are also required.

l’here are no tank farms to inspect at oil platforms in California waters but, the xude oil from oil wells on the platform enters a surge tank. The surge tank is equired to be connected to a vapor recovery system. Make sure the vapor mcov- ny system is working properly and that it is not leaking more than the minimum tmount of hydrocarbons.

1029 INSPECTION CHECKLIST

Ihe following is a general list of activities to perform to inspect oil field equipment. Make sure you also verify compliance with Permits to Operate for every piece of equipment.

July 1992


A. Valves, Flanges and Components 1. Note if them are. any leaking liquids during the whole inspection. 2. Acquire samples of leaks to see if they are violations. 3. Note if you see any vapor leaks. Look for distortion emanating from

equipment. 4. Check suspected leaks with hydrocarbon detector. 5. Acquire company’s records of leak-checking.

B. Steam generators and heater treaters 1. Look for visible emissions. 2. Check air fuel ratio. 3. Check that required emission control devices are on equipment and

working. 4. Acquire records..

C. Scrubber 1. Make sure there are no visible emissions beyond steam plume. 2. Check gas to liquid ratio. 3. CheckpH. 4. Acquire scrubber records.

D. Flares 1. Check for visible emissions. 2. Acquire records of usage. 3. Make sure flare has a continuous ignition device.

E. Fixed Roof Tanks 1. Look for distortion or stains emanating from the tops of tanks

(signhies vapor leak). 2. Check for holes in the tops of tanks. 3. Make sure hatches on the tops of the tanks are closed and gas tight. 4. Check pressure relief valves for vapor leaks (use hydrocarbon

detector). 5. Look to see there is a well maintained tank vapor recovery system. 6. Make sure vapor recovery system is not leaking any vapors. 7. Aquire tank records (tank contents, throughput, vapor pressure,

etc.).

July 1992 Page 400 - 13

Oil Fbkl Produetbn 400 INSPECTION

Page 400 - 14

F. oilwaterseparatofi 1. Make sure hatches are closed. 2. Look for vapor leaks (distortion rising from device) and liquid stains

from leaks. 3. Check sight glasses for vapor leaks. 4. Look around electric motor shafts for vapor leaks. 5. Check suspected areas with hydrocarbon detector. 6. Check vapor recovery system for leaks.

5. snmps 1. Make sure they are covered with a district-approved cover.

FL OfTshore oil Platforms 1. Note if there are any visible emissions r%om crew boats. 2. As you approach the platform, see if there are any visible emissions

coming from it Them should be no visible emissions. 3. Check the snrge tank for liquid leaks and vapor leaks. Make sure the

vapor recovery system for the surge tank is gas tight and working properly.

4. Obtain records for fuel and the amount of use of drilling engines, crane engines, and backup engines.

5. Check that the compressor engines for gas lift wells comply with NOx regulations. Obtain a copy of the record keeping for the engines.

6. Aquire the company’s records of leaking and repaired components. Sample any liquid leaks that you find.

103 POST-INSPECTION PROCEDURES

Prior to leaving the facility, the inspector should evaluate the compliance status )f the facility and should have obtained all the information necessary to com- )lete the inspection form. Make sure you have acquired all the necessary docu- nents to de&mine the compliance of the oil field operation.

The facility should be informed of the results of the inspection, advised of areas If concern where additional information or investigation is needed, or given a gotice of Violation (NOV) as soon as possible. Be prepared to make your compliance determinations, calculate excess emissions, and issue all necessary tiolation notices. Be able to document future NOVs which may be pending due

July 1992

400 INSPECTION Oil Field PWdUCthl

to sample results or additional information requests. All violations should be followed up, consistent with your district policy, to ensure that the source is brought into compliance.

404 RECORDKEEPING

Facility operators are required to keep records by district regulations and .Per- mits to Operate. Records are often used to determine compliance or sre used as evidence of violations of regulations. Recordkeeping will vary with the requirements of the rule and with each source.

For valves, connections, flanges and other leaky components the following records should be kept by facility operators.

1. The names, locations, types of components, and descriptions of any units where leaking components are found

2. The dates leaks are detected, emission levels @pm), of leaks, and methods of detection.

3. The dates and emission levels of m-check sfter leaks are repaired.

4. The total number of components inspected, and the total number and percentage of leaking components found by component types.

5. The frequency of the inspections (quarterly or annually).

It is also necessary for facilities to keep records for their tanks that are covered by permits. Items such as the liquid stored in each tank, the temperature of the stored liquid and the Reid vapor pressure may have to be recorded. The date that a tank is lilled, emptied, or cleaned should also be found in a company’s records. Since some tanks have throughput limits on their Permits to Operate, the throughput for those tanks must be recorded. It may be done monthly, weekly, or daily depending on the distxict regulation or Permit to Operate.

There are also some newer innovative methods of recordkeeping that can be used for oil field production. Records from emissions of leaking components can be kept by computer. A number of different software packages are available to be used for keeping emission records. By using an identification tag on

July 1992

Innovative Recordkeeping

Page 400 - 15

Oil Field Productbn 400 INSPECTION

Types of Tank Samples

Page 400 - 16

wmpotmts, the size, style, type, use, and location of a component can be easily identified. Tags with bar codes, punch holes or identification numbers can be used to identify a component and quickly do an inspection on it.

When e inspector also uses a data logger with a hyWn analyzer, emissions read from the analyzer can automatically be reunded for a leaking component. Using advanced component identification methods and computer software for recordkeeping makes recordkeeping faster and more efficient. Innovative recordkeeping also helps reduce human error in records.

405 SAMPLING

Sampling may be necessary at an oil field in order to determine compliance. Some of the items that may have to be sampled include liquid in a tank, leaking liquid, gaseous leaks, fuel for fired equipment and fuel used in internal combustion engines.

Crude oil samples may be taken from storage tanks or from the pipeline. Tanks are sampled by using thief sampling, bottle sampling or tank sampling methods. Pipelines are sampled by using continuous line sampling. A thief is a cylindrical device used to collect samples by lowering it on a graduated chain into a tank to the desired sample level and actuating a nip sealing a sample of oil in the thief. The thief can then be pulled out of the tank with the sample.

In order to do a bottle sample, a beaker sampler is lowered into a tank on a graduated chain to the desired level. A line comtected to a cork on the device is pulled, allowing the beaker to fill with oil. The beaker with the sample is pulled out of the tank and a small amount of oil on the top of the beaher is poured off in order to get a representative sample.’

There are many different types of tank samples that can be acquired from a tank using a thief or beaker (Figure 405. l).’ Some of the different samples include:

Bottom sample - A sample from the material on the bottom surface of a tank.

Clearance sample - A sample acquired four inches below a tank outlet.

Drain sample - A sample obtained from the draw-off or discharge valve.

July 1992

-


-2 0

Figure 405.1 Tank Sample. Locations

July 1992 Page 400 - 17

Continuous Sampling

Sample Collection Procedures

Page 400 - 18

400 INSPECTION

Lower sample - A spot sample that is taken from the level of a fixed tank outlet or swing-line outlet.

Middle sample - A spot sample acquired from the middle of the tank contents.

Running sample - A sample obtained by lowering a beaker to the outlet or swing line of a tsnk and pulling it up out of the tank through the oil at a uniform rate so that the beaker is three-fourths full.

Spot sample - A sample acquired from a specific location in a tank using a thief, bottle or beaker.

Top sample - A spot sample obtained six inches below the top surface of the Oil.

Upper sample - A spot sample taken at the mid-point of the upper third of the tank contents.

Samples can also be easily acquired from sample cocks located on the sides of some tanks. By opening the cock that leads to the desired level where a sample is desired, a sample can be collected

Continuous sampling is performed manually or automatically by using a sampling probe that is inserted into the pipeline being sampled. Some of the types of automatic, continuous samplers include the time cycle, flow responsive, and intermittent samplers. A time-cycle continuous sampler transfers equal increments of oil from the pipeline to the sample container at a uniform rate of one or more increments per minute. A flow-responsive sampler automatically adjusts to the flow rate of oil in a pipeline. The volume or frequency of the sample can be adjusted. An intermittent sampler transfers equal increments of oil from a pipeline to a sample container at a uniform rate of one or more increments per minute proportional to the amount of oil flow in the pipeline.

it is important that all samples are collected and preserved in accordance with defensible procedures. Make sure you follow the sampling guidelines and chain of custody procedures in your district. Legal issues can invalidate a sample if the proper test method or chain of custody policies am not followed. Make sure that all collection instruments, devices and containers are properly maintained and/or calibratecL

July 1992

c 400 INSPECTION Oil Field Production

Sample handling procedures should verify that samples have not been cootami- oated or altered. As few people as possible should handle samples. The names of all people handling samples and the date and time they handle them must be recorded so a cootinuous custody and control will be in writing from sample collectioo to preseotatioo. It is usually best to allow the facility operators to get samples for you but always observe the operator filling your sampling container. Do not let the filled container leave your sight or controL

Immediately after a sample is takeo a sample identification tag must be completed and attached to the sample container. The date, time, sample type, m- quired analysis, maximum time allowable between sample collectioo and analysis, sample location, project name, address, inspector name, and any preserva- tives in the sample should be included on the tag. Make sure that samples are packed properly. Samples may have to be kept chilled in a cooler especially if they are flammable.

After you take the samples you will need to obtain laboratory test results that provide the information you need to determine compliance. When you submit the samples, make it very clear to the lab what tests are needed and what units are required. Submit your samples in a timely manner and follow up on the paper work and results. If your district has a lab, use it. If you use an outside lab, develop procedures to ensure an accurate, complete and timely analysis.

Further information on manual sampling of petroleum and petroleum products can be found in the ASTM standards under designation D-4057-81.

406 INSPECTOR SAFETY

An oil field can be a dangerous place. You must use caution on an oil field to avoid serious injury or death.

1. Beware of pipes on or near the ground. They can be easy to trip over.

2. The surface of tired equipment and pipes can be very hot. Beware of what you touch.

3. Hydrogen sulfide @I$) is a poisonous gas and is encountered in many oil field operatioos. Keep a hydrogen sulfide detector with you. Hydrogen sulfide

July 1992

.

Page 400 - 19

Oil nehi Produetlon 400 INSPECTION

is heavier than air and settles in low areas. Hazardous levels of hydrogen sulfide are odorless, colorless and tasteless but at low levels it smells like rotten eggs. Be knowledgeable, H,S will kill you. Ask the facility operators about any hydrogen sulfide problems.

4. Eqnipment often starts automatically. Tie up long hair, remove ties and other clothing that could get caught in machinery.

5. Wear hard hat, steel-toed boots and eye protection.

6. Equipment on an oil field can be very noisy and damaging to hearing. Carry earplugs with you.

7. Never walk or put your weight on top of a tank. Some are old and weak and cannot support the weight of a person. Falling into a tank is often fatal.

8. Inspectors should use intrinsically safe equipment when inspecting oil fields. All electrical equipment, sampling apparatus, portable instruments and other possible sources of ignition should be intrinsicallv safe for use in potentially flammable or explosive atmospheres.

9. Check with facility operators for any special precautions.

Page 400 - 20 July 1992

I

400 INSPECTION 400 INSPECTION Oil Field Oil Field Production Production

Section 400 References

Mna Oil Field Emulsipns, Third Edition; Dallas, Texas, Austin, Texas, American Petroleum Institute Division of production and Petroleum Extension Service respectively, 1974.

July 1992 Page 400 - 21

500 LEGAL REQUIREMENTS Oil Field Production

501 HEALTH AND SAFETY CODE

California Health and Safety Code sections provide the statutory authority (or laws) by which your district and the ARB can adopt rules and regulations. The following CHSC sections are presented for your information:

501.1 Local and State Agency Responsibilities - 39002 501.2 ARB Responsibilities - 39003 501.3 Local/State Responsibilities - 40000 501.4 District Powers - 40701 501.5 District Rules and Regulations - 40716 501.6 Right of Entry with Inspection Warrant - 41510 501.7 Cogeneration Technology - 41515 501.8 Mitigation for Cogene-ration and Resource Projects - 41517 501.9 District Permit System - 42300 501.10 Requirements for Permit Issuance - 42301 501.11 Permit Approval: Powers and Duties of Air Pollution Control Gfficer -

42301.6 501.12 False Statements in Permit Applications - 42303.5 501.13 Applications for Variance - 42350 501.14 InterimVariance Applications - 42351 501.15 Emergency Variances - 42359.5 501.16 General Violations, criminal - 42400 501.17 Negligence, Criminal - 42400.1 50 1.18 General Violations, Civil - 42402 501.19 Negligence or Actual Injury, Civil - 42402.1 501.20 General Violations, Administrative Civil [Administrative

Penalties] - 42402.5 501.21 Recovery of Civil Penalties [Procedures/Considerations] - 42403 501.22 Statute of Limitations for Civil Actions - 42404.5

501.1 LOCAL AND STATE AGENCY RESPONSIBILITIES - 39002

Local and regional authorities have the primary responsibility for control of air pollution from all sources other than vehicular sources. The control of vehicular sources, except as otherwise provided in this division, shall be the responsibility of the State Air Resources Board. Except as otherwise provided in this division, including, but not liited to, Sections 41809,41810, and 41904, local and regional authorities may establish stricter standards than those set by law or by the state board for nonvehicular sources. However, the state board shall, after

July 1992

Agency Responsibilities

Page 500 - 1

Oil Field Productkn 500 LEGAL REQUIREMENTS

ARB

Local / State

Page 500 - 2

holding public hearings as required in this division, undertake control activities in any area wherein it determines that the local or regional authority has failed to meet the responsibilities given to it by this division or by any other provision of law.

501.2 ARB RESPONSlBlLlTlES - 39003

The State Air Resources Board is the state agency charged with coordinating efforts to attain and msintain ambient air quality standards, to conduct research into the causes of and solution to air pollution, and to systematically attack the serious problem caused by motor vehicles, which is the major source of air pollution in many areas of the state.

501.3 LOCAL/STATE FlESPONSlBlLlTlES - 40000

The Legislature finds and declares that local and regional authorities have the primary responsibility for control of air pollution from all sources, other than emissions ti-om motor vehicles. The control of emissions from motor vehicles, except as otherwise provided in this division, shall be the responsibility of the state board.

501.4 DISTRICT POWERS - 40701

A district shall have power: (a) To have perpetual succession. (b) To sue and be sued in the name of the district in all actions and proceedings in all courts and tribunals of competent jurisdiction. (c) To adopt a seal and alter it at its pleasure. (d) To take by grant, purchase, gift, devise, or lease, to hold, use, and enjoy, and to lease or dispose of any real or personal property within or without the district necessary to the full exercise of its powers. (e) To lease, sell or dispose of any property, or any interest therein, whenever, in the judgment of the district board, such property, or any interest therein, or part mereof, is no longer required for the purposes of the district, or may be leased for any purpose without interfering with the use of the the same for the purposes of the district, and to pay any compensation received therefor into the general fund of the district (f,) To cooperate and contract with any federal, state, or local governmental agencies, private industries, or civic groups necessary or proper to the accom- plishment of the purposes of this division.

July 1992

500 LEGAL REQUIREMENTS

dependence upon imported oil, (b) that the use of cogeneration technology can substantially increase. the efficiency of energy use in California and can also result in environmental and economic benefits for the people of the state, (c) that the expanded use of cogeneration technology is specifically encouraged as a matter of nation energy policy through the tax and regulatory incentives provided in the National Energy Act, and through state legislation which encour- ages the expeditious approval of cogeneration projects, and (d) the construction and operation of cogeneration facilities will result in an incremental air quality emissions benefit to the extent they reduce demand on existing utility combustion generation facilities in the same air basin aud that such benefit should be recognized in determinin g requirements for new cogeneration projects.

501.8 MITIGATION FOR COGENERATION AND RESOURCE PROJECTS - 41517

The Legislature further tinds and declares that the 1977 amendments to the federal Clean Air Act specifically author&e local governments to provide for the mitigation of the air quality impact of projects with communitywide benefits, such as cogeneration technology and resource recovery projects, by providing regional growth increments in the state implementation plan.

501.9 DISTRICT PERMIT SYSTEM - 42300

Every district board may establish, by regulation, a permit system that requires, except as otherwise provided in Section 42310, that before any person builds, erects, alters, replaces, operates, or uses any article, macbin~ equipmen, or other contrivance which may cause the issuance of air contaminauts, such person obtain a permit to do so from the air pollution control officer of the disnict.

The regulations may provide that a permit shall be valid only for a specified period. However, a permit shall be renewable upon payment of the fees required pursuant to Section 423 11, except where action to suspend or revoke the permit has been initiated pursuant to Section 42304,42307, or 42309, and such action has resulted in a final determination to suspend or revoke the permit by the air pollution control officer or the hearing board by whom, or before whom, such action has been initiated and all appeals, or time for appeals, from such final determination has been exhausted

Page 500 - 4 July 1992


501.10 REQUIREMENTS FOR PERMIT ISSUANCE - 42301

A permit system established pursuant to Section 42300 shall do all of the following: (a) Ensure that the article, machine, equipment, or contrivance for which the permit was issued shall not prevent or interfere with the attainment or maintenance of any applicable air quality standard (b) Prohibit the issuance of a permit unless the air pollution control officer is satisfied, on the basis of criteria adopted by the district board, that the article, machine, equipment, or contrivance will comply with all applicable orders, rules, and regulations of the district and of the state board and with all applicable provisions of this division. (c) Require, upon anmud renewal, that each permit be. reviewed to determine that pennit conditions are adequate to ensure compliance with, and the enforcement of, district rules and regulations applicable to the article, machine, cquip- ment, or contrivance for which the permit was issued which were in effect at the time the permit was issued or modified, or which have subsequently been adopted and made retroactively applicable to an existing article, machine, equipment, or contrivance, by the district board and, if the conditions are not consistent, require that the permit be revised to specify the permit conditions in accordance with all applicable rules and regulations. (d) Provide for the reissuance or transfer of a permit to a new owner or operator of an article; machine, equipment, or contrivance. An application for transfer of ownership only, or change in operator only, of any article; machine, equipment, or contrivance which had a valid permit to operate within the two-year period immediately preceding the application is a temporary permit to operate. Issu- ance of the tinal permit to operate shall be conditional upon a determination by the district that the criteria specitied in subdivisions (b) and (c) are met, if the permit was not surrendered as a condition to receiving emission reduction credits pursuant to banking or permitting rules of the district. However, under no circtmxtances shall the criteria specify that a change of ownership or operator alone is a basis for requiring more stringent emission controls or operating conditions than would otherwise apply to the article, machine, equipmen or contrivance.

501.11 PERMIT APPROVAL: POWERS AND DUTIES OF AIR POLLUTION CONTROL OFFICER - 42301.6

(a) prior to approving an application for a permit to construct or modify a source which emits hazardous air emissions, which source is located within 1,000 feet

July 1992 Page 500 - 5

Permit Requirements

Oil Field Produetbn

School Boundary

I 500 LEGAL REQUIREMENTS

from the outer boundary of a schoolsite, the air poJlmion control officer shall prepare a public notice in which the proposed project or mcdification for which the application for a permit is made is fully described. The notice may be prepad whet& or not the material is or would be subject to subdivision (a) of Section 25536, if the air pollution control officer determines and the administer- ing agency concurs that hazardous air emissions of the material may result from an air release, as defined by Section 44303. The notice may be combined with any other notice on the project or permit which is required by law.

(b) The air pollution control officer shall, at the permit applicant’s expense, distribute or mail the public notice to the parents or gmudians of children en- rolled in any school that is located within one-quarter mile of the source and to each address within a radius of 1,000 feet of the proposed new or modified source at least 30 days prior to the date final action on the application is to be taken by the officer. The officer shah review and consider all comments received during the 30 days after the notice is distributed, and shall include written responses to comments in the permit application file prior to taking fmal action on the application.

(1) Notwithstanding Section 49073 of the Education Code, or any other provision of law, the information necesssry to mail notices required by this section shall be made available by the school district to the air pollution control officer.

(2) Nothing in this subdivision precludes, at the discretion of the air pollution control officer and witb permission of the school, the distribution of the notices to the children to be given to their parents or gmudians.

(c) Notwithstanding subdivision (b), an air pollution control officer may require the applicant to distribute the notice if the district had such a rule in effect prior to Januaty 1,1989.

(d) The requirements for public notice pursuant to subdivision (b) or a district mle in effect prior to Jarmary 1,1989, are fuElled if the air pollution control officer or applicant responsible for giving the notice makes a good faith effort to follow the procedures prescribed by law for giving the notice, and, in these circnmstances, failure of any person to receive the notice shall not affect the validity of any permit subsequently issued by me officer.

Page 500 - 6 July 1992

500 LEGAL REQUIREMENTS Oil Field ProductIon

(e) Nothing in this section shah be deemed to limit any existing authority of any dktkt.

(f~ An applicant for a permit shall certify whether the proposed source or modification is located within 1,000 feet of a schoolsite. Misrepresemation of this fact may result in the denial of a permit.

(g) The notice requirements of this section shall not apply if the air pollution control officer determines that the application to construct or modify a source will result in a reduction or equivalent amount of air contaminants, as defined in Section 39013, or which are haxardous air emissions.

(h) As used in this section: (1) “Haxardous air emissions” means emissions into the ambient air of sir contaminants which have been identified as a toxic air contaminant by the state board or by the air pollution control officer for the jurisdiction in which the

c project is located. As determined by the air pollution control officer, haxardous air emissions also means emissions into the ambient air tram any substances identified in subdivisions (a) to (f), inclusive, of Section 44321 of the Health and Safety Code.

(2) “Acutely haxardous material” means any material defined pursuant to subdivision (a) of Section 25532.

501 .12 FALSE STATEMENTS IN PERMIT APPLlCATlONS - 42303.5

No person shall knowingly make any false statement in any application for a penniL or in any information, analyses, plans, or specifications submitted in conjunction with the application or at the request of the air pollution control officer.

501.13 APPLICATIONS FOR VARIANCE - 42350

Any person may apply to the hearing board for a variance from Section 41701 or from the rules and regulations of the district. However, if the district board established a permit system by regulation pursuant to Section 42300, a variance may not be granted tram the requirement for a permit to build, erect, alter, or

c replace.

July 1992

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Page 500 - 7

Oil Field Pmductbn 500 LEGAL REQUIREMENTS

Criminal Violations

Page 500 - 8

501.14 INTERIM VARIANCE APPLICATIONS - 42351

(a) Any person who has submitted an application for a variance and who desires to commence or co&me operation pending the decision of the hearing board on the application, may submit an application for an interim variance. (b) An inmhn variance may be granted for good causes stated in the order granting such a variance. The interim variance shall not be valid beyond the date of decision of the hearing board on the application of the variance or for more than 90 days from date of issuance of tire interim vatiance, whichever czclxrs fkst. (c) The hearing board shah not grant any interim variance (1) after it has held a hearing in compliance with the req uirements of Section 40826, or (2) which is being sought to avoid the notice and hearing requirements of Section 40826.

501.15 EMERGENCY VARIANCES - 42359.5

(a) Notwithstanding any other provision of this Article or of Article 2 (commencing with Section 40820) of Chapter 8 of Part 3, the Chairman of a dismct hearing board, or any odder member of the hearing board designated thereby, may issue, without notice and hearing, an emergency variance to an applicant. (b) An emergency variance may be issued for good cause, including, but not limited to, a breakdown condition. The district board in consultation with its air pollution control officer and the hearing board may adopt rules and regulations, not inconsistent with this subdivision, to further specify the conditions, and to what extent, an emergency variance may be. granted

The emergency variance shall not remain in effect longer than 30 days and shah not be granted when sought to avoid the provisions of Section 40824 or 42351.

501.18 GENERAL VIOLATIONS, CRIMINAL - 42400

(a) Except as otherwise provided in Section 42400.1 or 424W.2, any person who violates any provision of this pm or any order, permit ruIe, or regulation of the state board or of a district, including a district hearing board, adopted pursuant to Part 1 (commencing with Section 39000) to Part 4 (commencing with Section 41X)0), inclusive, is guilty of a misdemeanor and is subject to a line of not more than one thousand dollars ($1,000) or imprisonment in the county jail for not more than six months, or both.

July 1992

500 LEGAL REQUIREMENTS 011 Field PWAMZthl

(b) lf a violation under subdivision (a) with regard to the failure to operate a vapor recovery system on a gasoline cargo tank is directly caused by the actions of an employee under the supervision of, or of any independent contractor working for, any person subject to this part, the employee or independent contractor, as the case may be, causing the violation is guilty of a misdemeanor and is punishable as provided in subdivision (a). That liability shall not extend to the person employing the employee or retaining the independent contractor, unless that person is separately guilty of any action violating any provision of this part.

(c) The recovery of civil penalties pursuant to Section 42402,42402.1, or 42402.2, prechtdes prosecution pursuant to this section for the same offense. When a district refers a violation to a prosecuting agency, the filing of a criminal complaint is grounds requiring the dismissal of any civil action brought pursuant to this article for the same offense.

(d) Each day durhtg any portion of which a violation of subdivision (a) occurs is a separate offense.

501.17 NEGLIGENCE, CRIMINAL - 42400.1

(a) Any person who negligently emits an air contaminant in violation of any provision of this part or any rule, regulation, or order of the state board or of a district pertaming to emission regulations or limitations is guilty of a misdemeanor and is subject to a fine of not more than ten thousand dollars ($10,000) or imprisonment in the county jail for not mom than nine months, or both.

(b) Any petxon who owns or operates any source of air contaminants in violation of Section 41700 which causes actual injury, as deiined in subdivision (c) of Section 42400.2, to the health or safety of a considerable number of persons or the public is guilty of a misdemeanor and is punishable as provided in subdivision (a).

(c) Each day during sny portion of which a violation occurs is a sepsrate offense.

(d) The recovery of civil penalties pursuant to Section 42402,42402. I, or 42402.2. precludes prosecution pursuant to this section for the same offense. When a district refers a violation to a prosecuting agency, the filing of a criminal

Negligence, Criminal Fines

July 1992 Page 500 - 9

Oil Field Production 500 LEGAL REQUIREMENTS

Civil Violations

Negligence, Civil Penalties

Page 500 - 10

complaint is grounds requiring the dismissal of any civil action brought pursuant to this article for the same offense.

501.18 GENERAL VIOLATIONS, CIVIL - 42402

(a) Except as otherwise provided in Sectioa 42402.1 or 42402.2, any person who violates any provision of this pa or any order issued pursuant to Section 42316, or any order, permit, rule, or regulation of a district, including a district hearing board, or of the state board issued pursuant to Part 1 (commencing with Section 39OOQ to Part 4 (commencing with Section 41X0), inclusive, is liable for a civil penalty of not more than oae thoussnd dollars ($1,000).

(b) There is no liability under subdivision (a) if the persoa accused of the violatioa alleges by affirmative defense and establishes that the violation was caused by an act which was not the result of intentional or negligent conduct.

(c) Each day during any portioa of which a violation occurs is a separate offense.

501.19 NEGLIGENCE OR ACTUAL INJURY, CIVIL - 42402.1

(a) Any person who negligeatly emits an air contaminant ia violation of this part or any rule, regulation, or order of the state board or of a district pertaming to emission regulations or limitations is liable for a civil penalty of not more than ten thousand dollars ($10,000).

(b) Any person who owns or operates any source of air coataminants in violatioa of Sectioa 41700 which causes actual injury, as defmed in subdivision (c) of Sectioa 42400.2, to the health or safety of a considerable number of persons or the public is liable for a civil penahy as provided in subdivision (a).

(c) Each day during any portioa of which a violatioa occurs is a separate of- fease.

501.20 GENERAL VlOLATlONS, ADMINISTRATIVE ClVlL - 42402.5

ln additioa to any civil and crimiaal penalties prescribed under this article, a district may impose administrative civil penalties for a violatioa of this part, or any order, permit, rule, or regulation of the state bosrd or of a district, including

July 1992


a disuict hearing boat& adopted pursuant to FQrt 1 (commencmg with Section 39000) to Part 4 (commencing with Section 41500), inclusive, if the district board has adopted rules and regulations specifying procedures for the imposition and amounts of these penalties. No administrative civil penalty levied pursuant to this section may exceed five hundred dollars ($X0) for each violation. How- ever, nothing in this section is intended to restrict the authority of a district to negotiate mutual settlements under any other penalty pmvision of law which exceed five hundred dollars ($500).

501.21 RECOVERY OF CIVIL PENALTlES - 42403

The civil penalties prescribed in Sections 42401,42402,42402.1, and 42402.2 shall be assessed and recovered in a civil action brought in the name of the people of the State of Caliiomia by the Attorney General, by any district attorney, or by the attorney for any district in which the violation occurs in any court of competent jurisdiction.

In determining the amount assessed pursuant to Sections 42401, 42402, 42402.1, and 42402.2, the court shall take into consideration all relevant circumstances, including, but not liited to, the following:

(a) The extent of harm caused by the violation. (b) The nature and persistence of the violation. (c) The length of time over which the violation occurs. (d) The frequency of past violations. (e) The record of maintenance. (fj The mproven or innovative nature of the control equipment. (g) Any action taken by the defendant to mitigate the violation. (h) The financial burden to the defendant

501.22 STATUTE OF LlMlTATiONS FOR CIVIL ACTIONS - 42404.5

Any limitation of time applicable to actions brought pursuant to Section 42403 shall not commence to run until the offense has been discovered, or could reasonably have been discovered

Administrative Penalties

Procedures/ Considerations

July 1992 Page 500 - 11

011 Field FvJduction

Page 500 - 12


502 SUMMARY OF DISTRICT OIL FIELD PRODUCTION RULES

L BAY AREA AQMD 1. Regulation 8, Rule 18 - Valves and fhmges at petroleum refinery

complexes 2. Regulation 8, Rule 25 - pump and compressor seals at petroleum

refmeries & chemical plants 3. Regulation 8, Rule 28 - Fressure relief valves at petroleum

refineries and chemical plants 4. Regulation 9, Rule 1 - Iuorganic gaseous pollutants - sulfur dioxide 5. Regulation 9, Rule 2 - Inorganic gsseous polhuams - hydrogen

sulfide 6. Regulation 9, Rule 3 - Inorganic gaseous polhuants - NOx kom

heat transfer operations 7. Regulation 10, Rule 2 - Fossil fuel fired steam generators 8. Regulation 10, Rule 24 - Electric utility steam generating units 9. Regulation 10, Rule 26 - Gas turbines

U. FRESNO COUNTY AFCD 1. Rule 408 - Fuel burning equipment 2. Rule 410 - Storage of orgauic liquids 3. Rule 412 - Bulk gasoline & other liquid loading facilities 4. Rule 413 - Effluent oil water separators 5. Rule 413-l- Steam drive well vents - crude oil production

III. KERNCOUNTYAPCD 1. Rule411-Storageoforganichquids 2. Rule 411.1- Steam-enhauced crude oil production well vents 3. Rule 414 - Wastewater separators 4. Rule 414.1- Valves, pressure relief valves, flanges, thmaded

comtections and process drains at petroleum refineries and chemical plants

5. Rule 414.2 - Refinety process vacuum producing devices or VS-

6. Rule 414-3 - Refmery process uuit turnaround 7. Rule 414.5 - pump and compressor seals at petroleum refineries and

chemical plants 8. Rule 414.6 - Heavy oil test station (HOTS)

July 1992

500 LEGAL REQUIREMENTS Oil Field PWdUCthl

9. Rule 414.7 - Components serving light crude oil or gases at light crude oil and gas production facilities and components at natural gas processing facilities

10. Rule 414.8 - Crude oil production sumps 11. Rule 424 - St&r compounds from oil field steam generators 12. Rule 425 - Oxides of nitrogen emissions from steam generators

used in thermally enhanced oil recovery - western Kern County fields

13. Rule 425.1- Oxides of nitrogen emissions tram existing steam generators used in thermally enhanced oil recovery - central Kern County fields

14. Rule 427 - Emissions from stationary internal combustion engines

IV. KINGS COUNTY APCD 1. Rule 407 - Sulfur compounds 2. Rule 411- Storage of organic liquids 3. Rule 414.1- Valves, pressure relief valves and flanges at petroleum

refkries snd chemical plants 4. Rule 414.2 - Refmery process vacuum producing devices or

systems 5. Rule 414.3 - Refinery process unit turnaround 6. Rule 414.4 - Pump and compressor seals at petroleum refineries

V. MONTRREY BAY APCD 1. Rule 404 - Sulfur compounds and nitrogen oxides 2. Rule 412 - Sulk content of mels 3. Rule 413 - Removsl of sulfur compounds 4. Rule 417 - Storage of organic liquids 5. Rule 420 - Effluent oil water separators 6. Rule 427 - Steam drive crude oil production wells 7. Rule 423 - NSPS

SubpsrtD - Standards of performance for fossil fuel fired steam generators Subpart K - Standards of performance for storage vessels for petroleum liquids Subpart GG - Standards of performance for stationsry gas tur bines Subpart QQQ - Standards of performance for petroleum refinery wastewater systems

July 1992 Page 500 - 13


Page 500 - 14

IX. SOUTH COAST AQMD 1. Rule 431.1- Sulfur content of gaseous fuels 2. Rule 463 - Storage of organic liquids 3. Rule 464 - Wastewater separators 4. Rule 474 - Fuel bunting equipment oxides of nitrogen 5. Rule 475 - Electric power generating equipment 6. Rule 476 - Steam generating equipment 7. Rule 1110 - Emissions ftom stationary internal combustion engines

(demonstration) 8. Rule1 1 10.1 - Emissions from stationary internal combustion

engines 9. Rule 1146 - Emissions of oxides of nitrogen Born industrial,

institutional and commercial boilers, steam generators, and process heaters

10. Rule 1146.1- Emissions of oxides of nitrogen from small industrial, institutional and commercial boikrs, steam generators, and process heaters

11. Rule 1148 - Thermally enhanced oil recovery wells 12. Rule 1173 - Fugitive emissions of volatile organic compounds 13. Rule 1176 - Sumps and wastewater separators

X. VENTURA COUNTY APCD 1. Rule 54 - Sulfur compounds 2. Rule 64 - Sulfur content of fuels 3. Rule 71- Crude oil and reactive organic compound liquids 4. Rule 7 1 . 1 - Crude oil production and separation 5. Rule 71.2 - Storage of reactive organic compound liquids 6. Rule 71.3 - Transfer of reactive organic compound liquids 7. Rule 71.4 - Petroleum sumps, pits, ponds and well cellars 8. Rule 74.9 - Stationaty intemal combustion engines 9. Rule 74.10 - Components at crude oil production facilities and natural

gas production and processing facilities 10. Rule 74.15 - Boilers, steam generators, and process heaters 11. Rule 74.16 - Oilfield drilling operations

July 1992


503 ARB CONTROL STRATEGIES

The Air Resources Board (ARB) helps air pollution control districts (APCDs) to determine reasonable available control technology for various air pollution emission sounxs. The ARB has determined reasonably available control technol~ ogy @ACT) for contml of fugitive emissions of volatile organic compounds from oil and gas production and pmcessing facilities, chemical plants, and pipc- line transfer stations.

This determination inchtdes equipment standards, inspection rcquimments, and repair and re-inspection requirements for control of emissions from oil production facilities.

The ARB’s RACT determination for control of fugitive emissions may bc obtained from the California Air Resources Board, Stationary Source Division, Sacramento, California.

504 DEPARTMENT OF CONSERVATION DIVISION OF OIL AND GAS

504.1 THE ROLE OF THE DIVISION OF OIL AND GAS

The Public Resources Code, Division 3, Chapters one through four, governs the regulatory functions of the Division of Gil and Gas. The code charges the division with the responsibility of supervising oil, gas, and geothermal well drilling, operation, maintenance, and abandomnent operation to prevent damage to life, health, property, and natural resources. More specifically, the division must:

1. Prevent damage to underground oil, gas, and geothermal deposits;

2. Prevent damage to underground and surface waters suitable for irrigation or domestic use;

3. Prevent other surface environme.ntal damage, in&ding subsidence;

4. Prevent conditions that may bc hazardous to life or heal* and,

July 1 gg2 Page 500 - 15

011 Flekl ProductIon 500 LEGAL REQUIREMENTS

Page 5OQ - 16

5. Encourage the wise development of oil, gas, and geothermal resources through good conservation and engineering practices.

504.2 CALIFORNIA CODE OF REGULATIONS (TITLE 14) - SAFETY AND POLLUTION CONTROL EQUIPMENT RE- QUIREMENTS - 1747.1

(a) The following devices shall be installed and maintained in an operating condition on all pressurixed vessels and water sepamtion facilities when such vessels and separation facilities are in service. The opemtor shall maintain recordson~estmcture or facility showing the present status and history of each device including dates and details of inspection, testing, repairing, adjustment, and reinstallation or replacement.

(1) All sepsrators shall be equipped with high-low pressure shut-in sensors, low level shut-in conttols, and a relief valve. High liquid level control devices shah be. installed when the vessel can discharge to a gas vent line.

(2) Ah pressure surge tanks shah be equipped with a high and low pressure shut- iu sensor, a high level shut-in control, gas vent line, and relief valve.

(3) Atmospheric surge tanks shall be equipped with a high level shut-in sensor.

(4) All other hydmcarbon handling pressure vessels shall be equipped with high- low pressure shut-in sensors, high-low level shut-in controls, and relief valves, unless they are determined by the supervisor to txz otherwise protected- All low pressure systems COMCCtCd t0 high pressure systems shall be equipped with relief valves.

(5) Pilot-operated pressure relief valves shall be. equipped to permit testing with an extend pressure source. Spring-loaded pressure relief valves shall either be bench-tested or equipped to permit testing with an external pressure source. A relief valve shall be set no higher than the designed working pressure of the vessel. On all vessels with a rated or designed working pressure of more than KtO psi, the high pressure shut-in sensor shall be set no higher than 5 percent Mow the rated or designed working pressure. and the low pressure shut-in sensor shall be set no lower than 10 percent below the lowest pressure in the operating pressure range. On lower pressure vessels the above percentages shah be used as guidelines for sensor settings considering pressure and operating

July 1992


conditions involve except that sensor setting shall not be within 5 psi of the rated or designed working pressure or the lowest pressure in the operating pressure range.

(6) All pressure-operated sensors shall be equipped to permit testing with an external pressure source.

(7) All gas vent lines shall be equipped with a scrubber or similar separation equipment.

July 1992 Page 500 - 17

Oil Field Fmductbn 500 LEGAL REQUIREMENTS

505 DISTRICT REGULATIONS

I%issectionhasbeenprovidedforyoutoincl~~deyourdistrictregulationsthatapply to oil field production opemions. The ARB will not provide any amendments to this section. It is up to you to keep this current.

Page 500 - 18 July 1992

GLOSSARY Oil Field Productkm

Amine - Organic base used to hbsorb acidic gases. Monoethanolamine (MEA) and diethanolamine (DEA) are common amines.’

Amine Unit - A natural gas treatment unit used to remove comaminants such as H$ (hydrogen sulfide), COr(carbon dioxide), and C0S.t

Annulus of a Well - The space between the surface casing and the producing or well bore casing.’ The space between the tubing and casing.

API - American Petroleum Institute.1

API Gravity - Weight per unit volme of crude oil. It is a measurement that is related to specific gravity. The gravity system is more convenient to work with since oil specific gravities are fractions or decimals.r

Asphalt - A heavy solid hydrocarbon found in crude oil.

Backgromd Concentration - A reading expressed as methane on a portable hydrocarbon detection instrument which is taken at least three meters upwind from any components to be inspected and not influenced by emissions from any other specific place.

BACT - “Best Available Control Technology” - an emission limitation based on the maximum degree of emission reduction which (considering energy, environmentaI, and economic impacts and other costs) is achievable through application of production prccesses and available methods, systems, and techniques. In no event does BACI permit emissions in excess of those allowed under any applicable NSPS or NESHAP. It is applicable on a case-by-case basis for each major new (or moditled) emission source to be located in areas attain- ing the National Ambient Air Quality Standards. It applies to each pollutant regulated under the Federal Clean Air Act, and is concerned with Prevention of Significant Deterioration (PSD). See Sections 165(a) (4) and 169 of the Federal Clean Air Act.

Barrel - A measurement of crude oil volme. 1 barrel = 42 U.S. gallons?

Beam hmping Unit (Bad Pump) - A pumping machine where a beam is co~ected to a long string of rods that operate a pump at the bottom of an oil well-~ The other end of the beam has a large counterweight on it to balance the

July 1992 Gloss - 1

Oil Flald Fmduction

Gloss - 2

GLOSSARY

weight from the reds in the well. The end of the beam is driven up and down by a gear box connected to a motor. The counterweight is often put on the gear box of the rod pump itself, rotating around as the motor runs the gear box. These units are often nicknamed ‘horses” and are one of the most identifiable features on an cd field

Blow Down - The venting of a pressure vessel or pipe into another vessel or the atm0sphere.l

Casing - Steel pipe that is screwed together and cemented in an oil well after it is drilled to prevent ground water and oil at different levels in the ground from mixing. The casing gives an oil well structure, support and also prevents an oil well from caving-in. Two or more casings are cemented into a well including the surface string (200 to 1500 ft. long), the intermediate or salt string (up to 5000 ft. long) and the oil string which goes from the top to the bottom of the well (up to 20,000 ft. long).r AU the casing strings start at the top of the well.

Casinghead - The top of the casing set in a welh the psrt of the casing that protrudes above the surface and to which the control valves and flow pipes are attached.’

Centipoise - A unit of viscosity equal to 0.01 poise. One poise equals one dyne- second per square centimeter. Water at 2@C has a viscosity of 1.005 centipoises.4 (see Viscosity)

Cogeneration - A process where waste energy is used to produce elecniciq. Oil field facilities may produce their own electricity and sell their electricity to utilities.

Component - A device that is any of the following: valves, flanges, threaded connections, hatches, seals, packing, sight glasses, meters, pumps, compressors, pressux relief valves, snd seal fluid systems.

Compressor - A machine driven by electric motors or internal combustion engines used to compress or transport a gas from one location to another.

Connate Water - Water that is inherent to a crude oil producing formation. Fossil sea water that was trapped in the pore space of sediments during their deposition.2

July 1992

GLOSSARY Oil Field Production

Control Technology Guidelines (CTG) - A series of docume ttts prepued by EPA to assist states in defining reasonable available control technology (TUCT) for major sources of volatile organic compotmds (VOC). The documents provide information on the economic and technological feasibility of available techniques and in some cases, suggest limits on VOC emissions.

Crude Oil - Oil that has not been taken to a refinery; unmfined petroleum. A mixmre of hydrocarbons that exists in the liquid phase in natural underground reservoirs and remains in the liquid phase when brought to ambient conditions.

Cyclic Well - An oil well in which steam is injected for a period of time and then changed to a producing well.

Darcy - A unit of permeability. A porous medium has a permeability of one darcy when a pressure of one atm on a sample one cm long and one cm2 in cross section will force a liquid of one cp viscosity through the sample at the rate of one cm%ec.4

Density - Measure of mass per unit of volume, i.e. grams per liter and pounds mass or slugs per gallon.

Diesel Fuel - A fraction of crude oil in the light gas - oil range.’

Distillation - The process of sepsrating crude oil into its sepsrate components by heating it and then cooling and condensing the different fractions.’ The different components separate because the components have very different boiling points. Light, volatile hydrocsrbons such as naphtha and gasoline have low boiling points but components such as asphalt have high boiling points.

Drill Bit - Cutting tool put on the end of the drill pipe used to drill sn oil well. Drill bits wear out during drilrmg and must be replaced (see Tripping).

Drilling Mud - A special mixtare of clay, water, and chemical additives that is pumped through drill pipe out through the drill bit into the hole while drilling in order to cool the drill bit, carry cuttings to the surface out of the hole and prevent the hokfrom colhxpsing.l

Drill Pipe - Hollow pipe used to turn the drill bit in the ground to drill an oil well. Drill pipe sections are screwed together as drilling progresses.

July 1992 Gloss - 3

Oil Field PVJdUCtiO~ GLOSSARY

Drilling Platform - An offshure struchm anchored to the sea floor, made of a large diameter pipe frame for oil production at sea. As many as 60 wells may bc drilled fmm a platforn~~

Emulsion - A mixture. of oil and water in which various methods must be employedinordertoremov ethewatert?omtheoiL Anoilandwatermixture that won’t separate by settling.

Enhanced Oil Recovery Methods (EOR) - Methods of adding energy to an oil well reservoir to produce oil after natural reservoir pressure is depletd Some of these methods include water flooding, natural gas injection and chemical injection.

Explcsive Limits - Range of vapor concentrations that will burn in air. A flame will not be sustained at a vapor concentration below the lower explosive limit @EL) or above the upper explosive limit (UEL).

Flange - A type of pipe coupling made in two halves. Each half is screwed or welded to a length of pipe and the two halves are then bolted together, joining the two lengths of pipe.l

Flare - A control device used to burn natural gas when there is a compressor breakdown or other upset condition. They may also be used with vapor recovery systems on loading racks or tank batteries.

Fraction - A sepsrate, identitiable part of crude oih the product of a refming or distillation process.1

Free Water - Water that is produced with oil that settles out of the oil within tive minutes while sitting stationary in a settling space in a vessel?

Free Water Knuckout - A long cylindrical vessel used to separate tree water from crude oil. The difference in density between oil and water is used to remove water. Water is heavier than oil and sinks to me bottom of the tank.

Fugitive Emissions - The escape of liquid or vapor VOC’s into the atmosphere from man made equipment. Hydrocarbon emissions from oil field equipment me. hgitive emissions.

Gloss - 4 July 1992

-

GLOSSARY Oil Field ProductIon

Gasoline - The most valmble &incd traction acquired from crude.oil. It is lighter than naphtha.

Gas Lift - A method of l@ing oil out of an oil well by using natural gas. Natural gas is pumped into the well and at the hottom of the well it becomes part of the fluid in the well. As the gas expands it lifts oil to the surface. ‘Ibis method of production is often used in offshore oil wells.’

Gas Lift Valve - A valve used to transfer natural gas into an oil well for a gas lift operation. A series of these valves rue placed throughout an oil well.

Gas Oil - A refined fraction of crude oil heavier than kerosene that is often used as diesel fuel.

Gas Turbine - A thermodynamic device used to change chemical energy from a fuel to mechanical energy. Compressed air and a fuel such as gasoline or natural gas enter the combustor of a gas turbine. Hot gases from the combustion of fuel and air exit at a high velocity, driving a tnrbine. The mechsnical energy from a gas turbine may be used to drive generators for electricity at an oil field Excess electricity may be sold to utilities. (See Cogeneration)

Glycol Dehydrator - A device used to remove minute smounts of water from natural gas>

Gun Barrel - A settling tank that is used to remove natural gas and water from an emulsion. Emulsion (water and oil) enter the gun barrel after passing through separators. They are cylindrically shaped tanks and aren’t used as much today as they were iu the past.

Heater Treater - A tire1 fired device that combines all the various pieces of equipment used to treat an emulsion in one vessel. In heater treaters the effects of chemicals, heat, settling and otten electricity are applied to an emulsion. Heater treaters remove natural gas and oil from an emulsion. There rue many different types of heater treaters available for different emulsions that may be encountered. Some may be applied more to knocking out water while others may be suited for extremely cold climatea

Heavy Gil - A thick oil with the consistency of cold molasses. It is denser and has more carbon atoms than lighter crude oils. Heavy oil is not as valuable as light oil since it yields less gasoline, naptha and kerosene but more asphalt than

July 1992 Gloss - 5

GLOSSARY

Gloss - 6

light oil. Any oil with au AFq gravity less than 265s considered to be a heavy Oil.

Horse Head - A horse head shaped part that co~ects to the end of the walking ~~~~e~~e~dc~~~of~~we~p~~g~t~~~to hive sucker rods to operate a pump at the bottom of a well. Horse heads have an arc on one side of them to push and pull the polished rods straight in and out of a well head.

Hydrocarbons - Orgauic compounds of hydrogen and carbon atoms. Crude oil is made of a large number of these different compounds. (examples: hexane, heptane, octane, benzene)

Hydrogen Sulfide @-I$) - An odorous, poisonous, unwanted gas that is encountered in many oil production operations. It has a strong rotten egg odor but it cannot be detected by a person’s sense of smell at high concentrations. Precau- tions should always be taken for HrS detection at oil fields with H.$ problems.

Hydraulic Pump - A pump where a fluid such as water is pumped down to the bottom of an oil well driving another pump that lifts crude oil to the surface.

Inaccessible Component - A component that is located more than fifteen feet above ground when the only access is from the ground or a component that is six or more feet from a platform required for access to a component.

Injection Well - A well used to inject steam water or natural gas in order to help force oil to producing oil wells to improve production. Injection wells sre ofteu ones that were once us4 for production.

Internal Combustion Engine - A thermodynamic device used to change chemical energy from a fuel such as gasoline, natural gas or diesel oil to mechanical energy. Combustion of the fuel within each cylinder of the engine drives pistons which turn a crankshaft. Internal combustion engines may be used to run compressors at an oil field or pumps for oil wells.

Intrinsically Safe - Equipment or wiring in which any spark or thermal effect, produced either normally or in specified fault conditions, is incapable of causing ignition of a mixture of flammable or combustible material in air at its most easily ignited concentration.

July 1992

t’- GLOSSARY Oil Field Production

Kerosene - A component of crude oil that is a fuel that is heavier than naphtha but lighter than gas - oil.

Landfarming - A means of waste management where petroleum wastes are mixed with soil to allow bacteria to break it down.

Light Crude Oil - Crude oil that has an API gravity equal to or greater than 30’ and a vapor pressure greater than 1.5 psia. It is determined by using ASTM Method D-1298-85.

Loadlng Rack - An elevated walkway that supports vertical filling lines and valves for fling tank cars or trucks from the top with crude oil1

Material Safety Data Sheets (MSDS) - Informatlon sheets provided to users by chemical manufactumrs providing information concerning the hazsrds of materials. The format is specified by the federal Occupationsl Safety and Healm Administration (OSHA) in Title 29, Sections 19151917 of the Code of Federal Regulations.

Membrane Separator - A unit with no power or moving parts that selectively removes COr (carbon dioxide), I-JS (hydrogen sulfide) and HrO (water) from natural gas.

Micellar Surfactant Flooding - A tertiary recovery technique where crude oil from a field depleted by conventional means is recovered by injecting water mixed with certain chemicals into the producing formation. The chemicaI reduces the surface tension of the oil clinging to porous rock allowing the oil to be pumped out with the flooding solution:

Miiible - The ability to mix two or more subtances together. Liquids that are not miscible sepsrate according to their densities where heavier substances with higher specific gravities sink below lighter ones. A substauce that is miscible with each of two immiscible liquids that is used to reduce the interfacial tension between the two immiscible liquids. Some oil recovery methods use substances miscible with oil and water in order to increase oil production.4

Miscible Displacement - Displacement of oil by a fluid with which it is miscible. When such a fluid contacts the oil, the two liquids dissolve each into the other and form a single liquid phase. There is no interface between the fluids and hence there are no capillary forces active.4

July 1992 Gloss - 7

Oil Field Oil Field F%dUCthl F%dUCthl GLOSSARY GLOSSARY

~ble~-A~~~~~~~v~~~~wh~~o~ more formation - flood fluids are used, one behind tbe other. For example, CO2 may he injected into the ground followed by waterflooding.r

NAAQS - (National Ambient Air Quality Standards) National Ambient Air Quality Standards are developed by EPA pursuan t to Section lG9 of the Federal Clean Air Act. NAAQS exist for nitrogen oxides, sulk oxides, particulate matter, ozone and carbon monoxide.

Naphtha - A volatile, colorless liquid tiaction of crude oil that is used as a solvent for paint and dry cleaning fhridr

Natural Gas - Gaseous hydrocarbons made up of at least 80% methane and maybe some ethane, propane, and butane. Namral gas is often found with crude 0%

Nitrogen Oxides - (NOx) A compound of a nitrogen atom and one or more oxygen atoms. These compounds are emissions of combustion and lead to ozone formation. (examples: NO = nitrogen oxie NO2 = nitrogen dioxide)

Notice of Violation - Document issued to a company for violating air pollution regulations.

Oil And Gas Production Field - A facility where crude petroleum and natural gas production is conducted as detined by Standard Industrial Classification (SIC) code 1311.

Oii Gauge Tanks - Tanks used to test the oil coming from a well or group of wells.

Oil LACX (Lease Automated Custody Transfer) Tanks - Tanks containing crude oil with negligible amounts of water and sediment that is ready for u-arts- port to refineries.

Oil Water Separator - A machine used to seqarate out small amounts of oil remaining in produced water. They are often referred to as ‘Wemco Units”.

Gloss - 8 July 1992

t- GLOSSARY Oil Field Production

Oil Wash Tanks - A tank used to se.para& crude oil and water. The difference in density between crude oil and water is the means by which the two sre separated. Crnde oil is lighter and stays on top of the water in the tar&

Ozone - (Or) A colorless, odorless gas formed from chemical reactions between hydrocarbons, nitrogen oxides and sunlight that is irritating and damaghrg to humans, plants and anhnals. It is the one of the main components of smog and is California’s biggest air pollution problem.

Permeability - The capacity of transmitting a fluid. The degree of permeability depends upon the size and shape of the pores and the sixe, shape and extent of the interconnections. The units of permeability are the Darcy?

Permit To Operate - A document issued to the owner of pollution generating equipment allowing the owner to use the equipment in a manner to reduce emissions.

PH Scale - A scale ranging from 0 to 14 used to measure the acidity and alkalinity of a solution where 0 is the strongest acid, 14 is the suongest base and 7 is neutral. Numbers less thau 7 are solutions of increasing acidity and numbers greater than 7 are of increasing alkalinity1

Pit - A lined or un-lined excavated depression in the ground which is used intermittently or in emergencies to collect crude oil and water.

Pitman - A steel member that connects to the counter weight and to the walking beam of an oil well pumping unit. The pitman transmits the rotation of the crank to the up and down motion of the walking besm.

Plunger Pumps - Cylindricsl pumps equipped with plungers that are placed in the bottom of an oil well to lift fluid from the well to the surface? These pumps are actuated by beam pumping units.

Pond - A lined or un-lined excavated depression in the ground used to contain produced water.

Porosity - The volume of pore space expressed as a percentage of the total volume of the rock mass; measures the absorbent capacity of the material or the volume of liquid held by the pore~.~

July 1992 Gloss - 9

011 Field Production GLOSSARY

Portable Tanks - Tanks used for many purposes including: temporary storage of oil during a workover or stimulation procedure and storing solids from other tanks.

Pressure Relief Valve - (PRV) A valve on the top of a tank used to prevent the pres.me inside a tank t?om getting too high or too low.

Process Turnaround - Shutting down part or all oil field production in order to do cleaning or servicing. Large emissions of hydrocsrbons can occur during a process turnaround.

Produced Water - Water that is produced from oil in an oil well.

Produced Water Separator Tanks - Tanks that are used to separate out small amounts of oil that are left in produced water.

Produced Water Tanks - Tanks used to store clean produced water that is a by- product of oil production.

Producing Well - Wells which produce crude oil and/or natural gas.

Reactive Organic Compound - (ROC) See Volatile Organic Compound.

Retinery - Location where crude oil is distilled and made into many different pdUCtS.

Repressming Operation (Pressure Maintenance) - The injection of fhrid into a reservoir whose pressure has been largely depleted by producing wells in the field This secondary recovery technique is used to increase the reservoir pressure in order to mover additional quantities of 0iLt

Reservoir - A section of porous rock under the gnxmd that contains an accumulation of natural gas and/or oil.

Sampson Post - Posts that support the walking beam of a beam pumping unit.

Scrubber - A piece of equipment used to control SOx emissions from steam generators or other oil tired equipment.

Gloss - 10 July 1992

c GLOSSARY Oil Field ProductIon

Skimming - The prcccss of removing sm& amounts of oil from the surface of water using a skimmer.

Soda Ash Tower - A device used to pmduce an alkaline solution to neutralixe tbe acid from SOx in a scrubber.

Sour - Natural gas or oil that contains a large amount of sulfur compounds.

Specific Gravity - Weight of given volume of any substance compared with the weight of an equal volume of water. Relative density.

Stationary Source - A pollution source that is fixed and not moving.

Steam Generator - An oil or natural gas tired piece of equipment used to change water to steam. The steam is then injected into injection wells in order to improve oil production.

Stripping - Removing volatile products from a substance by heating.

Stuffing Box - A packing gland, chamber, or “box” used to hold packing material compressed around a movhrg pumping rod to prevent the escape of gas or liquid They may also be referred to as pump seals.

Sucker Rods - Steel rods that a~ screwed together and put into an oil well in order to operate the pump at the bottom of the well in a rod pump confIguration.

Sulfur Dioxide - (SOx) A compound of a sulfur atom and one or more oxygen atoms. These compounds are emissions from the combustion of fuels with sulfur in them.

Sump - A lined or un-lined excavated depression in the ground which is used to continuously separate crude oil, produced water and solids.

Surface Tension - A tension force that exists between the molecules of a liquid because of the attraction between polar molecules.

Surfactant - A substance that helps two materials mix together by reducing the interfaciaJ tension between them. Surfactants are used in oil recovery to increase oil prcduction by making oil and water mix iuto one liquid phase, making

July 1992 Gloss - 11

011 Field PWdUCtiM GLOSSARY

oil easier to pump out of a reservoir. Surfactant molecules have a polar end which at&a&s water molecules and an organic end which attracts oil.

Sweet - Natural gas or oil (hat contains little or no sulfur compounds1

Tank Farm, Tank Battery - A group of tanks.

Tar - One of the heaviest fractions in crude oil. It is used for asphalt or roofing materials.

Thief - A metal or glass cylinder with a spring actua@d closing device that is lowered into a tank to obtain a sample of oil or to the bottom of the tank to take a column of heavy sediment. The thief is lowered into the tank on a line that when jerked will nip the spring valve enabling the operator to obtain a sample at any desired level.’

Throughput - The capacity or production limit of a tank or other piece of equipment on an oil field. Throughput limits may be put on some tanks by Permits to Operate. Throughput is usually in barrels.

Tripping - The process of removing all the drill pipe out of a hole in order to replace the drill bit when it is worn out. This process will occur many times during the drilling of an oil well.

Valve - A mechanical device used to control the flow of liquid or gas from one place to another.

Vapor Recovery System - Unit used to collect vapors of volatile products in crude oil. A commonly used efficient means of air pollution contml used in oil fields.

Vapor Pressure - The pressure exe-rted by a vapor that is in equilibrium with its liquid state.l

Viicsi~y - The measure of the ability of a liquid to flow. A liquid with a high viscosity will not flow as well as one with a low viscosity.

Volatile - A substance that evaporates at a high rate at a low temperature.


GLOSSARY Oil Field Production

Volatile Organic Compound (VOC) - Any compound with at least one carbon atom except: methane, CaTbotl monoxide, carbon dioxide, carbonic acid metallic carbides, metallic carbonates ammonium carbonate, methylene chloride, 1 , 1,l trichloroethane (methyl chloroform), 1,1,2 trichlorotrifluoroethane (CFC-113), trichlorofluoromethane ((XT-1 l), dichlorodifluoromethane (CFC-12), dichlorotetrsfluoroethane (CFC-114), chloropentafluoroethane (CFC- 115), nifluoromethane (CFC-23), HCFC-123 (dichlorotrifluoroethane), HFC- 134a (tetrafluoroethane), HCFC-14lb (dichlorofluoroethane), HCFC-142b (chlorodifluoroethane), and chlorodifluoromethane (CFC-22).

The exact listing of compounds may vary. Some districts use the terms ptecur- sor or reactive organic compounds to denote VOC. As a note, many of these compounds which rue listed as exempt compounds may contribute to upper atmosphere oxone destruction. Other exempt compounds am bemg investigated as possible toxic air contaminants. Finally, carbon dioxide is considered to be a ‘greenhouse gas” which may contribute to global warming, and carbon monoxide is a primary pollutant.

Variance - F&mission given to a facility by an AF’CD or AQMD to legally pollute beyond regulated limits because of a breakdown or other condition.

Volatility - The tendency of a liquid to evaporate. Liquids with high boiling points have low volatility and vice versa.

Walking Beam - The steel beam of a beam pumping unit, which connects with the horse head snd pitman, that oscillates at each end of the beam turning about a linkage near the center of the beam.


Oil fleld Production GLOSSARY

Waterflooding - A secondary recovery method where water is injected into an d reservoir to force additional oil out of resmoir rock and into the well bores Df producing wells>

Wettability - As applied to peuoleum reservoirs, the relative affinity of the mexisting oil and water phases to adhere to the surface of a rock. If the rock is predominantly in contact with water, it is said to be preferentially water-wet, Similarly, if rock is predominantly covered with oil, it is referred to as oil-wet.

Wellbead - An assembly of valves mounted to the casinghead of an oil well thmugh which a well is produced An oil production line and vapor recovery line are comxcted to a wellhead. Wellheads are often referred to as “Christmas lICX%“J


(I GLOSSARY Oil Field Froducth

Glossary References

I. Langekamp, R. D.a of Oil m Third Edition; Tulsa, Oklahom PeMWell Publishing Company, 1981.

2. m of Oil B, Dallas, Texas, American Petroleum Institute Production Department, 1976.

3. Treat&z Oil Field Emulsions, Third Fdition; Dallas, Texas, Austin, Texas, American Petroleum Institute Division of Production and Petroleum Extension Service respectively, 1974.

4. M. M. Schumacher - editor, med Oil Reco erv Seco datv and Tertiatv Methe Park Ridge, New Jersey; Noyes Data Co&ration, i978.


APPENDIX A Oil Field Production

July 1992 A-l

EPA METHOD 21

Oil Field Production APPENDIX A

--I PmddkmAgmcy Pt. 6% App’& Math. 21

104 F+#. - Ea.zi4

A-2 July 1992

APPENDIX A Oil Field Production

788

July 1992 A-3

Oil Field Praduction APPENDIX A

7a9

A-4 July 1992

I APPENDIX A 011 Field

Production

Pt. 60, App. A, Moth. 22 40 cl% al. I (7-l-87 Edition)

July 1992 A-5

APPENDIX B Oil Field Production

SOUTH COAST AQMD RULE 1173

July 1992 B-l

(Adopted July 7,1989)(Amended December 7,199O) 0

RULE 1173. FUGlTlVE EMISSIONS OF VOUTILX ORGANIC COMPOUNDS

(4 mo= This rule is intended to control volatile organic compounds leaks from valves, fittin~~pumps, compressors, pressure relief devices, diaphragms, hatches, sight- glasses, and meters at refineries, chemical plants, oil and gas production fields, natural gas processing plants, and pipeline transfer stations.

(b) Definitions: For the purpose of this rule the following definitions shah apply:

BACKGROUND is the ambient concentration of volatile organic compounds in the air determined at least one (1) meter upwind of the component to be inspected CHEMICAL PLANT is any facility engaged in producing organic or inorganic chemicals, and/or manufacturing products by chemical processes. Any facility or operation that has 282 as the first three digits in its Standard Industrial Classification Code as defined in the Standard Industrial Classification Manual is included. COMMERW NATURAL GAS is a mixture of gaseous hydrocarbons, with at least 80 percent methane, and less than 10 percent by weight volatile organic compounds, determined according to test methods specified in subparagraph (g)(2). COMPONENT is any valve, fitting pump, compressor, pressure relief device, diaphragm, hatch, sight-glass, and meter. They are further classified as: (A) MAJOR COMPONENT is any 4-inch or larger valve, any 5-hp or

larger pump, any compressor, and any 4-inch or larger pressure relief device.

(B) MINOR COMPONENT is any component which is not a major component.

COMPRESSPOR is a device used to compress gases and/or vapors by the addition of energy, and includes all associated components used for comecting and sealing purposes.

1173 - 1

Rule 1173 (Cont.) (Amended December 7,WMJ)

~(6) EXEMPT COMPOUND is any of the folIowing compounds which have been determined to be non-precursors of ozone: -. (A) Group I (GeneraI)

chlorodifluoromethane (HCFC-22) dichIorotrifIuoroethane (HCFC-123) tetrafhtoroethane (HFCl34a) dichIorofluoroethane (HCFC-14lb) chIorodifhtoroethane (HCFC-142b)

(B) Group II (Under Review) methylene chloride l,l,l-trichloroethane (methyl chIoroform) trifiuoromethane (FC-23) trichlorotrifh.toroethane (CFC 113) dichIorodifluoromethane (CFC-12) trichlorofluoromethane (CFC-11) dichlorotetratluoroethane (CFC-114) cloropentafluoroethane (CFC-115)

The Group II compounds may have restrictions on their use because they are toxic or potentially toxic, or upper atmospheric ozone depleters, or cause other environmental impacts. The use and emissions of chlorofluorocarbons (CFC) will be phased out at the earliest practicable date on or before 1997.

(7) FACILITY is a refinety, cbemicai plant, oiI and gas production field, naturaI gas processing plan4 or pipeiine transfer station.

(8) FIELD GAS means feed stock gas entering the natural gas processing plant.

(9) FITIIhrG is a component used to attach or connect pipes or piping details, including but not Iimited to fianges and threaded connections.

(10) GAS LEAK is one of the fohowing: (A) MAJOR GAS LEAK FOR ANY COMPONENT EXCEPT FOR

A PRESSURE RELIEF DEVICE is the detection of gaseous volatile organic compounds in excess of 10,000 ppm as methane above background measured according to test procedures in subparagraph (h)(l).

(B) MINOR GAS LEAK FOR Ah’Y COhfPONENT EXCEPT FOR A PRESSURE RELIEF DEVICE is the detection of gaseous

1173 - 2

Rule 1173 (Cont.) (Amended December 7,l990)

voIatiIe organic compounds in excess of 1,000 ppm but not more than 10,000 ppm as methane above background measured according to test procedures in subparagraph (h)(l).

(C) MAJOR GAS LEAK FOR A PRESSURE RELIEF DEVICE is the detection of gaseous voIatiIe organic ‘compounds in excess of 200 ppm as methane above background measured according to test procedures in subparagraph (h)( 1).

(11) HATCH is any covered opening system that provides access to a tank or container, usuahy through the top deck.

(12) INACCESSIBLE COMPONENT is any component located over fifteen feet above grotmd when access is required from the ground or any component located over six feet away from a platform when access is required from the platform.

(13) INSPECTION is either of the foIIowing: (A) OPERATOR INSPECTION is a survey of components by the

operator for the purpose of determining compIiance with this rule. (B) DISTRICT INSPECTION is a survey of components by District

personnel or their representatives. (14) LIQUID LEAR is the dripping of liquid volatile organic compounds at

the rate of more than three drops per minute. (l5) LUBRICATING FLUID is a fluid that provides lubrication of moving

parts in a pump, including barrier fhrids. (16) NATURAL GAS PROCESSING PLANT is a facihty engaged in the

separation of naturaI gas Iiquids from field gas and/or fractionation of the Iiquids into naturaI gas products, such as ethane, propane, butane, and naturai gasoline. Excluded from the definition are compressor stations, dehydration tmits, sweetening units, field treatment, underground storage facihties, Iiquified namrai gas tits, and field gas gathering systems unkss these facihties are located at a naturaI gas processing plant.

(17) OIL AND GAS PRODUCI’ION FIELD is a facility on which crude petroleum and naturaI gas production and handhng are conducted, as defined in the Standard IndustriaI CIassification ManuaI as Industry No. 1311, Crude Petroleum and Natural Gas.

1173 - 3

Rule 1173 (Cont.) (Amended December 7,l!I90)~

PIPELINE TlUNSFER STATION is a facility which handles then’ transfer and storage of petroleum products or. crude petroleum in pipelines. PEATFORM is any raised permanem horixontal surface for the purpose. of gaining access to components. PRESSURE RELIEF DEVICE (PRD) is a pressure relief valve or a rnpture disc. PRESSURE RELIBF VAL.VE (PRV) is a valve which is automatically actuated by upstream static pressure, and used for safety or emergency purposes. PUMP is a device used to transport fluids by the addition of enera, and includes all associated components used for connecting or sealing purposes. REFINERY is a facility that processes petroleum, as defined in the Standard Industrial Classification Manual as Industry No. 2911, Petroleum Refiig. REPAIR is any of the following: (A) ON-SITE REPAIR is corrective action for the purpose of

eliminating leaks and which is not a significant repair. (B) SIGNIFICANT REPAIR is corrective action for the purpose of

eliminating leaks involving the temporary removal or taking out of service of a component.

RUPTURE DISC is a diaphragm held between flanges for the purpose of isolating a volatile organic compound from the atmosphere or from a downstream pressure relief valve. VALVE is a device that regulates or isolates the fluid flow in a pipe, tube, or conduit by means of an external actuator; including flanges, flange seals, and other components used for attachment or sealing. VOLATILE ORGANIC COMPOUND (VOC) is any volatile compound containing the element carbon, excmding methane, carbon monoxide, carbon dioxide, carbonic acid, metallic carbides or carbonates, ammonium carbonate, and exempt compounds.

1173 - 4

Rule 1173 (Cont.) (Amended December 7,wo)

(c) Leak Control Requirements (1) Any liquid leak or gas leak of over 50,000 ppm detected by District

inspection shall constitute a viohtion of this rule. (2) Any major gas leak detected by District inspection, within any continuous

24-hour period, and nmbering in excess of the Leak Thresholds for that component listed below in Table 1, shall constitute a violation of this rule.

TAKE 1. LEk+XTI-IRESHOLDS Comnonent &No.ofLealrs Max. No. of Leaks

(25J~kS (over m compents inspected) eompcments inspected)

Valves 1 0.5% of mber inspected

-S 2 1% of number inspected Compressors 1 1 PRDs 1 1 Other Components 1 1

The maximum munber of leaks in Table 1 shall be rounded upwards to the nearest integer, where required.

(3) Open-ended lines and valves located at the end of lines shall be sealed with a blind flange, plug, cap, or a second closed valve, at all times except during operations requiring process fluid flow through the open-ended he.

(d) Identification Requirements (1) All major components shall be physically identified clearly and visibly for

inspection, repair, replacement, and recordkeeping purposes. (2) JUl minor components shall be clearly identified in Piping and

Instrumentation (P&I) flow diagrams, and/or grouped together functionally for inspection, repair, replacement, and recordkeeping purposes.

(3) Any change(s) in major component identification shall require prior written approval from the District, Office of Operations.

1173 - 5

Rule 1173 (Cant.) (Amended December 7,l!WO)

(e) Operator Inspection Requirements (1) All accessrble pumps, compressors, and pressure relief devices shah be

audio-visually inspected once during every eight-hour operating period, except for -ed oil and gas production fields, and umruumed pipeline transfer stations.

(2) All accessible components shall be inspected quarterly. . (3) All inaccessible components shall be inspected ammally. (4) A pressure relief device shah be inspected within 14 calendar days after

every ftmctional pressure relief. (5) The inspection frequency for accessible components, except pumps and

compressors, at a facility, as required in subparagraph (e)(2), may change from quarterly to annually, provided all of the following conditions are met. (A) All accessible components, except pumps and compressors, at that

facility have been successfully operated and maintained with no liquid leaks and with major gas leaks within the Leak Thresholds for such components listed in Table 1, for five consecutive quarters; and

(B) The above is substantiated by documentation ‘and submitted for written approval from the District, Office of Operations.

The annual inspection frequency for. all accessible, components, except pumps and compressors, if approved in subparagraph (e)(S), shall revert to quarterly, should the ammal inspection or District inspection show any . hquid leak or major gas leaks in excess of the Leak Thresholds for such

components listed in Table 1.

(f) Maintenance Requirements (1) A component shall be repaired or replaced within the following time

period after detection of the leak by operator inspection or District inspection, according to Table 2, Repair Periods.

1173 - 6

Rule 1173 (Cont.) (Amended December 7,l!WO)

TABLE 2. RBPAIR PERIODS Twe of Leak Time Period

Minor Gas Leak 14 Calendar Days Major Gas Leak 5 Calendar Days Gas Jiak over 50,000 pprn 1 Calendar Day Liquid Leak 1 Calendar Day

(2) The repaired or replaced component shall be subjected to operator inspection within 30 days of the repair or replacement.

(3) A component or parts thereof shall be replaced with Best Available Control or Retrofit Technology (BACT or BART), or vented to an air pollution control device approved by the District, Office of Gperations, after it has been subjected to five significant repair actions for a liquid leak or a major gas leak within a continuous nvelve-month period.

(4) The reporting provisions of Rule 430 shall not be applicable to components being repaired or replaced under the provisions of this rule, except compressors.

(g) Recordkeeping Requirements (1) Records of leaks detected by quarterly or annual operator inspection, and

subsequent repair and reinspection, shall be submitted to the District, Office of Gperations, within 30 or 60 days, respectively. Such records shall be submitted on standard forms spezified by the District, and shall contain all information required on the form.

00 Test Methods (1) Measurements of gaseous volatile organic compound leak concentrations

shall be conducted according to EPA Reference Method 21 using an appropriate analyxer calibrated with methane at a distance of 1 cm or less from the source.

(2) The volatile organic compound content of fluids shall be determined using ASTM methods E-168, E-169, or E-260, or any other equivalent method approved by the District, Office of Operations, in writing.

1173 - 7

Rule 1173 (Cont.) (Amended December 7,l990)

(3) All records of operator inspection and repair shall also be maintained at - the facility for a period of two (2) years and made available to the District staff on request.

(i) Compliance Schedule All facilities shah be in compliance with this rule by February 1,199l.

(j) Other Rules and Regulation Applicability (1) Affected facilities shah comply with the provisions of Rules 466, 466-1,

and 467 until February 1, 1991, or until compliance with this rule is achieved, whichever is earlier.

(2) In case of conflict between the provisious of this rule and any other rule, the provisions of the rule which more specifically applies to the subject shall prevail.

(k) Exemptions The provisions of this rule shall not apply to the following cases, where the person seeking the exemption shall supply the proof of the applicable criteria to the satisfaction of the District, Office of Operations:

w

(2)

(3) (4)

(7) O?

Components which present a safety haxard for inspection as documented and established in a safety manual or policy, previously, or with the prior written approval of the District, Office of Operations. Components being repaired or replaced within the specified repair or replacement period, as given in Table 2. Components exchtsively handling commercial natural gas. Components exchrsively handling fhdds with a VOC concentration of ten percent by weight or less, determined according to test methods specified in subparagraph (h)(2). Components incorporated in lines, while operating under negative pressures. Components totally contained or enclosed such that there are no VOC emissions into the atmosphere. Lubricating fluids. Components buried below gromd.

1173-S

Rule 1173 (Cont.) (Amended December 7,l99o)

0 (9) Components handling liquids exclusively, if the weight percent

evaporated is ten percent or less at lXPC, as detemked by ASTM Method D-86.

(10) Pressure vacuum valves on storage tanks.

1173 - 9

APPENDIX C 011 Field Production

ASTM 4057

Reprinted, with permission, from the Annual Sook of ASTM Standards, copyright American Society for Testing and Materials, 1916 Race Street, Philadelphia, PA 19103

This standard has been superseded by a new edition. To obtain a copy of the latest edition, please contact ASTM.

July 1992 C-l

Oil Field Producfion APPENDIX C

f# Desigmtion:D4057-8ia Al---

4 ~IJesigna~ MPMS (alapm 8.1)

Standard Practice for : Manual Sampling of Petroleum and Petroleum Products’

don by Atson M&xxi3 D2U2 Tcs M&d for Quamitati~ ExGauion of Bi-

tumen fmm Bituminous Paving Mix.m&

July 1992

APPENDIX C 011 Field Pmduction

July 1992

247

Oil Field Production APPENDIX C

c-4 July 1992

APPENDIX C

.-~- Oil Field

Production

249

July 1992 c-5


@J D4057

-fY CLOVE HITW

-

C-6 July 1992

APPENDIX C 011 Field Production

8.52 Skip orB@e Tr&&mpla of tip CZ’gWS of crude petroleum may ta taken by the following mubods by

July 1992 c-7

Oil Field Pmduction APPENDIX C

C-8 July 1992

APPENDIX C Oil Field Production

July 1992 C-Q


c-10 July 1992


P.S.2 .dpQ.n 9.6.2.1 Tub

July 1992 c-11


9.7.3.1 Tbi.+Tke ttdd sixd bz design.33 so dm a

c-12 July1992

APPENDIX C I

011 Field Production

9.821 Ship Auger-Ux a tip anger v4 in. (19 mm) ln diamct~,similnrtotbatshoninF~7,andofzui3icir.nt

9.8.4 Lubomtw 1nspeaion-If there are any 5isii dif-

July 1992 c-13

Oil Field Production I

APPENDIX C

@I D4057

c-14 July 1992

APPENDIX ,C Oil Field Production

-

4lb D4057

July 1992 c--Is


C-16

-

July 1992


Al. PltECAUIIONARY SIAlEhlEWS

July 1992 c-17

A Air Fuel Ratio 400-6,7,13 Air Pollution Control Gfficer 500-6 APmravity 300-33 Application For Variance 500-7 ARB 200-10 ArtiticialLift 300-11 Authority To Construct 200-15400-3

B Background Concentration 4Kl-4 Ball Valves 400-5 Bay Arca AQMD 500- 12 Beaker Sampler 400-16 Blowout Prevention 300-3 Bolts 400-8 Bottle Sampling 400-16 Bottom Sample m-16 Bridle 300-13

C California Air Resources Board 400-12, California’s Crude Gil Production 200-7 California Health & Safety Code 400-2 Capillary Forces 300- 18 Carbon Dioxide Miscible 300-20 Carrier Bar 300-13 Casing 300-l ,7

Head 300-13 strings 30&13 Vapor Recovery 400-9

Cementing 300-6 Centritugal Pumps 400-5 Chart Recorder 400-11 Christmas Tree 304%10,400-9 Civil Penalties 200-17 Clearance Sample 400-16 CO~Emissions 300-58 Cogeneration Technology 500-3 Combustion Air 300-28 Combustion Emissions 200-13 Compliance 200-17 Compliance Assistance Program (CAP) Components 200-9,400-3,4,12,15 Compressors 400-9,10

Cemrifugal 400-5

IN

500-2

100-l

IEX Reciprocating 400-5

Conductor Pipe 300-49 Continuous Sampling 400-16,18 Counter Weight 300-13 crank 3cO-13 Crew Boats 400-12 Ckimhal Penalties 200-19 Crustal Movements 2f!O-2 Cyclic Steam Injection 300-23

Data Logger 400-18 Dehydration Unit 30-36 Derrick 300-3 Detection Techniques 200-12 Development Well 300- 1 Direct Maintenance 200-17 Dissolved Gas Drive 2m2 District

Inspectors 100-l Permit System 500-4 Powers 500-2 Regulations 400-1,3,7,15,5(X3-12

Division of Gil And Gas 500-15 Drain Sample 400-16 Drilling 200-8,300- 1

Mud 300-2 Rig 3CO-2 Vessels 300-I,57

DrillPipe 300-3 Dump Lever 300-39

E Electricity 300-14 Electrostatic Treaters 300-43 Emission Inventory 200-l 1 Emissions 200-10 Emulsion 300-39,40,41,43,49,400-7 Enhanced Gil Recovery 200-9,300-16 Enforcement 200- 16 EPA Method 21 200-12 Equipment 400-20 Equipment Check 400-2 Exploratory Well 200-8,300-l

JULY 1992 INDEX- 1

F File Review 400-I Fireboxes 300-43 PinedEquipment 400-6 Fiiflood 300-31 Fixed Roof Tanks 400-7,13 Flanges 3CO-10,400-3,4,5,13,15 Flare System 200-14,400-6,7,13 muid Level 300-13 Forbay 300-52 Free Water Knockout 300-39 Fresno County APCD 500-12 Froth Flotation Units 300-60

G GtlS

Cap 200-3 compressors 300-60 Dehydrators 300-60 Drive 200-3 Gathering System 300-28 Lift 300-15 Turbines 200-14

Gaseous Emissions 300-36 Gate Valve 400-5 Gear Reducer 300-13 GeneraJ Violations, Civil 500- 10 General Violations, Criminal 500-8 Geometric Patterns 300-24 Globe Valves 400-5 Gravity 200-2 Gun Barrel 30049

H Health & Safety Code 200-14,400-2,500-l Heat~Exchanger 30-28 HeaterTreaters 300-14,400-7,13 Heaters 300-44

Direct 300-44 Fluid Jacket 300-45 Jug 300-45

Heavy Gil 300-33, NO-6 Hydraulic Lift 300- 14 Hydraulic Powered 3CXI-12 Hydrocarbon Analyxers, Detectors 300-10,400-

JULY 1992

19,20

I Jmmiscible Gas Injection 300-18 Industry Opemors 100-l mjection Wells 300-17 Jn-Situ Combustion 300-24,3 I Jnspection & Maintenance 200- 12 hpection che4Mist 400-12 intrinsically Safe 400-20

J, K Kelly 300-l Kern County APCD 500- 12 Kings county APCD X0-13

L LACT Units 300-54,400-7,ll Leak

Detection Methods 400-3 Free 200-17

Leaking Components 2OO-13,16 Leaks 206-13 Legal Requirements 400- 1 Liner 300-6 LocaJ Air Polhrtion Control District 200-14 Lower Sample NO-18

Ill Manometer 400-11 Material Safety Data Sheet 400-2 Meters 400-6 Mice&r Solution 300-22 Middle Sample 4CO-18 Migration 200-I Miscible Displacement 300-21 Mobility Ratio 300-l&300-21 Monterey Bay APCD 500-13 MudCake 300-3 Mud Weight 300-3

4,8,16 Hydrogen Miscible 300-19 Hydrogen Suhide 200-14,300-61,400-2,3,9,10,

INDEX- 2

N Natural Gas 400-6,7,11

6 Negligence, Qiminal 500-9 Notice of Violation 400-3,14 NOx Emissions 200-9,300-58, m3,6,7

0 Gffshom 200-7,300-1,56,400-11,14 oil 300-54

Droplets 200-l FieldProduction 200-1,300-154 Pools 200-2 Suing 300-6

Gil Water Separators 400-9,11,14 Gnshore 200-7,300-l Grganic Vapor Analyzer (OVA) 400-8 Grigin of Petroleum 200-I

P Packing 400-5

Gland 4C0-5 Rings 400-5

Particulate Matter 200-9 Penalties 200-17 Permit System 200-14 Permit To Gperate 200-15,400-1,3,7,12,15 PH 400-6,13 Pipelines 400-9,16 Pitman 300-13 Pits 300-52 Platforms 300-59,400-11,16 Plug Valves 400-5 Phmger Lift 300-16 Polished Rod 300-13,400-5 Ponds 300-52 Pore Spaces 300-17 Power Plant 300-12 Pm-inspection Procedures 400-l Pressure J%@izing Lines 400-10 Pressm Relief Valves 200-13,400-8,10,13 Pressure/Vacuum Valves 200-9 Ptimary Oil Recovery 300-l 1 Prime Mover 3CO-12 Frobe400-4 Prohibitory Rules 200-16

Pump 200-9,30060,400-5 Pumping unit 300-l 1

Q R Reciprccating Pumps 400-5 Recomkeeping 400-15 Recovery Efficiency 200-6 Regulations 200-14 Relocation 200-18 Repairs 200-13 Reservoir Energy 300- 19 Reservoirs 200-2 Right of Entry 500-3 Rivets 400-8 RGC 400-3,lO RodBeam 300-11 Rod Pump 300-13,400-5 Rotary Method 300-l Rotary Table 300-l Rule 1173 200-16 Rmming Sample 400-18

S Safety 404%11,19,500-16 Salt Water 200-2 Sample 400-16 sampling 400-16,18

Continuous 400- 18 Pmbe 400-18 Thief 400-16

Sampson Post 300-13 scope of Manual lt%1 Scrubbers 400-6,7,13 Seals 200-9 Secondary Recovery 300-16 Selective Catalytic Reduction 400-6 Selective Non Catalytic Reduction 400-6 Separators 300-3760 Sight Glasses 200-9,400-3,6 Site Inspection 400-l SkimPits 300-52 Soap Solution 200-12

JULY 1992 INDEX- 3

Soda Ash Towers 400-6 Solvent 300-19 South Coast AQMO 2OO-16,X)0-14 SGx Emissions 300-58,400-3,6,7 Spot Sample 400-18 Steam

Drive 300-26 Generator 300-28,400-6,13 Stimulation 300-24

Steel Cables 300-I Stock Tank 300-36 Storage Tank 300-55 Stuffing Box 300-9,400-5 SuckerRods 300-llJ3 Sumps 300-52,40@9,14 Surfacing

casing 300-4 string 300-4

T Tank Battery 300-54,400-IO Tank Gauge Hatches 400-8,13 Tank Vapor Recovery 400-IO,11 Tee 300-13 Tertiary Recovery 300- 19 Test Separator 300-36 Thermal Recovery 300-23 Thief 300-54,400-16

Hatch 300-54 Sampling 400-16

Threaded CoMections 30&23 Time-cycle Continuous Sampler 400-18 Top Sample 400-18 Treatment Plant 300-33 Tubing String 300-6J3

U Undirected Maintenance 200-16 Upper Sample 400-18

v Valves 300-10,400-3,4,5,15 Vapor Recovery 3CO-27,51,56,400-9,10,11 Venting 400-8,ll Ventura County APCD 300-4,53,500-14 Viscosity 300-18,24

JULY 1992

VGC Emissions 300-58,400-3,9,10

W WashTanks 300-49 wastewater separators 300-51 water 300-17

currents 2w-2 Drive 200-3 Tmatment Facility 30-16

waterIlooding 300-17 Well 300-l Well Construction 300-4 Wellhead 300-7,400-5

XYZ

INDEX- 4

Acknowledaements · Acknowledaements We appreciate all the assistance that was given to our effort...

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Transcript of Acknowledaements · Acknowledaements We appreciate all the assistance that was given to our effort...