Timothy L. Vaughn

Measurements of Methane Emissions from Natural Gas Gathering Facilities and Processing Plants: Measurement Results

Facility-level methane emissions were measured at 114 gathering facilities and 16 processing plants in the United States natural gas system. At gathering facilities, the measured methane emission rates ranged from 0.7 to 700 kg per hour (kg/h) (0.6 to 600 standard cubic feet per minute (scfm)). Normalized emissions (as a % of total methane throughput) were less than 1% for 85 gathering facilities and 19 had normalized emissions less than 0.1%. The range of methane emissions rates for processing plants was 3 to 600 kg/h (3 to 524 scfm), corresponding to normalized methane emissions rates <1% in all cases. The distributions of methane emissions, particularly for gathering facilities, are skewed. For example, 30% of gathering facilities contribute 80% of the total emissions. Normalized emissions rates are negatively correlated with facility throughput. The variation in methane emissions also appears driven by differences between inlet and outlet pressure, as well as venting and leaking equipment. Substantial venting from liquids storage tanks was observed at 20% of gathering facilities. Emissions rates at these facilities were, on average, around four times the rates observed at similar facilities without substantial venting.

Methane Emissions from Natural Gas Compressor Stations in the Transmission and Storage Sector: Measurements and Comparisons with the EPA Greenhouse Gas Reporting Program Protocol

Equipment- and site-level methane emissions from 45 compressor stations in the transmission and storage (T&S) sector of the US natural gas system were measured, including 25 sites required to report under the EPA greenhouse gas reporting program (GHGRP). Direct measurements of fugitive and vented sources were combined with AP-42-based exhaust emission factors (for operating reciprocating engines and turbines) to produce a study onsite estimate. Site-level methane emissions were also concurrently measured with downwind-tracer-flux techniques. At most sites, these two independent estimates agreed within experimental uncertainty. Site-level methane emissions varied from 2-880 SCFM. Compressor vents, leaky isolation valves, reciprocating engine exhaust, and equipment leaks were major sources, and substantial emissions were observed at both operating and standby compressor stations. The site-level methane emission rates were highly skewed; the highest emitting 10% of sites (including two superemitters) contributed 50% of the aggregate methane emissions, while the lowest emitting 50% of sites contributed less than 10% of the aggregate emissions. Excluding the two superemitters, study-average methane emissions from compressor housings and noncompressor sources are comparable to or lower than the corresponding effective emission factors used in the EPA greenhouse gas inventory. If the two superemitters are included in the analysis, then the average emission factors based on this study could exceed the EPA greenhouse gas inventory emission factors, which highlights the potentially important contribution of superemitters to national emissions. However, quantification of their influence requires knowledge of the magnitude and frequency of superemitters across the entire T&S sector. Only 38% of the methane emissions measured by the comprehensive onsite measurements were reportable under the new EPA GHGRP because of a combination of inaccurate emission factors for leakers and exhaust methane, and various exclusions. The bias is even larger if one accounts for the superemitters, which were not captured by the onsite measurements. The magnitude of the bias varied from site to site by site type and operating state. Therefore, while the GHGRP is a valuable new source of emissions information, care must be taken when incorporating these data into emission inventories. The value of the GHGRP can be increased by requiring more direct measurements of emissions (as opposed to using counts and emission factors), eliminating exclusions such as rod-packing vents on pressurized reciprocating compressors in standby mode under Subpart-W, and using more appropriate emission factors for exhaust methane from reciprocating engines under Subpart-C.

Methane Emissions from United States Natural Gas Gathering and Processing

New facility-level methane (CH4) emissions measurements obtained from 114 natural gas gathering facilities and 16 processing plants in 13 U.S. states were combined with facility counts obtained from state and national databases in a Monte Carlo simulation to estimate CH4 emissions from U.S. natural gas gathering and processing operations. Total annual CH4 emissions of 2421 (+245/-237) Gg were estimated for all U.S. gathering and processing operations, which represents a CH4 loss rate of 0.47% (±0.05%) when normalized by 2012 CH4 production. Over 90% of those emissions were attributed to normal operation of gathering facilities (1697 +189/-185 Gg) and processing plants (506 +55/-52 Gg), with the balance attributed to gathering pipelines and processing plant routine maintenance and upsets. The median CH4 emissions estimate for processing plants is a factor of 1.7 lower than the 2012 EPA Greenhouse Gas Inventory (GHGI) estimate, with the difference due largely to fewer reciprocating compressors, and a factor of 3.0 higher than that reported under the EPA Greenhouse Gas Reporting Program. Since gathering operations are currently embedded within the production segment of the EPA GHGI, direct comparison to our results is complicated. However, the study results suggest that CH4 emissions from gathering are substantially higher than the current EPA GHGI estimate and are equivalent to 30% of the total net CH4 emissions in the natural gas systems GHGI. Because CH4 emissions from most gathering facilities are not reported under the current rule and not all source categories are reported for processing plants, the total CH4 emissions from gathering and processing reported under the EPA GHGRP (180 Gg) represents only 14% of that tabulated in the EPA GHGI and 7% of that predicted from this study.

Evaluation of Emissions and Performance of Diesel Locomotives With B20 Biodiesel Blends: Static Test Results

This paper describes the results to date of a study to quantify the exhaust emissions and performance characteristics of 20% soy methyl ester biodiesel blends (B20) in diesel locomotives representative of a typical commuter transit fleet. Testing is performed with #2 diesel summer blend, #2 diesel winter blend, ultra low sulfur diesel (ULSD) summer blend, ULSD winter blend and B20 blends with each of these fuels. Tests are performed on two different diesel locomotive types to determine the differences in performance and emissions between older and newer locomotive engines when operating on biodiesel blends. Specifically, tests are performed on a GP40FH-2 locomotive equipped with an EMD 16-645 engine manufactured from a 1960’s design and a recently manufactured ALSTOM PL42AC locomotive equipped with an EMD 16-710 engine. The tests are being performed in two phases. The first phase of the project is performed by operating the diesel engines statically (using a load bank) over the full test matrix of 8 fuels. During the static testing phase, brake specific exhaust emissions and fuel consumption are computed for each fuel blend using the line-haul and switcher duty cycles as outlined in the CFR Part 40 Title 92 Federal Test Procedure. Each fuel/locomotive test combination is performed 3 times to ensure repeatability. The second phase of the project consists of mobile in-use emissions testing using a simulated, mobile duty cycle based on actual commuter rail routes. To accurately quantify the exhaust emissions, measurements are made using a Sensors SEMTECH-D mobile emissions analyzer to measure CO, CO2 , NO2 , NO, O2 , and total unburned hydrocarbons (HCs), along with a Wager 6500RR Railroad Opacity Meter. Instantaneous fuel consumption is monitored using two AW Company JV-KG positive displacement flow meters, which measure the supply and return fuel flow rate, respectively.Copyright

Correction to Measurements of Methane Emissions from Natural Gas Gathering Facilities and Processing Plants: Measurement Results.

Facility-level methane emissions were measured at 114 gathering facilities and 16 processing plants in the United States natural gas system. At gathering facilities, the measured methane emission rates ranged from 0.7 to 700 kg per hour (kg/h) (0.6 to 600 standard cubic feet per minute (scfm)). Normalized emissions (as a % of total methane throughput) were less than 1% for 85 gathering facilities and 19 had normalized emissions less than 0.1%. The range of methane emissions rates for processing plants was 3 to 600 kg/ h (3 to 524 scfm), corresponding to normalized methane emissions rates <1% in all cases. The distributions of methane emissions, particularly for gathering facilities, are skewed. For example, 30% of gathering facilities contribute 80% of the total emissions. Normalized emissions rates are negatively correlated with facility throughput. The variation in methane emissions also appears driven by differences between inlet and outlet pressure, as well as venting and leaking equipment. Substantial venting from liquids storage tanks was observed at 20% of gathering facilities. Emissions rates at these facilities were, on average, around four times the rates observed at similar facilities without substantial venting. ■ INTRODUCTION Methane is the primary component of natural gas; it is also a potent greenhouse gas (GHG). The Environmental Protection Agency (EPA) estimates that the natural gas system contributes 23% of U.S. anthropogenic methane emissions. However, there are discrepancies between recent studies and EPA GHG inventories in some natural gas producing areas. The EPA GHG inventories largely rely on data collected in the early 1990s and may not reflect recent changes in technology, operations, and regulation. New measurements are needed to characterize methane emissions from the natural gas system. This study investigates the methane emissions from natural gas gathering and processing (G&P) facilities, which, collectively, gather natural gas from production wells, remove impurities, and deliver it to interand intrastate pipeline networks. We define gathering and processing as the equipment and pipeline network between the sales points at well pads and downstream delivery points. This includes gathering pipelines, and the equipment at gathering facilities: compressors (driven by electric motors (“motors”) and/or natural gas-fired internal combustion engines (“engines”) or turbines), dehydration systems to remove water, and treatment systems to remove hydrogen sulfide and/or carbon dioxide. Processing plants often house this equipment on a larger scale, acting as central nodes in a system of smaller gathering facilities. Processing plants also separate natural gas liquids (NGLs) (such as ethane, propane, butane, and heavier hydrocarbons) from methane. For this study, processing plants are defined as the facilities that meet the 40 CFR Part 60 Subpart KKK definition of “natural gas processing plant” based on the presence of NGL extraction. Facilities that only fractionate NGLs were not included in this study. This paper presents facility-level measurements of methane emission rates at 130 G&P facilities (114 gathering and 16 processing). A mobile laboratory was used to perform downwind tracer flux measurements, which is an established technique to estimate the total emissions of methane (or other Received: October 28, 2014 Revised: January 23, 2015 Accepted: January 28, 2015 Published: February 10, 2015 Article