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

1

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 Consulting, 720 West Arapaho Road, 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 technologies are leading to greatly increased production 

activity in many areas of the United States (U.S.). Environmentally responsible development of 

this critical asset requires an understanding of the potential impacts of air pollutant emissions 

from upstream oil and gas production sites. These emissions can include volatile organic 

compounds (VOCs), which may impact regional ozone levels, hazardous air pollutants (HAPs) 

that could potentially create air quality concerns for near-site residents, and greenhouse gases 

(GHGs) such as methane (CH4), a potent radiative forcing agent. A key to understanding 

emissions and mitigation options is in the development and optimization of cost-effective 

measurement methods specific to the upstream oil and gas production. Better measurements and 

models not only help protect the environment, but also help facilitate efficient resource 

development by alleviating concerns where appropriate. 

Air emissions from oil and gas production sites vary based on a number of factors including the 

geologically-determined composition of the oil and gas product (wet or dry gas), age of well, 

production equipment designs, and equipment maintenance states. The U.S. EPA’s mandatory 

GHG reporting rule1

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 compliance 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 measurement study of production pad emissions in the 

Greeley, CO area conducted by ARCADIS in coordination with Sage Environmental Consulting 

(Sage) and in collaboration with several industry operators. The study focused on determination 

of instantaneous VOC and CH4 emissions from production pads (with emphasis on 

oil/condensate tank emissions) using non-invasive measurement techniques. In addition to 

preliminary emissions results, this abstract describes the instrumentation 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 camera 
Air & Waste Management Association 105th Annual Conference & Exhibition, June 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 information, 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 range 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 the 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 emissions (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-related (i.e. leaking thief hatches). Atmospheric storage tank 

emissions (both oil/condensate and produced water) can be described as (1) tank breathing 

losses, that occur due to vapors produced by diurnal temperature changes, (2) tank working 

losses, that are caused by displacement during tank filling cycles, and (3) tank flashing losses, 

that occur when liquids with entrained gas experience a pressure drop during transfer of the 

liquid from a wellhead or separator. Of these four production pad emission 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 losses 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 for 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 execute quantification techniques could be used to 

produce reliable short-term emission measurements from these systems in order to increase 

emissions knowledge and compare actual 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-invasive measurement 

approaches, such as infrared video and real-time leak measurements coupled with subsequent 

laboratory analysis of acquired canisters. Another goal of the study was to improve 

understanding of the performance of high volume sampling equipment6,7 for emissions that are 

VOC rich (defined here as combustible vapor < 95% CH4). A final goal was to improve 

understanding of non-invasive measurement techniques for study of condensate tank flash 

emissions. Other studies4,5 investigating flash emissions have performed measurements using 

installed vent flow meters and with 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 volume sampler described below. Because flash 

emissions occur at irregular intervals and are not sustained, they are challenging for short 

duration direct measurement approaches. To help address this issue, the site operators manually 

induced flashing events, when deemed safe by the site operator and study personnel. 
Air & Waste Management Association 105th Annual Conference & Exhibition, June 19-22, 2012, San Antonio, TX 

3

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 the 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 and meteorological data, generation of a detailed inventory of all 

major on-site equipment, creation of a site sketch 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 emission point was identified, the camera operator 

documented the type of equipment that was emitting and the location of the leak or vented 

emission and the video was saved. 

Following the IR camera survey, a Bacharach Hi Flow SamplerTM (BHFS, Bacharach Inc. New 

Kensington, PA, USA) was used to determine the emissions rate from all safely accessible 

emission points identified by the survey (Figure 1). The BHFS is designed for measuring CH4 

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-CH4 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 volume of the emitted gas and surrounding air through a flexible hose 

into a manifold for analysis. The sample first passes through a flow restrictor 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 CH4. 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 rates 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 conducted using a three (3) standard cubic feet, 

anti-static measurement bag placed over the emission 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 105th Annual Conference & Exhibition, June 19-22, 2012, San Antonio, TX 

4

For the BHFS measurements, the instrument-determined 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 combustibles in the background sampling area 

Flow (cfm) = Flow rate of sample and background air in cubic feet per minute 

The BHFS response is calibrated at 2.5% and 100% CH4 before each day’s trials. As detailed in 

the results and discussion section, the translation of the BHFS from downstream natural gas 

inspection applications (where CH4 dominates the emission speciation profile) to upstream 

applications on VOC-rich streams is not straightforward and the instrument-determined emission 

rate is now believed to deviate significantly from actual values under certain conditions. 

In addition to BHFS readings, evacuated canister samples 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 individual 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 canister. The sample collection integration time 

was approximately 30 seconds. Canisters were generally collected at the 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 and severity of emission points detected. The 

canisters were analyzed for the US EPA Photochemical Assessment Monitoring (PAMS) Target 

Volatile Organic Compounds (VOC), as well as percent level CH4, ethane, ethene, propene, and 

propane by ASTM D1946/D1945.

Calculation of a emission rate of total combustibles (all canister-measured compounds) or total 

VOCs (all compounds excluding CH4 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 canister-based emission rate is a modified 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 results from ppmv to units of mg/m3

, and converting the 

BHFS gas flow rate to standard gas flow. The VOC emission rate is calculated using Equation 2: 

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

Where: 

 ER = VOC Emission Rate (lb/year) 

 C = VOC Concentration (mg/m3

) 

 CFMstd = Flow rate (ft3/min) corrected to standard conditions 
Air & Waste Management Association 105th Annual Conference & Exhibition, June 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

0.48

BHFS Reading (SCFM)

N = 46 

N = 16 

N = 8 

N = 16 N = 9 

Figure 2: BHFS volumetric emission rate readings by component group: () individual 

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

Condensate 

Tank 

Pressure Relief 

Device 

Pneumatic Device Connection 

and Other 

Pd. Water 

Tank 

A

B

C

D

E

F

G

 CF = Units Conversion Factor = 3.75 E-06 (1 m3/35.32147 ft3) *60 minutes/hour 

* (1 lb/453592.37 mg) 

Field data were collected electronically on data loggers and archived daily at the end of testing. 

Further information on procedures is contained in references 3 and 6. 

Results and Discussion 

A total of 23 sites were surveyed, excluding two replicate site visits. The average production pad 

consisted of five wells, 258 valves, 2,583 connectors, three condensate tanks, one produced 

water tank, four thief hatches, five pressure relief devices, three separators, 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 four utilized a two stage separation process to 

further recover natural gas by reducing the net pressure by approximately one fourth of the liquid 

sent to the condensate tanks via a buffer tank. 
Air & Waste Management Association 105th Annual Conference & Exhibition, June 19-22, 2012, San Antonio, TX 

6

Each emission that was detected with the IR camera (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 grouping is shown in Figure 2. Condensate tank 

emissions were identified as leaking thief hatches (N=44) and vent structure (N=2). All 

measurements in the pressure relief device category came from condensate tank emissions. 

Thirteen of the produced water tank measurements 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 from a vapor recovery unit knock-out pot (0.34 

SCFM) and a leaking compressor filter (0.294 SCFM). The final category represents all 

miscellaneous connections and fittings 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 (labels A-G), associated with the condensate tank emissions, are 

present to reference specific measurements described in Figure 3. 

As discussed in the experimental methods section, the BHFS is calibrated to CH4 and the 

volumetric emission determination is believed to be relatively accurate for measurement of 

emissions within its operational range that are primarily composed of CH4 (i.e. combustibles > 

95% CH4). Emissions from well pads in Weld County Colorado have high VOC to CH4 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 study since a large percentage of the measurements 

came from condensate tank emissions. It is hypothesized that because the BHFS utilizes a dual 

mode catalytic oxidation/ thermal conductivity sensor to determine combustible gas 

concentrations, measurements of sample stream gases with different physical properties than 

CH4 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 rate bias due to density differences 

of the sample stream relative to CH4 are also likely present but are not discussed here. 

As determined by canister analysis (discussed subsequently), the typical hydrocarbon profile 

varies by source (i.e. condensate tank compared to non-tank) but is dominated by aggregate nonCH4 species (ethane, propane, butane, etc) for this 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 determined volumetric emission readings can be 

biased low (Figure 3). The ordinate of Figure 3 shows the difference in the BHFS determined 

volumetric emission rate (called BHFS) and that found by combining the canister-derived total 

combustibles concentration with the BHFS total flow rate (called canister), 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 believed 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 response is calibrated at 2.5% (mid range of the catalytic 

oxidation mode) and 100% CH4 before each day’s trials. Since the relative thermal conductivity 

of CH4 compared to air is significantly higher than that of other observed hydrocarbons (at the 

pellistor’s operating range around 500 C), the concentration reading (and hence leak rate 

determination) of the BHFS underestimates actual by progressively larger amounts with 
Air & Waste Management Association 105th Annual Conference & Exhibition, June 19-22, 2012, San Antonio, TX 

7

increasing total concentration of non-CH4 combustibles. This situation occurs for larger leaks 

but is also affected by the coupling of the extraction 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 that 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 were some of the highest actual emissions. In 

fact, cases A, C, and D, were condensate flash 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 response 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 internal flow rate density 

compensation issues that arise from non-CH4 emissions. These factors are the subject of further 

investigation. Regardless of cause, this low bias 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 (currently 10.5 CFM maximum total flow rate) so alternative measures, 

such as calibrated leak bagging, become more attractive.6,7 

Methane and VOC mass emission rate estimates were produced for a subset of observed leaks 

(N=33) using the previously described procedure which combines the BHFS total flow and 

canister analysis (Figure 4). The VOC emission values represent 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 canister-determined emission rates with 

increasing combustibles concentration 
Air & Waste Management Association 105th Annual Conference & Exhibition, June 19-22, 2012, San Antonio, TX 

8

calculating the volumetric ratio of CH4 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 CH4 ratios (17.2%). Twenty five of the tankrelated canisters were acquired during thief hatch measurements with three from pressure relief 

or vent devices. The latter subset showed an average CH4 ratio of 20.3% ( = 6.8%). The CH4

ratio difference between the tank-related and non-tank related emissions is evident in Figure 4b 

which shows very low non-tank related VOC emissions. 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 and is the subject of further investigation. 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

0.26

 CH4 Emission 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

2.6

VOC Emission Rate (g/s)

N = 28 N = 28 

N = 5 

Tank (CH4) Non-tank (CH4) Tank (VOC) Non-tank (VOC) 

(a) (b) 

N = 5 

N = 5 

N = 28 

Figure 4: (a) CH4 and (b)VOC Mass emission rate by canister calculation: () individual readings, 

() CH4 mean, () CH4 median, (□) VOC mean, (▲) VOC median, bars represent  1 . 
Air & Waste Management Association 105th Annual Conference & Exhibition, June 19-22, 2012, San Antonio, TX 

9

SUMMARY 

Improved understanding of both air pollutant emissions 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 national asset. This extended abstract presents 

preliminary information from a direct measurement study of production pad emissions near 

Greeley, CO, conducted by ARCADIS in coordination with Sage Environmental Consulting and 

in collaboration with several industry operators. The goals of the study were to improve 

understanding of component-level emissions, speciation profiles, non-invasive measurement 

approaches, and condensate tank flash emissions. In addition to preliminary emissions results, 

this abstract describes the instrumentation used for data collection and methods used for 

emissions quantification. Next steps include continued processing of this data set to better 

understand instrument performance, measurement uncertainty, and source emissions. 

Additionally, recommendations for next steps in laboratory studies, field 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 Gases: Petroleum and Natural Gas 

Systems; Final Rule, U.S. Federal Register, 40 CFR 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 Measurements, Interim Report on Recent Survey Studies.

Proceedings of 105thAnnual Conference of the Air & Waste Management Association, 2011-A21-AWMA, June 19-22, 2012, San Antonio, Texas. 

3. City of Fort Worth Natural Gas Air Quality Study, prepared by Eastern Research Group and 

Sage Environmental Consulting, 2011, available at http://fortworthtexas.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 Consortium Report, H051C, 2009; available at 

http://files.harc.edu /Projects/AirQuality/Projects/H051C/H051CFinalReport.pdf, (accessed 

January 22, 2012). 

5. Gidney, B.; Pena, S. Upstream Oil and Gas Storage Tank Project, Flash Emissions Models 

Evaluation, Texas Commission on Environmental Quality Report , 2009; available at 

http://www.tceq.texas.gov /assets/public/implementation/air/am/contracts/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/emissions/downloads10/Subpart-W_TSD.pdf
Air & Waste Management Association 105th Annual Conference & Exhibition, June 19-22, 2012, San Antonio, TX 

10

8. Descriptions of the Bacharach Hi Flow SamplerTM design and operation limits are based on 

best available information including discussions with the manufacturer and the distributor of the 

instrument. This abstract is being communicated 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, direct measurements, methane, VOC, HAP, GHG,