E

C

/R Incorporated Providing Environmental Technical Support Since 1989

6330 Quadrangle Drive, Suite 325  Chapel Hill, North Carolina 27517

Telephone: (919)484-0222  Fax: (919) 484-0122

MEMORANDUM

DATE: July 28, 2011

SUBJECT: Natural Gas Production NSPS – Technology Reviews

FROM: Bradley Nelson, EC/R Incorporated

TO: Bruce Moore, EPA/OAQPS/SPPD/CCG

The purpose of this memorandum is to present the results of a review to identify any 

developments in practices, processes, and control technologies for pollutant emission sources for 

the Oil and Natural Gas Production New Source Performance Standards (NSPS). This analysis 

is part of EPA’s review efforts in accordance with section 111(b)(1)(B) of the Clean Air Act. 

Section 1 provides background information on section 111(b)(1)(B), the source 

categories, and the requirements of the NSPS that address emissions from these categories. 

Section 2 discusses the exploration of developments in practices, processes, and control 

technologies that have occurred since the original development of these NSPS, and Section 3 

provides the conclusions of this investigation.

1.0 BACKGROUND

1.1 Section 111(b)(1)(B)

Section 111 of the Clean Air Act requires EPA to establish standards of performance for 

emissions of air pollutants which reflects the degree of emission limitation achievable through 

the application of the best system of emission reduction which (taking into account the cost of 

achieving such reduction and any nonair quality health and environmental impact and energy 

requirements) the Administrator determines has been adequately demonstrated. These standards 

are often referred to as new source performance standards, or NSPS standards. Section 111 also 

contains provisions requiring EPA to revisit these standards. Specifically, paragraph 

112(b)(1)(B) section states:

(B) ... The Administrator shall, at least every 8 years, review and, if 

appropriate, revise such standards following the procedure required by 

this subsection for promulgation of such standards. Notwithstanding 

the requirements of the previous sentence, the Administrator need not 

review any such standard if the Administrator determines that such 

review is not appropriate in light of readily available information on 

the efficacy of such standard...
2

1.2 Description of Source Categories and NSPS Standards

There are two NSPS that currently impact the oil and natural gas production sector. The 

Standards of Performance for Equipment Leaks of VOC from Onshore Natural Gas Processing 

Plants (40 CFR 60, subpart KKK) addresses volatile organic compound (VOC) emissions from 

leaking equipment at onshore natural gas processing plants. The Standards of Performance for 

Onshore Natural Gas Processing: SO2 Emissions (40 CFR 60, subpart LLL) addresses sulfur 

dioxide (SO2) emissions from natural gas processing plants. 

The natural gas processing segment of the oil and natural gas sector includes the 

processing of raw natural gas to produce “pipeline quality” dry natural gas. Natural gas is

primarily made up of methane, but often contains water vapor, hydrogen sulfide (H2S), carbon 

dioxide (CO2), helium, nitrogen and other compounds. While some of the processing can be

accomplished in the production segment, most of the complete processing of natural gas takes 

place in the natural gas processing segment. Natural gas processing operations separate and 

recover natural gas liquids (NGL) or other non-methane gases and liquids from a stream of 

produced natural gas through components performing one or more of the following processes: oil 

and condensate separation, water removal, separation of NGL, sulfur and CO2 removal, 

fractionation of natural gas liquid and other processes, such as the capture of CO2 separated from 

natural gas streams for delivery outside the facility. Natural gas processing plants are the only 

operations covered by the existing NSPS.

Equipment Leaks from Onshore Natural Gas Processing Plants

Equipment leaks are emissions from valves, pump seals, flanges, compressor seals, 

pressure relief valves, open-ended lines, and other process and operation components. The 

amount of pollutant emissions from equipment leaks is dependent on the type and number of 

equipment components and the leak rate of those components. Components such as pumps, 

valves, pressure relief valves, flanges, agitators, and compressors are potential sources that can 

leak due to seal failure. Other sources, such as open-ended lines, and sampling connections may 

leak for reasons other than faulty seals. In addition, corrosion of welded connections, flanges, 

and valves may also be a cause of equipment leak emissions. 

Subpart KKK requires the natural gas processing facility to monitor components using a 

leak detection and repair (LDAR) program as described in 40 CFR part 61, subpart VV. For 

most components, this requires monthly inspection of the components using a volatile organic 

compound (VOC) detection instrument. If a leak greater than 10,000 parts per million is 

detected, then the facility is required to repair that leak in 15 days.

SO2 Emissions from Onshore Natural Gas Processing

Raw natural gas often contains water vapor, H2S, CO2, helium, nitrogen and other 

compounds. When the natural gas contains H2S and CO2, it is referred to as “sour gas” and 

removal of the components is required to produce “pipeline quality” dry natural gas. If the gas is 

sour, then H2S and CO2 need to be removed in an acid gas removal process called “sweetening”. 

The sweetening process separates the acid gases (H2S and CO2) from the field gas. The acid gas 

is then further processed for elemental sulfur recovery. The most common sulfur recovery unit is 

the Claus process, which uses a series of catalytic stages to recover approximately 97 percent of 
3

the sulfur. Subpart LLL provides specific standards for additional SO2 emission reduction 

efficiency, on the basis of sulfur feed rate and the sulfur content of the natural gas. The

regulation applies to facilities that have a design capacity equal to or greater than 2 long tons per 

day of H2S. The minimum SO2 percent reduction efficiency ranges from 74 percent (acid gas 

streams with a less than 10 percent H2S content and a sulfur feed rate greater than or equal to 2 

long tons per day) to 99.8 percent (acid gas streams with a H2S content of greater than or equal to 

50 percent and a sulfur feed rate greater than 300 long tons per day).

2.0 PRACTICES, PROCESSES, AND CONTROL TECHNOLOGIES

For the purpose of this exercise, EPA considered a “development” in the natural gas 

processing segment to be:

 Any add-on control technology or other equipment (e.g., floating roofs for storage tanks) 

that was not identified and considered during NSPS development, 

 Any improvements in add-on control technology or other equipment (that was identified 

and considered during NSPS development) that could result in significant additional 

emission reduction,

 Any work practice or operational procedure that was not identified and considered during 

NSPS development, and

 Any process change or pollution prevention alternative that could be broadly applied that 

was not identified and considered during NSPS development.

Table 1 summarizes the practices, processes, and control technologies considered during 

the development of the NSPS standards for these categories. This is followed by descriptions of 

the searches for developments since that time. The specific information sources that were 

consulted in this effort included EPA’s RACT/BACT/LAER clearinghouse (section 2.1), current 

EPA LDAR programs (Section 2.2), and direct correspondence with the industry (section 2.3).

Table 1. Summary of Practices, Processes, and Control Technologies Identified and 

Considered for the Natural Gas Processing NSPS Development

Source Category/

Emission Source Practices, Processes, and Control Technologies

Natural Gas Processing

Equipment Leaks Leak detection and repair programs, specific equipment modifications

Sulfur Recovery Unit 2-Stage Claus, 3-Stage Claus, Cold Bed Adsorption, Tail Gas Treatment
4

2.1 RACT/BACT/LAER Clearinghouse

Under EPA's New Source Review (NSR) program, if a company is planning to build a 

new plant or modify an existing plant such that air pollution emissions will increase by a large 

amount, then the company must obtain an NSR permit. The NSR permit is a construction permit 

which requires the company to minimize air pollution emissions by changing the process to 

prevent air pollution and/or installing air pollution control equipment. In obtaining an NSR 

permit, a source will be required to install one of the following:

 Reasonably Available Control Technology (RACT), is required on existing 

sources in areas that are not meeting national ambient air quality standards (i.e., 

non-attainment areas). RACT is a control technology that is reasonably available, 

and both technologically and economically feasible. 

 Best Available Control Technology (BACT), is required on major new or 

modified sources in attainment areas and is an emissions limitation that represents 

the maximum degree of control that a source can achieve. BACT can be add-on 

control equipment or process modification.

 Lowest Achievable Emission Rate (LAER), is required on major new or modified 

sources in non-attainment areas and represents the most stringent emission 

limitation contained in any State implementation plant (SIP) or the most stringent 

emission limitation achieved in practice by a source.

BACT and LAER (and sometimes RACT) are determined on a case-by-case basis, 

usually by State or local permitting agencies. EPA established the RACT/BACT/LAER 

Clearinghouse, or RBLC, to provide a central data base of air pollution technology information 

(including past BACT and LAER decisions contained in NSR permits) to promote the sharing of 

information among permitting agencies and to aid in future case-by-case determinations.

These practices, processes, and control technologies are all examples of the types of 

emission reduction techniques that were considered in the development of NSPS for equipment 

leaks and SO2 emissions at natural gas processing plants. The RBLC search identified two 

entries with SO2 emission reductions of 99.9 percent, but neither provided information on the 

H2S content of the feed stream. 
5

Table 2. Summary of the RBLC Processes, Practices, and Control Technologies for 

SO2 Control and Equipment Leaks at Natural Gas Processing Facilities

Control Method

Identified in RBLC

Considered under 

NSPS? (Y/N) Comments

SO2 Control

Thermal/Catalytic

Oxidizer

Y

2-Stage Claus Y

3-Stage Claus Y

Recycle Selectox Y

Tail Gas Cleanup Y

Equipment Leaks

Leak Detection and 

Repair

Y The current NSPS requires a 40 CFR part 60, 

subpart VV LDAR program. A 40 CFR part 60, 

subpart VVa LDAR program and alternative 

work practices were also reviewed.

Low Emission Design 

Equipment

N This technology has not yet been proven to be 

effective for reducing emissions.

2.2 Current EPA LDAR Programs

The current NSPS for equipment leaks for natural gas processing facilities requires 

compliance with specific provisions of 40 CFR part 60, subpart VV. This subpart VV-level 

LDAR program requires monthly monitoring of valves and a leak definition of 10,000 ppm. 

Since the promulgation of the 40 CFR part 60, subpart KKK requirements, EPA has developed a

more stringent LDAR program (40 CFR part 60, subpart VVa) that lowers the leak definition to 

500 ppm and includes the annual monitoring of connectors. There have also been advancements 

in optical gas imaging and ultrasound LDAR monitoring. These instruments measure the 

magnitude of the leak, but are unable to measure the concentration of the leak. The general 

control device and work practice requirements in 40 CFR part 60, subpart A allow for the use of 

these instruments as an alternative to the Method 21 monitoring. 

2.3 Natural Gas STAR

New practices, processes, and control technologies were reviewed from the Natural Gas 

STAR program. The Natural Gas STAR Program is a flexible, voluntary partnership that 

encourages oil and natural gas companies to adopt cost-effective technologies and practices that 

improve operational efficiency and reduce pollutant emissions. The program provides the oil 

and gas industry with information on new techniques and developments to reduce pollutant 

emissions from the various processes.
6

Equipment Leaks

 Ultrasound Leak Detection1- Ultrasound leak detectors are used to reveal high frequency 

sounds associated with gas leakage. The ultrasound detector indicates whether the valve 

is tightly shut and the magnitude of leakage.

 Directed Inspection and Maintenance2- A directed inspection and maintenance program 

begins with a baseline survey to identify and quantify leaks. Repairs are then made to 

only the leaking components that are cost-effective to fix, based on criteria such as repair 

cost, expected life of the repair, and payback period. Subsequent surveys are designed 

based on data from previous surveys, allowing operators to concentrate on the 

components that are most likely to leak and are profitable to repair.

 Compressor Rod Packing Systems3– Increased frequency of reciprocating engine 

compressor rod packing replacement can reduce methane, VOC, and HAP emissions 

from compressors.

 Replacement of Wet Seals with Dry Seals4– Replacement of wet seals with dry seals 

reduces operating costs and methane, VOC, and HAP emissions from centrifugal 

compressors.

The ultrasonic leak detection provides the magnitude of the leak, but does not quantify 

the leak. This option is allowed as an alternative work practice under 40 CFR part 60, subpart A. 

The directed inspection and maintenance program was not considered because it is based on the 

criteria of cost of repair versus emission reductions. The compressor rod packing and dry seal 

replacement options reduce leaking emissions from compressors. These options were considered 

as effective options for reducing VOC emissions. It was determined that compressor emissions 

should be addressed separately in the NSPS, because the current LDAR regulations do not 

address the replacement of rod packing for reciprocal engines or dry seals for centrifugal 

compressors directly. Therefore, these options will be included in the compressor portion of the 

new NSPS.

Sulfur Recovery Units

The Natural Gas STAR program did not provide any new or emerging technologies for 

sulfur recovery. 

 

1 EPA (2004). Partner Reported Opportunities: Use Ultrasound to Identify Leaks. Natural Gas STAR.

2

EPA (2006). Lessons Learned: Directed Inspection and Maintenance at Gas Processing Plants and Booster

Stations. Natural Gas STAR. 

3 EPA (2006). Lessons Learned: Reducing Methane Emissions from Compressor Rod Packing Systems. Natural Gas 

STAR.

4 EPA (2006). Lessons Learned: Replacing Wet Seals with Dry Seals in Centrifugal Compressors. Natural Gas 

STAR.
7

3.0 CONCLUSIONS

In order to identify developments in practices, processes, or control technologies that 

could be used to further reduce emissions from Natural Gas Processing, the following sources of 

information were searched: EPA’s RACT/BACT/LAER clearinghouse, and Natural Gas STAR.

For sulfur recovery, the RBLC results identified two facilities that achieved 99.9 percent 

control efficiency of sulfur using a Claus sulfur recovery unit with a tail gas treating unit. Based 

on this information, the original NSPS data was reevaluated and it was discovered that a 

99.9 percent SO2 reduction technology was cost effective for facilities with a sulfur feed rate of 

5 long tons per day and a H2S content equal to or greater than 50 percent. Therefore, this option 

was not considered a development in practices, processes or control technologies as it was 

considered in the development of the existing NSPS. 

For equipment leaks, the RBLC and Natural Gas STAR programs did not provide any 

additional practices or technologies for reducing HAP from equipment leaks. The only new 

developments for equipment leaks were found in EPA’s current LDAR programs. In addition to 

the current requirements in 40 CFR part 60, subpart VV, EPA has promulgated more stringent 

LDAR programs that include: 40 CFR part 60, subpart VVa and alternative work practices 

under 40 CFR part 60, subpart A. The subpart VVa-level program has a leak definition of 500 

ppm and includes the annual monitoring of connectors. The general control device and work 

practice requirements in 40 CFR part 60, subpart A allow for the monthly monitoring of 

components using an optical gas imaging and ultrasound equipment with an annual Method 21–

based LDAR check. Each of these options was evaluated for the new NSPS. The compressor 

packing and seal replacement are effective options for reducing VOC and methane emissions 

from reciprocating and centrifugal compressors. Therefore, reciprocating and centrifugal 

compressors were evaluated separately for the new NSPS for all of the oil and gas segments.
ATTACHMENT 1

INFORMATION FROM THE RACT/BACT/LAER CLEARINGHOUSE
RBLC Information for Equipment Leaks

RBLCID FACILITY_NAME SIC_CODE NAICS_CODE PROCESS_NAME PROCCESS_TYPE PROCESS_NOTES POLLUTANT CONTROL_METHOD_CODE CONTROL_METHOD_DESCRIPTION EMISSION_LIMIT_1 EMISSION_LIMIT_1_UNIT PERCENT_EFFICIENCY

CA-1145

BREITBURN ENERGY - NEWLOVE LEASE, 

ORCUTT HILL FIELD 1311 212299 OIL AND GAS: FUGITIVE COMPONENTS 13.39

EQUIP: LOW-EMISSION DESIGN VALVES, 

CONNECTIONS AND SEALS (SEE BELOW), MFR: 

VARIOUS, TYPE: VALVES, FLANGES, PUMP SEALS, 

COMPRESSOR SEALS, ETC, MODEL: VARIOUS, FUNC 

EQUIP: PIPING COMPONENTS IN OILFIELD 

OPERATIONS, FUEL_TYPE: , SCHEDULE: CONTINUOUS, 

H/D: 24, D/W: 7, W/Y: 365, NOTES: VALVES: 

BELLOWS, DIAPHRAGM SEAL, SPRING-LOADED 

PACKING, EXPANDABLE PACKING, GRAPHITE 

PACKING, PTE-COATED PACKING, PRECISION 

MACHINED STEM, SEALANT INJECTION AND LDAR: 

100 PPMV THC. FLANGES/CONNECTORS/OTHER: 

WELDED, NEW GASKET RATED TO 150% OF PROCESS 

PRESSURE AT PROCESS TEMPERATURE. LDAR: 100 

PPMV THC COMPRESSOR SEALS (ROTARY DRIVE): 

VENTED TO VAPOR RECOVERY OR CLOSED VENT, 

DUAL/TANDEM MECHANICAL SEALS, LEAKLESS 

DESIGN (E.G. MAGNETIC DRIVE). LDAR: 100 PPMV 

THC COMPRESSOR SEALS (RECIPROCATING DRIVE): 

VENTED TO VAPOR RECOVERY, ELASTOMER 

BELLOWS, O-RING SEALS, DRY RUNNING SECONDARY 

CONTAINMENT SEALS. LDAR: 100 PPMV THC PUMP 

SEALS: VENTED TO VAPOR RECOVERY OR CLOSED 

VENT, DUAL/TANDEM MECHANICAL SEALS. LDAR: 

500 PPMV THC PRDS: VENTED TO VAPOR RECOVERY 

OR CLOSED VENT, SOFT-SEAT DESIGN. LDAR: 100 

PPMV THC SOURCE TEST RESULTS: VOC A

LOW EMISSIONS DESIGN AND LOWER LDAR 

THRESHOLD (SEE BELOW) 100 PPMV 0

IL-0073 EXXONMOBIL OIL CORPORATION 2911 324110 FUGITIVES 50.007 VOC N 3.76 T/YR 0

LA-0228 BATON ROUGE JUNCTION FACILITY 4613 486910 FUG002 FUGITIVE EMISSIONS 42.004 VOC P

CONDUCT A LEAK DETECTION AND REPAIR 

PROGRAM AS SPECIFIED BY 40 CFR 63 

SUBPART R 7.44 T/YR 0

TX-0364 SALT CREEK GAS PLANT 1321 211112 FUGITIVES, NGLFUG 50.007 VOC N NONE INDICATED 9.08 LB/H 0

TX-0364 SALT CREEK GAS PLANT 1321 211112 FUGITIVES, CO2FUG 50.007 VOC N NONE INDICATED 9.33 LB/H 0

TX-0440 CORPUS CHRISTI LNG 4922 221210 FUGITIVES (4) 50.007 VOC N 1.96 LB/H 0

TX-0454

EL PASO NATURAL GAS CORNUDAS 

COMPRESSOR STATION 4922 486210 FUGITIVES (4) 64.002 VOC N 0.13 LB/H 0

TX-0457

CITY PUBLIC SERVICE LEON CREEK 

PLANT 351 333311 PLANT FUGITIVES (4) 64.002 VOC N 0.07 LB/H 0

TX-0465 SALT CREEK GAS PLANT 1321 221210 FUGITIVES (4) 64.002 VOC N 9.08 LB/H 0

TX-0465 SALT CREEK GAS PLANT 1321 221210 FUGITIVES 64.002 VOC N 9.33 LB/H 0

TX-0492

VIRTEX PETROLEUM COMPANY 

DOERING RANCH GAS PLANT 2911 324110 FUGITIVES (4) 50.007

TOTAL UNCONTROLLED FUGITIVE EMISSIONS ARE 

LESS THAN 10 TPY, SO NO MONITORING IS 

REQUIRED. THE COMPANY WILL IMPLEMENT DAILY 

WALKTHROUGHS TO INSPECT THE PIPING. THERE 

ARE ALSO H2S MONITORS ON SITE TO CAPTURE ANY 

H2S LEAKS. VOC N 0.88 LB/H 0
RBLC Information for Sulfur Recovery Units

RBLCID FACILITY_NAME SIC_CODE NAICS_CODE PROCESS_NAME PROCESS_TYPE THROUGHPUT THROUGHPUT_UNIT PROCESS_NOTES POLLUTANT CONTROL_METHOD_CODE CONTROL_METHOD_DESCRIPTION EMISSION_LIMIT_1 EMISSION_LIMIT_1_UNIT PERCENT_EFFICIENCY

AL-0171

MOBIL OIL EXPLORATION & 

PRODUCING SOUTHEAST, INC. 1311 211111 NATURAL GAS SWEETNING, DEHYRATION 50.002 160 MMSCF/D

SULFUR RECOVERY FOLLOWED BY THERMAL 

OXIDIZATION. THROUGHPUT ALSO INCLUDES 280 

TON SULFUR/DAY Sulfur Dioxide (SO2) P SCR AND THERMAL OXIDIZER 511 LB/H 99.9

AL-0174

MOBIL OIL EXPLORATION & 

PRODUCING SOUTHEAST, INC. 1311 211111 NATURAL GAS SWEETENING AND DEHYDRATION 50.002 Sulfur Dioxide (SO2) P SWEET FUEL GAS 0.25 GRAIN/100 SCF 0

AL-0175

MOBIL OIL EXPLORATION & 

PRODUCING SOUTHEAST, INC. 1311 211111 SULFUR RECOVERY UNIT 50.002 Sulfur Dioxide (SO2) A SCR AND THERMAL OXIDIZER 105.5 LB/H 9 0

CA-0413 TEXACO REFINING AND MARKETING 1311 CLAUS SULFUR RECOVERY UNIT 50.006 9 0 LONG TPD Sulfur Dioxide (SO2) A AMINE-BASED TAIL-GAS TREATING UNIT 1 0 PPM H2S INCIN FEED 99.9

CA-0523 MOBIL OIL COMPANY 1311 TEOR OPERATION (WITH SULFUR REMOVAL) 50.006 150000 SCFD Sulfur Dioxide (SO2) A SULFA CHECK SULFUR SCRUBBING SYSTEM FOR H2S 29.1 LB/DAY 9 5

LA-0011.B LOUISIANA OPERATIONS 138 221210 INCINERATOR, TAIL GAS, SULFUR RECOVERY 62.019 1 0 MMBTU/H Sulfur Dioxide (SO2) P GOOD COMBUSTION PRACTICES 524 LB/H 0

LA-0059 CITGO PETROLEUM CORP. 1311 324110 TREATING UNIT, TAILGAS 50.006 1.3 MMDSCF/H Hydrogen Sulfide P SULFTEN PROCESS 1 0 PPMV 0

LA-0059 CITGO PETROLEUM CORP. 1311 324110 TREATING UNIT, TAILGAS 50.006 1.3 MMDSCF/H Sulfur, Total Reduced (TRS) P SULFTEN PROCESS 300 PPMV 0

ND-0010 WESTERN GAS RESOURCES,INC. 1321 211112 AMINE TREATING AND FLARE 50.002 6 MM CUBIC FEET/DAY Sulfur Dioxide (SO2) N 116 LB/HR 0

NM-0018 LIQUID ENERGY CORP. 1321 211112 AMINE UNIT 50.002 2 0 MMSCFD Sulfur Dioxide (SO2) A SCR, COLD BED ADSORPTION 123.3 T/YR 9 8

NM-0020 LIQUID ENERGY CORP. 1321 211112 AMINE UNIT 50.002 4 0 MMSCFD Sulfur Dioxide (SO2) A SRU 4-STATE CLAUS PROCESS 246.5 T/YR 9 8

TX-0501 TEXSTAR GAS PROCESS FACILITY 132 221210 TAIL GAS INCINERATOR STACK 19.9 Sulfur Dioxide (SO2) N 350 LB/H 0

TX-0501 TEXSTAR GAS PROCESS FACILITY 132 221210 TAIL GAS INCINERATOR STACK 19.9 Hydrogen Sulfide N 1 0 LB/H 0

WY-0024

LOUISIANA LAND & EXPLORATION CO.-

LOST CABIN GAS PT 1311 INCINERATOR, TAIL GAS (PHASE II) 50.006 1 7 SCFM

SCOT TAIL GAS INCINERATOR FOLLOWING A 3 STAGE 

CLAUS PLANT. Hydrogen Sulfide P

PRIMARY CONCERN AT FACILITY MINIMIZING SO2 

EMISSIONS. 0.8 LB/H 0

WY-0024

LOUISIANA LAND & EXPLORATION CO.-

LOST CABIN GAS PT 1311 INCINERATOR, TAIL GAS (PHASE II) 50.006 1 7 SCFM

SCOT TAIL GAS INCINERATOR FOLLOWING A 3 STAGE 

CLAUS PLANT. Sulfur Dioxide (SO2) B

3 STAGE CLAUS PLANT FOLLOWED BY SCOT TAIL GAS 

SYSTEM 115 LB/H 99.8

WY-0041

LOUISIANA LAND AND EXPLORATION 

COMPANY-LOST CABIN 1311 211111 INCINERATOR, TAIL GAS, 2 EACH 50.006 19250 SCFH ONE INCINERATOR PER PHASE. Sulfur Dioxide (SO2) A 3 - STAGE CLAUS PLANT AND A SCOT TAIL GAS UNIT 79.8 LB/H 99.8

WY-0041

LOUISIANA LAND AND EXPLORATION 

COMPANY-LOST CABIN 1311 211111 INCINERATOR, TAIL GAS, 2 EACH 50.006 19250 SCFH ONE INCINERATOR PER PHASE. Hydrogen Sulfide N 0.6 LB/H 0

WY-0042

LOUISIANA LAND AND EXPLORATION 

COMPANY-LOST CABIN 1311 211111 INCINERATOR, TAIL GAS 50.006 17000 SCFM

SHELL CLAUS OFFGAS TREATING (SCOT) TAIL GAS 

INCINERATOR FOLLOWING A 3-STAGE CLAUS PLANT. Hydrogen Sulfide A

3-STAGE CLAUS PLANT TO BE FOLLOWED BY SCOT 

TAIL GAS SYSTEM 0.8 LB/H 9 6

WY-0042

LOUISIANA LAND AND EXPLORATION 

COMPANY-LOST CABIN 1311 211111 INCINERATOR, TAIL GAS 50.006 17000 SCFM

SHELL CLAUS OFFGAS TREATING (SCOT) TAIL GAS 

INCINERATOR FOLLOWING A 3-STAGE CLAUS PLANT. Sulfur Dioxide (SO2) A 3 STAGE CLAUS PLANT AND SCOT TAIL GAS SYSTEM 115 LB/H 99.8

WY-0056

LA LAND & EXPLORATION CO. - LOST 

CABIN GAS PLANT 1311 CLAUS/ SCOT SULFUR RECOVERY UNITS, TRAIN 3 50.002

TAIL GAS INCINERATOR BURNS TAIL GAS FROM SHELL 

CLAUS OFF GAS TREATING (SCOT) UNIT. SULFUR 

RECOVERY OF TRAIN III CLAUS/ SCOT UNITS TO BE 

NO LESS THAN 99.8%. CEMS TO BE USED. Hydrogen Sulfide A

TAIL GAS INCINCERATOR TREATS H2S AND OTHER 

SULFUR COMPOUNDS EMITTED BY 

THE CLAUS/SCOT PROCESS AND, AS A RESULT, 

GENERATES CO, NOX AND SO2. ALSO SEE POLLUTANT 

NOTES. 2.2 LB/H 0

WY-0056

LA LAND & EXPLORATION CO. - LOST 

CABIN GAS PLANT 1311 CLAUS/ SCOT SULFUR RECOVERY UNITS, TRAIN 3 50.002

TAIL GAS INCINERATOR BURNS TAIL GAS FROM SHELL 

CLAUS OFF GAS TREATING (SCOT) UNIT. SULFUR 

RECOVERY OF TRAIN III CLAUS/ SCOT UNITS TO BE 

NO LESS THAN 99.8%. CEMS TO BE USED. Sulfur Dioxide (SO2) N SEE POLLUTANT NOTES 312 LB/H 0