1. The authors would like to thank the following people and organizations for their valuable input in executing this project: EPA ORD Bill Squier, EPA Region 8, EPA ORD NRMRL QA, ARCADIS, Sage Environmental, Enthalpy Analytical, City of Fort Worth, and the participating industry cooperators. Direct Measurement Tools A Direct Measurement Study of Air Emissions from Oil & Natural Gas Production Pads in the DJ Basin Adam P. Eisele 1 and Eben D. Thoma 2 1 U.S. EPA, Region 8, Office of Partnerships and Regulatory Assistance,1595 Wynkoop Drive, 8P-AR, Denver, CO 80202, 2 U.S. EPA, Office of Research and Development, National Risk Management Research Laboratory, 109 TW Alexander Drive, E343-02, Research Triangle Park, NC 27711 Objectives A one-week cooperative field study with oil and natural gas (O&NG) producers characterized volatile organic compound (VOC) and methane (CH 4 ) emissions from production well pads in the Denver-Julesburg, Basin (Greeley, CO area) in July, 2011. 1,2 The study had two main objectives: 1) Improve information on speciated VOC and CH 4 emissions from well pads using previously demonstrated on-site leak inspection and rapidly executed direct measurement approaches 3, and 2) Investigate the performance of a commercially available non-invasive CH 4 leak measurement technology (high flow sampler) for general application in upstream operations with high condensate production (wet gas). The study documented and measured volumetric emission rates from 99 components on 23 well pads and produced speciated canister data (n=33). Advantages: Easy to deploy, cover large areas Able to detect many VOC emissions common to O&NG activities Disadvantages: Expensive to purchase Does not speciate or quantify gases Imagery is weather-dependent High Flow Sampler (HFS) HFS Performance High Flow Measurements Short-term Emission Rates References: 1 Modrak, M.T.; Amin, M.; Ibanez, J.; Lehmann, C.; Harris, B.; Ranum, D.; Thoma, E.D. ; Squier, B.C. Understanding Direct Emission Measurement Approaches for Upstream Oil and Gas Production Operations, Control # 2012-A-411-AWMA, Proceedings of the 105th Annual Conference of the Air & Waste Management Association, June 19-22, 2012, San Antonio, Texas. 2) U.S. EPA Report, Oil and Gas Production Pad Air Emissions Study, EPA Office of Research and Development, National Risk Management Research Laboratory, Atmospheric Pollution Prevention and Control Division, Durham NC, 27711, and, EPA Region 8, Denver CO, 80202, (in review). 3) City of Fort Worth Natural Gas Air Quality Study, prepared by Eastern Research Group and Sage Environmental Consulting, 2011; at web site: http://fortworthtexas.gov/uploadedFiles/Gas_Wells/AirQualityStudy_final.pdf, (accessed April 12, 2013). Canister at HFS Outlet Optical Gas Imaging Acknowledgments Advantages: Non-invasive leak rate measurement Adaptable to measure most production pad components Disadvantages: Designed for 100% CH 4 leaks (Unknown performance mixed hydrocarbon leaks) Limited leak rate range (≈ 10.5 cfm) Advantages: Collect sample for composition analysis in conjunction with HFS volumetric measurement Data can support HFS correction factors Disadvantages: Post collection lab analysis needed Expensive to routinely employ Hydrocarbon Emission Rate (scfm) Cond. Tank Thief Hatch Cond. Tank PRD/Vent Prd. Water Tank Vent/Cov. Separator- Related n43111617 Avg0.21 0.130.04 Std. Dev. (σ)0.330.190.110.09 Min0.000.010.00 Max1.390.630.400.34 MW (g/mol) Cond. Tank (All) Prd. Water Tank Vent/Cov. Separator, Well. Other (All) n2715 Avg53.283.135.5 Std. Dev. (σ)5.0N/A12.0 Min41.183.123.9 Max65.483.152.2 HC Emission Rate (scfm) VOC Emission Rate (lb/hr) CH 4 Emission Rate (lb/hr) HAP Emission Rate (lb/hr) Benzene Emission Rate (lb/hr) Condensate Tank (non flash) n54 Avg0.210.840.120.050.01 Std. Dev.0.301.140.190.060.01 Median0.110.410.060.030.00 Min0.00 Max1.395.431.070.340.06 Condensate Tank (flash) - not sustained n77777 Avg1.596.740.760.300.06 Std. Dev.1.365.880.750.310.05 Median2.329.640.550.150.08 Min0.040.120.040.010.00 Max3.1614.761.740.730.12 Produced Water Tank n16 Avg0.131.050.040.210.04 Std. Dev.0.110.830.030.160.03 Median0.110.870.030.170.03 Min0.000.030.000.010.00 Max0.403.050.120.600.11 Separator-related, Well-related, Other n29 Avg0.070.080.110.00 Std. Dev.0.12 0.180.010.00 Median0.01 0.00 Min0.00 Max0.430.510.610.030.00 As opposed to the predominately CH 4 emissions encountered in reference 3, this study in wet gas areas found emissions with large VOC to CH 4 ratios. Under these conditions, the HFS tends to underestimate emissions (trend line), likely due to low bias in the combustibles concentration sensor caused by differences in gas properties compared to CH 4 1,2 In the case of large emissions (i.e. tank emissions during separator dump), the HFS can malfunction (open circles) as the combustibles concentration greatly exceeds 5% producing very low emission results. This is illustrated by comparison of two levels of canister-corrected HFS emission rates for the 33 canister-sampled emission events. Emission rate 1 (ER1) is HFS-determined using canister average MW in place of the normally assumed 100% CH 4 MW. ER2 replaces the HFS sensor-determined combustible concentration with the canister-determined value (total combustible concentration in canister). The table below contains a summary of volumetric emission rates in scfm (at 25°C and 101.325 kPa). Emission rates were determined by the HFS and, where available, canister-derived total hydrocarbon % values were used in place of the HFS sensor data for total combustible concentration (25% of data). A summary of the canister molecular weight (MW) statistics grouped by source is presented in the table below. This study used Ozone Precursor method (EPA/600-R-98/161) coupled with ASTM 1946/D1945 analysis of CH 4, ethane and propane. 1,2 This analysis set has significantly more overlap for oil and natural gas product-related compounds (i.e. ethane, propane, other alkanes), compared to the TO-15 method used previously 3 which provides more coverage for HAP compounds. The use of the term "total hydrocarbon emissions" refers only to the summation of the compounds analytically determined and does not represent comprehensive assessment of all potentially emitted pollutants. 1,2,3 Canister Measurements Conclusions Optical Gas Imaging A mid-range infrared (IR) camera equipped with a 3.2–3.4 µm optical filter was used to detect gas released from individual production components on each well pad. The photos to the right illustrate the hydrocarbon (HC) gases escaping from an open vent (circled in red) on a condensate tank. Optical gas imaging increased the efficiency of identifying leaks during this study. The IR camera is not able to speciate or quantify individual gases in HC emission plumes. Current emission rate estimates derived using average HFS data and canister MWs are shown.* These are “snap shot” measurements and some emission types (e.g. tank flash) are periodic in nature and only last only a few minutes, so extrapolation to tons per year values is not meaningful (leads to gross overestimate). 1,2 Tank-related emissions are also affected by seasonal and diurnal changes and this study was conducted during near peak emissions (summertime / day). 62% of IR camera-detected emissions were related to condensate tanks Commercial HFS systems designed for CH 4 can underestimate mixed HC emissions and can be overwhelmed (malfunction) when attempting to assess condensate tank flash events. Canister correction of HFS is likely needed to compensate for mixed gas streams encountered in upstream operations in wet gas areas. Where applicable, control device efficiency measurements should be included during well pad direct measurement studies. *Estimates subject to revision in report review process (reference 2)