Recent regulatory and legislative developments in the state of California (e.g., Assembly Bill (AB) 1647 and AB 617) will increase the extent of air quality monitoring in communities near petroleum refineries and at facility fencelines. This work reports results over a three-year period for currently-installed community and fenceline air quality monitoring for the Chevron refinery in Richmond, California, USA. This paper presents the most comprehensive air quality dataset that has been published to date for a community near a petroleum refinery, including concentration of different air toxics (e.g., benzene, toluene, xylenes, etc.) and criteria air pollutants (e.g., ozone (O₃), sulfur dioxide (SO₂), and particulate matter (PM)). Instrumental techniques such as ultra-violet differential absorption spectroscopy (UV-DOAS), laser-based spectroscopy and real-time gas chromatography (GC) were used in the community and fenceline monitors. From 2015 to 2017, measured concentrations at community monitors near the Richmond refinery were generally below California thresholds for acute and chronic health (only two exceedances were observed for 8-h average benzene concentrations during the three-year monitoring period). Although more detailed speciation for volatile organic compounds (VOCs) and fine particulate matter (PM_2.5) would be needed to confirm certain source profile identities, preliminary application of source apportionment methods indicates the prevalence of typical urban emission profiles, such as from traffic, in the measured community data.

Summary: Methane management is a key greenhouse gas (GHG) reduction focus within the oil and gas industry. While there are a variety of techniques for methane detection and measurement, aircraft-mounted sensors have become popular for both academic studies and operators in onshore regions in North America due to their ability to screen many sites in a relatively short amount of time. Many traditional leak detection and repair (LDAR) techniques, like optical gas imaging (OGI), and emerging approaches, such as aircraft-based or satellite-based screenings, are periodic, which means that they can provide information about the presence of emissions and approximate rates during the observation period. Scaling periodic observations to annual emission estimates needed for regulatory and corporate reporting requires information on emission duration, which is not generally provided by the same screening techniques. In the literature to date, there have been several statistical approaches proposed for the annualization of basin-level methane observations, but these techniques may struggle to downscale to individual operators, across which methane emission intensities are expected to vary. In this paper, we propose a novel, conceptual framework for using other sources of data, such as records from operator inspections and parametric monitoring, to help define the duration of detected methane emissions. Such information may prove to be a useful input to measurement-informed methane emission protocols that are under development by multistakeholder groups, like GTI Energy Veritas and federal agencies in the United States.

A variety of liquid unloading techniques are used to clear accumulated liquids from the wellbore to increase production rates for oil and gas wells. Data from national measurement studies indicate that a small subset of wells with plunger lift assist, that vent with high frequency and short event duration, contribute a significant fraction of methane emissions from liquid unloading activities in the United States. Compared to direct measurement of emissions at 24 wells in a field campaign, the most commonly used engineering emission estimate for this source category, which is based on the volume of gas in the wellbore, does not accurately predict emissions at the individual well (R² = 0.06). An alternative emission estimate is proposed that relies on the duration of the venting activity and the gas production rate of the well, which has promising statistical performance characteristics when compared to direct measurement data. This work recommends well parameters that should be collected from future field measurement campaigns that are focused on this emission source.

Methane management is a key greenhouse gas reduction focus within the oil and gas industry. While there are a variety of techniques for methane detection and measurement, aircraft-mounted sensors have become popular for both academic studies and operators in onshore regions in North America due to their ability to screen many sites in a relatively short amount of time. Many traditional leak detection and repair techniques, like optical gas imaging, and emerging approaches like aircraft-based or satellite-based screenings are periodic, which means that they can provide information about the presence of emissions and approximate rates during the observation period. Scaling periodic observations to annual emission estimates needed for regulatory and corporate reporting requires information on emission duration, which is not generally provided by the same screening techniques. In the literature to-date, there have been several statistical approaches proposed for annualization of basin-level methane observations, but these techniques may struggle to downscale to individual operators, across which methane emission intensities are expected to vary. This paper proposes a novel, conceptual framework for using other sources of data, such as records from operator inspections and parametric monitoring, to help define the duration of detected methane emissions. Such information may prove to be a useful input to measurement-informed methane emission protocols that are under development by multi-stakeholder groups, like GTI Energy Veritas, and Federal agencies in the United States.