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.

Figure 1.

Distributions of well counts from this study (primary ordinates axes, solid bars) with actual field study-selected distributions (secondary ordinated axes, dashed line) for: (a) well spud dates; (b) 2017 well oil production; (c) 2017 well gas production.

Figure 2.

Illustration of OGI detection threshold assumptions and important emission level demarcation points for IPCs and CPCs. The IPC designed seepage rate is assumed to be below OGI detection limit in all observing modes.

Figure 3.

Breakdown of the PS/PC systems found on facilities (first four bars), along with a summary of OGI survey results pertaining to the primary dataset of working, NG emitting PCs (N = 453). The OGI-observed data set was 447 and includes both auto and HSM/auto observations.

Figure 4.

HVS measured IPC (gray bars) and CPC (blue bars) ERs. The detection limit of the technique is 0.1 scf/hr and IPCs 13 and 14 do not represent accurate measurements due to variable emission from the IPCs.

Figure 5.

(a) Comparison of PC actuations per facility ranked by production (black bars) to facility oil production normalized by inlet separator count (dashed gray line). (b) Comparison of facility MI rates (black bars) to facility oil production normalized by separator count (dashed gray line).