Greenhouse Gas Reporting Rules and Increasing Energy Efficiency

A little more than one year ago, I highlighted how the U.S. Environmental Protection Agency (EPA) Greenhouse Gas (GHG) Reporting Rules were beginning to impact U.S. process manufacturers. The post, EPA Greenhouse Gas Reporting Rules and Flow Measurement shared ways measurement devices could assist in this reporting.

I caught up with Emerson’s Patrick Truesdale who recently presented, De-mystifying GHG Monitoring and Reporting – Achieve Benefits from Compliance, at a Cleveland ISA meeting, along with members from the Rosemount Analytical brand team.

In the presentation, Patrick highlighted elements of the Greenhouse Gas Mandatory Reporting Rule (GHG MRR) and how process manufacturers could use information from the monitoring to improve energy efficiency.

For those not all ready familiar with the reporting rules, they are based on the notion of carbon dioxide equivalents (CO2e) and global warming potentials (GWP). The gases that need to be monitored and their respective GWPs include:

  • CO2 = 1
  • CH4 = 21
  • N2O = 310
  • HFC23 = 11,700
  • PFC14 = 6,500
  • SF6 = 23,900

Patrick explained that 25,000 metric tons of CO2e emitted per year triggers the reporting requirements for some manufacturers and producers. Effective January 1 of this year, an estimated 3000+ oil and gas facilities whose emissions exceed the 25K threshold were included in these reporting requirements. These facilities cover many oil and gas related segments including onshore and offshore petroleum and natural gas production, onshore natural gas processing plants, onshore natural gas transmission compression, underground natural gas storage, liquefied natural gas storage, liquefied natural gas import and export equipment, and natural gas distribution. The reporting requirements cover CO2, CH4, and N2O and include process, combustion, and fugitive-related direct and upstream emissions.

These reporting rules include emissions from a wide range of process equipment such as pneumatic devices, wellheads, pipelines, storage tanks, compressors, flare stacks, and processing equipment involved in oil separation and gas dehydration. A full list of what’s included is at Subpart W-Petroleum and Natural Gas Systems on the EPA website.

For all of the additional work required to meet these reporting rules, there can be some upside. The additional monitoring equipment can assist with mass and energy balances and help to establish key performance indicators (KPIs) for ongoing continuous improvement. Also, through the additional sensors, control loops variability can be reduced and leaks can be spotted and repaired sooner. Patrick cited several examples such as loss reduction through increased mass balance accuracy, increased combustion efficiency reducing fuel consumption, and increased distillation purity by using the additional process sensor inputs to improve the control strategies running these processes.

On older facilities with energy inefficient furnaces, heaters, distillation columns, vapor recovery, and water treatment equipment, the data collected from the sensors may provide the justification for equipment replacement or emission recovery systems.

Patrick closed by noting that the key for automation engineers is to look for opportunities to achieve performance benefits while complying. Justifications based on energy efficiency improvements will help lead to compliance and hopefully more than offset the additional expense of these regulatory requirements.

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