Understanding oil and gas pneumatic controllers in the Denver–Julesburg basin using optical gas imaging

Abstract

In the spring of 2018, a 10-day field study was conducted in Colorado's Denver-Julesburg oil and natural gas production basin to improve information on well pad pneumatic controller (PC) populations and identify PCs with potential maintenance issues (MIs) causing excess emissions through a novel optical gas imaging (OGI) survey approach. A total of 500 natural gas-emitting PCs servicing 102 wells (4.9 PCs/well) were surveyed at 31 facilities operated by seven different companies. The PCs were characterized by their designed operational function and applications, with 83% of the PC population identified as intermittent PCs (IPCs). An OGI inspection protocol was used to investigate emissions on 447 working PCs from this set. OGI detected continuous emissions from 11.3% of observed IPCs and these were classified as experiencing some level of MIs. OGI imaging modes were observed to have a significant effect on emission detectability with high sensitivity mode detection rates being approximately 2 times higher compared to auto mode. Fourteen snapshot emission measurements (not including actuations) were conducted on IPCs in this category using a high-volume sampling device with augmented quality assurance procedures with observed emissions rates ranging from 0.1 up to 31.3 scf/hr (mean = 2.8 scf/hr). For PCs with continuous depressurization type (CPC), 36.8% had continuous emissions observed by OGI. Four supporting emission measurements were conducted on CPCs with one unit exceeding the low bleed regulatory emission threshold with an emission rate of 9.9 scf/hr (mean = 4.2 scf/hr). Additional information was collected on PC actuation events, as observed with OGI, which showed a strong correlation between observed actuation events and facility production compared to observed continuous emissions caused by MIs which did not correlate with facility production.Implications: A novel survey approach of pneumatic controllers at oil and natural gas production facilities in the Denver-Julesburg basin, using optical gas imaging and supporting emission measurements, was demonstrated as an effective method to identify controllers with potential maintenance issues causing excess emissions. The results of the pneumatic controller and optical gas imaging surveys improved information on pneumatic controller populations within the basin and also demonstrated the significant effect optical gas imaging modes have on emission detections.

Detection Limits of Optical Gas Imaging for Natural Gas Leak Detection in Realistic Controlled Conditions

“…Instrument detection limit studies in controlled conditions show that OGI is capable of detecting CH 4 leaks in the 1–4 g·hr –1 range, with many HCs exhibiting better detection sensitivity than CH 4 due to higher integrated absorption strength in the observed spectral band. − Prior studies have identified several physical and environmental factors that affect the active DT and can result degradation of detection sensitivity by orders of magnitude. Observation distance, atmospheric dispersion of the emitted plume (e.g., wind speed), and the apparent temperature difference between the emitted gas and background scene (Δ T ), which includes both ambient temperature blackbody radiation and direct solar reflection, are significant determining factors in OGI detection performance. − Whereas instrument and environmental factors affecting OGI detection sensitivities are becoming better understood, human and method protocol effects, such as the difference between proximate high-dwell observations of specific components versus more routine LDAR scanning leaks surveys are just beginning to be studied. − A limited number of studies have compared OGI, M21-type detections, and emission rate measurements on O&G sites, documenting the sensitivity advantage of hand-held M21 probes in detection of small emissions but also noting the fundamentally different aspects of the approaches and the types of emissions found. Previous field work on O&G sites indicates the ability of OGI to detect small emissions (e.g., <1.5 standard cubic feet per hour (scfh) or ≈30 g·h –1 ) under favorable conditions, but also to miss larger emissions under unfavorable conditions. − …”

Uncertainty Quantification of Methods Used to Measure Methane Emissions of 1 g CH4 h−1

“…This is sometimes a real challenge in the field with emissions coming from awkward parts of the Christmas tree configuration or the pumpjack, but it can be overcome by using an optical gas imaging (OGI) camera in tandem to ensure that all the gas is collected. However, OGI cameras are expensive (>$50k), and they may not be able to detect emissions of less than 20 g of CH 4 h −1 [19,20].…”

“…Other methods can be used to quantify emissions but are not well suited to measure the relatively small amounts of CH 4 that are typically emitted from abandoned wells [3,4,11,18]. For example, the quantification limit of optical gas imaging (OGI) cameras is higher than the average abandoned well's emission by at least a factor of two [19,20], tracer release requires road access, which is problematic for most abandoned wells as they are generally in wooded areas [21], aircraft survey methods have a lower quantification limit of 1 kg of CH 4 h −1 [22], and satellites have a lower quantification limit of 100 kg of CH 4 h −1 [23]. To date, the Hi-Flow sampler is the only ACR-approved non-chamber method.…”

Methane emissions from oil and gas production sites and their storage tanks in West Virginia

“…A study team member used a FLIR GF320 or FLIR GFx320 OGI camera (FLIR Systems, Billerica, MA) for visual inspections. For this study, the OGI detection threshold was assumed to be 2.0 standard cubic feet per hour (scfh), using a special observation protocol and an experienced operator ( Zeng and Morris, 2019 ), in line with similar OGI detection studies ( Stovern et al, 2020 ; Thoma et al, 2017 ; Ravikumar et al, 2018 ; Zeng and Morris, 2019 ). Both the OGI surveys and subsequent quantification measurements represent short durations or “snapshots.” For emissions quantification, the team used a modified version of our FFS that we believe was more suitable for measurement of tank and larger source emissions.…”