Air & Waste Management Association 105 th Annual Conference & Exhibition, J une 19-22, 2012, San Antonio, TX

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## Understanding Direct Emission Measurement Approaches for Upstream Oil and Gas Production Operations

Control # 2012-A-411-AWMA
Mark T. Modrak and M. Shahrooz Amin ARCADIS Inc., 4915 Prospectus Drive, Suite F, Research Triangle Park, NC 27713, USA
J. Ibanez, C. Lehmann, B. Harris, and D. Ranum Sage Environmental Consu lting, 720 West Arapaho Roa d, Richardson, Texas 75080, USA Eben D. Thoma and Bill C. Squier U.S. EPA, Office of Research and Development, National Risk Management Research Laboratory, 109 TW Alexander Drive, E343- 02, Research Triangle Park , NC 27711, USA



### INTRODUCTION Breakthroughs in oil and gas extraction technolog ies are leading to greatly increased production activity in many areas of the Unite d States (U.S.). Environmentally responsible development of this critical asset requires an understanding of the potential imp acts of air pollutant emissions from upstream oil and gas production sites. These emissions can in clude volatile organic compounds (VOCs), which may imp act regional ozone levels, h azardous air pollutants (HAPs) that could potentially create air quality concer ns for near-site reside nts, and greenhouse gases (GHGs) such as methane (CH 4 ), a potent radiative forcing agent. A key to understanding emissions and mitigation options is in the de velopment and optimization of cost-effective measurement methods specific to the upstream oi l and gas production. Better measurements and models not only help protect th e environment, but also help facilitate efficient resource development by alleviating concer ns where appropriate. Air emissions from oil and gas pr oduction sites vary based on a number of factors including the geologically-determined composition of the oil an d gas product (wet or dry gas), age of well, production equipment designs, and equipment mainte nance states. The U.S. EPA’s mandatory GHG reporting rule 1 will greatly increase knowledge of GHG emissions from oil and gas production operations, but there is an ongoing need to improve emissions estimates, as well as to facilitate identification and remediation of complia nce issues related to air quality. To improve both the measurement methods and emissions knowledge for this sector, the U.S. EPA Office of Research and Development (ORD), and its partners are investigating both on-site direct and offsite remote measurement approaches. 2

This extended abstract describes a direct m easurement study of production pad emissions in the Greeley, CO area conducted by ARCADIS in coor dination with Sage Environmental Consulting (Sage) and in collaboration with several industry operators. Th e study focused on determination of instantaneous VOC and CH 4 emissions from production pads (with emphasis on oil/condensate tank emissions) us ing non-invasive measurement te chniques. In addition to preliminary emissions results, th is abstract describes the inst rumentation used and issues encountered in the study. 

### BACKGROUND In conjunction with a July 2011, EPA mobile measurement campaign in Weld County CO, 2 ARCADIS contracted Sage to perform on-site emission surveys at 23 oil and gas production pads in the area using previously demonstrated direct measurement and infrared cameraAir & Waste Management Association 105 th Annual Conference & Exhibition, J une 19-22, 2012, San Antonio, TX

2 techniques. 3 The measurements were conducted in collaboration with three oil and gas companies that provided site access, process in formation, engineering descriptions, and safety oversight. The specific locations surveyed during the field study were determined prior to field deployment and were chosen to represent the ra nge of operations (e.g. different gas qualities, condensate or produced water generation, etc.) present in the area and to maximize data collection efficiency. The identities of th e companies and sites will remain anonymous for reporting purposes. Emissions from production pads can be fugitive or vented in origin and for the purposes of this study, are grouped into four categories, tank em issions (three types) and non-tank emissions from auxiliary equipment(all other production pad emissions). As evidenced in recent measurement studies, 2,3 the most readily identified emission points by infrared camera observation are storage tank-rela ted (i.e. leaking thief hatche s). Atmospheric storage tank emissions (both oil/condensate and produced water) can be de scribed as (1) tank breathing losses, that occur due to vapors produced by diurnal temperature cha nges, (2) tank working losses, that are caused by displacement during ta nk filling cycles, and (3) tank flashing losses, that occur when liquids with entrained gas e xperience a pressure drop during transfer of the liquid from a wellhead or separator. Of these four production pad emi ssion categories (three tank and non-tank auxiliary), tank flashing losses are generally thought to be much larger than the others on an instantaneous basis. For this study, measurements from three of the four defined emission categories make up part of the data set (no tank working losse s were observed). The air pollutant emissions from storage tanks can be mitigated in part by control devices, such as venting to flares, a technique typically employed in the Greeley, CO area. Although engineering calculations exist fo r estimation of tank emissions, 6,7 the effectiveness of controls due to engineering design variability, such as combustor back pressure, and maintenance-related variables such as thief hatch seal integrity, lead to uncertainty in actual emissions in comparison to estimates. Ideally a non-invasive, easy to ex ecute quantification techni ques could be used to produce reliable short-term emission measuremen ts from these systems in order to increase emissions knowledge and compare actua l emission to estimates. The general goals for the study were to improve understanding component-level emissions and speciation profiles from production pads in the study area using non-i nvasive measurement approaches, such as infrared vi deo and real-time leak measurem ents coupled with subsequent laboratory analysis of acquired canisters. Another goal of the study was to improve understanding of the performance of high volume sampling equipment 6,7 for emissions that are VOC rich (defined here as combustible vapor <
 95% CH 4 ). A final goal was to improve understanding of non-invasive measurement te chniques for study of condensate tank flash emissions. Other studies 4,5 investigating flash emissions ha ve performed measurements using installed vent flow meters and w ith techniques to seal leaks so as to force all flow through the measurement location. This study investigates the utility of a less invasive approach to investigate flash emissions using a high volum e sampler described below. Because flash emissions occur at irregular intervals and ar e not sustained, they are challenging for short duration direct measurement approaches. To help address this issue, th e site operators manually induced flashing events, when deemed safe by the site operator and study personnel.Air & Waste Management Association 105 th Annual Conference & Exhibition, J une 19-22, 2012, San Antonio, TX

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### Experimental Methods The production pad infrared (IR) video survey and emission measurement procedures are discussed briefly here and will be detailed in a future EPA report. 6 The methods are nearly identical to those used by Sage in execution of th e site measurements portion of the City of Fort Worth Natural Gas Study. 3 For each well pad, a pre-measurement site survey was conducted that included collection of GPS a nd meteorological data, generation of a detailed inventory of all major on-site equipment, creation of a site sket ch showing the location of all major components, and collection of several photographs of the site. After the pre-measurement data was recorded, a leak inspection survey of the site was conducted using a model GasFinderIR® video camera (FLIR Inc, Billerica, MA, USA). When an em ission point was identified, the camera operator documented the type of equipment that was em itting and the location of the leak or vented emission and the video was saved. Following the IR camera survey, a Bacharach Hi Flow Sampler TM (BHFS, Bacharach Inc. New Kensington, PA, USA) was used to determine th e emissions rate from all safely accessible emission points identified by the survey (Figur e 1). The BHFS is designed for measuring CH 4 leaks in downstream natural gas inspection and maintenance applications ( in natural gas processing plants for example), but less is known about its use in upstream measurement applications on gas streams that can possess significant non-CH 4 components. The following description of the BHFS design and operation is based on the best information available at the time of publication. 8 The BHFS consists of an intrinsically safe, induced flow (blower) sampling system that pulls a certain vol ume of the emitted gas and surrounding air through a flexible hose into a manifold for analysis. The sample first passes through a flow rest rictor where a pressure differential is measured and used to calculate the flow rate of the sample-air mixture. The BHFS automatically corrects the flow rates for difference in the density of air and CH 4 . A portion of the sample is diverted to a combustibles sensor based on a dual mode catalytic oxidation/ thermal conductivity pellistor (e2v technologies ltd. Chelmsford, Essex, United Kingdom) to determine measured gas concentrations. A similar sensor is also used to determine the background combustibles concentration. In automatic mode, the sampler lowers the induced flow to 80% of the initial value and compares the calculated leak rate to provide confidence that the leak was captured in its entirety. Care is taken that the exhaust of the sampler does not impact the background

sensor. In this study, for low emission ra tes where vapor concentrations were below the detection limit of the BHFS, the concentration was determined with a Thermo Toxic Vapor Analyzer 1000B (Thermo Scientific, Franklin, MA, USA). For large emissions exceeding the BHFS’s upper flow range of 10.5 cfm, a bagging measurement was conduc ted using a three (3) standard cubic feet, anti-static measurement bag placed over the emissi on source (if conditions were deemed safe and the source was accessible) and its fill time was recorded. Figure 1: Example of a condensate tank vent measurement with a BHFS.Air & Waste Management Association 105 th Annual Conference & Exhibition, J une 19-22, 2012, San Antonio, TX

4 For the BHFS measurements, the instrument-det ermined emission rate is calculated using Equation 1:

Emission (cfm) = Emission % - Background % * Flow (cfm) (1) 100 Where: Emission (cfm) = Flow rate of emission in cubic feet per minute Emission % = Volume percent of combustibles in the sample stream Background % = Volume percent of combus tibles in the background sampling area Flow (cfm) = Flow rate of sample and b ackground air in cubic feet per minute
The BHFS response is calibra ted at 2.5% and 100% CH 4 before each day’s trials. As detailed in the results and discussion section, the transla tion of the BHFS from downstream natural gas inspection applications (where CH 4 dominates the emission speci ation profile) to upstream applications on VOC-rich streams is not straightforward and the instrument-determined emission rate is now believed to devi ate significantly from actual values under certain conditions. In addition to BHFS readings, evacuated canister sa mples were collected at a select number of detected emission points at each site. Data from the canister samples in conjunction with the BHFS total flow results were used to compare with the volumetric emissions rate determined by the BHFS alone and also to estimate the mass emission rates of indi vidual organic compounds from selected emission points. The samples were collected directly from the exhaust port of the BHFS during sampling, using a 6 liter SUMMA canis ter. The sample collection integration time was approximately 30 seconds. Canisters were ge nerally collected at th e largest emission point at each site, determined by the BHFS emission flow rate (cfm). A total of 33 canisters were acquired at the 23 sites. At least one canister was acquired at each site. The number of canisters at each site was dependent on and the amount a nd severity of emission points detected. The canisters were analyzed for the US EPA Phot ochemical Assessment Monitoring (PAMS) Target Volatile Organic Compounds (VOC ), as well as percent level CH 4 , ethane, ethene, propene, and propane by ASTM D1946/D1945.

Calculation of a emission rate of total combustibles (all can ister-measured compounds) or total VOCs (all compounds excluding CH 4 and ethane) using canister information was accomplished by summing the concentrations of individual measured species to achieve a total measured pollutant volume percent which was then multiplied by the total BHFS gas flow rate (converted to standard conditions). This can ister-based emission rate is a m odified version of Eq. (1) where the pollutant concentration is determined by the canister instead of the BHFS combustibles

sensor. Calculation of speciated mass emissions from the canister data was accomplished by first converting the VOC concentration re sults from ppmv to units of mg/m 3 , and converting the BHFS gas flow rate to standard gas flow. The VOC emission rate is calcul ated using Equation 2:

ER = C * CFMstd * CF * 8760 (2)

Where:

ER = VOC Emission Rate (lb/year)

C = VOC Concentration (mg/m 3 )

CFMstd = Flow rate (ft 3 /min) corrected to standard conditionsAir & Waste Management Association 105 th Annual Conference & Exhibition, J une 19-22, 2012, San Antonio, TX

5 0.134 0.229

0.126 0.110

0.078 0.111 0.276

0.109

0.072

0.008

-0.04 0.00 0.04 0.08 0.12 0.16 0.20 0.24 0.28 0.32 0.36 0.40 0.44 0.48BHFS Reading (SCFM) N = 46

N = 16 N

= 8

N = 16 N = 9 Figure 2: BHFS volumetric emission ra te readings by co mponent group: (

 ) individual readings, (  ) mean, (  ) median, bars represent  1  . Inset labels (A-G), see Figure 3.

Condensate Tank Pressure Relief Device Connection Pneumatic Device and Other Pd. Water

Tank A B

C D E F G CF = Units Conversion Factor = 3.75 E-06 (1 m 3 /35.32147 ft 3 ) *60 minutes/hour * (1 lb/453592.37 mg)

Field data were collected electroni cally on data loggers and archived daily at the e nd of testing. Further information on procedures is contained in re ferences 3 and 6.


### Results and Discussion A total of 23 sites were surveyed, excluding two re plicate site visits. Th e average production pad consisted of five wells, 258 valves, 2,583 conn ectors, three condensate tanks, one produced water tank, four thief hatches, five pressure relief devices, three se parators, and all sites contained one flare/combustor. One production pad contained a dehydration unit, and four each contained one vapor recovery unit. Reference 6 contains engineering details of each production pad visited along with a layout sketch of each site . Of the 23 sites surveyed, 19 processed field gas by a single stage three phase separator and f our utilized a two stag e separation process to further recover natural gas by reduc ing the net pressure by approxima tely one fourth of the liquid sent to the condensate tanks via a buffer tank.Air & Waste Management Association 105 th Annual Conference & Exhibition, J une 19-22, 2012, San Antonio, TX

6 Each emission that was detected with the IR ca mera (93 total) was measured with the BHFS to determine the BHFS volumetric leak rate of the mixed vapor stream. The average emission rate determination for five major component group ing is shown in Figure 2. Condensate tank emissions were identified as leaking thief hatc hes (N=44) and vent structure (N=2). All measurements in the pressure relief device category came fr om condensate tank emissions. Thirteen of the produced water tank measuremen ts were from vents with two described as hatches and one as a cover. Emissions from five pneumatic control devices were measured with “other” category consisting of one valve, two equipment vent devices. The remaining two measured emissions in this category came fr om a vapor recovery unit knock-out pot (0.34 SCFM) and a leaking compressor filter (0.294 SC FM). The final category represents all miscellaneous connections and fitt ings observed to be leaking. As similarly observed in other studies, 2,3 leaking thief hatch seals on condensate tanks was the most frequently observed production pad emission category. The difficulty in maintaining seal integrity is readily acknowledged by industry collaborators for this study. Additional details on emissions from various component types with associated IR video examples will be included in the presentation. The inset labels in Figure 2 (l abels A-G), associated with th e condensate tank emissions, are present to reference specific m easurements described in Figure 3. As discussed in the experimental met hods section, the BHFS is calibrated to CH 4 and the volumetric emission determination is believed to be relatively accurate for measurement of emissions within its operational rang e that are primarily composed of CH 4 (i.e. combustibles >

 95% CH 4 ). Emissions from well pads in We ld County Colorado have high VOC to CH 4 ratios due to the wet gas nature of the production in this area (in contrast to Fort Worth, TX). 3 This difference is particularly exaggerated for this st udy since a large percentage of the measurements came from condensate tank emissions. It is hypo thesized that because the BHFS utilizes a dual mode catalytic oxidation/ thermal conductiv ity sensor to determine combustible gas concentrations, measurements of sample stream gases with different ph ysical properties than CH 4 will affect various aspects of the operation of the BHFS. The primary effect is found to be in the vapor concentration determination used in Eq 1. Flow ra te bias due to density differences of the sample stream relative to CH 4 are also likely present but are not discussed here. As determined by canister analysis (discussed subsequently), the typi cal hydrocarbon profile varies by source (i.e. condensate tank comparedto non-tank) but is dominated by aggregate nonCH 4 species (ethane, propane, butane, etc) for th is study (in contrast to profiles from dry gas fields). 3 For this study, when sampled combustibles concentrations exceed
 10%, (caused by low dilution through the BHFS), the BFHS determ ined volumetric emission readings can be biased low (Figure 3). The ordi nate of Figure 3 shows the diffe rence in the BHFS determined volumetric emission rate (calle d BHFS) and that found by combin ing the canister-derived total combustibles concentration with the BHFS total fl ow rate (called caniste r), plotted against the total combustibles percent by volume in the canister (abscissa). At up to  5% combustible concentration by volume, the BHFS’s sensor is be lieved to operate in catalytic oxidation mode then, as the concentration increases, the oxidation is saturated and the sensor switches to thermal conductivity mode. The unit’s re sponse is calibrated at 2.5% (mid range of the catalytic oxidation mode) and 100% CH 4 before each day’s trials. Sin ce the relative thermal conductivity of CH 4 compared to air is significantly higher than that of other observed hydrocarbons (at the pellistor’s operating range around 500 C), the c oncentration reading (and hence leak rate determination) of the BHFS underestimates actual by progressively larger amounts withAir & Waste Management Association 105 th Annual Conference & Exhibition, J une 19-22, 2012, San Antonio, TX

7 increasing total concentration of non-CH 4 combustibles. This situat ion occurs for larger leaks but is also affected by the coupling of the extrac tion system which controls the dilution of the vapor stream.
The underestimation of the volumetric emission rate in these cases can be very significant as evidenced by the inset labels (A-G) of Figure 3 th at link the largest absolute difference measures (BHFS - Canister results) to the BHFS determined values shown in Figure 2. It is the case that among the lowest measured values with the BHFS we re some of the highest actual emissions. In fact, cases A, C, and D, were condensate fl ash emission events, which are known to greatly exceed breathing emissions on a short time duration basis. It is believed that this underestimation in the volumetric emission re sponse of the BHFS is due mostly to the aforementioned concentration determination issues caused by the thermal conductivity differences found in VOC-rich streams, but may also be due in part to inte rnal flow rate density compensation issues that arise from non-CH 4 emissions. These factors are the subject of further investigation. Regardless of cause, this low bi as can be reduced through additional dilution of the sampling stream (increasing clean air flow). This would however further limit the useful range of the instrument (curren tly 10.5 CFM maximum total flow rate) so alternative measures, such as calibrated leak ba gging, become more attractive. 6,7

Methane and VOC mass emission rate estimates we re produced for a subset of observed leaks (N=33) using the previously de scribed procedure which combines the BHFS total flow and canister analysis (Figure 4). The VOC emission values represen t the summation of 55 canister measured compounds that were above detection limit (excludes ethane and methane). All measurements were either associated with a condensate tank emissions or one of five non-tank related emissions sampled (two separator, two well head and one dehydrator). The speciation profiles for the tank and non-tank emissions were very different. A measure is found by G

A B
C D E F

-3.5 -3.0 -2.5 -2.0 -1.5 -1.0 -0.5 0.0 0.5

0 5 10 15 20 25 30 35 40 45 50 55 Cansiter Concentration (%)BHFS - Canister Emisison Rate (SCFM) Figure 3: Difference in BHFS and cani ster-determined emission rates with increasing combustibles concentrationAir & Waste Management Association 105 th Annual Conference & Exhibition, J une 19-22, 2012, San Antonio, TX

8 calculating the volumetric ratio of CH 4 to the summation of other measured compounds (VOCs plus ethane) which yields values 243.3% (  = 161.3%) and 38.3% (  = 26.8%) for non-tank and tank related emissions respectively. It is noted that one produced water tank is included in the tanks set which possessed amongst the lowest CH 4 ratios (17.2%). Twenty five of the tankrelated canisters were acquired dur ing thief hatch measurements with three from pressure relief or vent devices. The latter subset showed an average CH 4 ratio of 20.3% (  = 6.8%). The CH 4 ratio difference between the tank -related and non-tank related emi ssions is evident in Figure 4b which shows very low non-tank related VOC emissi ons. Five tank canisters were identified as being acquired during flash emissions and these samples showed CH4 to VOC ratios similar to the full set (39.6%,  = 35.1%). VOC emission measurements associated with these five flash canisters were (2.31 g/s, 1.59 g/s, 1.50 g/s, 0.20 g/s, and 0.02 g/s). The last of these values is believed to be unrealistically low an d is the subject of further inves tigation. Data at this point is considered preliminary and is subject to revision.

0.05 0.04

0.01 0.02 0.40

0.13 0.02 0.00

-0.02 0 0.02 0.04 0.06 0.08

0.1 0.12 0.14 0.16 0.18

0.2 0.22 0.24 0.26CH4Emission Rate (g/s)

-0.2 0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 1.8 2 2.2 2.4 2.6VOC Emission Rate (g/s) N

= 28 N = 28

N

= 5

Non-tank (CH 4 ) Tank (VOC) Non-tank (VOC) Tank (CH 4 ) 

### (a) (b)

N = 5 N = 5 N = 28 Figure 4: (a) CH 4 and (b)VOC Mass emission rate by canister calculation: (

 ) individual readings, (  ) CH 4 mean, (  ) CH 4 median, ( 

### □ ) VOC mean, ( ▲ ) VOC median, bars represent  1 

.Air & Waste Management Association 105 th Annual Conference & Exhibition, J une 19-22, 2012, San Antonio, TX

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### SUMMARY Improved understanding of both air pollutant em issions from oil and gas production operations and accuracy of the tools we use to measure and model these emissions is important for environmentally responsible development of this na tional asset. This exte nded abstract presents preliminary information from a direct measurement study of production pad emissions near Greeley, CO, conducted by ARCADIS in coordinati on with Sage Environmental Consulting and in collaboration with several industry operators. The goals of the study were to improve understanding of component-level emissions, sp eciation profiles, non-invasive measurement approaches, and condensate tank flash emissions. In addition to preliminary emissions results, this abstract describes the instrumentation us ed for data collection and methods used for emissions quantification. Next steps include co ntinued processing of th is data set to better understand instrument performance, measur ement uncertainty, and source emissions. Additionally, recommendations for next steps in laboratory studies, fi eld testing, and method development activities for sector specific non-invasive measurement approaches will be formulated.



### REFERENCES

1. U.S. EPA. 2010. Mandatory Reporting of Greenhouse Ga ses: Petroleum and Natural Gas Systems; Final Rule , U.S. Federal Register, 40 CF R Part 98, EPA–HQ–OAR–2009–0923; FRL– 9226–1, at Web Site: http://edocket.access.gpo.gov/2010/pdf/2010-28655.pdf

. 2.Thoma, E.D.; Squier, B.C.; D. Olson, Eisele, A.P.; DeWees, J.M.; Segall, R.R.; Amin, M. S.; Modrak, M.T. Assessment of Methane and VOC Emissions from Select Upstream Oil and Gas Production Operations Using Remote Measuremen ts, Interim Report on Recent Survey Studies. Proceedings of 105 th Annual Conference of the Air & Wa ste Management Association, 2011-A21-AWMA, June 19-22, 2012, San Antonio, Texas.

3. City of Fort Worth Natural Gas Air Quality Study , prepared by Easter n Research Group and Sage Environmental Consulti ng, 2011, available at http://f ortworthtexas.gov/uploadedFiles /Gas_Wells/AirQualityStudy_final .pdf (accessed January 6, 2012).

4. Hendler, A.; Nunn, J.; Lundeen, J.; McKaskle, R. VOC Emissions from Oil and Condensate Storage Tanks , Texas Environmental Research Consor tium Report, H051C, 2009; available at http://files.harc.edu /Projects/AirQuality/P rojects/H051C/H051CFina lReport.pdf, (accessed January 22, 2012).

5. Gidney, B.; Pena, S. Upstream Oil and Gas Storage Tank Project, Flash Emissions Models Evaluation, Texas Commission on En vironmental Quality Report , 2009; available at http://www.tceq.texas.gov /assets/public/impl ementation/air/am/cont racts/reports/ei/20090716- ergi-UpstreamOilGasTankEIModels .pdf (accessed January 22, 2012).

6. EPA Report, Oil and Gas Production Pad Air Emission Study, Weld County, Colorado

, prepared by ARCADIS under EP-C -09-027, (in preparation).

7. U.S. EPA. Greenhouse Gas Emissions Reporting From the Petroleum and Natural Gas Industry, Background Technical Supporting Document, supporting 40 CFR Part 98.230, 77 FR 11039Subpart W – Petroleum and Natural Gas Systems, at web site: http://www.epa.gov/climatechange/emi ssions/downloads10/Subpart-W_TSD.pdfAir & Waste Management Association 105 th Annual Conference & Exhibition, J une 19-22, 2012, San Antonio, TX

10 8. Descriptions of the Bacharach Hi Flow Sampler TM design and operation limits are based on best available information includ ing discussions with the manufactur er and the distributor of the instrument. This abstract is being communicat ed to the distributor and manufacturer and any corrections will be noted in presentation and full EPA report. Any misrepresentation is unintentional.



### KEYWORDS oil and gas production, fugitive emission, dir ect measurements, me thane, VOC, HAP, GHG,