# 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 Moor e, 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 emis sions 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 S ection 3 provides the conclusions of this investigatio n.

1.0 BACKGROUND

1.1 Section 11 1 (

b ) (1 ) (B)

Section 111 of the Clean Air Act requires EPA to establish standard s 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 e nvironmental 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

The re are two NSPS that currently impact the o il and n atural g as p roduction sector. T he Standards of Performance for Equipment Leaks of VOC from Onshore Natural Gas Process ing

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: SO 2 Emissions (40 CFR 60, subpart LLL ) addresses sulfur dioxide (SO 2 ) 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 (H 2 S), carbon dioxide (CO 2 ), 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 o ne or more of the following processes: o il and condensate separation, water removal, separation of NGL, sulfur and CO 2 removal,

fractionation of natural gas liquid and other processes, such as the capture of CO 2 separated from natural gas streams for deliv ery 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 comp onents 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.

SO 2 Emissions from Onshore Natural Gas Processing

R aw natural gas often contains water vapor, H 2 S, CO 2 , helium, nitrogen and other

compo unds. When the natural gas contains H 2 S and CO 2 , it is referred to as “sour gas” and

r emoval of the components is required to produce “pipeline quality” dry natural gas. If the gas is sour, then H 2 S and CO 2 need to be removed in an acid gas removal proce ss called “sweetening”.

The sweetening process separates the acid gases ( H 2 S and CO 2 ) 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 of3

the sulfur. Subpart LLL provides specific standards for additional SO 2 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 H 2 S . The minimum SO 2 percent reduction efficiency ranges from 74 percent ( acid gas

streams with a less than 10 percent H 2 S content and a sulfur f eed rate greater than or equal to 2 long tons per day) to 99.8 percent ( acid gas streams with a H 2 S 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 d uring 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 procedur e 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, p rocesses, 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 th is 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

C onsidered for the Natural Gas Pro cessing 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 Treatment4

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 ai r 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/o r 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 am bient 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 decision s 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 technique s that were considered in the development of NSPS for equipment

leaks and SO 2 emissions at natural gas processing plants. The RBLC search identified two

entries with SO 2 emission reductions of 99.9 percent, but neither provided information on the

H 2 S content of the feed stream.5

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

SO 2 Control and Equipment Leaks at Natural Gas Processing Facilities

Control Method Identified in RBLC Considered u nder

NSPS ? (Y/N) Commen ts

SO 2 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 month ly 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 measur e the concentration of the leak. The g eneral 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, process es, 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 o perational 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 Detection 1

- 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 Maintenance 2

- 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 repai r, 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 Systems 3

– Increased frequency of reciprocating engine compressor rod packing replacement can reduce methane, VOC, and HAP emissions from compressors.

 Replacement of Wet Seals with Dry Seals 4

– R eplac ement of wet seals with dry seals

reduces operating costs and methane , VOC, and HAP em issions 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 m aintenance 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

a s 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 w ill 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: D irected I nspection and M aintenance at G as P rocessing P lants and B ooster
S tations. 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 cle aringhouse, 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 or iginal 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 H 2 S content equal to or greater than 50 percent. Therefore, this opti on 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 program s 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 V V, EPA has promulgated more stringent LDAR programs that include: 40 CFR part 60, subpart VV a 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 monitorin g of connectors. The g eneral 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 o f 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