Document ID: EPA-HQ-OAR-2010-0505-7578
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2016-06-03T04:00Z

MEMORANDUM   

TO:		Amy Hambrick, EPA/OAQPS/SPPD/FIG

FROM:	David Hendricks, EC/R, Inc.

DATE:	April 22, 2016

SUBJECT:	Summary of the February 11, 2016, Meeting with the Gas Processors Association (GPA) and the U.S. Environmental Protection Agency 
--------------------------------------------------------------------------------

I.	INTRODUCTION

The Gas Processors Association (GPA) requested this meeting with EPA to present an overview of their comments on the September 18, 2015 proposed Oil and Natural Gas Sector NSPS (80 FR 56593).

II.	ATTENDEES

The following is a list of participants in the meeting.

U.S. Environmental Protection Agency
Amy Hambrick (by phone)
Gerri Garwood (by phone)
Charlene Spells (by phone)
Bruce Moore
Jodi Howard
Lisa Thompson
Matthew Witosky
Eric Goehl
Penny Lassiter

GPA and Member Organizations
Matthew Hite, GPA
Melanie Roberts, Targa 
Adrienne Sandoval, Tesoro
Laura Higgins, DCP
Claudio Galli, Enbridge
Jaron Hill, Williams
Karen Lyall, ONEOK
Richard Quinnette, ONEOK
Jeff Stovall, Crestwood Midstream (by phone)
Dave Oldaker, Enterprise Products (by phone)

EC/R Incorporated
David Hendricks (by phone)

III.	SUMMARY OF DISCUSSION

Bruce Moore opened the meeting and explained to the attendees that since the EPA is in the post-proposal phase of the NSPS and CTG, EPA personnel would listen to their comments but cannot respond to any of the issues raised. However, the EPA welcomed the comments. The attendees offered the following comments.

NSPS Proposal
 Electronic Reporting
 Concerned that electronic reporting requirements would be more tedious to submit on a site by site basis rather than allowing multiple sites to be submitted by one submitter.  Preferred the ability to bulk submit.
 Inquired if the required responsible official can be delegated.
            
 Implementation Time
 Requested a phased in implementation time, longer than 60 days, in order to come into compliance with the requirements; especially considering the potential number of compressor stations that may retroactively be subject from proposed rule date. 
 Other concerns over implementation timing included the potential need to purchase equipment, line of vendors, develop procedures for LDAR, create a site monitor plan, and personnel issues including hiring and training.

 Pneumatic Pumps
 Stated that engineering assessments will need to be made.
 Concerned that rule language regarding control implementation now states pumps must be controlled "within 60 days after installation" and requested this be revised to "60 days after startup" because a pneumatic pump may be installed but not be started up right away. Revising language as suggested would help ensure there are no logistical noncompliance issues.
 Other pneumatic pump issues includes the time needed to figure out if it is feasible to route the stream, etc.
 Noted that pneumatic pumps are usually at remote locales, especially the larger ones.
 Stated that many pneumatic pumps are low usage pumps, used only a couple times a year, to transfer engine oil, compressor oil or triethylene glycol.
            
 Definition of Well Site
 Concerned that the definition of well site does not distinguish between the different companies that own assets on the well site. Would like the rule to recognize legal structure of how an ONG structure works: 2 entities, upstream and midstream. Upstream producers and well sites and midstream gathering and boosting, compression. These are separate legally distinct entities.
 Concerned that well site is defined very broadly and in terms of geographic area and should recognize the legal structure and distinction in infrastructure. Wanted to make sure confusion is avoided about where the rule requirements apply and who is responsible for compliance.
 Expressed that these issues come into play because there can be a midstream infrastructure located in geographic proximity to well sites. 
 Most common examples are meters that meter the gas from a well to a gathering and boosting station. Point of custody transfer. Meters are used to establish the basis for payment. Often located in geographic proximity to well sites; sometimes right on wellsite. Well site operators cannot operate or maintain those meters. They are not their property. Noted that it would be a COI for the well site operators to do so. Conversely, the midstream operators have no control over the well site. 
 Requested affected facility definition clarity. Stated they would like to see something similar to Colorado Rule 7, which clarifies that oil production facilities in their definition related to the LDAR program was meant to include all emissions points and any other equip or associated pipe components owned, operated or leased by the producer located at the oil production facility. Do not think geographic proximity was meant to be included in definition.
 Requested clarifying the definition of well site is only to the point of custody transfer to midstream operations. Expressed that "owned and operated by or leased by a producer" is as cleaner way to work out the definition.
            
            
            
 Definition of Modification at a Compressor Station
 Concerned that the language pull in the entire compressor station and would like a simpler definition so they do not have to count components and perform complicated calculations. X+1 definition is their intention. 
 Suggested tweaking the definition for a couple of reasons. If not doing X+1, it will be ambiguous, for example, if you remove one compressor away and put in another without adding an additional compressor, then that would not meet definition of having changed something/increased emissions. Proposed tweaking the definition to state that: if you make a physical change of original equip that increases compression capacity of that station. 
 Regarding compression capacity, noted that there may be a nameplate capacity but changing pressure of gas in the field can change compression capacity, with greater pressure, without changing nameplate design capacity.
            
 Component Counts
 Opposed the requirement to conduct component counts.
 Noted that typically these are unmanned facilities so it is difficult to conduct these at reasonable time and cost.
            
 Definition of Compressor Within the Definition of Modification
 Did not want it to be unclear what kind of compressor is being added, so brought up VRU example. If installing a control device, asked if it would it count as a new device and if entire facility would be affected. 
 Suggested defining compressor to mean; a reciprocal or centrifugal compressor that moves natural gas; does not cover a vapor recovery tank or storage equipment.
            
 Definition of Compressor Station Site
 Suggested more clearly separating out the transmission compressor site and gathering compressor site so that it would specify that the gathering compressor station would be prior to the end of the natural gas ports and define transmission compressor stations separately so there would be no overlap between compressors and plants.
            
 Definition of Fugitive Emissions Component
 Concerned that the definition is overly broad and encompasses equipment never before considered fugitive emissions components (FEC) in previous monitoring programs. 
 Proposed removing a number of listed equipment types such as heaters and dehydration units that are actually small process units, which typically have an FEC on them - all having valves and/or flanges. 
 Requested that blowdown vents be excluded from the requirements because they consider blowdown vents to be only the pipe. Compressors typically must be shut down to be blown down.
 Concerned that the definition states "including but not limited to..." Suggested this could lead to interpretation issues, with no clear certainty of what components to be monitored.  
            
 Pneumatic Pump Standards
 Concerned over the cost estimate that EPA used. Provided alternative cost estimates in the comment letter they submitted to the rule that they think more represent what is found at compressor stations and this increases cost of control. 
 Requested clarification on the definition of "control device" that it does not include things not meant to be controlled, such as catalytic converters or heaters like a glycol reheater that is used sometimes as a control device but sometimes not. Condensers on a glycol unit would technically be a control device.
 Suggested the definition of control device as in OOOOa, clarifying that these devices are already designed to meet the NSPS.
 Requested allowing `like size' replacement of pneumatic pumps, which may be done due to age or wear; may need a replacement pump but with the same size, etc. without triggering rule. 
            
 Monitoring and Testing
 Asserted that the monitoring and testing requirements in the proposed rule do not include associated costs. 
 If a control device is not an NSPS OOOO control device, it might not have the monitoring or construction efficiencies needed in the proposed rule.
            
 Requested an exemption option where it is not feasible to route to a control device or to do so would not meet the required destruction efficiency or would create safety issues associated with routing to control device.

 Requested an exemption for low use pumps, similar to that in subpart VVa for compressors in VOC service less 300 hr/yr. Design is meant to be used less than 300 hr/yr.

 Expressed a time-related concern that once it is determined that a facility is an affected facility requiring control, there will be a yet indeterminate amount of time necessary to get that control in place. 

 Stated that the 60 day timeframe is challenging for replacement of a failed part vs thinking ahead for a pump or compressor installation. 

 Noted concerns regarding the proximity of equipment located at well sites. With subpart OOOO storage tanks and vapor combustors (VC), for example, they install VCs as far away as possible. If those distant skids (can be 100 ft apart) now must be routed, they would have laid sites out differently.

 Commented on the removal of a control device when no longer necessary for other equipment. Asked if the control device is no longer needed for control of a storage vessel, is it still required for the pneumatic pump. Noted that it would no longer be cost effective to operate the control device on the storage vessel, so would like to be able to shut the control device down. The rule currently provides no off-ramp for this. 

 Third Party Verification and Review
 Concerned that they did not have the opportunity to comment on this regarding such issues as implementation, mechanisms to be used and cost effectiveness.
 Expressed that they see it being EPA's job to enforce the rules that are there, not for GPA, for example, to pay a 3rd party to do so. 
 Questioned use of 3d party review. They think should probably not be used. Stated it would be problematic to get those systems evaluated by a 3rd party; added it may be insufficient capacity of such reviewers and certified staff.
            
 Stated that public disclosure of compliance data would cause more confusion than clarity. 

 Flares
 Flares used to control OOOO equipment should not be subject to section 60.18 because facilities are typically remote and during emergency or upset might need to blow steam to meet the requirements of 60.18, especial compressor stations with flares not historically required to meet 60.18. 
 Final OOOO clarified that it did not apply to flares but there is still a question concerning performance testing (PT) because the PT section states that only flares that met 60.18 were exempt from PT requirements; stated this creates confusion. 
 Requested that flares not be required to meet 60.18 during an upset and clarify in the PT section to state that flares designed and operated in accordance with 60.18 during normal operations would be exempt from PT.
 Expressed that in the requirements for control devices in the tanks section, there is no language related to flares. Requested that flares be included back in that section stating explicitly that flares can be used to control tanks.
 Requested revising rule to state that a flare is allowed as a control device at storage vessels - section 5412 should allow flares.
 Requested that the exemption for PT should apply to flares designed and operated in accordance with 60.18 during normal operations - all flares not only sonic.
 Requested that, regarding Table 3, 60.18 should apply during normal operations.
 Noted that sonic flares are typically used to control high flow situations, outside of norm operations. These flares cannot meet requirements during high flow scenarios. 
 Requested that during an emergency, flares not be required meet 60.18. Noted that, at that time, the flares are not behaving as control devices but as safety devices.
            
 Stated there was an inconsistency between the equation used by EPA and NSPS subpart KKK for control devices. Disputed EPA's equation and concerned that on issue will be that older equipment will be more easily subject to more stringent regulations using the EPA equation.  Plants could trigger cap expenditure and be subject to the rule due to one small change, such as changing a small valve. Proposed a CPI-based equation based on a ratio. Provided detailed explanation, beginning on page 42, of the comments they submitted for the proposed rule. 

 LDAR Issues
 Took issue with the site-specific walking plan requirement because of the hundreds of compressor stations. Creating such plans is time and data intensive without increasing the likelihood of OGI monitoring finding every source. Stated it is overly onerous when factoring in the number of sites and the limited potential for emission reductions. 
 Concerned that if a contractor does not follow the walking path precisely, they will be out of compliance.
 Requested an extension to 180 days for the initial survey site after the compressor station goes live; due to geographic remoteness, availability of contractors, etc. and potential for several sites coming under regulations at the same time. Will need more time to schedule contractors, develop plan, ramp up. 
 Requested an increase over the 15 days to find and complete a repair due to the remoteness of many locations, they may not be able get there. Many facilities are visited perhaps once a week or so by operators, but maintenance personnel visit site only when needed. Repair staff may visit site, find a problem but not be able to get back to conduct required repair as quickly as suggested in 15 days. Added that while some repair work is conducted by in-house staff, some is contracted out.
 Commented on the use of percent leakers  -  varied timeline based on percent leakers. Preferred a set timeline with no percent leaker determination. Stated the percentage based would create excessive work; additionally do not have enough data for compressor station LDAR to know what the average leak rate is.