### SOUTH COAST AIR QUALITY MANAGEMENT DISTRICT

FINAL STAFF REPORT FOR

Proposed Rule 1148.1 - Oil and Gas Pr oduction Wells

Proposed Amended Rule 222 - Filing Requirements f or Specific Emission Sources Not Requiring a Written Permit Pursuant to Regulation II

Dated: February 24, 2004

Deputy Executive Officer Planning, Rule Development, and Area Sources Elaine Chang, DrPH

Assistant Deputy Executive Officer Planning, Rule Development, and Area Sources Laki Tisopulos, Ph.D., P.E.

Senior Manager Planning, Rule Development, and Area Sources Larry M. Bowen, P.E.

Author: Kennard Ellis Air Quality Engineer II

Reviewed by: Edward Muehlbacher, P.E. Program Supervisor

Frances Keeler Senior Deputy District Counsel John Olvera Senior Deputy District CounselSOUTH COAST AIR QUALITY MANAGEMENT DISTRICT

GOVERNING BOARD



### Chair: WILLIAM A. BURKE, Ed.D. Speaker of the Assembly Appointee

Vice Chair: S. ROY WILSON, Ed.D. Supervisor, Fifth District Riverside County Representative

Members:

MICHAEL D. ANTONOVICH Supervisor, Fifth District Los Angeles County Representative

JANE W. CARNEY Senate Rules Committee Appointee

WILLIAM S. CRAYCRAFT Councilmember, City of Mission Viejo Cities Representative, Orange County

BEATRICE LAPISTO-KIRTLEY Councilmember, City of Bradbury Cities Representative, Los Angeles County, Eastern Region

RONALD O. LOVERIDGE Mayor, City of Riverside Cities Representative, Riverside County

JAN PERRY Councilmember, City of Los Angeles Cities Representative, Los Angeles County, Western Region

BILL POSTMUS Supervisor, First District San Bernardino County Representative

JAMES W. SILVA Supervisor, Second District Orange County Representative

CYNTHIA VERDUGO-PERALTA Governor’s Appointee

DENNIS YATES Councilmember, City of Chino Cities Representative, Cities of San Bernardino Cou nty

Executive Officer

BARRY R. WALLERSTEIN, D.Env.PR 1148.1/PAR 222 i February 24, 2004 TABLE OF CONTENTS

EXECUTIVE SUMMARY

-------------------------------------------------- ------------------------------ 1

Proposed Rule 1148.1 - Oil and Gas Pr oduction Wells

Proposed Amended Rule 222 - Filing Requirements f or Specific Emission Sources Not Requiring a Written Permit Pursuant to Regulation I I

PROPOSED RULE 1148.1

BACKGROUND ----------------------------------------

--------------------------------------------------- -- 3

A. Purpose B. Legislative Authority C. AQMP Control Measures D. Oil and Gas Production – Abandoned Wells, Well C ellars, Separation and

Treatment E. AQMD Rules Regulating Oil and Gas Production F. Other California APCD Rules Regulating Oil and G as Production G. California Department of Conservation – Division of Oil and Gas

H. Affected Facilities

EMISSIONS INVENTORY ------------------------------- ------------------------------------------------10

A. Well Cellars B. Steam Injection Wells

C. Produced Gas

CONTROL TECHNOLOGY ASSESSMENT --------------------- -------------------------------------12

A. Sample Management

B. Equipment Installation, Maintenance and Repair

C. Inspection and Maintenance

PROPOSED RULE --------------------------------------

--------------------------------------------------- -17

A. Purpose B. Applicability

C. Definitions D. Requirements E. Operator Inspection Requirements F. Recordkeeping Requirements

G. Test Methods H. ExemptionsPR 1148.1/PAR 222 ii February 24, 2004

EMISSION REDUCTIONS ------------------------------- -------------------------------------------------21

A. Well Cellars

B. Produced Gas

C. Total VOC Emission Reductions

COST AND COST EFFECTIVENESS ----------------------- -------------------------------------------22

A. Liquid Control Cost

B. Untreated Produced Gas Control Cost C. Cost-Effectiveness Analysis

INCREMENTAL COST EFFECTIVENESS -------------------- ---------------------------------------29

IMPACT ASSESSMENT --------------------------------- -------------------------------------------------36

A. Socioeconomic Assessment B. Comparative Analysis C. Draft Findings Required by the California Health and Safety Code

AMENDMENTS SUBSEQUENT TO THE JANUARY HEARING ------ -------------------------38

COMMENTS AND RESPONSES ----------------------------

----------------------------------------- 38 42

REFERENCES ----------------------------------------

--------------------------------------------------- - 4 8 53

PROPOSED AMENDED RULE 222

BACKGROUND ----------------------------------------

------------------------------------------------- 4 9 54

LEGISLATIVE AUTHORITY -----------------------------

-------------------------------------------- 4 9 54

PROPOSED AMENDMENTS -------------------------------

------------------------------------------ 50 55

COST AND COST-EFFECTIVENESS -----------------------

---------------------------------------- 50 55

DRAFT FINDINGS ------------------------------------

-------------------------------------------------- 51 56Final Staff Report

PR 1148.1/PAR 222 1 February 24, 2004 

### EXECUTIVE SUMMARY

Proposed Rule 1148.1 - Oil and Gas Production Wel ls
The purpose of Proposed Rule (PR) 1148.1 – Oil and Gas Production Wells, is to reduce volatile organic compound (VOC) emissions from well cellars as well as from sources of untreated process gas located at oil and gas produc tion facilities. These goals will be achieved through an enhanced visual inspection and maintenance program and by requiring facilities to control untreated produced gas.

PR 1148.1 will implement Control Measure FUG-05 of the 2003 Air Quality Management Plan (AQMP).

Currently there are three rules in the South Coast Air Quality Management District (AQMD) that address fugitive emissions at oil and g as production fields. Rule 1148 – Thermally Enhanced Oil Recovery Wells limits the VO C emissions from steam drive wells. Rule 1173 – Control of Volatile Organic Com pound Leaks and Releases from Components at Petroleum Facilities and Chemical Pla nts, addresses VOC leaks and releases from pumps, valves, and other components. Rule 1176 – VOC Emissions from Wastewater Systems controls emissions from sumps, w astewater separators and associated control equipment.

Currently, the AQMD has no rule in place that addre sses the fugitive emissions from the control of well cellars. In addition, the AQMD doe s not have a rule that requires control of untreated produced gas at oil and gas production operations. PR 1148.1 will control

VOC emissions from these sources. Well cellar main tenance and other activities at oil field production facilities are regulated by the St ate of California, Department of Conservation, Division of Oil, Gas and Geothermal R esources, in accordance with California Code of Regulations, Article 3; Section 1774 - Oilfield Facilities and Equipment Maintenance. The proposed rule will work in concert with State regulations.

The overall VOC emission reductions resulting from the proposed rule will be 1.76 tons per day. Of this amount, 0.97 tons per day of VOC emission reductions will come from the improved maintenance of wellheads and well cell ars. Another 0.79 tons per day of VOC emission reductions will be obtained by control ling produced gas that would have otherwise been vented to the atmosphere.

Based on the reduction of emissions from both well cellars and produced gas sources, the overall cost effectiveness of PR 1148.1 is $2,483 p er ton of VOC reduced.

Proposed Amended Rule 222 - Filing Requirements f or Specific Emission Sources Not Requiring a Written Permit Pursuant to Regulati on II
Rule 222 was adopted in September 1998 and subseque ntly amended in May 2000 to help simplify and streamline the permitting process by reducing the number of permit applications required by the AQMD. The rule identi fies specific types of equipment that individually have small emissions and minimal toxic health risks. However, in the aggregate, these equipment categories have signific ant emissions or health risk.Final Staff Report

PR 1148.1/PAR 222 2 February 24, 2004 Operators of such equipment are required to file in formation with AQMD which includes a description of the equipment, facility informatio n, and other data for estimating emissions and determining compliance. Compliance i s achieved for such equipment by meeting existing rule and recordkeeping requirement s. The implementation of Rule 222 has resulted in a filing program for low-emitting e quipment as an alternative to the conventional permitting process. This amendment wi ll require filing for additional equipment that previously was not subject to Rule 2 22, which includes well cellars, wellheads and well pumps that will be regulated und er PR 1148.1.Final Staff Report

PR 1148.1/PAR 222 3 February 24, 2004 

### PROPOSED RULE 1148.1

BACKGROUND

A. PURPOSE

The purpose of PR 1148.1 – Oil Field Production Wel ls is to reduce VOC emissions from

the wellheads and the well cellars located at oil a nd gas production facilities through an enhanced self-inspection and maintenance program. The proposed rule will also reduce VOC emissions by controlling or treating process ga s that would have otherwise been vented directly into the atmosphere. VOCs are prec ursors to ozone and the AQMD is designated as an extreme non-attainment area for th e federal and state ozone standards.

B. LEGISLATIVE AUTHORITY

The California Legislature created the AQMD in 1977 (the Lewis-Presley Air Quality Management Act, Health and Safety Code Section 4040 0 et seq.) as the agency responsible for developing and enforcing air pollut ion control rules and regulations in the South Coast Air Basin (Basin). By statute, the AQM D is required to adopt an AQMP demonstrating compliance with all state and federal ambient air quality standards for the Basin (Health and Safety Code Section 40460(a)). I n addition, the AQMD must adopt rules and regulations that implement the AQMP [Heal th and Safety Code Section 40440(a)].

The California Clean Air Act (CCAA) requires distri cts that are unable to achieve five percent annual emission reductions to demonstrate t o the California Air Resources Board’s (CARB’s) satisfaction that it has included every feasible measure in its plan and an expeditious adoption schedule. CARB interprets the adoption of “every feasible measure” to mean that at a minimum, a district cons ider regulations that have been successfully implemented elsewhere. CARB also allo ws local air districts to consider not only technological factors, but also social, enviro nmental, economic (e.g., costeffectiveness), and energy factors which prevail in the district, along with the resources realistically available to the district to adopt, i mplement, and enforce the measures. (CARB, 1999)

C. AQMP CONTROL MEASURES

PR 1148.1 will implement Control Measure FUG-05 - E mission Reductions from Fugitive Sources (VOC), pursuant to the 2003 AQMP, which has an emissions reduction target of 2.0 tons per day (tpd) by the end of 2008 . This control measure proposes further VOC emission reductions from fugitive emission sour ces, such as refineries, oil and gas production facilities, terminals, chemical plants a nd manufacturing facilities. These VOC

emission reductions are needed to contribute toward s achieving attainment of the national ambient air quality standard for ozone Section 182( b) (1) (A) of the Federal CAA.Final Staff Report

PR 1148.1/PAR 222 4 February 24, 2004 D. OIL AND GAS PRODUCTION OPERATIONS

Oil field production involves bringing crude oil an d produced gas from the subsurface to the surface and preparing it for shipment to the re finery. This process involves drilling, well construction and operations, treatment, separa tion and storage. This rule will address onshore wells exclusively.

In oil drilling operations, two well types are comm only drilled; exploratory and development. Exploratory wells are drilled into un known formations in search of oil and gas. Development wells are wells that are drilled within an area that has already proven to be productive. Once oil or gas is discovered in a commercial viable quantity, development wells are drilled to recover as much of the oil or gas as possible. There are also service wells which are drilled for injecting liquids or gases into an underground formation in order to increase the pressure and for ce the oil toward the producing wells.

Service wells also include wells drilled for the un derground disposal of salt water produced with the oil and gas.

During the last 40 years, rotary drilling technique s have been improved so that the drill string can follow a curved path as the hole gets de eper. Such controlled directional drilling can tap reserves that are inaccessible by vertical drilling. This technique is very useful and has allowed oil deposits lying beneath t he Pacific Ocean off California to be reached by wells drilled directionally from shore.

When discovered, a crude oil reservoir can contain 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 pr essure of the groundwater. At this pressure a large part of the gas is dissolved in th e oil. These two fluids, the initial water and the gas in solution, combine to provide the dri ving force for moving the oil into the well where it is pushed by the underlying pressure.

A field may yield 20 percent to 30 percent of the o il and gas through the natural pressure of the underground formation. However, when pressu res in the oil reservoir fall to levels where a well will not produce by natural energy, so me method of artificial lift must be

used. Some artificial lift methods include rod-bea m pumping, gas lift, hydraulic pumping and subsurface centrifugal pumping. The rod pumpin g unit is a complete set of surface equipment necessary to impart an up and down motion which allows oil to the pushed to

the surface.

After drilling, an oil well is constructed and it m ay best be described as a pipeline, reaching from the top of the ground to the oil-prod ucing formation. It is through this pipe that oil is brought to the surface. The pipeline i s 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. Sometimes in drilling a well, more t han one commercially productive formation is found. In such cases a separate tubin g string is run inside the casing for each productive formation. Production from the separate formations is directed through the proper tubing strings and is isolated from the othe rs by packing that seals the annularFinal Staff Report

PR 1148.1/PAR 222 5 February 24, 2004 space between the tubing strings and casing. These are known as multiple completion

wells.

To control the flow of oil and gas from the time th e well starts producing, a set of valves and control equipment is put in place at the top of the well. This arrangement is

sometimes referred to as a wellhead or “Christmas t ree” because of its many branch-like fittings. It is usually made of steel and it forms a seal to prevent well fluids from blowing or leaking at the surface. The wellhead is sometim es made up of many heavy fittings with certain parts of the wellhead designed to hold pressures up to 20,000 psi. In other cases, wellheads may be just a simple assembly to s upport the weight of the tubing in the well and may not be built to hold pressure. The ki nd of head and configuration to be used is determined by well conditions, with high pr essure formations requiring heavy, high-pressure wellheads.

Because of the valves, flanges and threaded connect ions on the wellhead, fugitive emissions from the oil, water and gas flow are a po ssibility. 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

.

Abandoned Wells
When an oil or gas reservoir is depleted, the well is abandoned and the site is cleaned up. The hole is plugged with cement to protect all unde rground strata, prevent any flow or leakage at the surface and protect water zones, in accordance with California Code of Regulations, Subchapter 4; section 1920.1. Salvage able equipment is removed; pits used in the operations are filled in and the site is reg raded. Where practical the ground is replanted with grass or other kinds of vegetation a nd sometimes home building sites are

constructed.

Well Cellars

In most cases the wellhead resides in or above the well cellar which is a small subsurface containment basin used to capture any leaking liqui d from oil and gas extraction or

maintenance and workover of the well or wellhead. Based on research of AQMD’s Annual Emissions Reporting program, well cellars we re determined to be a source of considerable fugitive emissions. Well cellars can be lined or unlined and there can be

one or more wellheads allocated to a well cellar. On average, a well cellar has approximate dimensions of 6 feet by 6 feet with a d epth of between 5 feet to 8 feet. In

the absence of containers used to catch discarded l iquid (crude/water) produced during sampling and maintenance at the wellhead, there is an accumulation of crude oil that falls to the bottom of the well cellar. Therefore, it is common to find well cellars with an accumulation of crude oil in the bottom. Also, sin ce there needs to be access to wellheads for maintenance and sampling, well cellar s are uncovered and become sources of volatile organic compound emissions when crude o il is collected in this containment.

Separation and Treatment
After the well fluids and gas reach the wellhead th ey are transferred to a treatment plant. At the treatment plant the crude oil, natural gas, produced water and solid contaminantsFinal Staff Report

PR 1148.1/PAR 222 6 February 24, 2004 are separated and treated. A treatment plant may b e simple or complex and can take many different forms depending on treatment needs. Typically, the treatment plant

includes a well flow-line manifold in addition to s eparators, free water knockout vessels, heaters (if crude is heavy), heater-treaters, wash tanks, stock tanks, wastewater separators or oil/water separators, sumps, pits, ponds and a v apor recovery unit.

Some of the equipment that require permits by the A QMD include American Petroleum Institute (API) separators, tanks, vessels, heaters , boilers, vapor recovery units, internal combustion engines and clean-out sumps which are in most cases part of the wastewater system permit unit, oil dehydration unit or water i njection facilities. Open ditches also require a permit, but there are no active permits c urrently in the South Coast Basin.

Issues related to wastewater associated with the se paration and treatment process are addressed in AQMD Rule 1176.

The well fluids (oil/water) and gas mixture flows t o a well manifold that connects with each well in the field. From the manifold, the mix ture is directed to either a test or a production separator. A test separator separates a nd measures the three phases separately and is used to determine the production of each wel l from the field. Under normal conditions, the mixture flows to a production separ ator or free water knockout where gas is separated from the mixture. From there, the oil /water stream flows to a free water knockout vessel, a heater treater, a wash tank and an oil/water separation vessel where

water is removed from the oil. After it is determi ned that there is a sufficient reduction of water content, the oil flows to an oil storage or s tock tank. Upon sale, the oil flows through Lease Automated Custody Transfer (LACT) uni ts for metering.

Gases removed from the oil during treatment may be treated and then 1) sold to a utility; 2) used as fuel by the operator; 3) re-injected int o the reservoir for pressure maintenance; or 4) vented to the atmosphere (usually only during emergency upset conditions at larger facilities). Gas collected from separators and oil treaters, along with vapors from storage tanks, may be processed through a dehydration unit (usually containing glycol). This unit removes the water from the gas before it is put int o a sales pipeline or used again in the dehydration process. A common practice to control production gas from small to medium operations is to use a gas-fired heater whic h burns the facility’s gas and produces heat to reduce the viscosity of the crude oil produ ct. Reducing the viscosity of crude oil facilitates the handling within the production oper ation or the transport via pipeline to the

refineries.

The oily water collected from the separators and th e oil treaters may flow directly to a sump or may flow to a water treatment facility prio r to disposal. At the water treatment facility the oil content of the water is reduced by skimming tanks, dissolved air flotation units, pits, filters or a combination of these. Th e water may be used on-site, discharged to the surface, or injected back into water injection wells or disposal wells. Vapor recovery is usually on all of the separation vessels and is piped back to the gas pipeline for dehydration.Final Staff Report

PR 1148.1/PAR 222 7 February 24, 2004 E. AQMD RULES REGULATING OIL AND GAS PRODUCTION

Health and Safety Code Section 40727.2 requires a c omparative analysis of the proposed rules and all existing federal air pollution contro l requirements, as well as existing or proposed AQMD rules and regulations that apply to t he same equipment or source type. There are no federal air pollution control requirem ents that apply to wells or well cellars. There are currently three AQMD rules that regulate the emissions of fugitive VOCs at Oil

and Gas Production facilities and one rule that exe mpts most oil production equipment from permit requirements.

Rule 1148
This rule applies to Thermally Enhanced Oil Recover y Wells. It limits VOC emissions to 4.5 pounds per day or less per well for both wells that are connected to vapor control systems and those that are not.

Rule 1173
Rule 1173 - Fugitive Emissions of Volatile Organic Compounds serves the purpose of reducing VOC leaks from components such as valves, fittings, pumps, compressors, pressure relief devices, diaphragms, hatches, sight glasses and meters at oil and gas production fields, natural gas processing plants an d pipeline transfer stations

.

Rule 1176
This rule applies to wastewater systems and associa ted control equipment located at petroleum refineries, onshore oil production fields , off-shore oil production platforms, chemical plants and industrial facilities. Sumps a nd wastewater separators are required to be covered with either a floating cover equipped wi th seals or a fixed cover, equipped with a closed vent system vented to an Air Pollutio n Control system.

Currently, under Rule 1176(i)(5)(H), well cellars u sed in emergencies at oil production fields are exempt if clean-up procedures are implem ented within 24 hours after each emergency occurrence and completed within ten (10) calendar days.

Rule 219 Exemption
All wellheads, except for those with steam injectio n are exempt from written permit requirement per Rule 219 (n) (1) – Natural Gas and Crude Oil Production Equipment.

F. OTHER CALIFORNIA AIR POLLUTIOIN CONTROL DISTRICT (APCD) RULES REGULATING OIL AND GAS PRODUCTION

Santa Barbara County APCD

Rule 344
This rule was adopted in November 1994. The purpos e of the rule is to address VOC emissions associated with sumps, pits and well cell ars. As far as well cellars areFinal Staff Report

PR 1148.1/PAR 222 8 February 24, 2004 concerned, the rule seeks to minimize the collectio n of crude oil, requiring operators to use a portable container with a cover to collect li quid whenever a valve at the wellhead is opened, and also to pump out liquid when the depth exceeds 50 percent of the total well cellar depth.

Rule 325
This rule applies to equipment used in the producti on, gathering, storage, processing, and separation of crude oil and natural gas prior to cu stody transfer. The rule requires that emissions of produced gas be controlled at all time s using properly maintained and operated systems that direct all produced gas to a gas plant, a flare or any other device that has a VOC vapor removal efficiency of at least 90 percent by weight. There is a provision in the rule that exempts gas used in a ta nk battery vapor recovery system, which is expected to be well controlled.

Ventura and San Luis Obispo County APCD’s
Ventura County Air Pollution Control District (VCAP CD) and San Luis Obispo County

Air Pollution Control District have rules controlli ng emissions similar to SBCAPCD Rule 344. There are slight differences in the time allo wed before pump-out and the length of time organic material can be stored in a well cella r. VCAPCD also has a gas production

control rule similar to SBCAPCD Rule 325.

G. CALIFORNIA DEPARTMENT OF CONSERVATION DIVISION OF OIL, GAS & GEOTHERMAL RESOURCES

Currently, the maintenance of well cellars at oil a nd gas production operations in California is overseen by the Department of Conserv ation’s Division of Oil, Gas & Geothermal Resources (Division of Oil and Gas). Th e Public Resources Code, Division 3, Chapters one through four, governs the regulator y functions of the Division of Oil and Gas. The code charges the Division of Oil and Gas with the responsibility of supervising oil, gas and geothermal well drilling, operation, m aintenance, plugging and abandonment operations to prevent damage to life, health, prope rty and natural resources. However, none of the regulations pertain to restricting the emissions of air contaminants from this equipment. More specifically, the Division of Oil and Gas must ensure actions are taken

to:

1) Prevent damage to underground oil, gas and geotherm al deposits; 2) Prevent damage to underground and surface waters su itable for irrigation or domestic use; 3) Prevent other surface environmental damage, includi ng subsidence; 4) Prevent conditions that may be hazardous to life or health; and 5) Encourage the wise development of oil, gas and geot hermal resources through good conservation and engineering practices.

The Division of Oil and Gas programs include well p ermitting and testing; safety inspections; oversight of production and injection projects; lease inspections; idle-wellFinal Staff Report

PR 1148.1/PAR 222 9 February 24, 2004 testing; inspection of oilfield tanks, pipelines, a nd sumps; hazardous and orphan-well plugging and abandonment contracts; and subsidence monitoring.

The oil fields in California are divided into six D istricts. The AQMD is located primarily

in District 1 and the southeast section of District 2. District 1 and District 2 are the second and third largest oil and gas producing Dist ricts in California, respectively. District 1 includes most of Los Angeles County and all of Orange, Riverside, San Bernardino, Imperial and San Diego Counties. A sma ll section of northwest Los Angeles County is located in District 2. Most of the produ cing oil fields in District 1 are located in Los Angeles and Orange Counties with 75 percent of the 2001 production coming from the from the following oil fields: Wilmington, Huntington Beach, Inglewood, Long Beach, and Brea-Olinda. For 2001, these five oilfi elds had a combined total of 2,688 production wells. Wilmington had 1,228 production wells; Brea-Olinda 527; Inglewood 341; Huntington Beach 324; and Long Beach 268.

In 2001, there were 43 active oil fields with 4,164 oil producing wells in District 1. The AQMD portion of District 2 had 419 oil producing we lls. Of the 4,164 producing oil wells, 3,169 wells were onshore, while the remainin g 995 were offshore wells. Therefore, the total number of on-shore wells in th e AQMD in 2001 was 3,588 (3,169 + 419).

The 2,688 production wells located in the five majo r producing oil-fields represent almost 85 percent of the onshore wells in District 1. Also, there were 72 new wells drilled and another 52 wells completed in 2001 in D istrict 1 alone. When a well is drilled there is no production of oil and gas. However, a well is determined to be properly completed when the manner of producing oil or gas o r injecting fluids into the well is satisfactory and the well has maintained production of oil or gas or injection for a continuous 6-month period. There were also 201 wel ls that were plugged and

abandoned.

H. AFFECTED FACILITIES

Operators of oil wells and well cellars are not req uired to obtain AQMD permits for that equipment and not all oil wells utilize well cellar s. Only those facilities with equipment

such as API separators, tanks, vessels, heaters, boilers, i nternal combustion engines and clean-out sumps (part of the dehydration or wastewa ter system permit unit), and “control” equipment such as heaters, flares, gas tr eatment equipment, internal combustion engines and boilers would have AQMD permits.

The Division of Oil and Gas requires permits for oi l and gas production facilities. Based on data from their 2001 annual report, the Division of Oil and Gas has identified 220 facilities that operated 3,588 onshore wells locate d within the AQMD.

Based on the AQMP’s 2000-2001 Annual Emissions Repo rting (AER) program, 54 facilities or oilfield operators reported VOC emiss ions of four tons per year or greaterFinal Staff Report

PR 1148.1/PAR 222 10 February 24, 2004 from well cellars and other equipment operated at t hose facilities. The other remaining 166 facilities (220 - 54 = 166) are classified as a rea sources.



### EMISSIONS INVENTORY

Based on information provided by the Division of Oi l and Gas, the production of crude oil in District 1 has dropped from 62.5 million bar rels per year in 1987 to 32.3 million barrels in 2001 and District 2 has dropped from 18. 3 million barrels per year in 1987 to 10.5 million barrels per year in 2001. In Southern California, 1991-92 marked a period

of time when several onshore wells were abandoned d ue to a home construction boom as well as regulations which increased the cost of ope rations considerably. In addition, the cost of imported crude oil affects the operation (p rofitability) of local oil wells.

Although California’s crude production has decrease d over the last 15 years, current demand for petroleum is still substantial and Depar tment of Oil and Gas permits for new wells continue to be issued each year. Therefore, there still exists a need to ensure that oil and gas production facilities are operated so t hat there are minimal fugitive emissions

in the South Coast Basin.

In order to address the 2003 AQMP control measure F UG-05, staff examined the activities of oil and gas production wells. A broa d-based approach was taken to establish which sources were viable options for possible emis sion reductions. A search of AQMD

databases based on Standard Industrial Classificati on (SIC) codes (1311-crude petroleum and natural gas; 2821-chemicals and allied products , 2911-petroleum refining and 5171- petroleum bulk stations and terminals) that were ap plicable to oil and gas production activities was completed. This search resulted in a total of 95 facilities of which 54 were

associated with SIC 1311. It was established that emissions from the remaining 41 sources were already being reported under the AQMD AER program.

A. WELL CELLARS

The emission inventory was established based on rep orted emissions by oil and gas facilities for the fiscal year 2000-01 and the 2003 AQMP. In 2000-01, 54 oil and gas production facilities reported 0.62 tpd of VOCs fro m the well cellars in the AQMD AER program. Almost 80 percent of the total VOC emissi ons came from 13 of the facilities identified in the inventory.

To determine the contribution of area sources (oil and gas operations that did not report emissions under the AER program), staff used the 20 10 AQMP Controlled Planning Inventory, which estimates fugitive VOC emissions f rom well cellars as 0.59 tpd. The 2010 planning inventory was based on current oil pr oduction with the assumption that there would be zero growth in the oil and gas produ ction industry. As such, the 2010 planning inventory is equal to the 2000-01 emission s inventory and is used in estimating

both VOC emission reductions and cost effectiveness . Therefore, the total fugitive VOC emissions from all well cellars (point and area sou rces) are estimated to be 1.21 tpd forFinal Staff Report

PR 1148.1/PAR 222 11 February 24, 2004 2000-01. The number of onshore wells, VOC emission s from well cellars and overall VOC emissions from oil and gas operations are shown in Table 1.

Table 1 – Breakdown of Well Cellar Emissions

Point Sources Area Sources (2) Total

No. of Wells 2,257 (1) 1,331 3,588 (3)

Well Cellar Emissions (tpd) 0.62 (4) 0.59 (5) 1.21

Emissions from all

Oil & Gas Production Sources (tpd) 3.11 (5) 2.95 (5) 6.06 (5)

(1) Represents the number of onshore wells listed i n the Division of Oil & Gas - 2001 Annual Report, f or the facilities reporting well cellar emissions (2000-2001 AER). (2) Area sources defined by the AQMD as sources f or which operators did not report emissions to the AER program. (3) Represents the total number of onshore wells li sted in the Division of Oil & Gas -2001 Annual Repo rt. (4) VOC emissions reported under the 2000-2001 AER program. (5) Based on AQMP 2010 Planning Inventory.

B. STEAM INJECTION WELLS

Thermally enhanced oil recovery wells are sources o f VOC emissions whereas the steam injection wells have negligible VOC emissions. Two facilities in the South Coast Basin reported VOC emissions of 76 tons of VOCs for 2000- 01, from the thermally enhanced oil recovery operations. The wellheads at these fa cilities are vented to steam generators and/or boilers. In addition, one of the two compan ies has already started to cut back their operations by reducing their energy production by g oing from a total of 26 steam generators to five since it plans on abandoning the project in a year or two. These changes have been made in preparation for plans to develop a housing project at the site. Therefore, staff will not pursue further regulation of steam injection wells at this time.

C. PRODUCED GAS

Currently, the AQMD does not have detailed records documenting the amount of produced gas for oil and gas production facilities. The 2001 Annual Report of the Division of Oil and Gas reported produced gas from approximately 2,800 wells located at 100 onshore facilities in the AQMD as 11 billion cu bic feet for the year 2001. Based on interviews of facility operators, it was estimated that approximately 99.1 percent of the produced gas is directed to on-site gas treatment e quipment, on-site control equipment, such as heaters, flares, internal combustion engine s or boilers, or directed to other facilities, such as the Southern California Gas Com pany or other facilities using pipeline quality “natural gas”. Therefore, the remaining 0. 9 percent of the produced gas which is approximately 100 million cubic feet of produced ga s which is uncontrolled and is vented directly to the atmosphere.Final Staff Report

PR 1148.1/PAR 222 12 February 24, 2004 Produced gas is primarily methane and non-methane h ydrocarbon compounds. Only the reduction in non-methane hydrocarbons will be consi dered as VOC emission reductions. The volume of produced gas was determined from data listed in the Division of Oil & Gas 2001 Annual Report and the AQMD permitting data base. The average molecular weight of the produced gas from the oil wells is as sumed to be that of a typical natural gas based on five different compositions listed in the Petroleum Engineering Handbook. The gas density was calculated using the average mo lecular weight of the produced gas divided by the gas constant of 379.4 cubic feet per lb-mole (ideal gas at standard conditions).

Data/Assumptions : Untreated Volume of Produced Gas 100 million cubic feet per year Gas Molecular Weight (MW) 23 lb/lb-mole (average) Gas Density 0.0606 lb/cubic feet Produced Gas Methane Content 90 percent (average) Heater Destruction Efficiency 95 percent

Based on this data, the overall mass of non-methane VOC gases produced in the South Coast Basin prior to control or combustion is as fo llows:

100 x 10 6 cu ft gas x (1.0-0.9) x 0.0606 lb x 1 ton x 1 year = 0.83 tpd year cu ft 2000 lb 365 day



### CONTROL TECHNOLOGY ASSESSMENT

There are three primary techniques for reducing VOC emissions from well cellars: (a) sample management, (b) equipment installation and r epair, and (c) implementing an inspection and maintenance program. In addition, t here are a number of techniques for controlling the emissions of produced gas.

A. SAMPLE MANAGEMENT

Sample management focuses on the good work practice standards which include catching and collecting discarded liquid produced at the wel lhead during sampling. The use of a portable container prevents the crude oil from fall ing to the bottom of the well cellar or on the ground, spreading out and emitting from the surface of the accumulation. The container is equipped with a cover, which is requir ed to be closed whenever crude oil is not being collected, to significantly reduce VOC em issions to the atmosphere. The collected crude oil is typically added back to the separation treatment system.Final Staff Report

PR 1148.1/PAR 222 13 February 24, 2004 B. EQUIPMENT INSTALLATION, MAINTENANCE AND REPAIR

1. Crude Oil

Three possible equipment installations/modification s and component maintenance and repair are briefly described.

a) Adapter Installation This technology involves the installation of an ada pter to the stuffing box for the pump rod of the oil well. The adapter includes a r eservoir to collect leakage from the stuffing box packing. Similar to the use of a container under Sample Management, the use of a portable container prevent s the crude oil from falling to the bottom of the well cellar or on the ground, spr eading out and emitting from

the surface of the accumulation. The reservoir is e quipped with a cover, which is required to be closed whenever crude oil is not bei ng collected, to significantly reduce VOC emissions to the atmosphere. The adapte r also includes a shut off switch that will automatically shut down the pump o peration when the liquid in the reservoir is nearly full.

b) Stuffing Box Maintenance This option involves the increased maintenance and repair of the stuffing box. The stuffing box is a packing gland, chamber, or “b ox” used to hold packing material compressed around a moving pumping rod to prevent escape of gas or liquid. Therefore, adjusting or replacing the pack ing will reduce the fugitive emissions resulting from the accumulation of crude oil in the well cellar or on the ground and thereby eliminate associated clean-up co sts.

c) Closed-Purge Systems A closed-purge system captures leaking liquid and e ither returns it to a production system or routes it to a closed disposal system. T he control efficiency of a closedpurge system depends on the percentage of leakage t hat is routed to the disposal system. A closed-purge system can be installed on a single component or on a group of components. The control efficiency of clos ed-purge system can be at least 95 percent.

2. Produced Gas

a) Gas Plant The overall objective of an oil and gas production facility is to prepare the oil and gas for pipeline transport. The oil is usually tra nsferred to a pipeline terminal and eventually to a refinery, while the gas may be sold to a pipeline company for further sale or transported directly to a gas plant for additional treatment. The types of process equipment required at a production facility depend on the quality of the well-head product and whether or not both oi l and gas are produced by the

well.Final Staff Report

PR 1148.1/PAR 222 14 February 24, 2004 Produced gas exiting the separators is composed pri marily of methane, ethane, propane and butane. It may also contain impurities such as nitrogen, helium, carbon dioxide, hydrogen sulfide, mercaptans and wa ter vapor. Condensable hydrocarbons are recovered from the gas using absor ption, refrigeration or gas expansion processes. Water is removed by passing t he gas through equipment such as glycol dehydrators, where water is absorbed by the glycol. This water is ultimately vented as steam from the glycol reboiler

.

Gas sweetening and product separation are often con ducted at a gas plant that is not located at the oil and gas production facility. In order to “sweeten” sour produced gas, hydrogen sulfide and carbon dioxide a re usually scrubbed from the gas using an amine solution in an absorption tower. The acid gas stream may be flared, incinerated or processed further in a sulfu r-recovery facility, and the scrubbed gas stream is further processed to separat e products.

Some small oil and gas production operators are par t of a cooperative system that purchases gas from other small operators and collec tively sends it to a gas plant. However, other smaller oil and gas production opera tors do not produce large enough quantities of gas that are of suitable quali ty to be sent directly to a pipeline company. For these operators, a gas plant may be cost-prohibitive and therefore it is not regarded as a cost effective co ntrol option. One of the following control options would be selected by these operator s

b) Heaters Produced gas can be used as fuel for heaters that a re used to heat crude oil. When the crude is heated, its viscosity is reduced there by allowing for easier transport of the material. There are two types of heaters that are usually used at oil and gas production operations. They are direct-fired and i ndirect-fired heaters.

A direct-fired heater is one in which the fluid to be heated comes in direct contact with the immersion-type heating tube or element of the heater. Direct-fired heaters are generally used to heat non-corrosive or ganic fluids that are under relatively low pressure. These units are normally constructed so that the heating tube can be removed for cleaning, repair or replace ment.

An indirect-fired heater is one in which the fluid passes through pipe coils or tubes immersed in a bath of water, oil, salt, or ot her heat transfer medium that, in turn, is heated by an immersion-type heating tube s imilar to the one used in the direct fired heater. The immersion-type heating tu be heats the bath, which in turn heats the fluid flowing through coils immersed in t he bath. When water is used as the bath, water free of impurities will prolong the life of the heater and prevent fouling of the surface of the heating tube and coil s. Indirect fired heaters are generally used to heat corrosive or high pressure f luids. Indirect heaters are constructed so that the heating tube and pipe coil are individually removable for cleaning and replacement.Final Staff Report

PR 1148.1/PAR 222 15 February 24, 2004 Heaters designed to comply with Rules 1146, 1146.1 and 1146.2 will reduce VOC’s by a minimum of 95 percent.

c) Flares Produced gas is a byproduct of many oil field produ ction facilities. Facilities use flares to burn off produced gas when their compress ors break down, are being serviced, or when there is another problem in the p roduced gas production system. In some cases, flares are used when the heating val ue of the gas cannot be recovered economically because of intermittent or u ncertain flow or when process upsets occur as described above. Some operators ma y flare all their produced gas if they do not recover it. Flares may also be used on the vapor recovery system at a loading rack or tank battery. If properly operat ed and maintained flares should not give off any visible emissions and only a flame should be emanating from the stack of a flaring unit. If the flare uses supplem ental natural gas, it must be equipped with a device that automatically shuts off the flow of natural gas in the event of a flame-out or a pilot failure. This will minimize the potential of an explosive mixture of gas accumulating in the area s urrounding the flare.

Some types of flares include steam-assisted, air-a ssisted and pressure head flares. Steam- assisted flares are single burner tips, elev ated above ground, that burn the vented gases in a diffusion flame. This type of fl are system injects steam into the combustion zone to promote turbulence and to induce air into the flame. Steamassisted flares also account for the majority of fl ares installed. Flares can typically achieve a VOC destruction efficiency of a t least 90 percent.

During discussion with the Santa Barbara County Ai r Pollution Control District (SBCAPCD) staff revealed that many small oil and ga s production facilities in their jurisdiction have installed their own operato r-built flares to suit their individual gas treatment needs and meet SBCAPCD rul e requirements.

Flares will also need to meet all applicable regula tory requirements in the AQMD.

d) Other Combustion Devices Gases removed from the oil during treatment may be burned as fuel. The fuel may be used in devices such as internal combustion (IC) engines, heater treaters, boilers, steam generators or turbines. At some fac ilities these IC engines are used to drive pumps, compressors and other prime movers involved in the oil and gas production operations.

e) Carbon Adsorbers Activated carbon adsorption systems can also be use d to control VOC emissions. In situations where the carbon is virgin material, the VOC reduction efficiency will be high. However, when the carbon becomes sat urated, it will have to be replaced and the spent carbon will have to be regen erated.Final Staff Report

PR 1148.1/PAR 222 16 February 24, 2004 C. INSPECTION AND MAINTENANCE

A required inspection and maintenance (I & M) progr am is effective in reducing fugitive VOC emissions. In this approach, the four most imp ortant factors in determining the control effectiveness are: (1) to determine that a leak is occurring or has occurred, (2) to correct the cause of the leak, (3) to remove or cle anup the accumulation of VOC emitting material, and (4) to determine the frequency at whi ch the leaks are occurring. An I & M program can be designed to identify oil production well components that are emitting

sufficient amounts of material to warrant reduction of the emissions through repair.

To determine the effectiveness or a control factor for well cellars, staff analyzed two rules that require an I & M program: AQMD Rule 1173 – Control of Volatile Organic Compound Leaks And Releases From Components At Petr oleum Facilities and Chemical Plants and SBCAPCD Rule 344 - Petroleum Sumps, Pit s and Well Cellars.

AQMD Rule 1173 requires the use of a Leak Detection and Repair (LDAR) program. LDAR incorporates the elements of an I & M program. However, LDAR goes one step further in that it quantifies the fugitive gaseous VOC leaks with a portable analyzer, as per United States Environmental Protection Agency ( USEPA) Reference Method 21. Inspections with VOC measurements for heavy liquid pumps are required on a quarterly basis. All other components must meet an emission concentration limit. A conservative estimate of a control factor for components (pumps, valves, connectors, ect.) in heavy liquid service (including crude oil) was documented as 84 percent. (Rule 1173 Staff Report – October 10, 2002).

SBCAPCD Rule 344 requires the use of a sample manag ement program and an I & M program that includes the installation of an adapte r system and/or maintenance and repair to reduce fugitive VOC emissions. A 70 percent con trol factor was estimated by SBCAPCD staff. Although not explicitly stated in t he rule, SBCAPCD equipment permitting staff requires weekly inspections as a p ermit condition when issuing well cellar permits, since SBCAPCD requires written perm its for production wells and well

cellars.

SBCAPCD Rule 344, adopted in February 1996 and subs equently approved by CARB and USEPA for inclusion in the SIP, claimed reducti on of well cellar VOC emissions from 406 tpy in inventory year 1995 to 94 tpy in in ventory year 1997; an overall 77 percent reduction in VOC fugitive emissions from we ll cellars. Although some of the

emission reductions can be attributed to shutdown a nd closure of production wells, the majority of the reported VOC reductions were claime d to be as a result of the implementation of sample management and I & M of we ll cellars required by the rule.

A control factor of 80 percent is used to calculate the VOC emission reductions resulting from an I & M program for well cellars. This deter mination is based on AQMD’s experience with the highly successful implementatio n of the I & M programs for light and heavy liquids and gases under Rule 1173 that ha ve resulted in significantly fewer leaking components at affected facilities, the repo rted success of the SBCAPCD’s RuleFinal Staff Report

PR 1148.1/PAR 222 17 February 24, 2004 344 in reducing fugitive VOC emissions, and the fac t that PR 1148.1 goes beyond the SBCAPCD rule by requiring quarterly total organic c ompound (TOC) measurements

based on USEPA Method 21.



### PROPOSED RULE

A. PURPOSE

PR1148.1 reduces VOC emissions from oil field produ ction well heads and the well

cellars that house the wellheads that control the f low of crude oil from onshore oil wells. These reductions will be accomplished through an im proved sample management, and an inspection and maintenance program. The proposed r ule will also reduce the amount of produced gas released to the atmosphere by requirin g it to be collected and controlled.

B. APPLICABILITY

This rule will apply to wellheads and well cellars at onshore facilities where petroleum is produced, gathered, separated, processed and stored

.

C. DEFINITIONS

Key definitions are listed in the proposed rule for clarity.

SIC Code 1311 defines an oil and gas production fie ld as a facility where both crude petroleum and natural gas production are conducted. However, the primary purpose of PR 1148.1 is to reduce VOC emissions resulting from the accumulation of crude petroleum in the well cellar and the release of gas eous VOC from the wellhead.

Sensitive receptor is defined as a school, a licens ed daycare center, a hospital or a convalescent home since special inspection and repa ir requirements apply to wells and well cellars located near these receptors.

D. REQUIREMENTS

Well cellars at oil and gas production operations a re a source of VOC emissions. Prior to this proposed rule, there were no rules that addres sed this source category.

To accomplish the VOC emission reductions, the prop osed rule will require the implementation of improved sample management utiliz ing good work practice standards through the use of a portable container with a cove r anytime a valve is opened at the wellhead. This requirement has an effective date o f July 1, 2004.

Periodic audio-visual inspection of the stuffing bo x of the oil well pump and quarterly inspection and TOC measurement of the well cellars is required starting July 1, 2004.Final Staff Report

PR 1148.1/PAR 222 18 February 24, 2004 The proposed rule has established that if the AQMD inspection detects that a TOC concentration in the well cellar exceeds 500 ppm as determined by USEPA Method 21, the operator will be in violation of this rule. A TOC concentration of 250 ppm, and also

for those well cellars located within 100 meters of a sensitive receptor, 2 inches of accumulated organic liquid, measured by AQMD inspec tion or operator inspection will trigger maintenance or repair of the wellhead stuff ing box or other source of leakage and

the removal of accumulated material in the well cel lar.

PR 1148.1 will also require the operator to minimiz e emissions during maintenance and well workover. The proposed rule requires the opera tor to remove any liquid that accumulates in the well cellar during maintenance o r workover, within two (2) days after such activity has been completed. In the event tha t a portable enclosed storage vessel is used to store the crude oil or petroleum products d uring a well workover or during significant maintenance, the operator will also be required to equip the enclosed storage vessel with air pollution control (APC) equipment. The APC equipment will reduce the

VOC emitted from the collected crude oil/water mixt ure from being released into the atmosphere. The APC unit will also be required to reduce VOC emissions to less than 250 ppm of TOC and the operator will be required to conduct USEPA Method 21 measurement at the time of filling to verify this c oncentration limit.

As part of their maintenance activity, operators wi ll occasionally apply steam to production wells to clean them since this will enab le the wells to function more efficiently and ultimately decrease the overall cos t of production. Before the well is steamed the underground equipment is removed. This equipment may include underground pump lift rods, usually hundreds of fee t long, which are pulled through the wellhead. This activity creates gallons of crude o il that accumulates in the well cellar. Steam is then applied to the underground formation through the wellhead and the heat

from the wellhead in turn heats the contents of the well cellar. Therefore, in order to minimize the evaporation of VOCs, the proposed rule requires that immediately prior to steaming the well, the operator shall pump out the well cellar in which the well is located. In addition, all liquids should be pumped out after steam cleaning components in a well cellar. Since these are planned activities, it is reasonable to require the operator to remove the source of potential fugitive emissions.

PR 1148.1 will also focus on ensuring that if and w hen crude oil does accumulate in the

well cellars the residence time is minimized. This requirement will be accomplished through quarterly inspections and maintenance of co mponents of the oil well. The operator is required to pump out or remove any orga nic material that accumulates in the well cellar within five calendar days after the mat erial is discovered or after the operator

determines that the total TOC concentration in the well cellar exceeds 250 ppm using

USEPA Method 21. In cases where oil wells are loca ted within 100 meters of a sensitive receptor, the operator is required to pump out or r emove any organic material within 24

hours.

At many larger oil and gas production facilities, p roduced gas that is extracted from production wells is treated at a gas plant in prepa ration for use as fuel in engines, boilers and turbines; for sale to the Southern California G as Company or other buyers; or forFinal Staff Report

PR 1148.1/PAR 222 19 February 24, 2004 underground injection at the facility. Gas treatme nt may involve the removal of carbon dioxide and hydrogen sulfide. These operations alon g with some of the smaller type facilities may also direct their produced gas to ot her combustion equipment to reduce potential VOC emissions. The proposed rule require s that in the absence of a gas plant, the operator has to control the emissions of all pr oduced gas, except gas that is associated with a tank battery which already has a closed-type vapor recovery system. Control may be achieved by use of any control equipment that: a ) is capable of achieving a VOC destruction efficiency of at least 95 percent by we ight or b) demonstrates an outlet VOC concentration of 50 ppm or less, no later than Janu ary 1, 2006. In order to verify that the equipment efficiency and the VOC concentrations in the exhaust, operators will be required to perform periodic source tests using the relevant EPA Methods (25 and 25 A), the equivalent District Method 25.1 or USEPA Method 21. EPA Test Method 18 or ARB

Method 422 discussed in the Test Methods section of the rule will be required to be used to determine emissions of exempt compounds.

The proposed rule will also require that if any con trol device used to reduce the VOC emissions requires the use of supplemental natural gas, it will be required to be equipped

with an automatic shut-off device in the event that there is a flame-out or a pilot failure. This shut-off device will prevent any leaks of natu ral gas that may occur when the flame of the control equipment is extinguished.

The rule also requires that for produced gas handli ng activities within 100 meters of a sensitive receptor, operators are required to repai r any gaseous leaks of 250 ppm TOC or greater, within 24 hours of discovery or take actio n to prevent the release of TOCs. This requirement addresses the Governing Board’s Environ mental Justice directive which places increased emphasis on emission sources withi n close proximity of sensitive

receptors.

E. OPERATOR INSPECTION REQUIREMENTS

For wellhead stuffing boxes located in well cellars , the operator is required to conduct weekly visual inspections, which will take effect o n July 1, 2004. Weekly visual inspection of the stuffing boxes will allow the ope rator to repair any leaks before there is a sizeable accumulation of organic liquid in the we ll cellar. If a liquid leak is observed, the operator must conduct a USEPA Method 21 measure ment within two days of discovery. In addition, the operator will be requi red to perform quarterly inspections using a portable analyzer if liquid or the presence of organic material is visible in the well cellar. The operator may choose to schedule these inspections to coincide with the quarterly inspections required for Rule 1173.

In the AQMD, we expect to find only a small number of oil and gas production wells that have wellheads, which are not located in a well cel lar. Therefore, when leaks occur in these situations, the crude oil-water mixture accum ulates on the soil and will evaporate and be released to the atmosphere. For this reason , if a stuffing box is not located in a well cellar, the operator will be required to do da ily visual inspections.Final Staff Report

PR 1148.1/PAR 222 20 February 24, 2004 In order to address the Governing Board’s Environme ntal Justice directive, the proposed rule also includes a provision that takes into cons ideration facilities that are located within 100 meters of a sensitive receptor. In thes e circumstances, operators are required to do daily audio-visual inspections as well.

PR 1148.1 also includes a provision that allows an operator to perform monthly visual inspections for stuffing boxes fitted with a stuffi ng box adapter with a well shut off

switch and a closed crude oil collection container. If the operator decides to add a stuffing box adapter equipped with a well shut off switch, and a closed container that collects any liquid leak, he may seek to change the frequency of visual inspection of the stuffing box. For there to be a change in inspecti on frequency to monthly, the operator will need to seek the prior approval of the AQMD Ex ecutive Officer. This reduction in inspection frequency is due to the fact that the ad apter with a shut off switch helps to reduce the chances of liquid leakage onto the groun d. In addition, the operator will be expected to maintain the adapter and the shut off s witch and ensure that they are both kept in good working condition at all times. Howev er, this inspection frequency option does not apply to wells located within 100 meters o f a sensitive receptor.

F. RECORDKEEPING REQUIREMENTS

Facility operators will be required to maintain rec ords of inspections and repair and the conditions that would require them to pump out thei r well cellars. These records are to be kept in a form acceptable to the AQMD that will include the time and date, in addition to a description of actions taken and the individua ls responsible for these actions.

Records of data collected must be maintained for a period of three years and a minimum of five years for all Title V facilities. Facility operators must also maintain purchase and installation records for stuffing box adapter syste ms and all records must be made available to the Executive Officer upon request.

G. TEST METHODS

Proposed rule language requires approved test metho ds to be used in determining TOC or VOC concentration and control efficiency.

H. EXEMPTIONS

PR 1148.1 has an exemption for any wells that have been idle and out of operation for more than six months, for wells that have been offi cially abandoned as defined by the Division of Oil and Gas, or for water, gas, or stea m injection wells. The operator must have inspection and production records to demonstra te compliance with these exemptions.

Most wells are not free flow wells and would requir e the application of energy applied by a pump. Therefore, when a well has been idle for a s long as six months and there are neither gaseous nor liquid leaks, the chances of fu ture leaks become minimal.Final Staff Report

PR 1148.1/PAR 222 21 February 24, 2004 In cases where a well has been certified as abandon ed by the Division of Oil and Gas, the hole is plugged with cement to protect the undergro und strata and to prevent any flow or leakage of crude oil at the surface.

Rule 1148 addresses requirements for steam injectio n wells and therefore are not included in PR 1148.1. Wells that are exclusively associated with water and gas injection are different from production wells and do not prod uce crude oil flows. Therefore, the activities of these wells are exempted from this pr oposed rule.

Rule 1176 allows the use of well cellars for storag e of VOC-containing materials during emergencies, provided certain requirements are met. Under the provisions of these requirements, well cellars are exempt from some of the limits and requirements of Rule 1148.1 during emergencies.



### EMISSION REDUCTIONS

To achieve the VOC emission reductions, the rule wi ll require periodic visual and USEPA Method 21 inspections and improved maintenanc e of the well cellar and wellheads. As part of the improved maintenance req uirements, AQMD will limit both the length of time that the operator is allowed to have crude oil remain in the well cellar, and the depth of liquid in the well cellar before p ump-outs are required. Produced gas

from the oil wells will need to be treated and stor ed/transported offsite, flared, or

controlled to reduce VOC emissions.

A. Well Cellars

The fugitive VOC emission inventory for well cellar s in the AQMD is 0.62 tpd for the larger oil and gas production facilities and 0.59 t pd for the smaller “area sources”. Therefore, the total VOC emission inventory for all well cellars in the AQMD is 1.21 tpd (see Emissions Inventory).

As discussed in the “Inspection and Maintenance” se ction of the Control Technology Assessment, staff has determined that the control f actor for PR 1148.1 is 80 percent. Therefore, based on the 80 percent control factor, the total VOC emission reductions are

calculated as follows:

Emission Reductions = (1.21 tpd)(0.80) = 0.97 t pd

B. Produced Gas

Based on the 2001 annual report of the Division of Oil and Gas, staff’s calculations have determined that a total of approximately 100 millio n cubic feet of produced gas is released to the atmosphere without being treated or controlled. The VOC portion of these emissions is 0.83 tpd. It is expected that the sel ected method of control of produced gasFinal Staff Report

PR 1148.1/PAR 222 22 February 24, 2004 will be flaring. Based on permitting experience, a properly designed flare for an oil and gas production operation should achieve a minimum o f 95 percent control. Therefore, VOC emissions associated with the flaring of produc ed gas was calculated as follows:

VOC (non-methane gas) Emissions Reduced = (0.95) (0.83) = 0.79 tpd

C. Total VOC Emission Reductions

Therefore, the total reductions from this proposed rule are estimated as follows:

Total Reductions = (Reductions from well cella rs) + (Reductions from controlling produced gas)

= 0.97 tpd + 0.79 tpd = 1.76 tpd

Due to the fact that there was no emissions invento ry associated with produced gas emissions for the sources identified, SIP credit wa s not claimed for the 0.79 tons per day emissions reduction from produced gas, but these em ission reductions will provide an

environmental benefit. The VOC emission reductions that will be SIP creditable will be 0.97 tons per day.



### COST AND COST EFFECTIVENESS

PR 1148.1 will regulate VOCs from the liquid side o f crude oil production (primarily evaporation of crude oil) and VOCs from the untreat ed/controlled produced gas associated with crude oil production. In order to provide a clear understanding, staff will calculate the cost separately for these categories of VOC emission reductions and then

calculate the overall cost effectiveness of the com bined categories for the proposed rule.

A. LIQUID CONTROL COSTS

Oil leaks from wellhead components, as well as from sampling activities are considered lost production. Crude oil that spills during the daily sample gathering procedure would enter a container as described previously, and can then be added to the process stream. In addition, leaks large enough to trigger well cellar rule requirements will result in crude oil being pumped out and returned to the process st ream as opposed to being accumulated and emitted into the atmosphere. Pumping costs can be eliminated if the problem that causes accumulation in the well cellar or on the gr ound is corrected.

The costs of the proposed rule associated with cont rol of the liquid organic material are

as follows:

a) Purchase of sample containers; b) Daily or weekly visual inspections; and c) Periodic pump-out of organic liquid.Final Staff Report

PR 1148.1/PAR 222 23 February 24, 2004 The number of oil wells operating in the AQMD is ap proximately 3,588 as reported in the Division of Oil and Gas 2001 Annual Report. Th is number will be used to compute annual operating costs and capital costs in this re port.

A facility will be required to purchase containers with covers that are used to collect crude oil discharged during sampling and maintenanc e. It will be assumed that a facility will have one container for every four well cellars

.

The inspection program required by PR 1148.1 consis ts of periodic audio-visual inspections of the stuffing boxes and a quarterly U SEPA Method 21 inspections/TOC

measurement of the well cellars. Most of these ins pections can be conducted concurrently with inspections required by Rule 1173 with a minimal increase in inspection time. Rule 1173 requires audio-visual i nspections of the well pumps/stuffing boxes for manned oil and gas production wells once during every eight-hour operating period and TOC measurement once every quarter. The following will discuss in greater detail staff’s analysis regarding the additional in spection costs to implement PR 1148.1.

PR 1148.1 requires the operator to perform a weekly audio-visual inspection of the stuffing boxes located in or above the well cellar. PR 1148.1 also requires that a stuffing box installed on a wellhead pump that is not locate d in a well cellar or oil wells located within 100 meters of a sensitive receptor be audio- visually inspected daily. Staff

estimates that the total amount of additional time needed to conduct a PR 1148.1 audiovisual inspection, re-inspection and TOC measuremen t required by any observed leakage at the well pump stuffing box, and the extra handli ng associated with catching sampling discharge will take an average of 5 minutes per wel l. In addition, when the wellhead fittings are inspected quarterly pursuant to Rule 1 173, operators can take this opportunity to inspect the well cellar and address any related maintenance activities. However, this concurrent Rule 1173 inspection/TOC measurement eve nt will not be factored into the

cost-effectiveness calculations. Based on discussi ons with industry representatives and consultants that conduct USEPA Method 21 inspection s/TOC measurements at oil and gas operation facilities pursuant to Rule 1173, sta ff agrees that the quarterly TOC

measurements for PR 1148.1 will be conducted at the same time as the Rule 1173 measurements with minimal additional time required. Therefore, the oil and gas facilities will not incur any additional cost for this require ment of PR 1148.1. The 5-minute well cellar inspection is regarded as conservative since most wells would be located in the same vicinity and audio-visual inspection of its mu ltiple wells could be completed over a shorter time interval. The cost of the inspection is estimated at $25 per hour. Since the inspection of wells at manned oil and gas operation s can be conducted concurrently with Rule 1173 inspection, travel time costs will only b e considered for those wells located at

unmanned facilities. Staff will include an additio nal ten minutes per well inspection at

unmanned facilities in its cost calculations.

As previously discussed, the total number of onshor e oil wells operating in the AQMD is 3,588. The number of oil wells for the 54 oil and gas production facilities reporting under the AQMD’s AER program was determined to be 2 ,257 wells. It is assumed thatFinal Staff Report

PR 1148.1/PAR 222 24 February 24, 2004 all 2,257 wells are contained in well cellars and a re located at manned facilities. Therefore, by difference , the number of wells operating at the smaller oil and gas production facilities is 1,331 oil wells (3,588 - 2 ,257).

Staff estimates conservatively, based on discussion s with operators

, that 25 percent of these 1,311 wells are not located inside well cella rs. Based on the proposed rule, the operator of these 333 wells would have to inspect t hese wells on a daily basis. For purposes of the calculation, staff will assume that all of these wells are located at

unmanned facilities.

Compliance records indicate that there are 17 sites within 100 meters of a sensitive receptor. Of these 17 sites, five are manned and a re already subject to the once per eighthour shift inspection requirements of Rule 1173. T he remaining 12 sites which are

unmanned will incur additional cost associated with an increased inspection frequency

and travel costs. Staff estimates that there are o n average, 10 wells associated with each of these unmanned facilities. Therefore, there are a total of 120 wells located at

unmanned facilities that are within 100 meters of a sensitive receptor that will require daily audio-visual inspections.

The number of oil wells located at unmanned facilit ies that are subject to weekly audiovisual inspections is 878 wells (1,331 - 333 - 120)

.

Liquid Control Costs

(1) Capital Cost

It is estimated that the containers will be replace d every 3 years based on field experience with this type of equipment and that the cost of the containers will not change over each 3-year period, but will be adjuste d to present value using a real interest rate of 4 percent. The calculations below also takes into consideration that over a 10-year period, there will be 4-batches of containers purchased, starting at the beginning of the compliance period.

Batch #1 (Initial Purchase)

Container Expected Service Life for Metal Container 3 yea rs Individual Metal Container Cost $25 Container Capital Cost = (3,588 wells/1 container per 4 wells) $22,425

Batch #2 (year 3) Container Capital Cost = (0.889) ($22,425) = $ 19,936

Batch #3 (year 6) Container Capital Cost = (0.7903) ($22,425) = $17,722

Batch #4 (year 9)Final Staff Report

PR 1148.1/PAR 222 25 February 24, 2004 Container Capital Cost = (0.7026) ($22,425) = $15,756

Total Liquid Control Capital Cost (Present Value) = $75,839

(2) Annual O & M Cost

(a) Audio-Visual Inspections

(i) Wells with Well Cellars at Manned Facilities - Annual Inspection Cost (Based on weekly inspections for 2,257 well cellars ) @ 5 minutes per well cellar; $25/hr (technician labor)

2,257 w/cellars x 1 insp/wk x 52 wk/yr x (5/60) hr/ insp x $25/hr = $244,508/year

(ii) Wells with Well Cellars at Unmanned Facilities - Annual Inspection Cost (Based on weekly inspections for 878 well cellars) @ 5 minutes per well cellar and 10 minutes travel and $25/hr (inspection labor)

878 w/cellars x 1 insp/wk x 52 wk/yr x (15/60) hr/i nsp x $25/hr = $285,350/year

(iii) Wells without Well Cellars – Annual Inspectio n Cost (Based on daily inspections for 333 wells) @ 5 minu tes per well and 10 minutes travel and $25/hr (inspection labor)

333 w/o well cellars x 365 insp/yr x (15/60) hr/ins p x $25/hr = $759,656/year

(iv) Wells at Unmanned Facilities within 100 meters of a Sensitive Receptor (Based on daily inspections for 333 wells) @ 5 minu tes per well and 10 minutes travel and $25/hr (inspection labor)

120 wells x 365 days/yr x (15/60) hr/insp x $25/hr = $273,750/year

Total Annual Audio-Visual Inspection Cost = $1,563,264/year

(b) Pump-Outs

Wet Season Based on comments from facility operators, well cel lars are currently pumped out one time during the wet season due to accumulated r ain water. Therefore, since Rule 1148.1 requires that the criterion for pump-ou t is VOC concentration and not non-organic liquid depth for all but perhaps a few well cellars near sensitive receptors, staff does not estimate that there will be a need for any additionalFinal Staff Report

PR 1148.1/PAR 222 26 February 24, 2004 pump-outs during the wet season. As a result, ther e will be no additional pumpout cost to industry during the wet season due to t he adoption of this rule.

Dry Season Based on information provided by industry, the curr ent pump-out rate during the summer is estimated at approximately 651 pump-outs or 20 percent pump-outs based on a total of 3,255 (3,588 - 333) well s cellars. However, since PR 1148.1 requires operators to perform weekly visual inspect ions and requires pump-outs based on 250 ppm TOC, staff has estimated that ther e will be an additional 130 (20 percent of 651) new pump-outs associated with t his rule.

A combined vacuum truck and operator rate of $75 pe r hour, including travel and disposal costs, where appropriate, was provided by an operator of an oil and gas production facility. Based on this rate and assumi ng that each well pump-out takes 1⁄2 hour, the overall cost of pump-outs is as f ollows:

Pump-out cost = (130 pump-outs)(1⁄2 hr/pump-out)($7 5/hr) = $4,875/year

Inspections Pump-Outs Total Liquid Control Annual O&M Cost = $1,563,264 + $4,875

= $1,568,139

B. PRODUCED GAS CONTROL COSTS

Based on a review of the Division of Oil and Gas 20 01 Annual Report staff has determined that of the 220 facilities operating oil and gas wells in the AQMD, 100 facilities reported 11 billion cubic feet of produc ed gas. The Division of Oil and Gas does not have a deminimus reporting level. Based o n a review of the AQMD permitting database, and interview of facility operators in co njunction with the 2001 Division of Oil and Gas Annual Report, it was determined that 135 o ut of 220 oil and gas production facilities directed their produced gas to gas treat ment for use offsite or to gas control systems (flares, heaters, IC engines, or boilers). Approximately 99 percent of the reported produced gas was sold, used or controlled.

Staff estimated an overall average gas to oil ratio based on the total annual gas and oil production, respectively, for facilities that repor ted. This gas to oil ratio was used to estimate the annual gas production for facilities t hat reported only oil production (but no gas production) to the Division of Oil and Gas in 2 001. Further, the gas production rate was used to estimate the size (BTU rating) for a he ater that would be needed to control a facility’s produced gas.

It was determined that the remaining 85 (220 – 135) facilities did not treat nor control their produced gas. Since the cost of treating the produced gas for sale to other facilities or the Southern California Gas Company is not pract ical for the lower gas producingFinal Staff Report

PR 1148.1/PAR 222 27 February 24, 2004 facilities, staff believes that these facilities wi ll install heaters to combust the 100 million cubic feet per year of produced gas, using the deri ved energy to heat the crude oil in preparation for sale or use on site. Information p rovided for gas-fired heaters by manufacturers indicated that the installed unit pri ce of a heater designed to burn (or control) the produced gas from the smaller oil and gas production facilities ranged from $6,000 and $20,000 for heaters with a 400,000 BTU p er hour rating and from $31,000 to $60,000 for heaters rated at 2 MMBTU per hour. Alt hough it will overestimate the actual cost, staff assumed that all operators purchasing h eaters will do so at the high end of the range, or $20,000 for a 400,000 BTU per hour heater and $60,000 for a 2 MMBTU per

hour heater. The manufacturer also estimated annua l maintenance cost for small heaters to be about $1,000 per year. Further, based on sta ff’s estimation, it was determined that 83 of the 85 facilities would each be expected to i nstall one heater that was rated at approximately 400,000 BTU per hour. The remaining two (2) facilities would each require a 2 MMBTU per hour heater.

For facilities that are required to install heaters , there is a permit processing fee of $2,232.96 for the first heater (Schedule C). Altho ugh staff believes many of these facilities will qualify as a small business with a reduced permit processing fee, staff will base the costs as if all facilities are large busin esses and are subject to the full fee. There is also an annual operating fee of $722.68 for each heater.

Produced Gas Control Costs

(1) Capital Cost

Heaters For each heater there is a permit processing fee of $2,232.96. It should be noted that since the information provided by the heater manufa cturers indicated a range of $6,000 to $20,000 for a 400,000 BTU per hour heater (installe d) and that 83 out of 85 facilities were identified as requiring this category of heate r. Two facilities will need a 2,000,000 BTU per hour heater at an installed cost of $31,000 -$60,000.

Expected Service Life 10 years

i) Total Capital Cost (Installed) $20,000 x 83 h eaters = $1,660,000 (400,000 BTU/hr)

ii) Total Capital Cost (Installed) $60,000 x 2 he aters = $ 120,000 (2,000,000 BTU/hr)

iii) Permit Processing Fee = (85 x $2,232.96) = $ 189,802

Total Produced Gas Control Cost (Present Value) = $1,969,802Final Staff Report

PR 1148.1/PAR 222 28 February 24, 2004 (2) Annual O & M Cost

Heater
Annual O&M Costs = 85 x $1,000 = $85,000/year (including testing & maintenance)

Annual Operating Fee = 85 x $722.68 = $ 61,428/year

Total Annual Heater O&M Cost = (Annual Testing & M aintenance Cost) + (Annual Operating Fees)

Total Produced Gas Annual O & M Cost = $146,428

Total Costs for Liquid and Produced Gas Control

Total Capital Cost

= (Liquid Control Capital Cost) + (Produced Ga s Control Capital Cost)

= $75,839 + $1,969,802 = $2,045,641

Total Annual O & M Cost = (Annual Liquid O & M Cost) +

(Annual Produced Gas O & M Cost)

= $1,568,139 + $146,428 = $1,714,567

C. COST EFFECTIVENESS ANALYSIS

The cost-effectiveness analysis uses the Discounted Cash Flow (DCF) method to compute the present value of the costs of the propo sed rule over a recurring 3-year period (the assumed lifetime of the sample containers) adj usted for a 10-year period (the assumed lifetime of the heaters).

Consistent with rulemaking for other AQMD control m easures, a real interest rate of 4 percent will be used in this report to estimate the present value of the annual cost of operations and maintenance. Since all the costs ar e expressed in present value, the effects of future inflation are removed from this analysis. The annual recurring costs of inspection are assumed to be the same for each year . In order to calculate the present value of 10 years of annual costs at 4 percent, the annual cost is multiplied by the present value factor (PVF) of 8.11. The DCF cost effective ness can then be calculated as

follows:Final Staff Report

PR 1148.1/PAR 222 29 February 24, 2004 Overall Cost Effectiveness (based on 10 years) =

Total Capital Costs + (Total Annua l O & M Cost x 8.11)

Total Annual Emission Reducti ons (tpy) x 10 yrs

Overall Cost-Effectiveness (CE)

CE = ($2,045,641) + [($1,714,567 x 8.11] (1.76 ton/day x 365 days/yr x 10 yr)

CE = $2,483 per ton VOC reduced

Based on these calculations, the cost effectiveness is $2,483 per ton and therefore the cost effectiveness of implementing the rule would be wel l within the range that is generally

considered as cost-effective for VOC control measur es.



### INCREMENTAL COST-EFFECTIVENESS

Pursuant to Health and Safety Code Section 40920.6, prior to adopting rules or regulations to meet the requirement for best availa ble retrofit control (BARCT) technology pursuant to Sections 40918, 40919, 40920 , and 40920.5, or for a feasible measure pursuant to Section 40914, the AQMD is requ ired to adopt written findings that identify one or more potential control options whic h achieve emission reduction objectives, determine the cost-effectiveness of eac h potential control option and determine the incremental cost-effectiveness of pot ential control options.

The incremental cost effectiveness of PR 1148.1 wil l be determined by comparing the difference in the present values of control costs f or a potential control option and the proposed rule divided by the difference in the emis sion reductions between the potential control option and the proposed rule. Since the ec onomical life of the gas processing plant in the potential control option is 20 years, the present value of all components will be based upon the recurring cost of those potential control components over a 20-year period.

Control Option Requiring the use of a stuffing box adapter, a clos ed crude oil collection container and a

well shut-off switch that will shut down the well w hen the container is full, for all wellheads, would result in a reduction of loss of c rude oil. Use of this option would also significantly reduce the need for pump-outs. No ad ditional costs for pump-outs will be

added to the cost calculations. To evaluate the in cremental cost effectiveness for the liquid portion of the rule, it will be assumed that there would be a stuffing box adapter cost incurred at 3-year intervals. Therefore, over this (20-year) period there will be aFinal Staff Report

PR 1148.1/PAR 222 30 February 24, 2004 total of seven (7) stuffing box adapter replacement s. It is staff’s estimate that the cost of stuffing box adapters will not change over the 20-y ear period.

To evaluate the incremental cost effectiveness for the produced gas portion of the rule, requiring construction of a gas plant at all facili ties with uncontrolled wells will be evaluated as an option. Based on information obtai ned for this equipment, it was determined that the cost may range from $250,000 to $2.5 million based on the number of units and the complexity of the gas plant. For the purpose of this report an average capital cost of $1 million will be assumed, based o n the smaller facilities and the expected number of wells per facility. The informa tion also estimates annual operating cost to be 2 percent of the capital cost of the equ ipment and the useful life of the equipment was estimated to be 20 years.

Using information reported in the 2001 Division of Oil and Gas Annual Report and a telephone survey conducted by staff, it was estimat ed that approximately 85 facilities did not treat nor control their produced gas for sale t o other facilities or the Southern California Gas Company. Therefore, using a real in terest rate of 4 percent, the annual cost will be multiplied by a present value factor ( PVF) of 13.59.

Potential Control Option Cost

Liquid Control Cost

(1) Capital Cost

(a) Containers

As previously discussed in the Cost Effectiveness s ection, the containers will be replaced every 3 years. The cost of the containers will no t change over each 3-year period for calculation purposes since the cost will be adjuste d to present value using a real interest rate of 4 percent. Since the gas plant equipment l ife of this control option is 20 years,

staff will calculate the container costs over a 20- year period to normalize the costs and

associated emission reductions. The calculations b elow take into consideration that over a 20-year period the operator will purchase 7 batch es of containers, starting at the beginning of the compliance period.

Batch 1 (Initial Purchase) Expected Service Life For the Metal Container 3 y ears Individual Metal Container Cost $25 Container Capital Cost = (3,588 well/1 container per 4 wells) $22,425Final Staff Report

PR 1148.1/PAR 222 31 February 24, 2004 The following table summarizes the cost to purchase the container over the 20-year period.

Container Capital Cost for 20 years

Container

Batch

Number Years

Used Present Value

Discount

Factor Present Value

Capital Cost

1 1 -3 1.0 $ 22,425

2 4-6 0.8890 $ 19,936

3 7-9 0.7903 $ 17,722

4 10-12 0.7026 $ 15,756

5 13-15 0.6246 $ 14,067

6 16-18 0.5553 $ 12,453

7 19-20 0.4936 $ 11,069 Total Cost (over 20 years) $113,428

Capital Cost of Containers = $113,368

(b a ) Adapters The assumed life of the adapter is set at 3 years a t a cost of $600 per unit. The following

costs are associated with the installation of an ad apter based on 20 years to normalize the cost based on the gas plant equipment life, using t he present value factors at 4 percent interest at the recurring periods over the 20 years

.

i) Capital Costs = $600 x 3,588 = $2,152,800

ii) Installation Costs, including the use of 2 peop le for 2 hrs

4 hr/adapter x 3,588 adapters x $25/hr = $358,800

Total Cost for Adapters (1 st . Yr.) Capital + Installation = $2,511,600

Stuffing Box Adapter Capital Cost for 20 years Adapter

Batch

Number Years

Used Present Value

Discount

Factor Present Value

Capital Cost

1 1 -3 1.0 $ 2,511,600

2 4-6 0.8890 $ 2,232,812

3 7-9 0.7903 $ 1,984,917

4 10-12 0.7026 $ 1,764,650

5 13-15 0.6246 $ 1,568,745

6 16-18 0.5553 $ 1,394,691

7 19-20 0.4936 $ 1,239,726 Total Cost (over 20 years) $12,697,141Final Staff Report

PR 1148.1/PAR 222 32 February 24, 2004 Capital Cost of Adaptors = $12,697,141 Total Liquid Capital Costs = $113,386 + $12,697, 141 = $12,810,509

(2) Annual O&M Costs

(a) Stuffing Box Adaptors

(i) Inspection An adapter on a worn stuffing box will need resetti ng once monthly and take one hour each time. Otherwise, it will take 5 minutes per m onth to check. Operators are already required to do daily inspections on 120 out of 3,58 8 pumps since they located within 100 meters of a sensitive receptor. The remaining 3,46 8 wells can be inspected monthly. Therefore, the operator will not incur any addition al inspection costs for the stuffing box adaptors.

(ii) Maintenance Assumption: A conservative approach will be used in assuming t hat there is one wellhead per well cellar and that 50% of all wellheads have worn stuffing boxes.

(ii) 1, 734 adapters (on worn stuffing boxes) @ 1 hr/month @ $25/hr @ 12 mo/yr

= $520,200

(iii) 1,734 adapters (on good stuffing boxes) @ 5 mins pe r mth to check @ $25/hr @ 12 mo/yr

= $43,3500

Annual O&M Cost for Adapters = $520,200 + $43,500

= $563,550

(b) Audio-Visual Inspections

With the installation of the stuffing box adaptor w ith a container and an auto well shut off

to shut off the well when the container becomes ful l, oil leakage will be effectively eliminated. Therefore, the operator can change the ir audio-visual inspection frequency of the stuffing box on well pumps from daily or weekly , as required, to monthly for all wells not located within 100 meters of a sensitive recept or. The wells near sensitive receptors must be inspected daily.

(i) Wells with Well Cellars at Manned Facilities – Annual Inspection Costs (Based on monthly inspections for 2,257 wells @ 5 minutes per well; $25/hr technician labor)Final Staff Report

PR 1148.1/PAR 222 33 February 24, 2004 2,257 wells x 1 insp/mo x 12 mo/yr x 5/60 h r/insp x $25/hr = $56,425/year

(ii) Wells with Well Cellars at Unmanned Facilities – Annual Inspection Costs (Based on monthly inspections for 2,257 wells @ 5 minutes per well and 10 minutes travel; $25/hr technician labor)

878 wells x 1 insp/mo x 12 mo/yr x 15/60 hr /insp x $25/hr = $65,850/year

(iii) Wells without Well Cellars – Annual Inspecti on Costs (Based on monthly inspections for 2,257 wells @ 5 minutes per well and 10 minutes travel; $25/hr technician labor)

333 wells x 1 insp/mo x 12 mo/yr x 15/60 hr /insp x $25/hr = $24,975/year

(iv) Wells at Unmanned Facilities within 100 meters of a Sensitive Receptor (Based on daily inspections for 120 wells @ 5 minu tes per well and 10 minutes travel; $25/hr technician labor)

120 wells x 365 insp/yr x 15/60 hr/in sp x $25/hr = $273,750/year

Total Annual Audio-Visual Inspection Cost = $421,000/year

Total Liquid Annual O & M Costs = $563,550 + 421,000 = $984,550

Produced Gas Control Cost

(a) Capital Cost The assumed life of the gas plant is set at 20 year s at an average cost (capital and installation) of $1,000,000 per unit. The followin g represents the overall capital

cost for 85 facilities:

Capital Costs = $1,000,000 x 85 = $85,000,000Final Staff Report

PR 1148.1/PAR 222 34 February 24, 2004 (b) Annual O&M Gas Plant The annual O & M cost of the gas plant is 2% of the total capital cost of the equipment.

Total annual O & M cost for gas plant = 85 [ 2% ($1,000,000)] = $1,700,000

Total Costs

Total Potential Control Option Cost = (Capital Cost of Container) + (Capital Cost Adaptor) + (Capital Cost Option of Gas Plant) + (An nual Inspection & Maintenance Cost) x 13.59 + (Annual O & M Cost) gas plant x 13.59

= $12,810509 + $ 85,000,000 + ($984,550)(13.59) + ($1,700,000)(13.59)

= $134,293,544

Potential Control Option Emission Reductions

a) Well Cellars

The emission reduction associated with the use of a n adapter is 90 percent compared to 80 percent obtained from the proposed r ule’s I & M requirement.

Emission reductions associated with the use of adap ters: (1.21) tons/day x (0.9) (365) days/yr = 397.49 tons/year

Emissions reduction over 20-year period: 20 years (397.49 85 tons/year) = 7,950 tons

b) Produced Gas

The emission reductions associated with the use of a gas plant to control produced gas will be 100 percent. Emission Reductions = 0.83 tpd (365)days/yr = 302.9 5 tons/year

Emissions reduction over 20-year period: 20 years (302.95 tons/year) = 6,059 tons

Total Emission Reductions of Potential Control Opti on = 14,009 tons/20

yearsFinal Staff Report

PR 1148.1/PAR 222 35 February 24, 2004 Rule Proposal Cost (Adjusted for 20 years)

Total Cost Based on previous calculations in the Cost Effectiv eness section of the report, capital cost was based on 10 years. These costs will be adjuste d for a 20-year period for both the

containers and the heaters. The annual costs will be multiplied by the present value factor of 13.59 based upon 4 percent over 20 years.

Total Proposed Rule Control Cost

= $113,368 + (2)(1,969,802) + [(1,568,139) + (146, 428)] 13.59

= $27,353,938

Proposed Rule Emission Reductions (adjusted to 20 y ears)

Emissions reduction calculated in the Cost Effectiv eness section of the report are:

Liquid portion of the rule = 353.3 tons/year Produced gas portion of the rule = 287.8 tons/year

Total 20-yr Emissions Reduction = 12,833 tons

The following table lists the incremental cost-effe ctiveness along with the present value cost and emission reductions based on the proposed rule and the more stringent control option.

Incremental Cost-Effectiveness

Present Value ($) 20-yr Emission

Reduction (tons)

PR 1148.1 (20 yr period) $27,353,938 12,822

Control Option $ 134,293,544 14,009

Incremental Cost

Effectiveness ($/ton) 134,293,544 – 27,353,938 14,009 – 12,822 $90,092Final Staff Report

PR 1148.1/PAR 222 36 February 24, 2004 

### IMPACT ASSESSMENT

Pursuant to the California Environmental Quality Ac t (CEQA) and AQMD Rule 110, an Environmental Assessment (EA) is being prepared for Proposed Rule 1148.1 and will be

circulated for review. Comments received will be a ddressed when evaluating the potential for adverse environmental impacts from th e proposal and will be incorporated

into the EA.

A. SOCIOECONOMIC ASSESSMENT

Staff is preparing a socioeconomic assessment which is included as an attachment to the Staff Report in the hearing package.

B. COMPARATIVE ANALYSIS

Under the Health and Safety Code Section 40727.2, t he AQMD is required to compare and analyze PR 1148.1 with existing AQMD or federal regulations. There are no existing federal regulations and the comparison to other AQM D rules is discussed on pages 7 and 8 of this report.

C. FINDINGS REQUIRED BY THE CALIFORNIA HEALTH AND S AFETY

CODE

Health and Safety Code Section 40727 requires that prior to adopting, amending or repealing a rule or regulation, the AQMD Governing Board shall make findings of necessity, authority, clarity, consistency, non-dup lication, and reference based on relevant information presented at the hearing.

Necessity - The AQMD Governing Board has determined that a ne ed exists to adopt Proposed Rule 1148.1 to implement Control Measure F UG-05 of the 2003 Air Quality Management Plan (AQMP), to further reduce VOC emiss ions and make progress toward meeting the state and federal ambient air quality s tandards for ozone.

Authority - The AQMD Governing Board obtains its authority to adopt, amend or repeal rules and regulations from California Health and Sa fety Code Sections 39002, 40000, 40001, 40440, 40702 and 41508.

Clarity - The AQMD Governing Board has determined that Prop osed Rule 1148.1, as proposed to be amended, is written or displayed so that its meaning can be easily understood by the persons directly affected by it.

Consistency - The AQMD Governing Board has determined that Pro posed Rule 1148.1, as proposed to be amended, is in harmony with and n ot in conflict with or contradictory to, existing statutes, court decisions or state or federal regulations.Final Staff Report

PR 1148.1/PAR 222 37 February 24, 2004 Non Duplication - The AQMD Governing Board has determined that Pro posed Rule 1148.1, as proposed to be amended, does not impose the same requirements as any existing state or federal regulations, and the amen dments are necessary and proper to execute the powers and duties granted to, and impos ed upon, the AQMD.

Reference - The AQMD Governing Board by adopting this regula tion is implementing, interpreting or making specific the provisions of: Health and Safety Code Sections 40001 (rules to achieve ambient air quality standards), 4 0440(a), (rules to carry out the Air Quality Management Plan), (b) (Best Available Retro fit Control Technology), and (c) (rules which are also cost-effective and efficient) , 40702 (rules to execute duties necessary to preserve original intent of rule) and 40910 et seq., (California Clean Air Act).Final Staff Report

PR 1148.1/PAR 222 38 February 24, 2004 

### AMENDMENTS SUBSEQUENT TO THE JANUARY HEARING

Proposed Rule 1148.1 was the subject of a public he aring on January 9, 2004. Testimony at the hearing from DOGGR and representatives from industry expressed several concerns about the proposal. Based upon this testi mony, the Board continued the hearing to March 5 and directed staff to meet with DOGGR, i ndustry and other interested parties to address the concerns. Two lengthy meetings were held on January 28 and February 5 with DOGGR and industry to discuss their concerns.

Since some concerns were based on speculations abou t events that might occur if any rule was adopted, staff consulted with staff of SBCAPCD regarding the implementation of their rules that were adopted several years ago. T wo of the issues raised by DOGGR were that a rule such as PR 1148.1 would encourage operators to fill in their well cellars to avoid being subject to the rule and that a large number of marginal operators would desert their wells because of the additional operat ing costs a rule would impose.

SBCAPCD staff indicated that there were incidents o f well cellars being filled in but these were not widespread. However, there was no i ndication that mass desertion of wells by marginal operators occurred. On an unrela ted issue, they also recommended that in our exemption for maintenance and repair, d rilling and abandonment operations, we clarify that these activities are to be conducte d in a safe manner that minimizes

emissions.

As a result of these additional discussions, staff is proposing amendments to PR 1148.1. The following summarizes the amendments. The amend ments are not substantial and do not significantly affect the meaning of the rule. An explanation for each amendment is included in the summary.

A. OPTIONAL TWO-INCH TEST

PR 1148.1 requires that operators visually check fo r leakage of liquid into the well cellar. If evidence of organic liquid is discovered, the op erator must determine the TOC emissions using the equipment and test method speci fied in the rule. If the emissions are greater than 250 ppm of VOC, the operator is requir ed to remove the organic material. In addition, as currently written, the rule requires p ump-out for wells located near sensitive receptors if there is a 2-inch accumulation of orga nic material in the well cellar, irrespective of the TOC measurement.

Industry has argued that the direct measurement of TOC is a more effective method for determining emissions to the atmosphere than measur ing two inches of organic material, and that to require both methods for some well cell ars is unnecessary. Although many operators and the contractors that perform the quar terly inspections have the instruments necessary to measure TOC, some of the small operato rs may not have ready access to a TOC measuring instrument. Since the other district s that have EPA-approved well cellar rules allow measurement of the thickness of organic material accumulated in the well cellar using a “copper coat” gauge as the triggerin g mechanism for pump-out, PR 1148.1Final Staff Report

PR 1148.1/PAR 222 39 February 24, 2004 should allow that method as an option for the small operators that do not readily have

access to a TOC measurement instrument.

Staff concurs that measurement of TOC with an appro ved instrument is a most effective method for determining the magnitude of emissions t o the atmosphere and should be used when such an instrument is available. However, whe n an instrument is not available, use

of the standard that is in SBCAPCD and other distri cts’ rules that require pump-out when two inches of organic material is accumulated in th e well cellar is adequate to ensure emissions to the atmosphere are minimized. To requ ire both methods to be used concurrently at the same well cellar may not result in any additional air quality benefit.

Therefore, staff proposes to amend PR 1148.1 to req uire that operators only measure well cellar emissions with an approved TOC instrument wi th the option of the two-inch measurement as the triggering mechanism for pump-ou t. The quarterly inspection will continue to require the use of the TOC measuring in strument. The prohibitory standard, which is the primary enforcement standard, will als o continue to be based on TOC measurement. Therefore, this amendment is not a su bstantive change. Since there is no change in the requirement for pump-out, the amendme nt does not significantly change the meaning of the rule.

B. WELL DRILLING AND WELL ABANDONMENT

DOGGR commented that the proposed rule did not adeq uately provide for drilling and abandonment operations. Although these operations are done infrequently to a well, are of short duration and in the case of abandonment, w ill result in no potential to emit when the operation is complete, they nevertheless are op erations that may result in some venting of gas or accumulation of organic material in the well cellar during the safe completion of these operations.

Staff interpreted these activities as subcategories of routine maintenance when preparing our proposal. In our subsequent discussions with D OGGR and industry, it was pointed out that technically this may not be correct. Ther efore, to clarify and ensure that it is technically correct to those affected by the rule o r implementing it, language has been added to the requirements in paragraph (d)(3) and t he exemptions in paragraph (h)(2) to make clear that drilling and abandonment operations are to be regulated in the same

manner as routine maintenance or well workover and conducted in a safe manner that

minimizes emissions. This clarification of intent improves the meaning of the rule without significantly or substantively changing it.

C. REMOVAL OF WELL CELLARS

DOGGR expressed concern that some operators would c hoose to eliminate their well cellars in lieu of complying with the requirements of PR 1148.1, particularly since there

was some evidence of this in Santa Barbara after a well cellar rule was implemented

there. Elimination of well cellars could have a de trimental impact on the environment,Final Staff Report

PR 1148.1/PAR 222 40 February 24, 2004 not just air quality but other media as well. The reason one would choose to eliminate the well cellar is simply the cost savings on the perio dic inspections.

Staff concurs that well cellars are to provide an e nvironmental benefit to the air and other media and does not intend to encourage elimination of well cellars and their benefit. To

ensure there was not an economic incentive to elimi nate well cellars or forego well cellars at new wells, PR 1148.1 requires much more frequent inspection for wells without

well cellars. It was believed that the additional inspection cost would far outweigh the perceived economic benefit of eliminating well cell ars and, in effect in an indirect way, prohibit the elimination of well cellars.

To clarify the matter, staff proposes to amend PR 1 148.1 to address the elimination of the well cellar issue directly by prohibiting the elimi nation of a well cellar at a producing well and requiring well cellars at all new wells. Since this directly clarifies staff’s indirect prohibition of well cellar elimination cur rently in the proposed rule, it is not a substantive change nor does it significantly change the meaning of the proposed rule noticed for hearing.

D. SMALL PRODUCER EXEMPTION

DOGGR expressed the concern that the very marginal operator with low production wells would simply desert their operation because of the additional costs imposed by PR1148.1 would push them over the edge of economic viability . This was particularly of concern with wells with a low volume of produced gas that w ould be required to control the gas emissions. Since DOGGR would be responsible for ab andonment operations for those wells deserted by the operator, there was concern t hat if the rule triggered this for a number of operators all at once that there would no t be adequate resources to complete abandonment operations in a timely manner.

Staff determined that the overall cost effectivenes s of PR1148.1 is $2,483 per ton of VOC reduced which is very cost effective compared to ot her measures with AQMP. A significant portion of the cost is estimated to be for purchase, installation and operation of the produced gas control equipment. On an individu al basis, the cost effectiveness for the low volume gas producer could be greater than the i ndustry-wide average. For example, for a well that produces 200 cubic feet of gas per day that results in a little more than a pound per day of VOC, depending on the control used , the cost effectiveness ranges from $10,568 to $17,230 per ton reduced. Likewise, for a well that produces 400 cubic feet of produced gas per day the individual cost effectiven ess ranges from $5,284 to $8,615 per

ton of VOC reduced.

In order to estimate the number of wells that produ ce 200 cubic feet of gas or less and thus the emissions from those wells the DOGGR produ ction data from 2001 was used. However, DOGGR does not collect produced gas data f or such a low level of production but they do collect all oil production data. Altho ugh the gas to oil ratio varies, an average

ratio is 200 cubic feet: l barrel. The DOGGR data indicated 45 wells with production of one barrel or less. Assuming all 45 wells produce one barrel per day, the VOC emissions would be 45 lbs/day which is below the CEQA signifi cance threshold. Since the averageFinal Staff Report

PR 1148.1/PAR 222 41 February 24, 2004 production of those 45 wells ranges from zero to on e barrel per day, it is expected the

actual total emissions would be less.

Staff proposes an exemption from the gas control re quirements of PR1148.1 for facilities wells that cumulatively produce no more than 200 cu bic feet per day of gas or one barrel of oil per day, provided the wells are not located near a sensitive receptor. Staff believes

it would be cost-effective to control individual we lls or multiple wells at a facility when production exceeds the exemption level. It is cost -effective for multiple low-production wells at a facility since several wells could be ve nted to a single control device. Wells located adjacent to sensitive receptors are exclude d from this exemption consistent with the Board policy on environmental justice to provid e health protective standards near sensitive receptors. The other requirements of the rule will remain in place for these sources. To qualify, the operator must provide rec ords that demonstrate eligibility which would mean that those choosing gas production would need meter readings as records. Some operators already have meters but those that d o not would need to install one. However, since operators report the oil production to DOGGR, it is expected this would be the method most operators would choose to demons trate eligibility and it is not expected that the small operators will choose to in stall gas metering.

Since even under the worst case scenario the emissi on impact of the proposed exemption from the gas control requirements for low volume ga s production wells is below the CEQA significance threshold of 55 pounds per day of VOC, this amendment is not substantive nor does it significantly change the me aning of the proposed rule.

E. APPLICABILITY OF RULE 1173

Industry expressed a concern that the repair interv al in paragraph (d)(7) was different than that of Rule 1173 and since (d)(7) referred to produced gas handling equipment in general, there could be confusion that leaking comp onents subject to Rule 1173 would be subject to the repair interval of PR1148.1. It was not staff’s intent to mix the requirements of Rule 1173 with the repair intervals of PR1148.1 for components on produced gas handling equipment. Staff has include d language in paragraph (d)(7) to clarify this so that it does not significantly chan ge the meaning of the rule noticed for hearing nor is it a substantive change.Final Staff Report

PR 1148.1/PAR 222 42 February 24, 2004 

### COMMENTS AND RESPONSES

Comment 1 The definition of wellhead indicates that it is con nected to an oil production line and a vapor recovery line, but in some cases wells are no t connected to a gas gathering line. In addition, the vapor recovery line is in fact the ca sing gas line.

Response 1 The definition has been revised to incorporate this comment.

Comment 2 Requiring operators to install carbon canisters on vacuum trucks and portable tanks during well pump-outs is inconsistent with other op erations where this same equipment is used to handle petroleum.

Response 2 Consistent with other AQMD rules, PR 1148.1 has bee n revised to no longer require the

use of carbon canisters on vacuum trucks that are u sed to store crude oil, but requires that portable enclosed storage vessels or Baker tanks be equipped with air pollution control. Other AQMD rules require vapor control equipment to be in place for other types of storage vessels. Air pollution control equipment w ill reduce TOC emissions released to the environment to less than 250 ppm.

Comment 3 What is the basis for the maximum outlet concentrat ion of the Baker tank or other portable enclosed storage vessels being established as 50 ppm?

Response 3 The 50 ppm level is consistent with other AQMD rule s and control equipment permit conditions for VOC emissions released to the atmosp here. However, in response to comments received, the allowable maximum concentrat ion has been modified and set at 250 ppm to be measured as Total Organic Compound (T OC) emissions, not just as VOC. This measurement as TOC will simplify the implement ation of the rule, improve its enforceability, and will result in better maintenan ce procedures focusing on all organic

emissions.

Comment 4 The rule should be consistent with Rule 1176 by all owing the operator to pump out the well cellar within ten (10) days after discovery of organic liquid accumulation.

Response 4 Rule 1176 allows operators to store crude oil in we ll cellars for up to ten days for emergency purposes. PR 1148.1 has been revised to include this exemption. PR 1148.1 requires the operator to pump out the well cellar w ithin five (5) days or within 24 hours

for wells located within 100 meters of a sensitive receptor after the discovery of theFinal Staff Report

PR 1148.1/PAR 222 43 February 24, 2004 organic liquid accumulation in the well cellar. Si nce well cellars are receptacles that are open to the atmosphere, it is expected that any acc umulation of organic material will continue to volatilize if kept in the well cellar. Therefore, allowing the material to accumulate for longer periods of time prior to pump -out will undoubtedly result in the majority of VOCs being emitted to the atmosphere. This would be counterproductive to

the intent of the rule.

Comment 5 The rule requires that when the depth of the liquid in the well cellar exceeds 50% of the actual well cellar depth, this would trigger operat ors to pump out. During major storms this would require immediate pump-out of all well c ellars within two days even though there may be no oil in the cellars. The logistics of such a requirement would be, at best, cost prohibitive and potentially unsafe and would p rovide no benefit if the cellar contents are predominantly water.

Response 5 Staff has revised PR 1148.1 to require pump out of organic liquid material when the TOC concentration is 250 ppm or greater, and for those well cellars located within 100 meters of a sensitive receptor when there is an accumulati on of 2 or more inches of organic material. The revised rule in effect, excludes the pump out of well cellars that accumulate only water.

Comment 6 Paragraph (d)(4) – Requirements. Immediately befor e a well is steamed or after a wellhead is steam cleaned, the liquid accumulated i n the well shall be pumped out. This requirement does not make it clear that the Di strict is referring to fluids containing crude oil or other hydrocarbons as opposed to rainw ater, groundwater, brines or other fluids not containing VOCs that may be found in the cellars.

Response 6 The wording has been changed to clarify the intent of the requirement, which is to address organic liquids and not non-organic liquids such as rainwater, groundwater and

brines.

Comment 7 Industry would like a clarification of the requirem ent that indicates that no person is allowed to purposely hold crude oil or petroleum product in the well cellar.

Response 7 The wording has been changed to clarify the intent of the requirement and is as follows: No person shall be allowed to purposely store crude oil or petroleum product in the well

cellar.

The proposed rule requires that the operator only b e allowed to accumulate organic liquid in the well cellar during maintenance or well worko ver activities. In addition, the operator is required to pump out the well cellar wi thin 2 days after each maintenanceFinal Staff Report

PR 1148.1/PAR 222 44 February 24, 2004 activity has been completed. When there is accumul ation as a result of non-maintenance activity or when the total VOC concentration in the well cellar exceeds 250 ppm TOC and 2 inches of organic material for those well cel lars within 100 meters of a sensitive receptor according to test methods outlined in the rule, the operator is required to pump out the well cellar within 5 calendar days, or 2 da ys if the well is located near a sensitive receptor. PR 1148.1 includes an exemption consiste nt with Rule 1176 to allow storage of organic liquids resulting from emergencies for a pe riod of up to 10 days.

Comment 8

Well cellar emissions used to determine the emissio n inventory for this rule have been grossly overstated because fees for this source cat egory, emissions were estimated using an emission factor for VOCs that was based on organ ic material surface area exposed to the atmosphere. It is also believed that once the District started charging fees, operators were more careful in reporting emissions only for w ell cellars that actually contained organic liquid material and not for others that may have been empty.

Response 8 The emissions information that oil and gas producti on facilities reported to the AQMD as part of their Annual Emissions Reporting (AER) was used to establish the point source portion of the well cellar emissions inventory. Th is inventory captured 54 larger oil and gas production facilities located in the South Coas t Air Basin, while an estimate for the area source portion of the inventory for the remain ing smaller facilities that did not report was based on a 2010 AQMP planning inventory project ion. Any future improvements to the emissions inventory and emissions reductions re sulting from the implementation of Proposed Rule 1148.1 will be reflected in future re visions to the AQMP. Staff acknowledges the default emission factors are conse rvative by design to be health protective. The emission factor for well cellars w as developed by CARB in conjunction with KVB (a consulting firm) and this factor is the basis of well cellar emission factors used by other air districts in California. It is t he best emission factor currently available.

Comment 9

Based on information of operational practices in other state s, industry has learned that the stuffing box adapter has proven to be very inef fective.

Response 9 Stuffing box adapter manufacturers have indicated t hat the adapters are effective and have been used extensively outside of California. However, operators indicated they have determined that such devices require significa ntly more maintenance and may be more applicable in other areas of the country where wells are more remotely located. Since most wells in the SCAQMD are not remotely loc ated, an inspection and maintenance program could provide an equivalent emi ssion reduction without mandating the use of a specific technology for all wells. As an option, an operator may request the AQMD to change the audio-visual inspection frequenc y from daily or weekly to a monthly frequency for those wells/stuffing boxes th at are equipped with a stuffing box adapter. The change in inspection frequency is not allowed for wells located within 100 meters of a sensitive receptor.Final Staff Report

PR 1148.1/PAR 222 45 February 24, 2004 Comment 10 The District’s estimation of 550 million cubic feet (or 5% of 11,000 mmcf) of produced gas being vented to the environment is an overestim ation and the amount of uncontrolled produced gas is probably closer to 1% or 110 millio n cubic feet.

Response 10 AQMD records did not provide data on the amounts of produced gas reported by facilities in the South Coast Basin. Initially, st aff used the 2001 Division of Oil and Gas Annual Report to estimate the amount of produced ga s vented. In that report, less than 50% of oil and gas production facilities in the AQM D actually reported their gas production. In addition, the AQMD permitting datab ase indicated that less than half of these facilities directed their produced gas to tre atment systems for use offsite or to gas control systems (flare, IC engine or boiler). Base d on this information staff estimated that 5% (or 550 million cubic feet) of the total 11 billion cubic feet of produced gas was

untreated or uncontrolled.

Subsequently, the AQMD followed up this estimation with a telephone survey in conjunction with CIPA’s survey, which yielded data indicating that more facility operators use heaters and engines than the AQMD per mit database indicated. These heaters and engines do not require a written AQMD p ermit based on their size. This was not accounted for in the original estimation. Base d upon the follow-up survey which should yield a more accurate estimation, the revise d amount of uncontrolled and untreated produced gas is now expected to be approx imately 0.91 % or 100 million cubic

feet.

Comment 11 Industry has expressed concern that District Permit ting Division would only allow shrouded flares to be permitted and that the cost e ffectiveness analysis included in the draft staff report did not reflect the cost of the complex controls associated with shrouded flares.

Response 11 Staff has revised the rule to allow the operator th e option of choosing, with AQMD approval, any control equipment (not just flares) t hat is capable of achieving a VOC vapor removal efficiency of at least 95% by weight or an outlet VOC concentration of 50 ppm using test methods outlined in the rule. Infor mation obtained from a telephone survey led staff to believe that heaters were more commonly used at smaller oil and gas production operations due to cost and energy conser vation. Both heater and flare manufacturers have stated that their equipment comp ly with all applicable AQMD regulations.

Comment 12 Paragraph (d)(6) –Produced Gas Requirements. These rule requirements are not directly related to oil and gas productions wells, but are p roduction facility issues.Final Staff Report

PR 1148.1/PAR 222 46 February 24, 2004 Response 12 The AQMD, as an extreme non-attainment area, is req uired to implement all feasible control measures. Both Santa Barbara County APCD’s Rule 325 – Crude Oil Production and Separation and Ventura County APCD’s Rule 71.1 – Crude Oil Production and Separation include requirements for produced gas. Staff also determined that some oil and gas production operations, including smaller on es were venting produced gas to the atmosphere. Therefore, staff was required to deter mine if the rules are technologically feasible for oil and gas production facilities in t he AQMD. Staff has determined that the control of produced gas is both technologically fea sible and cost effective.

Comment 13 Paragraph (d)(6) – Control of Produced Gas. It req uires the operator to use a properly maintained system that directs all produced gas, ex cept gas used in a tank battery vapor recovery system to a system handling gas for fuel, sale or underground injection or to a flare or other device that demonstrates vapor remov al efficiency of at least 95% by weight.

Industry believes that this requirement is too rest rictive because minor amounts of gas are typically released to the atmosphere while serv icing a well or performing maintenance of well equipment at oil and gas produc tion operation facilities.

Response 13 Rule language has been revised to include a provisi on that exempts operators from venting produced gas during maintenance and repair activities.

Comment 14 Paragraph (d)(7) – Totalizing Gas Meters. Industry believes that it is not feasible to install a totalizing meter to measure monthly produ ced gas from an oil production field since gas produced within a typical production fiel d is measured by several meters and the aggregate of these devices is reported to the C alifornia Division of Oil and Gas.

Response 14 Totalizing gas meters were necessary to demonstrate a rule exemption level. Since staff has determined that the use of heaters is technolog ically feasible and cost effective at all production levels an exemption is no longer appropr iate. Therefore, the requirement to install a totalizing gas meter has been removed fro m PR 1148.1.

Comment 15 Industry questions the validity of the emission inv entory used for this rule based on the use of the 7.5 pounds VOC per square foot of accumu lated organic material exposed to the atmosphere.

Response 15 The 7.5 pound per square foot emission factor used to estimate the VOC emissions from well cellars was based on a study that was conducte d by CARB and KVB many yearsFinal Staff Report

PR 1148.1/PAR 222 47 February 24, 2004 ago. This emission factor was found to be in close correlation with emission factors used by other Air Quality Districts. While this current ly is the best emission factor available for this source category, any future improvement to the emission factor will be reflected in the future emissions inventory and AER. See als o response to Comment #8.

Comment 16 When cost effectiveness is evaluated for individual requirements, the numbers range from $300 per ton to $750,000 per ton which is much high er than the District’s estimate of $643 per ton.

Response 16 The cost analysis in the staff report has been revi sed and the revised current cost effectiveness is $2,483 per ton. However, although it is not common practice to break down cost effectiveness based on different rule req uirements, the well cellar and produced gas portions were each determined to be co st effective when evaluated separately. The cost effectiveness value of $750,0 00 per ton submitted by industry to staff was based on the cost of a large flare that w ould be used only at the larger oil and gas production facilities. These larger facilities currently meet the requirements for produced gas stated in PR 1148.1. Accordingly, sta ff’s cost and cost effectiveness were

much lower because the size and cost to control the produced gas at the smaller facilities venting directly to the atmosphere were significant ly lower.

Comment 17 Please modify the Applicability section PR 1148.1 t o clarify that the rule is intended to apply only to oil production wells that are located onshore.

Response 17 Staff has revised the Applicability subdivision to emphasize that the proposed rule applies only to oil and gas production wells locate d on land.

Comment 18 PR 1148.1, as currently written, requires all opera tors to pump-out the well cellar when a TOC concentration is detected at 250 ppm using EP A Method 21 or when 2 inches of organic material is measured in the well cellar. T his requires both standards to be applied when the Method 21 method should be suffici ent. This could trigger a pump-out even though the well cellar emissions are significa ntly below the 250 ppm of TOC

threshold.

Response 18 The proposal has been amended to require the additi onal requirement for pump-out when 2 inches or more of organic material has accumulate d in the well cellar for those well

cellars located within 100 meters of a sensitive re ceptor. Although staff believes the 250 ppm of TOC threshold is sufficient to limit emissio ns from well cellars in most instances, an additional factor of safety is appropriate near sensitive receptors. Organic material

accumulation in a well cellar is indicative of a le ak that should be repaired if good housekeeping and maintenance procedures are in plac e.Final Staff Report

PR 1148.1/PAR 222 48 February 24, 2004 Comment 19 Industry believes that the PAR 222 fee structure un fairly targets the larger facilities and

should be revised to distribute the cost more evenl y on a per facility basis as opposed to using the number of wells as a basis for fee determ ination. It should also be noted that the larger facilities already have a Rule 1173 fugi tive emissions program in place. This would mean that the AQMD’s incremental cost ($112,0 00) of implementing the PR 1148.1 sampling of well cellars cannot be justified since the inspector would be able to conduct Rule 1173 testing concurrently and would no t be required to make any additional trips to the facility.

Response 19 Staff has explored other options to determine a fee structure that would be equitable to industry, and at the same time address the cost ass ociated with AQMD staff conducting quarterly TOC well cellar measurements. Our analys is has determined that this is the best approach that would be equitable and revenue-n eutral. However, staff is open to reevaluate this issue at a later date.

Comment 20 The word “any” in paragraphs (d)(2), (d)(3) and (d) (5) should be removed from the proposed rule, since it could be interpreted that a well should be cleaned to a point

where there is no measurable TOC rather than to the minimum emission standards required by the rule.

Response 20 Staff has removed the language for clarity.

Comment 21 Short term use of a Baker tank during a well workov er operation for 2-3 days until fluids are transferred to a handling facility should not b e considered “storage” at the well site and, thus, subject to the requirement for carbon ca nisters and Method 21 measurements.

Response 21 Staff does not require immediate removal of organic material during maintenance and workover since pump-out operations may not be pract ical and the delay it could cause in the completion of maintenance or workover may resul t in greater emissions to the atmosphere than if accumulated material was removed soon after the maintenance or workover is complete. However, in those situations where the operator determines it is practical to pump-out to a storage tank during main tenance or workover control of the emissions from the tank should be required since it is technologically feasible and cost

effective.

Comment 22 The definition of Oil Production Field does not add ress operators with multiple well sites at non-contiguous surface locations that are produc ing from the same oil field that send the crude oil from several facilities to one produc tion field or tank farm for handling.Final Staff Report

PR 1148.1/PAR 222 49 February 24, 2004 Response 22

The definition “Oil Production Field” was needed to address the requirement to install totalizing gas meters to measure the produced gas a t a facility. Subsequently, staff has deleted the requirement to install totalizing gas m eters. Therefore, this definition is no longer needed and has been deleted from PR1148.1.

Comment 23 The District should revise the definition of a Stuf fing Box: “Stuffing Box is a packing gland, chamber, or “box” used to hold packing mater ial compressed around a moving pump rod” and delete “to reduce the escape of gas o r liquid.”

Response 23 Staff disagrees. Staff believes that the packing m aterial of the stuffing box reduces the escape of gas and liquid from the moving pump rod o f the oil well. This definition is used by the California Air Resources Board (CARB) in the ir inspection and training manual for oil well production facilities.

Comment 24 Staff should revise the rule requirements in paragr aph (d)(2) to include that the “container shall be kept closed to the atmosphere w hen it contains crude oil and is not in

use”.

Response 24 Staff agrees and has revised the rule.

Comment 25 Not all stuffing boxes are not located completely w ithin the well cellars. Staff should revise, where appropriate, the rule requirements to state “in or above a well cellar.”

Response 25 Staff agrees and has revised the rule.

Comment 26 PR 1148.1 requires operators to inspect well cellar s weekly which can change to a monthly frequency after such time when the operator equips the stuffing box with a stuffing box adaptor. The District should require quarterly inspections of the well cellars to be consistent with Rule 1173 inspection requirements. Therefore, the District should delete the requirement for weekly inspection s under paragraph (e)(3). [This comment was received on September 16, 2003, which w as based on the proposed rule released for the Public Workshop on August 26, 2003 ]

Response 26 After hearing industry comments at the Public Consu ltation Meeting on September 18, 2003, staff has revised PR 1148.1 to incorporate th e proposal by industry to include in PR 1148.1 an alternative to the required installation of stuffing box adaptors on well pumps. Staff has determined that this alternative, which i ncludes periodic audio-visual inspectionFinal Staff Report

PR 1148.1/PAR 222 50 February 24, 2004 of the stuffing box (daily for wells without well c ellars, weekly for wells with well cellars, and monthly for wells with stuffing box ad aptors and closed containers and an oil well auto shut off when the container is full) and a quarterly TOC measurement of the well cellar, and a maximum allowable TOC concentrat ion of 500 ppm results in greater VOC emission reductions compared to just requiring the installation of stuffing box adaptors. The inclusion of Rule 1173 inspection/TO C measurement requirements greatly enhances the effectiveness of PR 1148.1 compared to the visual inspection requirements of earlier draft rule proposals. Paragraph (e)(3) was clarified to require weekly audiovisual inspections of the well cellars.

Comment 27 Under Recordkeeping Requirements, the District sho uld delete references to paragraph (e)(3) and weekly inspection of well cellars, the n ame of the person and company performing the inspection because this information is collected with Rule 1173 inspections, and records of produced gas (since it may be impractical to measure all gas through a single gas meter).

Response 27 Staff has revised PR 1148.1 to clarify the requirem ent of weekly audio-visual inspection of well cellars and that AQMD will provide a record keeping form to ensure that duplicative reporting of information on the inspect ions with Rule 1173 does not occur. Staff has informed the industry representatives at the Public Consultation Meeting on September 18, 2003, that the reporting of produced gas can be determined by adding the volumes measured by several gas meters at the facil ity (and not a single meter for the whole oil field).

Comment 28 Industry does not believe that an exemption for con trol requirements for facilities with produced gas of 100,000 cubic feet per month is pra ctical since very few facilities operate at or below that level.

Response 28 The exemption for control requirements for faciliti es with produced gas of 100,000 cubic feet per month was based on a determination by staf f that it would not be cost effective to install and operate a small flare at or below that level. However, staff has since determined that small process heaters can be operat ed at very low level of produced gas. As a result, staff has removed the exemption for op erators with low levels of produced

gas.

Comment 29 Rule 1173 exempts components exclusively handling f luids with a VOC content of ten percent by weight or less. The industry suggests t hat the same apply to wells handling similar fluids under PR 1148.1Final Staff Report

PR 1148.1/PAR 222 51 February 24, 2004 Response 29 PR 1148.1 has established an action level (inspecti on, maintenance and repair) of 250 PPM TOC, as determined by EPA Method 21 to account for the non-VOC compounds. This action level is equivalent to 50 PPM VOC becau se most crude oil emissions and produced gas in the AQMD is anticipated to consist of non-VOC compounds such as methane (approximately 80 percent or more). The 50 PPM level is consistent with current BACT and permit condition levels for the re mediation of VOC contaminated soil (primarily petroleum products) under Rule 1166.

Comment 30 The requirement to conduct the measurement of TOC c oncentrations at a distance of no more than three inches above the organic liquid sur face is not practical because it will require our testing contractors to enter the well c ellar, which is a confined space.

Response 30 In discussions with a major manufacturer of portabl e organic vapor analyzers, staff was informed that the analyzers are sold with a three-f oot probe extension and that additional probe extensions could be added without compromisin g the accuracy of the TOC/VOC measurement, provided the operator allowed enough t ime) for the analyzer to stabilize.

Comment 31 Self monitoring by the operators should not be reli ed upon for compliance determination. In particular, I am concerned about those facilitie s located near young children.

Response 31 The AQMD has determined that self monitoring and in spection programs are effective in reducing emissions from industrial sources if they are accompanied by regular AQMD inspections and audits. Similarly, the self monito ring requirements in PR 1148.1 do not replace but augment AQMD’s inspection program. Mos t facilities use third party contractors to implement the self monitoring requir ements of AQMD rules. All records of inspection, maintenance, repair and pump-out wil l be audited by the AQMD.

PR 1148.1 has additional requirements for oil wells located near sensitive receptors, which includes schools (kindergarten to 12 th grade). These additional requirements include more frequent inspections and a faster resp onse to correct deficiencies upon discovery by the operator or AQMD staff.

Comment 32 What is the driving force behind the development of this rule?

Response 32 PR 1148.1 has been under active development since e arly 2003. The rule implements Control Measure FUG-05 in the 2003 AQMP. A similar control measure was included in the previous AQMP. In addition, since the AQMD is an extreme non-attainment area for ozone, the California Clean Air Act requires adopti on of all feasible measures, which

would include the elements of PR 1148.1. In an eff ort to further minimize exposure ofFinal Staff Report

PR 1148.1/PAR 222 52 February 24, 2004 sensitive receptors to emissions, the rule also inc ludes additional inspection and maintenance requirements for wells located within 1 00 meters of sensitive receptors as directed by the AQMD Board Environmental Justice In itiatives.Final Staff Report

PR 1148.1/PAR 222 53 February 24, 2004 

### REFERENCES

1. “Annual Report, California Department of Conserv ation, Division of Oil, Gas &

Geothermal Resources 2001”

2. California Air Resources Board. Identification o f Performance Standards for Existing Stationary Sources. A Resource Document. April 26, 1999.

3. “California Laws for Conservation of Petroleum a nd Gas”, January 2001

4. “Oil Field Production Manual, Compliance Assista nce Program”, California Air Resources Board, Compliance Division

5. “Petroleum Engineering Handbook”, edited by Howa rd B. Bradley, Editor-inChief, June 1989Final Staff Report

PR 1148.1/PAR 222 54 February 24, 2004 

### PROPOSED AMENDED RULE 222

BACKGROUND

The Air Pollution Control Permit Streamlining Act o f 1992 (Article 1.5 of Chapter 4 of the Health and Safety Code) requires air pollution control districts to “institute new, efficient procedures which will assist businesses i n complying with regional, state, and federal air quality laws in an expeditious fashion, without reducing protection of public

health and the environment.”

In September 1998, the AQMD Governing Board adopted Rule 222 - Filing Requirements for Specific Emission Sources Not Requ iring a Written Permit Pursuant to Regulation II, as an alternative to permitting comm only used equipment that emit small

amounts of air contaminants. The rule establishes a filing program wherein operators of such equipment are required to submit to AQMD a des cription of the equipment and data for estimating emissions and determining compliance . The filing program under Rule 222 reduces permit and renewal fees for the operato r, is less burdensome than the conventional permit process, and also decreases the permitting workload at AQMD.

Rule 222 currently includes three equipment categor ies: negative air machines used for asbestos removal, charbroilers, and boilers and pro cess heaters with rated heat inputs from 1,000,000 Btu per hour up to and including 2,0 00,000 Btu per hour. Staff is proposing to include in Rule 222 equipment associat ed with moving crude oil from the

subsurface to the surface which includes well cella rs, wellheads and well pumps. This encompasses approximately 3,588 oil producing wells located at 220 oil production facilities that will require filing to ensure compl iance with PR 1148.1, and to assist in the development of emission inventory data. The initia l filing fee and subsequent annual fee will be assessed to each group of up to four well c ellars. Staff has determined that this approach is equitable to all affected facilities, w hich can range in size of 1 well to just over 300 wells per facility. This approach is also expected to provide sufficient revenue to fund the administrative and the inspection requi rements of PR 1148.1. The majority of the equipment filings will be received in 2004.



### LEGISLATIVE AUTHORITY

H&SC section 40522.5 authorizes the AQMD to adopt “ a schedule of fees to be assessed

on area-wide or indirect sources of emissions which are regulated, but for which permits are not issued by AQMD to recover the costs of AQMD ’s programs related to these

sources.”

Chapter 6 of the H&SC section 40701(g) grants distr icts the power “to require any owner or operator of any air pollution emission source, e xcept a non-commercial, vehicular source, to provide (1) a description of the source, and (2) disclosure of the data necessary to estimate the emissions of pollutants for which a mbient air quality standards have been adopted, or their precursor pollutants.”Final Staff Report

PR 1148.1/PAR 222 55 February 24, 2004 

### PROPOSED AMENDMENTS

1. Rule applicability is expanded to include oil pr oduction well group which is no more than four well cellars located at an oil and gas pr oduction facility that would be subject to the requirements of PR 1148.1.

2. The terms “OIL PRODUCTION WELL GROUP”, “WELL CEL LAR”, “WELLHEAD”, and “WELL PUMP” are added to paragraph (c) of PR 1148.1 –

Definitions.

California Health and Safety Code Section 40727.2 A nalysis for Proposed Amended Rule 222 – Filing Requirements For Specific Emissio n Sources Not Requiring a Written Permit Pursuant to Regulation II.

Proposed Amended Rule (PAR) 222 imposes a filing an d annual renewal requirement for well cellars, wellheads and well pumps. This equip ment is currently exempt from District permitting requirements. Thus, the filing and annual renewal requirements constitute a “new reporting” requirement and the Di strict is required to perform an analysis pursuant to California Health and Safety C ode Section 40727.2 to determine all existing federal air pollution control requirements and any existing or proposed District rules or regulations that apply to the same equipme nt or source type. Staff has determined that there are no federal air pollution control requirements for well cellars, wellheads and well pumps. PR 1148.1 – Oil Field Pr oduction Wells will reduce VOC emissions resulting from the evaporation of unconta ined crude oil and the venting of produced gas directly to the atmosphere.



### COST AND COST-EFFECTIVENESS

PAR 222 will require that all facilities in the PR 1148.1 program be required to complete a filing process with the AQMD. Oil and gas produc tion facilities range in size from 1 to over 300 oil wells per facility. An initial filing fee of $112.66 and an annual fee of $112.66, respectively will be charged to each group of four wellheads/well cellar. Staff has determined that this proposal provides fee equi ty for the smaller facilities as well as the larger facilities and will provide revenue suff icient to fund the inspector position equivalent to implement the inspection requirement of PR 1148.1. All of the AQMD fees stated are based on Rule 301 for fiscal year 2003-0 4.

The specific initial filing fee and the annual rene wal fee are not part of the proposed amendment to Rule 222. The specific fee proposal w ill be part of the staff proposal to amend Regulation III – Fees that will be presented to the Governing Board in May 2004.

The proposed amendments to Rule 222 will not have a n effect on the emission levels normally associated with the equipment specified in this amendment. As a result,

traditional cost-effectiveness for this amendment c annot be calculated.Final Staff Report

PR 1148.1/PAR 222 56 February 24, 2004 The increased cost to industry resulting from the i nitial filing and the annual fees associated with the implementation of PR 1148.1 and amendment to Rule 222 are as

follows:

Facility Filing Fee Each group of four well pumps/well cellars (approxi mately 3,588 well cellars) identified in the program will be required to pay an initial f iling fee of $112.68)

Filing Fee Cost = 3,588 x $112.68 = $ 101,074

4

Annual Facility Filing Fee = 3,588 x $112.66 = $ 101,074/year

4



### DRAFT FINDINGS

Before adopting, amending, or repealing a rule, the California Health and Safety Code requires AQMD to adopt written findings of necessit y, authority, clarity, consistency, non-duplication, and reference, as defined in Healt h and Safety Code Section 40727. The draft findings are as follows:

Necessity - The AQMD Governing Board has determined that a n eed exists to amend Rule 222 - Filing Requirements for Specific E mission Sources Not Requiring a Written Permit Pursuant to Regulation II and to add approximately 3,600 oil producing

wells to improve inventory information and facilitate compli ance efforts .

Authority - The AQMD Governing Board obtains its authority t o adopt, amend, or repeal rules and regulations from Health and Safety Code Sections 40000, 40001, 40440, 40702, 42300 et seq.

Clarity - The AQMD Governing Board has determined that PAR 222 - Filing Requirements for Specific Emission Sources Not Requ iring a Written Permit Pursuant to Regulation II, are written and displayed so that th e meaning can be easily understood by persons directly affected by them.

Consistency - The AQMD Governing Board has determined that PAR 222 - Filing Requirements for Specific Emission Sources Not Requ iring A Written Permit Pursuant to Regulation II, are in harmony with, and not in conf lict with, or contradictory to, existing statutes, court decisions, federal or state regulat ions.

Non-Duplication - The AQMD Governing Board has determined that the proposed amendments to PAR 222 - Filing Requirements for Spe cific Emission Sources Not Requiring a Written Permit Pursuant to Regulation I I, do not impose the same requirement as any existing state or federal regula tion, and the proposed amended rules are necessary and proper to execute the powers and duties granted to, and imposed upon the AQMD.Final Staff Report

PR 1148.1/PAR 222 57 February 24, 2004 Reference - In adopting these regulations, the AQMD Governin g Board references the following statutes which AQMD hereby implements, in terprets or makes specific: Health and Safety Code Sections 40001 (rules to achieve am bient air quality standards), 40506 (rules regarding the issuance of permits), 40701 (r ules regarding district’s authority to collect information), 40725 through 40728, 42300 et seq. (authority for permit system), and 42320 (rules implementing the Air Pollution Per mit Streamlining Act of 1992).