Natural gas transmission companies are very unhappy with the EPA’s decision to tighten industry air emission limits. A consent decree signed by the EPA requires the agency to revise both New Source Performance Standards (NSPS) and national emission standards for hazardous air pollutants (NESHAP) for the natural gas industry, including for pipelines, by the end of February. Those are two separate EPA regulatory programs.
The upcoming February NSPS rule will regulate transmission pipelines for the first time and require emission reductions from pneumatic controllers, centrifugal and reciprocating compressors. The transmission NESHAP, established in 1999, would be revised to include “small” glycol gas dehydrators. Both regulatory programs seek to reduce emissions of volatile organic chemicals (VOC) from numerous pipeline sources.
Lisa Beal, vice president, Environment and Construction Policy, Interstate Natural Gas Association of America (INGAA), says VOC emissions from pipelines are insignificant. She calls the EPA decision to subject transmission pipelines to NSPS standards “questionable and not adequately supported.” She adds, “It appears that the proposed NSPS is a thinly veiled attempt to regulate transmission and storage greenhouse gas emissions.”
She argues that the EPA should not classify a pneumatic controller, which is a trivial VOC source and an equipment sub-component, as a “facility” under the NSPS. The NSPS would also require pipelines to equip centrifugal compressors with dry seal systems. But the EPA may allow a compliance option of wet seals combined with routing of emissions from the seal liquid through a closed vent system to a control device. Beal says only new centrifugal compressors should be regulated, and that wet seals should be allowed if the operator can demonstrate that VOC emissions are similar to dry seal missions.
There would be standards for reciprocating compressors, too. They would require replacement of the rod packing after 26,000 hours of operation are reached. With regard to reciprocating compressor rod packing requirements, Beal states those should be based on 35,000 operating hours and include an option to use condition-based maintenance to extend the operation of functional rod packing.
INGAA isn’t the only critic of EPA’s intended actions. State regulators will have to issue many more permits to gas transmission facilities as a result of the regulatory expansion. “From a regulatory perspective, these rules will significantly increase the permitting and enforcement workload for TCEQ as the delegated administrator,” says Mark Vickery, executive director, Texas Commission on Environmental Quality.
Again, though they address some of the same pollutants, the NSPS and NESHAP programs use different thresholds to determine equipment subject to VOC limits. The NSPS program uses a performance standard which reflects the degree of emission limitation achievable through the application of the “best system of emission reduction” (BSER) which the EPA determines has been adequately demonstrated.
NESHAPs apply only to “major sources” defined as facilities that emit or have the potential to emit 10 tons per year (tpy) or more of a single HAP or 25 tpy or more of any combination of HAP. NESHAPs are based on a maximum achievable control technology (MACT). That floor is the average level of HAP emission control achieved by the top 12 percent of that industry group’s currently operating sources.
The EPA is required to finalize NSPS and NESHAP standards for gas transmission pipeline by Feb. 28 because of the terms of a consent decree the agency signed as the result of a lawsuit filed by two environmental groups, the WildEarth Guardians and the San Juan Citizens Alliance.
EPA makes changes to pipeline GHG reporting rule
The EPA also made some decisions about another pipeline emissions rule at the end of December. This is the rule that requires pipelines to report their greenhouse gas (GHG) emissions from 2011 to the EPA. There is no limit on those emissions, at least not yet; there is just a reporting requirement for emissions of CO2, CH4 and N2O.
On Dec. 23, 2011, the agency announced its final changes to subpart W — that is the section of the overall GHG reporting rule which applies to petroleum and natural gas industry emissions. The agency made some definitional changes, which, depending on a company’s operations, could be significant — or not. For example, the definition of what a transmission pipeline is was narrowed to mean a Federal Energy Regulatory Commission (FERC) rate-regulated interstate pipeline, a state rate-regulated intrastate pipeline or a pipeline that falls under the “Hinshaw Exemption” as referenced in the Natural Gas Act.
The agency made it clear that it includes within the onshore natural transmission compression facility segment not only those facilities that move natural gas from production fields or gas processing plants, but also those that move gas coming from other transmission compressors. In addition, the agency stated explicitly that gas transmission compression facilities not only move gas into distribution pipelines, but also into liquefied natural gas storage or into underground storage.
PHMSA proposed safety changes raise questions
All the attention paid to passage of the new congressional pipeline safety bill obscured the smaller bore, yet in some instances controversial, regulatory changes PHMSA wants to make on its own. The proposed changes PHMSA announced at the end of November affect such things as the performance of post-construction inspections; leak surveys of Type B onshore gas gathering lines; the requirements for qualifying plastic pipe joiners; and the transportation of pipe.
The proposals are relatively minor in that they do not impose new recordkeeping or operational requirements, except in a couple of instances. But the proposals have already produced some controversy.
One proposal would prohibit anyone who participated in the construction of a gas distribution, transmission of hazardous liquid pipeline from inspecting the pipeline. Here, the PHMSA is responding to a request from the National Association of Pipeline Safety Representatives (NAPSR) to inject a greater amount of “independence” into the inspection requirement. But NAPSR asked for the prohibition to extend to any contractor, not “anyone who participated in the construction of the pipeline.”
John W. Roberts, president, professional engineers in California government (PECG), says his group is greatly concerned that this language leaves the regulation open for interpretation that the same contractor can inspect the work as long as it’s not inspected by an employee who participated in the construction. “PECG believes PHMSA should incorporate stronger regulatory language that prohibits contractors from inspecting the work of other contractors, and instead requires a public inspector to be responsible for the construction inspection of natural gas transmission pipelines,” he says. That is necessary, he adds, based on the “tragic events of San Bruno in 2010 which show that it’s absolutely critical that federal and state agencies step up their involvement in the physical inspection of the state’s natural gas pipeline network.”
The American Gas Association is also unhappy that PHMSA did not include one particular change to its regulations in the overall proposed rule it issued on Nov. 29, 2011. The AGA has been pressing the PHMSA for a few years to adopt a new version of ASTM International (ASTM) D2513 Polyethylene (PE) Gas Pressure Pipe, Tubing and Fittings (ASTM D2513-09A). This updated standard has numerous technical improvements over the 1999 version. But the PHMSA did not propose updating that piping standard.