VOC EMISSIONS FROM OIL

AND CONDENSATE STORAGE TANKS

FINAL REPORT

Prepared for:

Texas Environmental Research Consortium

4800 Research Forest Drive

The Woodlands, TX 77381

Prepared by:

Albert Hendler

URS Corporation

9400 Amberglen Boulevard (78729)

P.O. Box 201088

Austin, TX 78720-1088

Jim Nunn

COMM Engineering

P.O. Box 53743

Lafayette, LA 70707-3463

Joe Lundeen

Ray McKaskle

Trimeric Corporation

P.O. Box 826

Buda, TX 78610

October 31, 2006

Revised April 2, 2009
ii

-

Table of Contents

Page

Table of Contents..........................................................................................................................ii

List of Tables ...............................................................................................................................iii

Executive Summary..................................................................................................................ES-1

1.0 Introduction.................................................................................................................... 1-1

1.1 Objectives .......................................................................................................... 1-1

1.2 Background........................................................................................................ 1-1

2.0 Technical Approach....................................................................................................... 2-1

2.1 Selection of Sampling Sites............................................................................... 2-1

2.2 Measurement Approach..................................................................................... 2-3

2.3 Development of Regional Emissions Estimates................................................ 2-5

3.0 Measurement Results..................................................................................................... 3-1

4.0 Control Options.............................................................................................................. 4-1

4.1 Common Control Options.................................................................................. 4-1

4.1.1 Open Flares.............................................................................................. 4-1

4.1.2 Enclosed Flares........................................................................................ 4-1

4.1.3 Compressor-based Vapor Recovery Units............................................... 4-3

4.1.4 Eductor-based Vapor Recovery Units ..................................................... 4-3

4.2 Site-specific Control Methods........................................................................... 4-4

4.2.1 Pressurized Storage Tanks....................................................................... 4-4

4.2.2 Micro-turbine Generators......................................................................... 4-4

4.2.3 Refrigeration-based Vapor Recovery ...................................................... 4-4

4.3 Emission Control Strategies............................................................................... 4-5

4.3.1 Storage Tank Consolidation..................................................................... 4-5

4.3.2 Lower Operating Pressure in Separators.................................................. 4-5

4.4 Economic Comparison of Common Control Technologies............................... 4-5

4.5 Site-specific Factors........................................................................................... 4-9

5.0 Discussion, Conclusions, and Recommendations.......................................................... 5-1

6.0 References ................................................................................................................ 6-1

APPENDIX A Tank Battery Summary Information

APPENDIX B RFQ for Produced Oil and Gas Storage Tank Vent Gas

APPENDIX C Quality Assurance Project Plan
iiiList of Tables

Page

ES-1 Average, Standard Deviation, and Range of VOC Vent Gas Emission Factors 

Measured for Oil and Condensate Storage Tank Batteries...........................................ES-1

ES-2 Estimated VOC Emissions from Oil and Condensate Wellhead and Gathering Site 

Storage Tanks ...............................................................................................................ES-2

3-1 API Gravities and Separator Discharge Pressures for Sampled Tank Batteries............ 3-2

3-2 Vent Gas Flow Rates and Emissions for Oil Storage Tank Batteries............................ 3-3

3-3 Vent Gas Flow Rates and Emissions for Condensate Storage Tank Batteries.............. 3-4

3-4 Measured Vent Gas Speciation Profiles in Weight Percent for Oil Tank Batteries ...... 3-6

3-5 Measured Vent Gas Speciation Profiles in Weight Percent for Condensate

Tank Batteries............................................................................................................... 3-8

3-6 Total Vent Gas and VOC Emissions for East Texas Counties...................................... 3-18

4-1 Advantages and Disadvantages of Emission Control Devices and Emission

Control Strategies for Vent Gases from Produced Oil and Gas Condensate

Storage Tanks................................................................................................................. 4-2

4-2 Vent Gas Emission Control Technology Review Economic Comparison of Flare

and VRU Technology (5-year straightline amortization of capital).............................. 4-7

4-3 Vent Gas Emission Control Technology Review Economic Comparison of Flare

and VRU Technology (5-year straightline amortization of capital).............................. 4-8

List of Figures

2-1 Example Storage Tank Battery with Separators............................................................ 2-2

2-2 Vent Gas Gathering Pipe atop Storage Tanks................................................................ 2-3

2-3 Fox Model 10A Flow Meter .......................................................................................... 2-4

2-4 The East Texas Study Area (ERG, 2005)...................................................................... 2-6
ES--1

Executive Summary

This document reports measurements of speciated volatile organic compound (VOC) 

emissions from oil and condensate storage tanks at wellhead and gathering site tank batteries in 

East Texas. The measurements were made by directly monitoring the flow rates of gases 

escaping from storage tank vents and sampling the vent gases for chemical composition. An

emission factor reflecting tank working, breathing, and flashing losses for each tank was

calculated by dividing the measured emission rate by the amount of oil or condensate produced

during the sampling period. The emission factors are expressed in units of pounds of VOC per 

barrel of liquid hydrocarbon produced (lb/bbl). Average emission factors for oil and condensate 

storage tanks were multiplied, respectively, by oil and condensate production totals for East 

Texas counties, including the Dallas-Fort Worth (DFW), Houston-Galveston-Brazoria (HGB), 

and Beaumont-Port Arthur (BPA) ozone nonattainment areas, to estimate regional emissions. 

Options for controlling tank battery vent gas emissions are also presented and discussed.

Emission measurements were made at 11 oil and 22 condensate tank battery sites in the 

BPA, DFW, and HGB areas during May-July, 2006. The average VOC emission factors for oil 

and condensate storage tanks were 1.6 ± 99% lb/bbl and 33.3 ± 73% lb/bbl, respectively, where 

the uncertainties are represented by the 95% confidence intervals of the means (Table ES-1).

Variable site characteristics such as separator temperature, separator pressure, and the 

physicochemical properties of the liquid hydrocarbons, in addition to very low condensate

production rates at well sites in Denton and Parker counties are probable leading causes of the

uncertainty. 

Table ES-1. Average, Standard Deviation, and Range of VOC Vent Gas Emission Factors 

Measured for Oil and Condensate Storage Tank Batteries

Emission Factor (lb/bbl)

Oil Tanks

Number Sampled =11

Condensate Tanks a

Number Sampled = 22

Arithmetic Mean 1.6 33.3

Standard Deviation 2.3 53.3

95% Confidence Interval for Mean 0.0 – 3.1 9.1 – 57.7

Minimum 0.0 0.7

Maximum 6.8 215.1

Median 0.8 12.0

a Excludes data from one well site that was not representative of normal operating conditions

Table ES-2 gives the total uncontrolled VOC emissions estimated for wellhead and 

gathering site storage tanks in the HGB, DFW, and BPA based on the arithmetic mean emission 
ES--2

factors given in Table ES-1 and 2005 daily average oil and condensate production1

The number and selection of tank batteries that were sampled in this study were limited 

by budget and schedule constraints in addition to the finite pool of host sites that provided 

voluntary access. Future studies can reduce average emission factor uncertainty and broaden 

their applicability by sampling a larger number of tank batteries and by conducting the tests 

during a wider variety of weather conditions, respectively. 

. These 

estimates assume no vent gas controls at any source; although, it is evident based on screening of 

candidate host sites that vent gas is recovered at some undetermined number of tank batteries in 

East Texas. Additional uncertainties in the regional emissions estimates stem from the average 

emission factor uncertainties, which as noted above are close to a factor of 2, and the small 

number of test sites relative to the entire population of storage tank batteries in East Texas. 

Table ES-2. Estimated VOC Emissions from Oil and Condensate Wellhead

and Gathering Site Storage Tanks

Nonattainment Area Oil 

(bbl/Year)

Condensate 

(bbl/Year)

Estimated VOC 

(Tons per Day)

BPA 2,419,201 3,065,105 145

DFW 102,558 816,724 38

HGB 9,875,858 5,858,404 289

East Texas Attainment Counties a 49,939,437 16,171,858 846

East Texas Region Total a 62,337,054 25,912,091 1,317

a The East Texas Region is defined by all the Texas counties that are traversed by or east of Interstate-35

or Interstate-37, plus Montague, Wise, Parker, Hood, Somervell, and Bosque counties

 1 The 2005 oil and condensate production levels were downloaded during July 2006 from the Texas Railroad 

Commission Production Data Query System, which is located on the Internet at 

http://www.rrc.state.tx.us/interactive_data.html.
1-1

1.0 Introduction

This document reports measurements of speciated volatile organic compound (VOC) 

emissions from oil and condensate storage tanks at wellhead and gathering site tank batteries in 

East Texas. The measurements were made by directly monitoring the flow rates of gases 

escaping from storage tank vents and sampling the vent gases for chemical composition. An

emission factor reflecting tank working, breathing, and flashing losses for each tank was 

calculated by dividing the measured emission rate by the amount of oil or condensate produced 

during the sampling period. The emission factors are expressed in units of pounds of VOC per 

barrel of liquid hydrocarbon produced (lb/bbl). Average emission factors for oil and condensate 

storage tanks were multiplied, respectively, by oil and condensate production totals for East 

Texas counties, including the Dallas-Fort Worth (DFW), Houston-Galveston-Brazoria (HGB), 

and Beaumont-Port Arthur (BPA) ozone nonattainment areas, to estimate regional emissions. 

Options for controlling tank battery vent gas emissions are also presented and discussed.

The remainder of this section provides the objectives of this study and background 

information on vent gas emissions from oil and condensate storage tanks. Sections 2 and 3 of 

this report give the measurement approach and results, respectively. Section 4 describes options 

for controlling tank battery vent gas emissions. Conclusions and recommendations for future 

work are provided in Section 5. 

1.1 Objectives

The objective of this Texas Environmental Research Consortium (TERC) study is to 

support the Texas Commission on Environmental Quality (TCEQ) in its efforts to evaluate ozone 

control strategies for DFW and HGB by conducting three specific tasks:

1) Develop average emission factors, in units of pounds of VOC per barrel of oil or 

condensate produced (lb/bbl), from direct measurements of vent gas flow rates and 

chemical composition;

2) Use the average emission factors to estimate regional uncontrolled emissions for East 

Texas ozone nonattainment areas and the East Texas Region as a whole; and

3) Identify and compare options for controlling vent gas emissions.

The emissions estimates produced by this study are intended to improve the quality of 

region photochemical modeling that TCEQ is performing in support of the ozone State 

Implementation Plans (SIPs) for the HGB and DFW areas.
1-2

1.2 Background

Measurements conducted by the National Oceanic and Atmospheric Administration 

(NOAA) and other research organizations during the 2000 Texas Air Quality Study (TexAQS 

2000) suggested that the levels of volatile organic compounds (VOC) found in ambient air could 

not all be accounted for based on reported emissions estimates. Following this finding, the 

Texas Commission on Environmental Quality (TCEQ) began an intensive effort to identify, 

quantify, and reduce VOC emissions that previously had been underestimated. In 2005, using 

remote sensing measurement results, TCEQ identified oil and condensate storage tanks as a 

source category for potentially underestimated emissions (TCEQ, 2005).

Oil and condensate storage tank emissions at wellhead and gathering sites are composed 

of working losses, breathing losses, and flashing losses. Working losses are vapors that are 

displaced from a tank during the filling cycle and breathing losses are vapors that are produced in 

response to diurnal temperature changes. Flashing losses are vapors that are released when a 

liquid with entrained gases experiences a pressure drop, as during the transfer of liquid 

hydrocarbons from a wellhead or separator to a storage tank that is vented to the atmosphere. 

The U.S. Environmental Protection Agency (EPA) TANKS model (all versions as of 

September 2006) does not calculate flash emissions; however, several other methods are 

available for estimating flash emissions from oil and condensate storage tanks. These methods, 

to name a few, include direct measurement of vent gas flow and chemical composition; process 

simulator models such as HYSIM®, WINSIM® and PROSIM®; the American Petroleum 

Association’s E&P Tank model; and the Vasquez-Beggs equation. These emissions estimating 

tools are described elsewhere (TCEQ, 2006; ODEQ, 2004). TCEQ (2006) considers the direct 

measurement approach to be the most accurate for estimating oil and condensate storage tank 

emissions at wellhead and gathering sites; however, other, less accurate, approaches appear to be 

much more commonly used2

.

No reports of oil or condensate storage tank emission factors derived from direct vent gas 

measurements have been found in the public domain literature; however, Lesair Environmental, 

Inc. (2003) reported emission factors for 25 condensate storage tank batteries in Colorado based 

on sampling pressurized liquid from wellhead processing equipment and using the E&P Tank 

model and PROSIM® (Lesair Environmental, Inc., 2002) to calculate vent gas emissions. An 

analysis of the data by the Colorado Department of Public Health and Environment (CDPHE) 

produced average emission factors of 13.7 lb/bbl and 10.0 lb/bbl for different condensate 

 2 Costs may run approximately $2000-$3000 for a vent gas 24-hour flow rate measurement and grab sample for 

chemical composition. Direct measurements over weekly or monthly averaging periods may require installation of 

dedicated flow monitoring and data acquisition systems.
1-3

producing regions (CDPHE, 2006). When applied to condensate production rate estimates, 

CDPHE estimated a total uncontrolled emission inventory of 134 tons/day for the Denver Early 

Action Compact Area (CDPHE, 2004), an estimate that is roughly 25% of the total 

anthropogenic VOC emissions for the area. 
2-1

2.0 Technical Approach

This section describes the technical approach used to estimate emission factors and 

regional emissions of speciated VOC from oil and condensate storage tanks at wellhead and 

gathering sites in East Texas.

2.1 Selection of Sampling Sites

Producers of oil and condensate in the Houston-Galveston-Brazoria (HGB), 

Dallas-Fort Worth (DFW), and Beaumont-Port Arthur (BPA) ozone nonattainment areas were 

identified from a directory of entities registered with the Texas Railroad Commission's Oil 

and Gas Division. The oil and gas directory is available on the Internet at 

http://www.rrc.state.tx.us/divisions/og/ogdirectory/index.html. Telephone calls, explaining the 

purpose of this study and requesting permission to sample storage tank vent gas emissions, were 

placed to the top oil and condensate producers in the HGB, DFW, and BPA (about 40 companies 

producing greater than 1% of the total oil or condensate in any of the HGB, DFW, or BPA 

areas). The telephone canvassing yielded invitations from seven companies to perform the 

emission measurements at one or more wellhead or gathering sites. Reasons given for 

participating in the study included ground truthing of emissions estimates derived using other 

methods and evaluation of the economic value of vapor recovery. 

Efforts to gain broader participation in the study by other operating companies included a 

letter sent on TCEQ letterhead and an email message distributed by the Texas Oil & Gas 

Association (TXOGA) to its Upstream Environmental Committee, each explaining the purpose 

of the study and requesting voluntary cooperation. Neither of these additional efforts resulted in 

additional voluntary participation in the study.

Before any sampling was conducted at candidate tank battery sites, field inspections were 

made to determine the condition of the storage tanks and whether access to suitable sampling 

ports existed. The storage tank battery sites generally consisted of one or more wellheads, one or 

more high pressure separators and two or more storage tanks containing either water or liquid 

hydrocarbon (oil or condensate). A photograph of a typical storage tank battery site is shown in 

Figure 2-1. Five storage tank batteries out of 39 that we inspected were equipped with vapor 

recovery units. 

Some storage tank batteries in East Texas are configured with gun barrel tanks to separate 

the fluid produced from a well into oil, gas, and water upstream of the storage tanks. Some lease 

operators consider the gun barrel to be the only tank having flash emissions while the storage 

tanks are assumed to have only working and breathing emissions. Only one of the tank batteries 

that were sampled during this study was configured with a gun barrel tank.
2-2

Figure 2-1. Example Storage Tank Battery with Separators

The approximate age of the inspected tank batteries ranged from 2 to more than 50 years. 

The conditions of the storage tank batteries were found to vary quite a bit, with some older tanks 

being of bolted construction and the newer tanks being of welded construction. The welded tank 

batteries generally had piping for vent gas consolidation to a common vent. The storage tank 

capacities ranged from 300 to 500 barrels except for at one gathering station, which had tank 

capacities ranging from 5,000 to 10,000 barrels. This gathering station is identified below as 

Tank Battery #12.

Thirty-three tank batteries met the criteria for sampling vent gas emissions. Four of the 

older tanks that were inspected were not sampled because they had rusted tops with holes 

ranging in size from about one-half inch to over one foot diameter. Another two inspected sites 

did not meet our initial sampling criteria because vent gas was being controlled by vapor 

recovery units (VRUs). Later, with approval from HARC and TCEQ, we eliminated the 

condition against sampling tank batteries having vent gas controls as long as the control device 

could be switched off or bypassed to sample uncontrolled emissions. Indeed, Tank Batteries 3, 

5, and 6 had VRUs but were sampled with the VRUs switched off. Several tanks were found 

during our inspections with hatch covers that were left open allowing vent gas to escape. These 

tanks were sampled but only after the hatch covers were closed and sealed. Of the 33 tank 
2-3

batteries that were sampled, 27 transferred its liquid product by tanker truck, five by pipeline, 

and one by barge.

2.2 Meas urement Approach

Storage tank emissions were measured by determining vent gas flow rates and sampling 

the vent gas for chemical composition. Tank batteries having multiple tanks were sampled 

through common vent gas gathering pipes located at the tops of the tanks (see, for example, 

Figure 2-2). All vent gas measurements and sampling was conducted at atmospheric pressure. 

Thief hatches and other potential sources of fugitive emissions were all sealed before making any 

measurements.

Figure 2-2. Vent Gas Gathering Pipe atop Storage Tanks

Flow rates were measured using a Fox Instruments Model 10A Thermal Mass Flow 

Meter. This instrument uses a thermal flow sensor, which operates on the principle that fluids 

absorb heat. A heated sensor placed in the gas stream transfers heat to the gas in proportion to 

the mass flow rate. Using a bridge circuit, one sensor detects the gas temperature while a second 
2-4

sensor is maintained at a constant temperature above the gas temperature. The temperature 

difference results in a power demand that equals the gas mass flow rate. The thermal mass flow 

meter was certified traceable to the National Institute of Standards and Technology (NIST) in 

September 2005, with an accuracy of ± 0.75% of reading ± 0.5% of full scale. Flow rates were 

measured over periods of approximately 24 hours. Figure 2-3 shows the Fox flow meter 

connected to a storage tank vent.

Figure 2-2. Fox Model 10A Flow Meter

Vent gas composition was measured using the Gas Processors Association (GPA) 

Method 2286-95, titled “Tentative Method of Extended Analysis for Natural Gas and Similar 

Mixtures by Temperature Programmed Gas Chromatography” (GPA, 1995). This analytical 

method measures the chemical composition of gas mixtures using gas chromatography with 

flame ionization and thermal conductivity detectors.

The vent gas samples for laboratory compositional analysis were collected in 300 CC 

evacuated metal bottles. A flexible hose-metal tube combination was connected to one end of 

the bottle and a hand "squeeze" pump with one way valve was connected to the exit end of the 
2-5

bottle. The flex hose was inserted two feet into the instrumentation tube3 with flowing vent gas 

or into the stock tank just above the oil level. The valve on the "oil" side of the bottle was 

opened. Then the valve on the exit end of the bottle was opened. The hand pump with one way 

valve was pumped 150 times, both valves on the ends of the sample bottle were then closed, the 

sample unit was disassembled and the bottle was labeled with an identification tag to indicate the 

date and location of sample collection. The samples were hand delivered by the COMM 

Engineering field engineers to FESCO, Ltd. in Lafayette, Louisiana. From there, the samples 

were transported as registered hazardous cargo to the main FESCO laboratory in Alice, Texas, 

for analysis.

2.3 Development of Regional Emis s ion Es timates

An emission factor for each tank battery was derived from the field measurement of 

average vent gas flow rate, the compositional analysis, and measurement of oil or condensate 

production rate over the period in which the average flow rate was determined. The average 

emission factors for oil and condensate storage tanks were multiplied, respectively, by 2005 

annual oil and condensate production totals for East Texas counties (which were downloaded 

from the Texas Railroad Commission website during July 2006) and divided by 365 to estimate 

countywide daily vent gas emissions. The equation used to estimate countywide emissions is:

Emissions (ton/day) = [(EFo × Po) + (EFc × Pc)] ÷ 365

Where:

EFo and EFc = The arithmetic mean emission factors for oil and condensate tank 

batteries, respectively in lb/bbl; and 

Po and Pc = The county 2005 total oil and condensate production, respectively, in bbl.

The East Texas region for this study is defined by all the Texas counties that are traversed 

by or East of Interstate-35 or Interstate-37, including Montague, Wise, Parker, Hood, Somervell, 

and Bosque counties (Figure 2-4). 

 3 The "instrumentation tube" is a two inch diameter four foot long pipe into which all vent gas is routed so that all 

vent gas will flow across the thermal mass flow meter probe. The instrument probe of the thermal mass

flow meter is inserted horizontally at ninety degrees into the two inch "instrumentation tube." 
2-6

Figure 2-4. The East Texas Study Area (ERG, 2005)
3-1

3.0 Measurement Results

Table 3-1 gives the API gravities and separator discharge pressures for the 33 tank 

battery sites that were sampled. API gravities ranged from 19° to 48°, except at the 11 Denton 

County sites where API gravities ranged from 58° to 61°. Separator discharge pressures ranged 

from 34 psi to 48 psi except at the 11 Denton County sites and at one gathering station in 

Galveston County (Tank Battery 32). The Denton County separator discharge pressures were all 

approximately 200 psi and Tank Battery 32 in Galveston County had a separator discharge 

pressure of 121 psi. Brief descriptions of each tank battery site are given in Appendix A.

Tables 3-2 and 3-3 summarize the measurement results for oil and condensate tank 

batteries, respectively, and give the calculated emission factors in units of pounds VOC per 

barrel of oil/condensate produced. The emission factor for each tank battery was derived using 

the following equation.

EF = (Vent Gas × MW × F) ÷ (379 × PR);

Where:

EF = the VOC emission factor in lb/bbl;

Vent Gas = vented gas in scf/day;

MW = molecular weight of the vented gas in lb/lb-mole;

F = VOC weight fraction of the vented gas;

PR = oil or condensate production rate in bbl/day; and

379 = volume to mass conversion factor in scf/lb-mole at standard atmospheric 

pressure and 60°F

For example, Tank Battery No. 1 has:

1.59 lb/bbl = (4153 scf/day × 44.84 lb/lb-mol × 0.81) ÷ (379 scf/lb-mol × 250 bbl/day)

Site-specific emission factors for oil storage tank batteries ranged from 0.0 to 6.8 lb/bbl, 

with an arithmetic mean and 95% confidence interval of 1.6 ± 1.5 lb/bbl. Note that the vent gas 

from Tank Battery # 8, which had the lowest emission factor, 0.0 lb/bbl, was comprised entirely 

of methane, ethane, and carbon dioxide (Table 3-4). 

Site specific emission factors for condensate storage tank batteries ranged from 0.7 to 

1218 lb/bbl; however, the vent gas flow rate at Tank Battery #26, which had the highest emission 

factor, was measured during non-representative conditions in which approximately 97% of the 

vented volume was released during the first eight hours of the sampling period. Operating 
3-2

personnel at Tank Battery #26 attributed this anomaly to fracking at an adjacent well. Fracking 

is a process in which fluids are injected into a well bore under high pressure to force the release 

of oil or gas from rock formations. Excluding Tank Battery #26, the arithmetic mean emission 

factor and 95% confidence intervals for condensate storage tank vent gas was 33.3 ± 24.3 lb/bbl.

Table 3-1. API Gravities and Separator Discharge Pressures for Sampled Tank Batteries

Tank 

Battery

Date 

Sampled

Liquid 

Hydrocarbon County API 

Gravity

Separator

Discharge Pressure

(PSI)

1 05/02/06 Oil Liberty 19 34

2 05/11/06 Condensate Montgomery 42 41

3 05/09/06 Condensate Montgomery 41 38

4 05/10/06 Condensate Montgomery 40 34

5 05/10/06 Condensate Montgomery 43 46

6 05/09/06 Condensate Montgomery 39 33

7 05/16/06 Oil Waller 20 40

8 05/17/06 Oil Waller 20 40

9 05/16/06 Oil Waller 20 40

10 05/17/06 Oil Waller 20 40

11 06/09/06 Oil Jefferson 42 36

12 06/09/06 Oil Jefferson 42 42

13 07/10/06 Condensate Denton 61 ~200

14 07/10/06 Condensate Denton 59 ~200

15 07/11/06 Condensate Denton 61 ~200

16 07/11/06 Condensate Denton 61 ~200

17 07/13/06 Condensate Denton 58 ~200

18 07/13/06 Condensate Denton 58 ~200

19 07/14/06 Condensate Denton 58 ~200

20 07/14/06 Condensate Denton 59 ~200

21 07/19/06 Oil Montague 47 48

22 07/19/06 Oil Montague 44 45

23 07/20/06 Condensate Parker 48 39

24 07/20/06 Condensate Parker 41 36

25 07/17/06 Condensate Denton 58 ~200

26 07/17/06 Condensate Denton 58 ~200

27 07/18/06 Condensate Denton 59 ~200

28 07/15/06 Condensate Brazoria 46 38

29 07/26/06 Condensate Brazoria 42 41

30 07/26/06 Condensate Brazoria 42 36

31 07/27/06 Oil Galveston 45 38

32 07/27/06 Condensate Galveston 48 121

33 07/27/06 Oil Galveston 43 44
3-3

Table 3-2. Vent Gas Flow Rates and Emissions for Oil Storage Tank Batteries

Tank 

Battery County Area Vent Gas(scf/day) a

Mol. 

Wt. b

Total Vent 

Gas

(lb/day) c

Wt. % 

VOC d

VOC

(lb/day) e

Oil Prod 

(bbl/day) f

VOC 

(lb/bbl) g

1 Liberty HGB 4,153 44.8 491.3 81% 397.9 250 1.59

7 Waller HGB 977 19.8 51.1 18% 9.4 200 0.05

8 Waller HGB 48 16.4 2.1 0% 0.0 50 0.00

9 Waller HGB 18 35.7 1.7 64% 1.1 65 0.02

10 Waller HGB 89 51.6 12.1 71% 8.6 30 0.29

11 Jefferson HGB 2,909 22.3 171.1 29% 48.9 250 0.20

12 Jefferson HGB 2,594 43.9 300.6 73% 220.8 250 0.88

21 Montague E TX 14,974 43.1 1,700.9 72% 1,219 180 6.77

22 Montague E TX 6,992 42.7 788.5 43% 335.7 63 5.33

31 Galveston HGB 2,047 32.1 173.4 57% 99.1 125 0.79

33 Galveston HGB 6,335 21.5 359.4 22% 79.7 60 1.33

Arithmetic Mean 3,740 34 368 48% 220 138 1.6

Standard Deviation 4,438 12 504 27% 359 89 2.3

Minimum 18 16 2 0% 0 30 0.0

Maximum 14,974 52 1,701 1 1,219 250 6.8

Median 2,594 36 173 57% 80 125 0.8

a Measured vent gas flow rate in scf/day.

b Molecular weight of the vent gas sample.

c Vent gas emissions converted to units of lb/day.

d VOC content of vent gas, as percentage of total weight (excludes methane, ethane, carbon dioxide and nitrogen contents of the vent gas).

e Measured VOC emissions expressed in units of lb/day.

f An earlier version of this report attributed oil production rate data to the Texas Railroad Commission online interactive database. That was 

incorrect. Daily average oil production rates rates during the sampling period were obtained from site operating logs.

g VOC emission factor in units of lb/bbl.
3-4

Table 3-3. Vent Gas Flow Rates and Emissions for Condensate Storage Tank Batteries

Tank 

Battery County Area Vent Gas(scf/day) a

Mol. 

Wt. b

Total Vent 

Gas

(lb/day) c

Wt. % 

VOC d

VOC

(lb/day) e

Cond. Prod 

(bbl/day) f

VOC 

(lb/bbl) g

2 Montgomery HGB 11,406 27.3 821.3 47% 383.2 105 3.65

3 Montgomery HGB 12,642 33.4 1,113.8 62% 688.9 87 7.92

4 Montgomery HGB 1,807 34.3 163.4 57% 93.7 120 0.78

5 Montgomery HGB 863 42.2 96.2 70% 67.4 100 0.67

6 Montgomery HGB 6,200 36.4 594.6 65% 384.7 130 2.96

13 Denton DFW 793 46.4 97.0 81% 78.5 2 39.23

14 Denton DFW 2,744 30.5 220.7 53% 118.0 4 29.51

15 Denton DFW 584 47.6 73.4 82% 60.0 5 11.99

16 Denton DFW 1,084 50.0 143.1 85% 121.2 2 60.58

17 Denton DFW 4,594 36.6 443.2 65% 290.2 2 145.11

18 Denton DFW 1,015 38.9 104.2 70% 73.4 10 7.34

19 Denton DFW 291 44.3 34.0 77% 26.3 2 13.16

20 Denton DFW 3,113 46.4 380.8 80% 304.3 10 30.43

23 Parker DFW 1,358 51.9 185.9 81% 150.2 27 5.56

24 Parker DFW 53 43.0 6.0 70% 4.2 1 4.22

25 Denton DFW 926 89.0 217.4 99% 215.1 1 215.08

27 Denton DFW 235 54.0 33.5 86% 28.8 2 14.39

28 Brazoria HGB 2,846 30.2 226.9 55% 125.2 30 4.17

29 Brazoria HGB 21,601 43.5 2,476.4 83% 2,055 61 33.68

30 Brazoria HGB 1,639 34.2 147.9 62% 91.6 15 6.11

32 Galveston HGB 77,319 50.6 10,312.6 87% 9,016 142 63.49

26 Denton DFW 9,210 56.2 1,365.7 89% 1,218 1 1217.58

Arithmetic Mean i

7,291 43 852 72% 685 41 33.3

Standard Deviation i

16,906 13 2,238 13% 1,959 50 53.3

Minimum i

53 27 6 47% 4 1 0.7

Maximum i

77,319 89 10,313 99% 9,016 142 215.1

Median i

1,639 43 186 70% 121 10 12.0

a Measured vent gas flow rate in scf/day.

b Molecular weight of the vent gas sample.

c Vent gas emissions converted to units of lb/day.

d VOC content of vent gas, as percentage of total weight (excludes methane, ethane, carbon dioxide and nitrogen contents of the vent gas).

e Measured VOC emissions expressed in units of lb/day.

f An earlier version of this report attributed condensate production rate data to the Texas Railroad Commission online interactive database. That 

was incorrect. Daily average condensate production rates during the sampling period were obtained from site operating logs..

.

g VOC emission factor in units of lb/bbl.

i Excludes Tank Battery 26 (see text on page 3-1 for an explanation)
3-5

Table 3-4 gives the speciation profiles in weight percentages based on the extended gas 

analysis of vent gas samples collected from each oil storage tank battery. Table 3-5 gives the 

speciation profiles for condensate storage tank samples. Volatile organic compounds (which 

consisted of the entire gas analysis minus methane, ethane, carbon dioxide, and nitrogen)

comprised from 0% to 87% of the vent gas mass from oil tank batteries and from 53% to 99% of 

the vent gas mass from condensate tank batteries.

Table 3-6 gives the total uncontrolled VOC emissions estimated for wellhead and 

gathering site storage tanks in the HGB, DFW, and BPA based on the arithmetic mean emission 

factors given in Table ES-1 and 2005 daily average oil and condensate production4

. 

. The total 

uncontrolled VOC emissions estimate for HGB is 289 tons per day. The uncontrolled VOC 

emissions estimates for BPA and DFW are 145 tpd and 38 tpd, respectively; while the 

uncontrolled emissions estimate for the remainder of the East Texas Region is 846 tpd. These 

estimates assume no vent gas controls at any source; although, it is evident based on screening of 

candidate host sites that vent gas is recovered at some undetermined number of tank batteries in 

East Texas. Additional uncertainties in the regional emissions estimates stem from the average 

emission factor uncertainties, which as noted above are close to a factor of 2, and the small 

number of test sites relative to the entire population of storage tank batteries in East Texas. Users 

of these data should also be mindful that daytime high temperatures ranged from 98 – 107 F at 

Dallas-Fort Worth Airport during the 9-day period in mid-July, 2006, when condensate storage 

tanks were sampled in the DFW area. Hence, the average emission factors derived from these 

data are representative of weather conditions that are favorable for summertime ozone formation 

and accumulation but perhaps not for estimating annual emissions. 

 4 The 2005 oil and condensate production levels were downloaded during July 2006 from the Texas Railroad 

Commission Production Data Query System, which is located on the Internet at 

http://www.rrc.state.tx.us/interactive_data.html.
3-6

Table 3-4. Measured Vent Gas Speciation Profiles in

Weight Percent for Oil Tank Batteries

County:

Weight %

Site 1 Site 7 Site 8 Site 9 Site 10 Site 31 Site 33

Liberty Waller Waller Waller Waller Galveston Galveston

Nitrogen 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Carbon Dioxide 1.56 2.57 2.67 3.66 13.64 2.05 4.46

Methane 9.95 67.81 96.81 25.47 14.19 23.91 58.59

Ethane 7.50 11.23 0.53 6.46 1.38 16.91 14.75

Propane 21.83 14.91 0.00 12.75 1.83 21.82 9.97

Isobutane 9.84 0.51 0.00 5.35 0.65 9.94 3.57

n-butane 14.39 1.20 0.00 8.26 1.49 8.83 3.08

2,2-Dimethylpropane 0.06 0.00 0.00 0.06 0.00 0.16 0.06

Isopentane 7.20 0.05 0.00 4.22 1.53 3.83 1.45

n-pentane 5.54 0.13 0.00 2.59 1.07 2.59 0.88

2,2-Dimethylbutane 0.34 0.04 0.00 1.22 1.31 0.23 0.09

Cyclopentane 0.47 0.01 0.00 0.27 2.76 0.16 0.05

2,3-Dimethylbutane 0.53 0.06 0.00 2.17 0.84 0.29 0.08

2-Methylpentane 2.36 0.01 0.00 1.24 0.00 1.07 0.34

3-Methylpentane 1.27 0.00 0.00 0.96 0.97 0.57 0.17

n-Hexane 2.47 0.01 0.00 0.42 0.08 1.13 0.33

Methylcyclopentane 1.60 0.03 0.00 1.10 0.84 0.55 0.15

Benzene 0.28 0.00 0.00 0.25 0.01 0.29 0.09

Cyclohexane 1.89 0.01 0.00 0.68 0.43 0.78 0.20

2-Methylhexane 0.53 0.01 0.00 0.88 2.07 0.27 0.07

3-Methylhexane 0.50 0.01 0.00 0.32 0.23 0.26 0.07

2,2,4-Trimethylpentane 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Other C7's 1.30 0.16 0.00 4.20 9.27 0.59 0.16

n-Heptane 1.09 0.01 0.00 0.09 0.01 0.52 0.13

Methylcyclohexane 2.36 0.01 0.00 0.75 0.53 0.97 0.26

Toluene 0.62 0.01 0.00 0.37 0.18 0.24 0.09

Other C8's 1.78 0.11 0.00 5.45 18.98 0.76 0.22

n-Octane 0.48 0.01 0.00 0.48 1.39 0.23 0.08

Ethylbenzene 0.06 0.02 0.00 0.14 0.33 0.03 0.02

m+p-Xylene 0.28 0.02 0.00 0.56 0.38 0.13 0.08

o-Xylene 0.08 0.03 0.00 0.10 0.35 0.04 0.03

Other C9's 0.91 0.17 0.00 3.70 10.84 0.37 0.16

n-Nonane 0.22 0.01 0.00 0.89 0.51 0.12 0.07

Other C10's 0.51 0.46 0.00 3.16 8.81 0.21 0.16

n-Decane 0.07 0.02 0.00 0.49 0.28 0.05 0.04

Undecanes Plus 0.13 0.39 0.00 1.29 2.83 0.10 0.08

Sum 100.00 100.00 100.00 100.00 100.00 100.00 100.00

Wt% VOC a 80.99% 18.39% 0.00% 64.40% 70.80% 57.13% 22.19%

a Weight % VOC excludes nitrogen, carbon dioxide, methane, and ethane.
3-7

Table 3-4. (continued) Measured Vent Gas Speciation Profiles

in Weight Percent for Oil Tank Batteries

County:

Weight %

Site 11 Site 12 Site 21 Site 22

Mean Std. Dev.

Jefferson Jefferson Montague Montague

Nitrogen 0.00 0.00 0.00 0.00 0.00 0.00

Carbon Dioxide 3.58 3.69 10.58 45.84 8.57 12.93

Methane 59.43 13.96 9.36 8.46 35.27 30.21

Ethane 8.39 8.88 8.39 3.13 7.96 5.12

Propane 5.28 10.66 23.33 9.15 11.96 7.98

Isobutane 3.22 8.21 4.01 2.14 4.31 3.63

n-butane 3.74 8.56 16.42 9.85 6.89 5.46

2,2-Dimethylpropane 0.72 0.60 0.04 0.00 0.15 0.25

Isopentane 2.60 6.71 5.61 3.87 3.37 2.49

n-pentane 1.88 5.02 6.61 5.19 2.86 2.35

2,2-Dimethylbutane 0.46 0.97 0.02 0.02 0.43 0.50

Cyclopentane 0.13 0.28 0.63 0.39 0.47 0.79

2,3-Dimethylbutane 0.52 1.25 0.14 0.07 0.54 0.66

2-Methylpentane 0.84 2.32 1.89 1.26 1.03 0.89

3-Methylpentane 0.45 1.26 1.15 0.72 0.68 0.48

n-Hexane 0.80 2.21 2.75 1.87 1.10 1.05

Methylcyclopentane 0.46 1.30 1.56 0.99 0.78 0.59

Benzene 0.21 0.51 0.08 0.07 0.16 0.16

Cyclohexane 0.59 1.68 0.53 0.38 0.65 0.61

2-Methylhexane 0.22 0.62 0.36 0.22 0.48 0.59

3-Methylhexane 0.22 0.59 0.47 0.30 0.27 0.20

2,2,4-Trimethylpentane 0.00 0.00 0.00 0.00 0.00 0.00

Other C7's 0.71 1.85 1.82 1.13 1.93 2.71

n-Heptane 0.27 0.74 0.92 0.67 0.40 0.40

Methylcyclohexane 0.75 2.18 0.72 0.60 0.83 0.78

Toluene 0.23 0.75 0.11 0.16 0.25 0.24

Other C8's 0.88 2.77 1.30 1.05 3.03 5.52

n-Octane 0.08 0.47 0.33 0.29 0.35 0.39

Ethylbenzene 0.06 0.22 0.04 0.04 0.09 0.10

m+p-Xylene 0.19 1.04 0.05 0.10 0.26 0.31

o-Xylene 0.05 0.36 0.01 0.04 0.10 0.13

Other C9's 0.60 2.38 0.41 0.44 1.82 3.20

n-Nonane 0.08 0.92 0.11 0.22 0.29 0.34

Other C10's 0.88 3.43 0.18 0.55 1.67 2.65

n-Decane 0.20 0.86 0.05 0.46 0.23 0.27

Undecanes Plus 1.32 2.76 0.01 0.38 0.84 1.07

Sum 100 100 100 100 100 0

Wt% VOC a 29% 73% 72% 43% 48% 27%

a Weight % VOC excludes nitrogen, carbon dioxide, methane, and ethane.
3-8

Table 3-5. Measured Vent Gas Speciation Profiles in

Weight Percent for Condensate Tank Batteries

County:

Weight %

Site 13 Site 14 Site 15 Site 16 Site 17 Site 18 Site 19 Site 20

Denton Denton Denton Denton Denton Denton Denton Denton

Nitrogen 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Carbon Dioxide 0.65 2.20 0.82 0.59 1.71 0.85 0.67 0.66

Methane 8.53 31.52 6.52 5.83 23.26 20.24 13.81 7.91

Ethane 9.96 12.80 10.93 8.93 9.54 8.53 8.14 11.51

Propane 17.08 12.08 18.67 16.72 10.21 10.19 9.91 17.20

Isobutane 7.02 4.48 7.84 7.48 3.68 4.54 4.76 7.30

n-butane 15.93 9.14 15.50 16.24 8.30 9.53 11.02 14.69

2,2-Dimethylpropane 0.09 0.00 0.00 0.19 0.00 0.00 0.00 0.08

Isopentane 8.52 5.34 8.60 9.25 5.38 6.26 8.90 8.96

n-pentane 9.33 5.73 9.08 10.02 6.66 7.52 10.22 9.53

2,2-Dimethylbutane 0.27 0.18 0.27 0.30 0.19 0.25 0.38 0.32

Cyclopentane 0.19 0.10 0.15 0.20 0.16 0.15 0.20 0.15

2,3-Dimethylbutane 0.43 0.28 0.45 0.48 0.36 0.43 0.59 0.47

2-Methylpentane 3.77 2.55 4.17 4.31 3.58 4.23 5.29 4.08

3-Methylpentane 1.89 1.28 2.11 2.14 1.84 2.16 2.67 2.01

n-Hexane 4.73 3.15 5.26 5.12 5.22 5.98 6.58 4.72

Methylcyclopentane 0.78 0.46 0.76 0.77 0.86 0.83 0.94 0.63

Benzene 0.19 0.13 0.18 0.20 0.22 0.23 0.25 0.17

Cyclohexane 0.94 0.58 0.83 0.88 1.14 1.16 1.17 0.76

2-Methylhexane 1.11 0.84 1.05 1.16 1.44 1.68 1.65 1.05

3-Methylhexane 1.03 0.79 0.95 1.06 1.41 1.54 1.49 0.93

2,2,4-Trimethylpentane 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Other C7's 1.29 0.92 1.24 1.30 1.75 1.81 1.79 1.12

n-Heptane 1.82 1.43 1.50 1.84 2.77 2.87 2.66 1.57

Methylcyclohexane 1.28 0.97 0.93 1.23 1.98 1.84 1.79 1.03

Toluene 0.40 0.33 0.25 0.41 0.69 0.65 0.58 0.35

Other C8's 1.60 1.46 1.08 1.77 3.10 3.01 2.51 1.45

n-Octane 0.39 0.38 0.26 0.46 0.93 0.91 0.62 0.38

Ethylbenzene 0.01 0.02 0.01 0.02 0.04 0.03 0.02 0.01

m+p-Xylene 0.12 0.14 0.08 0.17 0.42 0.34 0.22 0.16

o-Xylene 0.02 0.02 0.01 0.02 0.07 0.04 0.03 0.02

Other C9's 0.45 0.46 0.28 0.59 1.43 1.36 0.77 0.50

n-Nonane 0.07 0.08 0.07 0.11 0.38 0.30 0.14 0.10

Other C10's 0.09 0.13 0.11 0.17 0.75 0.41 0.21 0.15

n-Decane 0.01 0.02 0.02 0.02 0.17 0.04 0.02 0.02

Undecanes Plus 0.02 0.04 0.04 0.03 0.38 0.09 0.04 0.03

Sum 100 100 100 100 100 100 100 100

Wt% VOC a 81% 53% 82% 85% 65% 70% 77% 80%

a Weight % VOC excludes nitrogen, carbon dioxide, methane, and ethane.
3-9

Table 3-5. (continued) Measured Vent Gas Speciation Profiles in

Weight Percent for Condensate Tank Batteries

County:

Weight %

Site 23 Site 24 Site 25 Site 26 Site 27 Site 28 Site 29 Site 30

Parker Parker Denton Denton Denton Brazoria Brazoria Brazoria

Nitrogen 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Carbon Dioxide 5.13 7.04 0.80 0.57 1.66 1.46 0.45 3.65

Methane 10.28 12.35 0.09 3.93 6.53 31.93 10.04 23.10

Ethane 3.79 10.46 0.19 6.35 5.83 11.46 6.54 11.31

Propane 3.31 12.62 0.43 12.70 9.84 15.54 21.42 16.47

Isobutane 3.58 5.99 0.43 5.82 5.17 7.81 24.37 8.90

n-butane 8.45 10.59 1.88 14.26 12.34 8.23 15.10 10.02

2,2-Dimethylpropane 0.16 0.17 0.02 0.13 0.10 0.10 0.17 0.19

Isopentane 9.76 6.89 4.69 9.59 8.76 4.57 8.77 6.60

n-pentane 9.87 6.44 7.67 11.47 10.03 3.35 4.75 4.37

2,2-Dimethylbutane 0.73 0.38 0.34 0.33 0.35 0.22 0.23 0.39

Cyclopentane 0.13 0.08 0.25 0.30 0.27 0.24 0.16 0.30

2,3-Dimethylbutane 0.84 0.46 0.78 0.62 0.56 0.33 0.45 0.50

2-Methylpentane 7.42 4.13 8.41 6.16 6.02 1.51 1.79 2.01

3-Methylpentane 3.90 2.18 4.31 2.97 2.94 0.78 0.81 1.06

n-Hexane 8.18 4.55 13.84 7.87 7.90 1.65 1.35 1.84

Methylcyclopentane 0.71 0.43 1.97 1.22 1.11 0.89 0.39 1.08

Benzene 0.39 0.19 0.52 0.27 0.27 1.07 0.28 1.35

Cyclohexane 1.39 0.75 3.08 1.37 1.49 1.01 0.51 1.09

2-Methylhexane 3.12 1.82 5.20 1.72 2.27 0.41 0.24 0.43

3-Methylhexane 2.43 1.45 4.43 1.50 1.94 0.40 0.21 0.40

2,2,4-Trimethylpentane 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Other C7's 1.82 1.00 4.22 1.74 1.94 0.80 0.47 0.87

n-Heptane 3.57 2.24 9.21 2.71 3.65 0.87 0.35 0.67

Methylcyclohexane 2.33 1.43 6.16 1.82 2.52 1.23 0.48 1.13

Toluene 1.08 0.67 2.12 0.56 0.83 0.68 0.10 0.67

Other C8's 4.16 2.82 9.77 2.24 3.34 1.09 0.32 0.73

n-Octane 1.06 0.80 3.05 0.59 0.87 0.45 0.08 0.21

Ethylbenzene 0.03 0.22 0.07 0.01 0.02 0.07 0.02 0.03

m+p-Xylene 0.43 0.32 0.98 0.20 0.29 0.21 0.02 0.13

o-Xylene 0.05 0.04 0.15 0.03 0.04 0.07 0.01 0.03

Other C9's 1.41 0.93 3.23 0.62 0.84 0.55 0.09 0.25

n-Nonane 0.22 0.23 0.64 0.13 0.14 0.23 0.02 0.07

Other C10's 0.25 0.30 0.77 0.18 0.13 0.41 0.03 0.11

n-Decane 0.04 0.06 0.28 0.05 0.02 0.11 0.00 0.02

Undecanes Plus 0.01 0.00 0.03 0.00 0.01 0.26 0.01 0.05

Sum 100 100 100 100 100 100 100 100

Wt% VOC a 80% 70% 99% 89% 86% 55% 83% 62%

a Weight % VOC excludes nitrogen, carbon dioxide, methane, and ethane.
3-10

Table 3-5. (continued) Measured Vent Gas Speciation Profiles in

Weight Percent for Condensate Tank Batteries

County:

Weight %

Site 2 Site 3 Site 4 Site 5 Site 6 Site 32 Mean Std

Montgomery Galveston

Nitrogen 0.57 0.00 0.00 0.00 0.00 0.00 0.03 0.12

Carbon Dioxide 4.24 3.54 7.44 9.10 5.81 0.83 2.72 2.64

Methane 39.71 26.30 22.07 12.06 19.27 2.15 15.34 10.73

Ethane 8.83 8.31 13.15 8.76 10.22 9.59 8.87 2.99

Propane 14.21 16.42 17.25 17.54 19.05 26.38 14.33 5.72

Isobutane 4.52 5.79 5.09 6.47 6.34 16.38 6.99 4.86

n-butane 8.44 10.73 8.70 11.92 11.79 14.83 11.26 3.47

2,2-Dimethylpropane 0.02 0.04 0.06 0.07 0.00 0.29 0.09 0.08

Isopentane 3.89 5.10 4.12 5.91 5.61 9.70 7.05 2.04

n-pentane 3.32 4.35 3.53 5.03 4.90 5.20 6.93 2.63

2,2-Dimethylbutane 0.11 0.18 0.15 0.21 0.18 0.83 0.31 0.17

Cyclopentane 0.37 0.57 0.44 0.68 0.62 0.22 0.27 0.17

2,3-Dimethylbutane 0.23 0.34 0.32 0.41 0.39 0.58 0.47 0.15

2-Methylpentane 1.19 1.72 1.51 2.05 1.97 2.25 3.64 2.03

3-Methylpentane 0.62 0.90 0.82 1.07 1.03 1.21 1.85 1.03

n-Hexane 1.21 1.79 1.68 2.13 1.97 1.94 4.48 3.11

Methylcyclopentane 1.35 2.01 1.80 2.40 2.05 0.77 1.10 0.58

Benzene 0.34 0.63 0.57 0.75 0.49 0.44 0.41 0.31

Cyclohexane 1.16 1.83 1.73 2.18 1.72 0.83 1.25 0.59

2-Methylhexane 0.33 0.50 0.40 0.60 0.37 0.45 1.27 1.15

3-Methylhexane 0.15 0.22 0.40 0.26 0.35 0.42 1.08 0.98

2,2,4-Trimethylpentane 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Other C7's 0.77 1.17 1.25 1.39 1.17 0.89 1.40 0.75

n-Heptane 0.47 0.76 0.81 0.91 0.64 0.69 2.00 1.90

Methylcyclohexane 1.52 2.54 2.51 3.03 1.94 0.93 1.85 1.16

Toluene 0.53 1.10 1.02 1.32 0.56 0.48 0.70 0.43

Other C8's 0.82 1.39 1.46 1.66 0.83 0.70 2.15 1.97

n-Octane 0.17 0.32 0.34 0.38 0.06 0.24 0.59 0.62

Ethylbenzene 0.04 0.06 0.06 0.07 0.03 0.03 0.04 0.04

m+p-Xylene 0.17 0.38 0.34 0.45 0.12 0.15 0.26 0.20

o-Xylene 0.04 0.08 0.07 0.10 0.02 0.04 0.05 0.03

Other C9's 0.31 0.54 0.57 0.64 0.39 0.26 0.75 0.67

n-Nonane 0.07 0.11 0.10 0.13 0.03 0.09 0.16 0.14

Other C10's 0.18 0.23 0.19 0.28 0.07 0.13 0.24 0.19

n-Decane 0.03 0.03 0.02 0.04 0.01 0.03 0.05 0.06

Undecanes Plus 0.07 0.05 0.05 0.05 0.02 0.07 0.06 0.09

Sum 100 100 100 100 100 100 100 0

Wt% VOC a 47% 62% 57% 70% 65% 87% 73% 14%

a Weight % VOC excludes nitrogen, carbon dioxide, methane, and ethane.
3-11

Table 3-6. Total Vent Gas and VOC Emissions for East Texas Counties

Region County Oil (bbl) Condensate (bbl) VOC (tons/day)

BPA HARDIN 1,240,479 470,853 24.2

BPA JEFFERSON 844,405 1,962,565 91.4

BPA ORANGE 334,317 631,687 29.6

BPA Total 2,419,201 3,065,105 145.2

DFW COLLIN 0 0 0.0

DFW DALLAS 0 0 0.0

DFW DENTON 31,209 729,760 33.4

DFW ELLIS 15 2 0.0

DFW JOHNSON 0 16,334 0.7

DFW KAUFMAN 55,574 0 0.1

DFW PARKER 15,760 65,330 3.0

DFW ROCKWALL 0 0 0.0

DFW TARRANT 0 5,298 0.2

DFW Total 102558 816,724 37.5

HGB BRAZORIA 1,697,448 719,494 36.5

HGB CHAMBERS 902,015 399,981 20.2

HGB FORT BEND 1,758,404 1,062,906 52.3

HGB GALVESTON 686,061 698,427 33.4

HGB HARRIS 1,529,176 515,274 26.8

HGB LIBERTY 1,412,532 2,256,552 106.1

HGB MONTGOMERY 756,038 142,456 8.1

HGB WALLER 1,134,184 63,314 5.3

HGB Total 9,875,858 5,858,404 288.7

East Texas ANDERSON 717,299 77,859 5.1

East Texas ANGELINA 4,022 3,831 0.2

East Texas ARANSAS 75,617 120,035 5.6

East Texas ATASCOSA 729,802 11,624 2.1

East Texas AUSTIN 265,450 138,234 6.9

East Texas BASTROP 93,440 12,139 0.8

East Texas BEE 320,007 202,036 9.9

East Texas BEXAR 122,739 0 0.3

East Texas BOSQUE 0 0 0.0

East Texas BOWIE 98,673 6,372 0.5

East Texas BRAZOS 1,960,987 83,578 8.0

East Texas BURLESON 2,157,633 89,232 8.7

East Texas CALDWELL 911,418 189 2.0

East Texas CALHOUN 372,434 129,446 6.7

East Texas CAMP 230,512 0 0.5

East Texas CASS 299,994 25,840 1.8

East Texas CHEROKEE 207,869 105,810 5.3

East Texas COLORADO 191,399 207,831 9.9

East Texas COOKE 1,573,679 22,650 4.4

East Texas DE WITT 63,426 660,652 30.3

East Texas FALLS 1,895 0 0.0

East Texas FAYETTE 1,432,596 306,067 17.1

East Texas FRANKLIN 387,794 59,908 3.6

East Texas FREESTONE 70,730 212,035 9.8

East Texas GOLIAD 337,355 581,157 27.3

East Texas GONZALES 214,143 11,900 1.0

East Texas GRAYSON 1,462,839 15,484 3.8

East Texas GREGG 2,738,433 203,848 15.2

East Texas GRIMES 122,487 55,957 2.8

East Texas GUADALUPE 1,349,477 353 2.9

East Texas HARRISON 459,255 530,475 25.2

East Texas HAYS 0 0 0.0

East Texas HENDERSON 575,893 42,701 3.2

East Texas HILL 2 0 0.0

East Texas HOOD 0 29,818 1.4

East Texas HOPKINS 361,851 2,612 0.9

East Texas HOUSTON 745,024 27,023 2.8
3-12

Table 3-6. (continued) Total Vent Gas and VOC Emissions for East Texas Counties

Region County Oil (bbl) Condensate (bbl) VOC (tons/day)

East Texas HUNT 0 0 0.0

East Texas JACKSON 747,698 309,131 15.7

East Texas JASPER 192,489 261,183 12.3

East Texas KARNES 266,421 82,701 4.3

East Texas LAVACA 138,396 395,281 18.3

East Texas LEE 1,599,865 51,564 5.8

East Texas LEON 954,219 65,828 5.1

East Texas LIMESTONE 91,433 73,589 3.6

East Texas LIVE OAK 440,424 191,048 9.7

East Texas MADISON 499,267 34,036 2.6

East Texas MARION 124,307 52,424 2.7

East Texas MATAGORDA 525,512 655,690 31.1

East Texas MCLENNAN 1,787 0 0.0

East Texas MILAM 509,923 225 1.1

East Texas MONTAGUE 1,453,589 8,246 3.5

East Texas MORRIS 2,218 0 0.0

East Texas NACOGDOCHES 3,510 278,609 12.7

East Texas NAVARRO 266,939 8,330 1.0

East Texas NEWTON 590,680 48,582 3.5

East Texas NUECES 532,854 861,081 40.5

East Texas PANOLA 382,559 1,768,349 81.6

East Texas POLK 548,423 523,988 25.1

East Texas RAINS 0 0 0.0

East Texas RED RIVER 167,665 0 0.4

East Texas REFUGIO 4,903,379 49,884 12.8

East Texas ROBERTSON 1,093,976 34,972 3.9

East Texas RUSK 2,373,074 329,178 20.1

East Texas SABINE 5,246 0 0.0

East Texas SAN AUGUSTINE 5,693 67 0.0

East Texas SAN JACINTO 34,696 194,018 8.9

East Texas SAN PATRICIO 408,206 967,860 45.1

East Texas SHELBY 62,081 173,367 8.0

East Texas SMITH 1,200,518 402,060 20.9

East Texas SOMERVELL 0 0 0.0

East Texas TITUS 503,970 0 1.1

East Texas TRAVIS 1,449 0 0.0

East Texas TRINITY 88,108 2,804 0.3

East Texas TYLER 298,463 2,143,080 98.5

East Texas UPSHUR 150,052 504,137 23.3

East Texas VAN ZANDT 936,231 7,734 2.4

East Texas VICTORIA 650,188 176,360 9.4

East Texas WALKER 3,093 2,885 0.1

East Texas WASHINGTON 484,995 150,890 7.9

East Texas WHARTON 1,234,462 715,697 35.3

East Texas WILLIAMSON 8,966 0 0.0

East Texas WILSON 281,082 68 0.6

East Texas WISE 387,282 639,902 30.1

East Texas WOOD 4,127,875 30,314 10.2

East Texas Total (Excluding HGB, BPA, and 

DFW) 49,939,437 16,171,858 845.7

Grand Total 62,337,054 25,912,091 1317.1
4-1

4.0 Control Options

This section provides a general discussion of control technologies that are relevant to 

vent gas from produced oil and gas condensate storage tanks. Table 4-1 outlines the advantages 

and disadvantages of each technology. The technology choice for a given vent stream is 

dependent on the vent flow, vent composition, and site considerations. 

4.1 Common Control Options

The use of flares and vapor recovery units (VRUs) are the most common control methods 

for the control of volatile organic compound (VOC) emissions due to flash streams. A more 

detailed economic comparison of these methods is shown in Section 4.4. 

4.1.1 Open Flares

Open flares are the lowest capital cost emission control device for vent gases from 

produced oil and gas condensate storage tanks. A typical open flare for this application would be 

a 2” to 4” diameter pipe that is approximately 20’ tall. The burner tip (flare tip) is located at the 

top of the pipe. A continuously lit pilot ensures that vent gases are combusted at the flare tip. 

Pilot fuel requirements are estimated at 20 scfh (standard cubic feet per hour) for this device.

A flame or detonation arrestor is recommended to ensure safe operation in this 

application. A small air blower may also be provided to prevent visible smoke at the top of the 

stack, depending on the composition of the vent gases. Solar powered piezoelectric ignition and 

flame detection can be used at sites that do not have electricity. 

A properly operated flare can achieve a destruction efficiency of 98 percent or greater 

(EPA, 1991).

4.1.2 Enclosed Flares

Enclosed flares combust the vent gases inside of the stack, avoiding the aesthetic 

concerns that can accompany visible flames produced by open flares. A typical open flare for 

this application would be a 24” to 48” diameter pipe and the stack would be approximately 10’ –

20’ tall. More burner tips are provided than for the open flare and the burner tips are located low 

enough inside the stack that there is no visible flame outside the stack. Air is drawn in through 

an adjustable opening in the bottom of the flare stack. A continuously lit pilot ensures that vent 

gases are combusted at the flare tip. Pilot fuel requirements are estimated at 20 scfh for this 

application.
4-2

Table 4-1. Advantages and Disadvantages of Emission Control Devices

and Emission Control Strategies for Vent Gases from

Produced Oil and Gas Condensate Storage Tanks5

Control Device / Control 

Strategy Advantages Disadvantages

Open Flare Low capital cost.

Low maintenance.

Electricity not required.

Visible flame.

Wastes potential value of vent stream.

Pilot fuel requirements.

Enclosed Flare Low capital cost.

Low maintenance.

Electricity not required.

Wastes potential value of vent stream.

Pilot fuel requirements.

Compressor-Based Vapor 

Recovery

Recovers high value vent stream.

Compress into sales gas line or use 

for fuel gas requirement.

More expensive than flares. 

Requirement for on-site fuel is needed or 

sales gas compressor inlet must accept gas 

at ~ 30 – 70 psig.

Eductor-Based Vapor 

Recovery

Recovers high value vent stream.

Compress into sales gas line or use 

for fuel gas requirement. 

Avoids moving parts and operating 

costs associated with a mechanical 

compressor.

Relatively new technology for this 

application.

May require use of high pressure (sales) gas 

for motive force in eductor.

Requirement for on-site fuel is needed or 

sales gas compressor inlet must accept gas 

at eductor discharge pressure (~ 40 psig).

Pressurized Storage Tanks Gases that would previously have 

been emissions are trucked out as 

revenue generating liquid at higher 

pressure or vapors can be used onsite for fuel or further compressed 

to sales gas pressure.

Pressurized transport trucks are required.

Capital costs approximately two times 

higher than atmospheric storage tanks.

Micro-turbine Generators Gases that would have previously 

been emissions are converted into 

electricity.

It is possible to replace 

combustion-driven equipment with 

electrical driven equipment on-site, 

resulting in more sales gas and 

lower emissions.

On-site need for electricity or access to 

local power grid required.

Relatively expensive equipment requires 

longer operation time to recoup costs.

Refrigeration-Based Vapor 

Recovery

Gases that would previously been 

emissions are converted into liquid 

hydrocarbon for sales.

Electricity is required for condenser for 

refrigeration system. 

Non-condensable vapors must be controlled 

or compressed and used as fuel or sales gas 

to achieve complete emission control.

Tank Consolidation Emissions are reduced, but not 

eliminated.

Minimal capital expenditure.

Lowers cost of future emission 

controls that may be added.

Lowers maintenance costs.

Not a significant reduction in flash 

emissions – just fugitive and breathing 

losses.

Adding Intermediate Pressure 

Separator or Lowering 

Separator Pressure

Additional gas and liquid 

hydrocarbon recovery is possible.

Low capital expenditure.

Must use on-site for fuel or a control device 

for additional vapors generated by 

intermediate and/or lower pressure 

separator.

 5 Biofiltration and activated carbon adsorption were not considered viable control techniques for vent gas emissions 

because of the relatively high operation and maintenance requirements and cost, respectively.
4-3

A flame or detonation arrestor is recommended to ensure safe operation in this 

application. Solar powered piezoelectric ignition and flame detection can be used at sites that do 

not have electricity.

A properly operated flare can achieve a destruction efficiency of 98 percent or greater 

(EPA, 1991).

4.1.3 Compressor-based Vapor Recovery Units

Higher oil and gas prices favor recovery of vent gases from produced oil and gas 

condensate storage tanks in lieu of combustion for the sake of emission control. Vapors can be 

collected from the storage tank vents and compressed to a pressure of 30 to 70 psig using a 

reciprocating, rotary vane or flooded screw compressor. The intermediate pressure vapors are 

used on on-site as fuel for combustion-fired process units such as heater-treaters and glycol 

dehydrator reboilers or they are routed to the suction side of sales gas compressors where they 

are further compressed to pipeline specification pressure and sold as product. Any liquids 

produced are collected in knockout pots and are returned to condensate storage tanks. The 

compressors are equipped with pressure sensors and bypass capability to prevent pulling a 

vacuum on the storage tanks. Properly maintained vapor recovery units can recover over 95% of 

potential vent gas emissions (EPA, 2003).

4.1.4 Eductor-based Vapor Recovery Units

Eductor systems have been developed for compression of produced oil and gas 

condensate storage tank vapors. High velocity liquid water or high velocity natural gas is used 

as the motive force to boost the pressure of the vent gases in the eductor. Vapors are collected 

from the storage tank vents and compressed to a pressure on the order of 40 psig at the outlet of 

the eductor. This system is equipped with flow safety valves, flow control mechanisms, pressure 

sensing, and temperature sensing devices which allow the system to operate under varying vent 

gas flow rates and prevent pulling a vacuum on the storage tanks. The intermediate pressure 

vapors are used on on-site as fuel for combustion-fired process units such as heater-treaters or 

glycol dehydrator reboilers or they are routed to the suction side of sales gas compressors where 

they are further compressed to pipeline specification pressure and sold as product. The eductor 

avoids the moving parts and energy costs associated with a compressor-based VRU.

Vapors are compressed using high velocity (high pressure) liquid water or natural gas as 

the motive force to boost the pressure of the vent gases entering the eductor. The eductor can 

only boost pressure to about 50 psig (typical site fuel gas pressure). If the vapors must be further 

compressed to reach a sales pipeline, a conventional compressor would be required. 
4-4

Properly maintained vapor recovery units can recover over 95% of potential vent gas 

emissions (EPA, 2003).

4.2 Site-specific Control Methods

Other emission control devices that are potentially applicable, but less likely to be 

universally implemented at East Texas oil and gas production sites are described below. If site 

and vent stream conditions are favorable, these methods can be competitive with the more 

common types already discussed.

4.2.1 Pressurized Storage Tanks

Pressurized storage tanks are another method that can be used to effectively eliminate 

emissions. The pressurized tank operates at high enough pressure that vapors from it can be used 

in local heaters or more easily compressed into the sales gas line. Costs for the tanks are 

estimated at $ 2.15 to $ 2.75 per gallon of storage capacity. Unless a condensate stabilizer is also 

used to reduce the oil vapor pressure, this approach also requires the use of pressurized transport 

vehicles, which are more expensive and less available than conventional atmospheric transport 

vehicles. An increase in product recovery is projected to compensate for the higher storage and 

transportation costs over a two year period. To be economical, this control method requires a 

rich vent gas stream and a high flow rate. It is more applicable to a central processing facility or 

a large tank battery. The reduction in vent gas emissions using pressurized tanks and a 

pressurized load out truck should be almost 100%. 

4.2.2 Micro-turbine Generators

Vent gases from produced oil and gas condensate storage tank can be compressed in a 

compressor and then burned in micro-turbines to generate electricity. This approach will be 

most applicable at sites that have a relatively steady vent gas supply from the storage tank battery 

and also a demand for electrical power or access to a utility power grid. It is also possible in 

some cases to replace aging combustion-driven equipment on site with electric-driven equipment 

which results in more sales gas and lower emissions.

Micro-turbine generators are more expensive than other control strategies and will 

require maintenance from experienced technicians. A longer expected period of production at 

the site is required to recoup the higher capital and operating costs. 

4.2.3 Refrigeration-based Vapor Recovery 

Refrigeration may be used to condense vent gases from produced oil and gas condensate 

storage tanks. This results in a liquid hydrocarbon product that will help to offset the operating 

and capital cost of the refrigeration equipment. Electrical power is required to operate the 

refrigeration system. The non-condensable vent gases can be compressed and used for fuel on-
4-5

site or sent to sales in order to achieve complete control of the emissions using this approach. 

Non-condensable gases could also be routed to a small flare. These units are more expensive 

than other vapor recovery units. 

4.3 Emission Control Strategies

In some cases, operational changes can result in emissions reductions from produced oil 

and gas condensate storage tanks. Such changes will reduce emissions, but the amount of the 

reduction is dependent on stream and site conditions. Strategies that involve operational 

changes, which might also be considered “best practices”, are described below.

4.3.1 Storage Tank Consolidation

Tank consolidation is one method that will help reduce emissions from produced oil and 

gas condensate storage tanks. Use of fewer hydrocarbon liquid storage tanks at a given site will 

reduce fugitive emissions and standing (breathing) losses due to temperature variations. The 

reduction of emissions due to tank consolidation will be more significant in fields where 

production levels have dropped, but multiple tanks are still being used.

 

Reducing the number of hydrocarbon liquid storage tanks in service at a given site also 

reduces maintenance costs and makes implementation of any subsequent emission control 

devices more economical.

4.3.2 Lower Operating Pressure in Separators

If the pressure of the liquids entering the produced oil and gas condensate storage tanks is 

higher than 40 or 50 psig, installation of an intermediate pressure separator and lowering the 

existing separator pressure to approximately 30 psig or just lowering the operating pressure in 

the existing separator to approximately 30 psig will reduce flashing losses from the storage 

tanks. Additional liquid hydrocarbons may also be recovered if an intermediate separator is 

added. It would be advantageous to use an intermediate separator if there is a site fuel gas 

requirement. Flash gas from the separator could supply a fuel gas header. Flashing losses can 

also be reduced by lowering the temperature of the heater treater, although that may adversely 

affect crude oil quality.

4.4 Economic Comparison of Common Control Technologies

Two of the most common technologies for controlling flash emissions are flares and 

compression-based VRUs. To compare the costs of these control technologies, a design basis 

was developed that encompassed the sampling results described in Section 3 of this report. A 

request for quote was prepared and sent to companies that provide open flares, enclosed flares, 

VRUs with compression, and VRUs with eductor. The request for quote is attached in Appendix 

B of this report.
4-6

Two flow rates, 5 Mscfd (Thousand Standard Cubic Feet per Day) and 25 Mscfd were 

listed in the request. Assuming 50% of the vent stream is non methane/ethane and the molecular 

weight is 35, the VOC emissions for the two flow rates are:

• 42 tpy VOC at 5 Mscfd; and 

• 211 tpy VOC at 25 Mscfd.

For the purposes of these cost estimates, the installed capital costs for flares and VRUs were 

equal to 1.5x and 2.5x the equipment cost, respectively. Note that the actual costs will vary from 

site to site depending on the lengths of piping required and other factors. No interviews with oil 

and gas production site operators were conducted to bracket the actual installed costs that might 

be incurred installing flares or VRUs at East Texas tank battery sites. Other cost assumptions 

were:

• Capital cost amortized over 5 years (Table 4-2) and 2 years (Table 4-3); 

• Natural gas had a value of $5/Mscf for calculating fuel gas requirement; and

• Vent gas value calculated as NG value x 2 (accounts for 2000 Btu/scf heating value).

Although two flow rates were listed in the request for quote, the vent gas flows are 

relatively low, and most vendors used the same equipment to handle both. As a result, the 

control cost of each technology in $/ton controlled is much lower for the higher flow case (25 

Mscfd). 

The results of the comparison are illustrated in Tables 4-2 and 4-3. Table 4-2 spreads the 

capital cost over five years, more typical of control technology evaluations. Table 4-3 shortens 

this period to two years because of the short production life that can be experienced at many of 

these sites. Table 4-3 represents a source that may have a high vent gas rate due to initial 

production rates, but experiences a sharp decline. In such a case, control might not be required 

and also might not be economical after two years. These control technologies are designed to be 

mobile and can be moved to a new site once the proper site preparation is done. 
4-7

 

 

 

Case 1 - High Flow Units Value Case 2 - Low Flow Units Value

Inlet gas rate Mscfd 25 Inlet gas rate Mscfd 5

Inlet VOC content vol% 50% Inlet VOC content vol% 50%

VOC Emissions tpy 210.67 VOC Emissions tpy 42.13

Natural Gas Cost/Value $/Mscf 5 Natural Gas Cost/Value $/Mscf 5

Vent stream MW lb/mol 35 Vent stream MW lb/mol 35

Vent Heating Value Btu/scf 2000 Vent Heating Value Btu/scf 2000

Total Capital Contribution

Installed Capital to Total Treating DRE

Technology Cost ($) Cost ($/yr) %

25 Mscfd 5 Mscfd 25 Mscfd 5 Mscfd 25 Mscfd 5 Mscfd 25 Mscfd 5 Mscfd

Open Flare * $22,000 $4,400 $900 $900 NA NA 5,300 5,300 $25 $126 98

Enclosed Flare $40,000 $8,000 $900 $900 NA NA 8,900 8,900 $40 $210 98

VRU - Compression $60,000 $12,000 $11,400 $2,000 $91,300 $18,300 (67,900) (4,300) -$320 -$100 99+

VRU - Eductor** $95,000 $19,000 $ 0 ** $ 0 ** $91,300 $18,300 (72,300) 700 -$340 $20 99+

Notes: 1) 1.5x capital installation factor for flares, 2x capital installation factor for VRUs

2) Operating cost represents cost of fuel requirement, uses NG cost factor above, $5/Mscf

3) Operating credit represents the value of vent gas recovered, calculated as NG value x (vent gas heating value / 1000)

4) Price quoted for VRU - Eductor was turn-key installed price, no multiplier is used for installation

5) VRU capital and operating costs do not include costs to compress from fuel gas pressure (30-70 psig) to sales gas/pipeline pressure.

* Open flare prices are based on vendor quotes with guaranteed performance. Flares can be constructed in the field for a fraction of these costs.

** VRU - Eductor has 0 operating cost if on-site demand for fuel gas exceeds volume of gas leaving the eductor. Otherwise operating costs would be higher 

for recompression of gas leaving the eductor than those for recompression of gas leaving a VRU-compressor to sales gas/pipeline pressure due to higher 

volume of gas requiring compression in the VRU - Eductor case.

Average Total

Treating Cost

($/ton VOC)

Operating Cost

Cost

($/yr) ($/yr) ($/yr)

Operating Credit Average Total

Recovered fuel gas Treating Cost

Table 4-2. Vent Gas Emission Control Technology Review 

Economic Comparison of Flare and VRU Technology

(5-year straightline amortization of capital
4-8

 

 

 

Case 1 - High Flow Units Value Case 2 - Low Flow Units Value

Inlet gas rate Mscfd 25 Inlet gas rate Mscfd 5

Inlet VOC content vol% 50% Inlet VOC content vol% 50%

VOC Emissions tpy 210.67 VOC Emissions tpy 42.13

Natural Gas Cost/Value $/Mscf 5 Natural Gas Cost/Value $/Mscf 5

Vent stream MW lb/mol 35 Vent stream MW lb/mol 35

Vent Heating Value Btu/scf 2000 Vent Heating Value Btu/scf 2000

Capital Contribution

Total Capital to Total Treating DRE

Technology Cost ($) Cost ($/yr) %

25 Mscfd 5 Mscfd 25 Mscfd 5 Mscfd 25 Mscfd 5 Mscfd 25 Mscfd 5 Mscfd

Open Flare * $22,000 $11,000 $900 $900 NA NA 11,900 11,900 $56 $282 98

Enclosed Flare $40,000 $20,000 $900 $900 NA NA 20,900 20,900 $100 $500 98

VRU - Compression $60,000 $30,000 $11,400 $2,000 $91,300 $18,300 (49,900) 13,700 -$240 $330 99+

VRU - Eductor** $95,000 $47,500 $ 0 ** $ 0 ** $91,300 $18,300 (43,800) 29,200 -$210 $690 99+

Notes: 1) 1.5x capital installation factor for flares, 2x capital installation factor for VRUs

2) Operating cost represents cost of fuel requirement, uses NG cost factor above, $5/Mscf

3) Operating credit represents the value of vent gas recovered, calculated as NG value x (vent gas heating value / 1000)

4) Price quoted for VRU - Eductor was turn-key installed price, no multiplier is used for installation

5) VRU capital and operating costs do not include costs to compress from fuel gas pressure (30-70 psig) to sales gas/pipeline pressure.

* Open flare prices are based on vendor quotes with guaranteed performance. Flares can be constructed in the field for a fraction of these costs.

** VRU - Eductor has 0 operating cost if on-site demand for fuel gas exceeds volume of gas leaving the eductor. Otherwise operating costs would be higher 

for recompression of gas leaving the eductor than those for recompression of gas leaving a VRU-compressor to sales gas/pipeline pressure due to higher 

volume of gas requiring compression in the VRU - Eductor case.

Average Total

Treating Cost

($/ton VOC)

Operating Cost

Cost

($/yr) ($/yr) ($/yr)

Operating Credit Average Total

Recovered fuel gas Treating Cost

Table 4-3. Vent Gas Emission Control Technology Review 

Economic Comparison of Flare and VRU Technology

(2-year straightline amortization of capital
4-9

4.5 Site-specific Factors

Site specific factors play a critical role in determining the best choice of VOC emission 

control from produced oil and gas condensate storage tanks. Some of these factors include:

1. Composition of the vent gas;

2. Field pressure or intermediate separator pressure;

3. Pressure of the vent gas;

4. Value of the vent gas (as fuel gas, sales gas or as a recovered liquid);

5. Availability of electricity;

6. Need for on-site fuel gas;

7. Sales gas compressor suction and discharge pressure specifications; and

8. The site’s progress along the declining production curve that defines the projected 

lifetime and production rates for the site.

It is important to consider these and other factors in the analysis of what technology to apply at a 

location. 
5-1

5.0 Discussion, Conclusions, and Recommendations

This document reports measurements of speciated volatile organic compound (VOC) 

emissions from oil and condensate storage tanks at wellhead and gathering site tank batteries in 

East Texas. The measurements were made by directly monitoring the flow rates of gases 

escaping from storage tank vents and sampling the vent gases for chemical composition. An 

emission factor reflecting tank working, breathing, and flashing losses for each tank was 

calculated by dividing the measured emission rate by the amount of oil or condensate produced 

during the sampling period. The emission factors are expressed in units of pounds of VOC per 

barrel of liquid hydrocarbon produced (lb/bbl). Average emission factors for oil and condensate 

storage tanks were multiplied, respectively, by oil and condensate production totals for East 

Texas counties, including the Dallas-Fort Worth (DFW), Houston-Galveston-Brazoria (HGB), 

and Beaumont-Port Arthur (BPA) ozone nonattainment areas, to estimate regional emissions. 

Emission measurements were made at 11 oil and 22 condensate tank battery sites in the 

BPA, DFW, and HGB areas during May-July, 2006. The average VOC emission factors for oil 

and condensate storage tanks were 1.6 ± 99% lb/bbl and 33.3 ± 73% lb/bbl, respectively, where 

the uncertainties are represented by the 95% confidence intervals of the means. Variable site 

characteristics such as separator temperature, separator pressure, and the physicochemical 

properties of the liquid hydrocarbons, as well as very low condensate production rates at well 

sites in Denton and Parker counties are probable leading causes of uncertainty. 

The average emission factor for condensate storage tanks reported here is more than

twice the average reported for condensate storage tanks in Colorado that were sampled as part of 

an earlier study for the Colorado Oil & Gas Association (Lesair, 2003). The Lesair study 

estimated vent gas VOC emissions for 25 condensate storage tanks statewide, 16 of which were

in the DJ Basin, near Denver. The average emission factors from that study were 13.7 ± 32% 

lb/bbl and 17.0 ± 32% lb/bbl for the statewide and DJ Basin tanks, respectively. Note that the 

Lesair study did not measure vent gas emissions directly but modeled emissions using E&P 

Tanks and the compositions and properties of pressurized liquid hydrocarbons sampled from the 

separator. Other explanations for the higher condensate tank emission factor reported here might 

include differences in wellhead or separator pressures, or the very hot ambient temperatures that 

persisted during the 9-day period when all the Denton and Parker county condensate storage 

tanks were sampled.6

The total uncontrolled VOC emissions estimated for wellhead and gathering site storage 

tanks in the HGB, DFW, and BPA based on the arithmetic mean emission factors reported here 

are 289 tons/day, 38 tons/day and 145 tons/day, respectively. These estimates assume no vent 

 6 Daytime high temperatures at DFW Airport ranged from 98 – 107 F.
5-2

gas controls at any source; although, it is evident based on screening of candidate host sites that 

vent gas is recovered at some undetermined number of tank batteries in East Texas. Additional 

uncertainties in the regional emissions estimates stem from the average emission factor 

uncertainties, which as noted above are close to a factor of 2, and the small number of test sites 

relative to the entire population of storage tank batteries in East Texas. 

The number and selection of tank batteries that were sampled in this study were limited 

by budget and schedule constraints in addition to the finite pool of host sites that provided 

voluntary access. Future studies can reduce average emission factor uncertainty and broaden 

their applicability by sampling a larger number of tank batteries and by conducting the tests 

during a wider variety of weather conditions, respectively.
6-1

6.0 References

CDPHE, 2004. Colorado State Implementation Plan for Ozone, Appendix C, Technical Support 

Document. Colorado Department of Public Health and Environment. February 26, 2004.

CDPHE, 2006. Oil and Gas Exploration & Production Condensate Tanks, an Overview of Air 

Quality Regulations. Colorado Department of Public Health and Environment. March 

2006.

EPA, 1991. Compilation of Air Pollution Emission Factors. Volume 1: Stationary Point and 

Area Sources, Fifth Edition, AP-42, Section 13.5. Industrial Flares. U.S. 

Environmental Protection Agency, Office of Air Quality Planning and Standards, 

Research Triangle Park, NC. September 1991.

EPA, 2003. Lessons Learned from Natural Gas Star Partners: Installing Vapor Recovery Units 

on Crude Oil Storage Tanks. U.S. Environmental Protection Agency, Air and Radiation, 

EPA430-B-03-015. October 2003.

Gas Processors Association, 1995. Tentative Method of Extended Analysis for Natural Gas and 

Similar Gaseous Mixtures by Temperature Programmed Gas Chromatography. GPA 

Standard 2286-95, Gas Processors Association, Tulsa, OK. 1995.

Lesair Environmental, Inc., 2003. Colorado E&P Storage Tank Emission Factor Development. 

Presented to the Denver Regional Air Quality Council, November 5, 2003. Accessed 

from 

http://www.raqc.org/ozone/EAC/Nov5/Lesair%20SPE%20Presentation%20100603.pdf

on April 3, 2009.

ODEQ, 2004. Calculation of Flashing Losses/VOC Emissions from Hydrocarbon Storage 

Tanks. Oklahoma Department of Environmental Quality. July 19, 2004.

TCEQ, 2005. TexAQS II Remote Sensing VOC Project (information provided by TCEQ staff). 

May 2005.

TCEQ, 2006. 2005 Emissions Inventory Guidelines Technical Supplement 6: Above Ground 

Liquid Storage Tanks. Texas Commission on Environmental Quality. January 2006.
APPENDIX A

Tank Battery Summary Information
A-1
A-2
A-3
A-4
A-5
A-6
A-7
A-8
A-9
A-10
A-11
A-12
A-13
A-14
A-15
A-16
A-17
A-18
A-19
A-20
A-21
A-22
A-23
A-24
A-25
A-26
A-27
A-28
A-29
A-30
A-31
A-32
A-33
APPENDIX B

Request for Quotation for Produced Oil

and Gas Storage Tank Vent Gas
Request For Quotation for Produced Oil and Gas Storage Tank Vent Gas

Background:

A client needs to evaluate control options to recover or destroy a vent stream for VOC emission reasons.

Sources are storage tank batteries for produced oil and gas condensate.

There are two flow rate options to consider because there are several sources (similar in size) separated by some distance. 

The decision to treat at each site or a central facility will be made based on the cost of control and other logistical issues.

Vent Stream Composition:

Nitrogen 0.5

Carbon Dioxide 4.0

Methane 45.5

Ethane 12.0

Propane 15.0

Isobutane 4.0

N-butane 7.0

2-2 Dimethylpropane < 0.1

Isopentane 2.5

N-pentane 2.5

Hexanes 2.5

hexanes plus 5.0

Pressure (psig) < 1

Temperature (F) 100

Flow Rate Cases

1) Individual site 5 Mscfd

2) Central facility 25 Mscfd

Facility Information:

• All equipment must be gas fired

• All instruments must be pneumatic

Quote Detail (be sure to include the following):

• Provide description of equipment, including approximate footprint

• Equipment cost

• Utility requirement to calculate operating costs (i.e., fuel gas)

• Destruction or recovery efficiency

Fax or Email Quote To

joe.lundeen@trimeric.com or ray.mckaskle@trimeric.com

425-963-1139 (efax)

Contact for Questions/Clarification

Joe Lundeen - 512-658-6313 Ray McKaskle - 512-785-4939


Section A1

Revision 1

January 13, 2005

Page 1 of 1

EVALUATION OF VOC EMISSIONS FROM FLASH AND CONDENSATE 

TANKS (H-51-C)

QUALITY ASSURANCE PROJECT PLAN

Prepared by:

URS Corporation

9400 Amberglen Blvd.

Austin, TX 78729

Prepared for:

Houston Advanced Research Center

4800 Research Forest Drive

The Woodlands, TX 77381

January 13, 2006

Approvals:

Albert Hendler, URS Project Manager: ____________________________________________

Date 

Don Burrows, URS QA Coordinator: ____________________________________________

Date

Kevin Fisher, Trimeric Project Manager: ____________________________________________

Date

Alex Cuclis, HARC Project Manager: ____________________________________________

Date
Section A2

Revision 1

January 13, 2006

Page 1 of 1

A2. Table of Contents

A. Project Management

Page

A1. Title Page and Approval Sheet ............................................................... A1-1

A2. Table of Contents ............................................................................... A2-1

A3. Distribution List ..................................................................................A3-1

A4. Project Organization ............................................................................A4-1

A5. Project Definition and Background ...........................................................A5-1

A6. Project Description ..............................................................................A6-1

A7. Quality Objectives and Criteria ...............................................................A7-1

A8. Special Training and Certifications ...........................................................A8-1

A9. Documents and Records ........................................................................A9-1

B. Measurement and Quality Control

B1. Experimental Design ............................................................................B1-1

B2. Sampling and Measurement Methods .........................................................B2-1

B3. Sample Handling and Custody .................................................................B3-1

B4. Analytical Methods ..............................................................................B4-1

B5. Quality Control ..................................................................................B5-1

B6. Equipment Testing, Inspection, and Maintenance...........................................B6-1

B7. Instrument Calibration and Frequency ........................................................B7-1

B8. Inspection/Acceptance of Supplies and Consumables ......................................B8-1

B9. Non-direct Measurements ......................................................................B9-1

B10. Data Management ..............................................................................B10-1

C. Assessment

C1. Assessments and Response Actions ..........................................................C1-1

C2. Reports to Management ........................................................................C2-1

D. Data Validation

D1. Data Review, Verification, and Validation ..................................................D1-1

D2. Verification and Validation Methods .........................................................D2-1

D3. Reconciliation with User Requirements ......................................................D3-1
Section A3

Revision 0

December 30, 2005

Page 1 of 1

A3. Distribution List

Albert Hendler URS Al_hendler@urscorp.com 512-419-6438

Carl Galloway URS Carl_galloway@urscorp.com 512-419-5335

Don Burrows URS Don_burrows@urscorp.com 512-454-4797

Alex Cuclis HARC acuclis@harc.edu 281-364-4049

Ita Ufot TCEQ iufot@tceq.state.tx.us 512-239-1935

Martha Maldonado TCEQ mmaldona@tceq.state.tx.us 512-239-1999

Teresa Hurley TCEQ thurley@tceq.state.tx.us 512-239-5316

Russ Nettles TCEQ rnettles@tceq.state.tx.us 512-239-1493

Bertie Fernando TCEQ bfernand@tceq.state.tx.us 512-239-1536

Dave Harper TCEQ dharper@tceq.state.tx.us 512-239-5746

Kevin Fisher Trimeric Kevin.fisher@trimeric.com 512-431-6323

Joe Lundeen Trimeric Joe.Lundeen@trimeric.com 512-658-6313
Section A4

Revision 2

July 31, 2006

Page 1 of 3

A4. Project Organization

A4.1 Purpose of Study

The purpose of this project is to develop speciated VOC emission factors and an 

inventory of speciated VOC emissions from liquid hydrocarbon (i.e., oil and condensate) storage 

tanks and pressurized vessels (i.e., separators and heater treaters) at oil and gas production sites 

in east Texas. The emission factors and emissions inventory are intended to be used by the 

Texas Commission on Environmental Quality (TCEQ) for evaluating ozone control strategies for 

the Dallas-Fort Worth (DFW) and Houston-Galveston-Brazoria (HGB) ozone nonattainment

areas. Storage tanks and pressurized vessels at oil and gas production sites may emit a 

significant fraction of the total anthropogenic VOC emitted in east Texas; however, no accurate 

regional emissions inventory currently exists for this source category.

A4.2 Roles and Responsibilities 

The project organization is presented in Figure A-1. The responsibilities of the key 

project staff follow the organizational chart.

Figure 1. Project Organization

The responsibilities of the project staff as they relate to the six tasks described in Section 

A6 are given below.

HARC

Project Manager

Alex Cuclis

URS

Project Manager

Albert Hendler

Task 1

QAPP

Albert Hendler

Don Burrows

Task 2

Field Sampling 

and Analysis

Jim Nunn

Task 3

Literature Search

Albert Hendler

Task 4

Emissions 

Estimation

Albert Hendler

Task 5

Control Options 

Analysis

Kevin Fisher 

Task 6

Reporting

Albert Hendler

URS

QA Coordinator

Don Burrows

Laboratory 

Analysis

FESCO, LTD
Section A4

Revision 2

July 31, 2006

Page 2 of 3

Albert Hendler (URS):

Task 1: QAPP

• Prepare QAPP

Task 3: Literature Search

• Perform literature search

• Document results

Task 4: Estimate Emissions

• Perform emissions estimate calculations

Task 6: Management and Reporting

• Provide project management, primary contact point for HARC

• Prepare monthly progress reports

• Track status of budget, schedule, and deliverables

Don Burrows (URS):

Task 2: QAPP

• Review QAPP

• Execute QA activities throughout project

Jim Nunn (COMM Engineering):

Task 2: Field Sampling and Analysis

• Lead field sampling effort

• Document field measurements and activities

• Coordinate laboratory analyses

Kevin Fisher (Trimeric):

Task 1: QAPP

• Identify candidate sampling sites

• Perform and document site visits

• Recommend sampling protocols

Task 6: Management and Reporting

• Manage Trimeric subcontract budget and deliverables

• Assist with report preparation
Section A4

Revision 2

July 31, 2006

Page 3 of 3

Joe Lundeen (Trimeric):

Task 1: QAPP

• Identify candidate sampling sites

• Perform and document site visits

• Recommend sampling protocols

Task 5: Control Options Analysis

• Manage Task

Task 6: Management and Reporting

• Assist with report preparation

Ray McKaskle (Trimeric):

Task 5: Control Options Analysis

• Perform control options analysis

FESCO, Ltd.:

Task 2: Field Sampling and Analysis

• Perform compositional analysis of vent gas samples by GPA Method 2286
Section A5

Revision 1

January 13, 2006

Page 1 of 1

A5. Problem Definition and Background

Storage tanks and pressurized vessels at oil and gas production sites may emit a 

significant fraction of the total anthropogenic VOC emitted in east Texas; however, no accurate 

regional emissions inventory currently exists for this source category. Unconfirmed estimates of 

VOC emissions from oil and condensate storage tanks are given in Table A-1. These estimates 

were derived using an emission factor of 13.7 pounds per barrel and oil and condensate 

production data from the Texas Railroad Commission website (www.rrc.tx.state.us). The 

emission factor was developed by the Colorado Department of Public Heath and Environment 

(CDPHE) based on sampling at condensate production sites in northeastern Colorado. Actual 

emission factors for east Texas oil and gas production sites may differ from the CDPHE estimate 

due to differences in the processing equipment on site and in the physical properties of the 

hydrocarbon liquids that are produced. The estimates in Table A-1 assume no controls on vent 

gas emissions; however, in reality the extent of controls throughout the region is unknown.

Table A-1. Oil and Condensate Production in East Texas for January-September 2005 and 

Estimated Uncontrolled VOC Emissions for Storage Tanks

Area Oil Production 

(BBL)

Condensate 

Production (BBL)

Estimated VOC 

(Tons/Day) 1

HGB 7,299,830 4,056,616 288

DFW 64,115 572,249 16

BPA 1,830,510 2,342,594 106

Rest of East Texas 36,762,823 10,806,740 1,207

1

Based on the CDPHE condensate production emission factor of 13.7 pounds per barrel.

Emissions from flashing are a significant, perhaps the major, component of storage tank 

vapor emissions to the air at oil and gas production sites. Flashing occurs when liquid 

hydrocarbons undergo pressure drops from processing pressures to atmospheric pressures as the 

liquids are transferred from high pressure separators or heater treaters into storage tanks. Unlike 

working and breathing losses, the two other components of storage tank emissions, flashing 

losses are not accounted for by the EPA Tanks model; however, several alternate methods for 

estimating flash emissions are available. For this project, flash emissions, along with working 

and breathing emissions, will be measured by direct sampling of the tank vent gas and 

measurement of the vent gas flow rate. 
Section A6

Revision 1

January 13, 2006

Page 1 of 3

A6. Project Description

URS will develop speciated VOC emission factors and an inventory of speciated VOC 

emissions from liquid hydrocarbon storage tanks and pressurized vessels at oil and gas 

production sites in east Texas, with emphasis on the DFW and HGB ozone nonattainment areas 

as well as Jefferson County. This will be achieved in two steps. First, field sampling will be 

conducted at a number of oil and gas production sites to measure VOC emission rates and collect

data on liquid hydrocarbon, i.e., oil or condensate, production. Second, regionally representative 

emission factors (in units of pounds of VOC emitted per barrel of oil or condensate produced) 

will be derived from the field data and applied to archived east Texas oil and gas production data 

to estimate monthly, annual, and average ozone season daily emissions on a county-by-county 

basis. A literature search for related emission factors and an analysis of control strategy options 

will also be conducted. This section gives a summary of the work to be performed. Specific 

data collection and analysis activities are described in greater details in Sections B1-B10 of this 

QAPP.

Task 1: Quality Assurance Project Plan

URS will develop a Quality Assurance Project Plan (QAPP) that describes the methods 

that will be used to acquire and analyze data as well as the procedures that will be used to assure 

the quality of the collected data and the accuracy of all calculations. The QAPP will conform, in 

content and format, to guidelines offered by the U.S. EPA document, titled EPA Requirements 

for Quality Assurance Project Plans QA/R-5. The QAPP will be drafted by the URS Project 

Manager and reviewed by the URS Quality Assurance Coordinator for this project. A draft

QAPP will be submitted to HARC for review. Comments on the draft QAPP will be addressed 

and a revision will be submitted to HARC for approval within seven days after the comments are 

received.

Task 2: Field Sampling and Data Collection

Field sampling and measurement data will be gathered at approximately 30-40 

representative oil and gas well sites in the DFW, HGB areas and Jefferson County. The 

composition of vent gases escaping from storage tanks will be measured by collecting grab 

samples from tank vents (or other suitable access ports, such as thief hatches, that would allow 

collection of samples from the vapor space) and sending the samples to SPL, Inc. laboratory for 

analysis. Flow rate measurements at each site will be made continuously over a 24-hour period 

to account for fluctuations that result from the tank loading cycles. Samples for compositional 

analysis and measurements of flow rate will also be collected from separators or heater treaters 

that are vented to the atmosphere. Emission rate measurements, based on vent gas composition 

and flow rate, will be divided by the barrels of oil or condensate produced during the 24-hour 

flow rate measurement to derive emission factors in units of pounds VOC emitted per barrel of 

oil or condensate produced (lbs/bbl).
Section A6

Revision 1

January 13, 2006

Page 2 of 3

Task 3: Literature Search

Information on emission factors reported in the literature or used by state regulatory 

agencies to estimate VOC emissions from liquid hydrocarbon storage tanks at oil and gas 

production sites will be gathered and summarized. As part of this task, URS will also survey 

emission inventory specialists from other oil and gas producing states over the telephone to 

identify emission factors and the approaches used for developing emission factors for oil and gas 

production sites. Information acquired by this task will be compared with field measurements 

from Task 2 and possibly used to supplement the field measurements when applying 

representative emission factors to parts of east Texas that will not be directly sampled.

Task 4: Emission Inventory Development

URS will develop a regional inventory of VOC emissions from liquid hydrocarbon 

storage tanks at oil and gas production facilities in east Texas (Figure A-2). Emission factors 

developed from Task 2 (and perhaps supplemented with information from Task 3) will be 

applied to archived oil and gas production data to estimate monthly, annual, and ozone season 

daily average emission rates on a county-by-county basis for east Texas. C1 through C12 

alkanes, along with benzene, toluene, ethylbenzene, and xylene will be reported.

Task 5: Control Technology Evaluation

The approximate costs and benefits of available options for controlling VOC emissions 

from liquid hydrocarbon storage tanks at oil and gas production facilities will be analyzed and 

reported. As part of this task, the applicability of vapor recovery to oil and gas production sites 

in east Texas will be evaluated.

Task 6: Management and Reporting

The URS project manager will track the budget, schedule, and status of all project 

deliverables, and report to HARC via monthly progress reports and periodic teleconferences on 

progress made toward achieving the project goals. In addition to providing an update on project 

financials, activities, and milestones achieved, each progress report will identify problems 

encountered as well as recommendations or efforts made toward problem resolution. Draft and 

final reports will be prepared and submitted to HARC to document the methods, results, and 

conclusions of this project. 
Section A6

Revision 1

January 13, 2006

Page 3 of 3

Figure A-2. East Texas Study Area (ERG, 2005)
Section A7

Revision 1

January 13, 2006

Page 1 of 1

A7. Quality Objectives

Table A-2 gives the quality objectives for direct measurements made as part of this 

project. Vent gas flow rate measurements will be made over 24-hour periods using an 

instrument capable of measuring flow rates to an accuracy of ± 10% of the average reading 

during the test. A broad range of flow rates is likely to be encountered which may require the 

use of different kinds of flow measurement instruments to meet the accuracy requirement. For 

example, extremely low vent flow rates may be more amenable to measurement by vane 

anemometer while a pitot tube or orifice plate meter may be used for the higher flow rates.

Additionally, vent gas grab samples for offsite compositional analysis will be collected, 

one per site, with the analytical accuracy objective being ± 10% for each reported compound. 

The completeness objective for vent gas flow rate and compositional analysis is at least 30 

measurements (with each flow rate measurement reported as a 24-hour average). 

Table A-2. Quality Objectives for Direct Measurements

MEASUREMENT 

VARIABLE

SAMPLE 

DURATION

SAMPLE 

FREQUENCY

ACCURACY COMPLETENESS

Vent Gas Flow 

Rate

24-hours Continuous/recorded 

as 1-minute 

averages

± 10% of 

reading

≥30 sites monitored

Vent Gas 

Composition

< 1 minute 

grab sample

One per site ± 10% 

defined as 

analytical 

repeatability

≥30 sites sampled
Section A8

Revision 1

January 13, 2006

Page 1 of 1

Section A8. Special Training/Certification

No special training or certifications are required for the project personnel; however, 

knowledge of the oil and gas production industry and possession of the source sampling 

technical skills needed to adapt to the wide range of source configurations likely to be 

encountered in this project are essential. The project team drawn together for this project 

possesses those attributes.

The field sampling task leader for this project has 25 years experience in emissions 

measurements, specializing in the development and application of sampling systems and 

measurement techniques for the types of adverse conditions likely to be encountered.

The field work will be supported by a team of chemical engineers and engineering 

technicians with 15+ years experience, most of which has been in the oil and gas production 

industry. The team has led and conducted numerous field tests involving flow measurements, 

sample collection, and analysis of various hydrocarbon streams. The team has direct experience 

in the use of a wide range of measurement techniques and equipment, e.g. pitot-tubes, vane 

anemometers, and orifice meters. This same team is also experienced in the process design and 

troubleshooting of oil and gas facilities, as well as in making emission estimates for such 

facilities.
Section A9

Revision 1

January 13, 2006

Page 1 of 2

A9. Documents and Records

A9.1. Communicating QA Project Plan Information

At the start of the project, the URS Project Manager will prepare a Project Management 

Plan containing information on the technical scope, budget, schedule, deliverables and contact 

information for all key project personnel. The Project Management Plan will also delineate the 

roles and responsibilities of key project staff. In addition to the Project Management Plan, this 

QAPP and any future revisions will be provided by the Project Manager to each project team 

member via hardcopy or email according to the distribution list given in Section A3 of this 

QAPP. Version control will be maintained using the document control format prescribed by the 

EPA QA/R-5 guidance document, an example of which is shown in the page header.

A9.2 Information Included in the Reporting Package

A list of documents and records that will be developed and maintained by the project 

team follows. Each item will be submitted to HARC as a draft for review before being submitted 

in final form. Note that information identifying the specific oil and gas production sites from 

where measurements were made, and the site operating companies, will be deleted from all 

hardcopy and electronic files delivered to HARC or its designees. The following items will be 

delivered:

• Field sampling logs (hardcopy);

• Raw flow rate measurement data (electronic spreadsheet);

• Laboratory data reports (hardcopy or electronic spreadsheet);

• Data used for emission factor calculations (electronic spreadsheet);

• Data used for emission inventory development (electronic spreadsheet);

• Speciated VOC emissions for east Texas counties (electronic spreadsheet); and

• Report of methods, activities, and results (hardcopy and electronic document).

Field sampling logs, which will be included in the reporting package, will contain the 

following information:

• A simple schematic diagram of the tank battery operation, with processing 

equipment and showing the location of the sampling port;

• County and geologic formation;

• Sampling date and time;

• Temperature of liquid product (if available);

• Amount of oil or condensate produced during the sampling period (in barrels);

• The well type (i.e., oil, gas, or casinghead);

• The number of wells served by the tank battery;

• The temperature of product leaving the separator (if available);

• The number of tanks in the tank battery;

• The approximate tank dimensions (i.e., diameter and height);
Section A9

Revision 1

January 13, 2006

Page 2 of 2

• The type of tank (i.e., oil, condensate, saltwater, gun barrel);

• The color, approximate age, condition and construction (i.e., bolted or welded) of 

the tanks; and

• The approximate age of the processing equipment.

A9.3 Retention and Final Disposition of Records

URS will store all records and documents developed for this project in a centralized filing 

system maintained by its Austin office for at least ten years following the completion of the 

project.
Section B1

Revision 1

January 13, 2006

Page 1 of 3

B1. Experimental Design

Field sampling and measurements will be performed at representative oil and gas 

production sites in the DFW Ozone Nonattainment Area as well as the HGB Ozone 

Nonattainment Area and the neighboring Jefferson County. Approximately 30-40 oil and gas 

production sites will be sampled. The sampling and measurement data will be used to derive 

factors for speciated VOC emissions in units of pounds of VOC emitted per barrel of oil and 

condensate produced, and ultimately used to develop a regional inventory of storage tank 

emissions from oil and condensate production in east Texas.

Figure B-1 is a schematic diagram of a typical oil or gas production site (Southern 

Research Institute, 2002). The well stream is first passed through a separator or a heater treater 

where liquid hydrocarbons (i.e., oil or condensate), gas, and water are separated. The gas exiting 

the separator is routed to a gas dehydrator to remove excess water or to a field compressor that

pressurizes the gas to pipeline sales pressure. Liquid hydrocarbons are routed to a tank (or a 

battery of more than one tank) where the hydrocarbons are stored in order to stabilize flow 

between production wells and pipeline or transportation by truck. Water is stored in a separate 

tank in preparation for disposal. Sites configured substantially different from the typical site will 

be not be sample since as they might be considered unrepresentative of the broader population of 

oil and gas production sites in the region.

Figure B-1. Schematic Diagram of an Oil and Gas Production Facility (Southwest 

Research Institute, 2002)

VOC emission rates will be measured by sampling the tank vent gas for compositional 

analysis and measuring the vent gas flow rate. Measurements of separator gas vented to the 

atmosphere will also be made. The concentration of each C1-C6 gas component in the sample, 
Section B1

Revision 1

January 13, 2006

Page 2 of 3

plus benzene, toluene, ethyl benzene, xylene (BTEX) and other C6+ VOC will be multiplied by 

the flow rate (averaged over 24-hours) to produce measurements of mass emission rates for each 

of the reported gas constituents and other C6+ VOC in units of pounds per hour. The mass 

emission rates will then be divided by the number of barrels produced during the 24-hour flow 

measurement period to produce emission factors in units of pounds per barrel. Critical 

measurements for this approach include the following:

• Vent gas composition;

• Vent gas flow rate; and

• Oil or condensate production rate

Approximately 30-40 well sites in the DFW, HGB, and Jefferson County areas will be 

selected for sampling based on the following criteria:

• The chemical and physical properties of the oil or condensate produced at the site are

typical of the region according to the expert opinion of the site operating company 

personnel;

• The processing equipment at the site are typical of the region according to the expert 

opinion of the site operating company personnel;

• No equipment is used to control vapor emissions from liquid storage tanks;

• The oil or condensate production rate is at least 2 barrels per day;

• The liquid storage tanks are of welded construction; and

• The site is easily accessible

The minimum number of oil and gas production sites that will be sampled in each 

geographic region is given in Table B-1. In determining these numbers, emphasis was placed on 

the HGB area due to the greater oil and condensate production rates (see Table A-1, for example) 

and the greater numbers of oil and gas fields contributing to the regional production. 

Table B-1 

Approximate Number of Oil and Gas Production Sites to be Sampled in Each Region

Region Oil Production Sites Gas/Condensate Production Sites

DFW 0 3-6

HGB 9-12 9-12

Jefferson Co. 1-3 1-3

Average oil production and condensate production emission factors will be developed for 

each geographic region and applied to liquid hydrocarbon production data available from the 

Texas Railroad Commission to estimate monthly, annual, and ozone season daily emissions for 

2005 or other year of interest to HARC. The emissions inventory will be expressed in terms of 

county-wide totals for east Texas counties identified in Figure A-1. Emissions inventories for 

counties where no direct sampling or measurements were conducted will be based on the average 
Section B1

Revision 1

January 13, 2006

Page 3 of 3

factor derived from all the sampling sites, from a subset of all sites deemed most representative, 

or factors identified from the literature review if appropriate.
Section B2

Revision 2

July 31, 2006

Page 1 of 1

B2. Sampling and Measurement Methods

Vapor grab samples for compositional analysis will be collected using evacuated, 

passivated stainless steel canisters. The canisters will be supplied by the analytical laboratory

and will be pre-evacuated in the laboratory to vacuums of at least 27 inches of mercury (i.e., 2 

inches of mercury absolute). The canister vacuums will be checked in the field, prior to 

sampling, to ensure the absence of measurable gas leakage during transport to the field and 

handling. Any canisters found to have less than 27 inches Hg vacuum will not be used for 

sampling. The gas samples will be collected from the tank vents or another suitable access port 

such as a thief hatch. The samples will be collected at least 2 feet from the flow measuring 

device to avoid disturbances in the flow measurement. A sampling probe made of stainless steel 

will be used to draw the gas sample from approximately 2 feet within the vent stack or tank 

vapor space and avoid possible entrainment of ambient air into the sample canister. The 

canisters will be filled to less than atmospheric pressure (e.g., approximately 5 inches Hg 

vacuum) to reduce the potential for moisture condensation. For sites having batteries of more 

than one liquid storage tank, only a single gas sample will be collected. For example, if all the 

storage tanks share a common vent, the gas sample would be collected from the common vent 

stack. Otherwise, a temporary manifold made of Teflon tubing may be constructed to channel 

the gas flow to a common sampling port.

Measurements of vent gas flow rates will be made using a Fox Instruments Model 10A 

Thermal Mass Flow Meter. This instrument uses a thermal flow sensor, which operates on the 

principle that fluids absorb heat. A heated sensor placed in the gas stream transfers heat to the 

gas in proportion to the mass flow rate. Using a bridge circuit, one sensor detects the gas 

temperature while a second sensor is maintained at a constant temperature above the gas 

temperature. The temperature difference results in a power demand that equals the gas mass 

flow rate. . The flow rate will be measured and recorded continuously over a 24-hour period at 

each sampling site. At sites having batteries of more than one liquid storage tank, the tank vents 

will be manifolded together to create a single port for measuring the total tank battery vent flow.

The air surrounding each tank will be screening using a portable total hydrocarbon analyzer to 

help in the detection and elimination of tank vapors that might be escaping for places other than 

from where the flow is to be measured.

The liquid production rates will be determined during the test period either by reading the 

level gauge on the tanks (if present at the site), or by manually gauging the tanks. The manual 

tank readings will be adjusted to account for any unloading of the tanks into tank trucks during 

the test. 
Section B3

Revision 1

January 13, 2006

Page 1 of 1

B3. Sample Handling and Custody

The chain of custody for vent gas samples will begin and end with the laboratory 

performing the compositional analysis. Sample canisters will be evacuated in the laboratory and 

then shipped to the field sampling team along with chain of custody records documenting the 

initial canister vacuum. No special procedures are required for handling or storing sample 

canisters in the field; however, vacuum checks will be made and recorded prior to sampling to 

verify that no air leakage into the canister has occurred following evacuation by the laboratory. 

Additionally, the canister vacuum will be checked after a sample has been collected for the 

laboratory to use as a reference to check whether air has leaked into the canister following 

sample collection. Samples will be returned to the laboratory via FedEx or other registered 

carrier along with chain of custody records and other associated documentation within seven 

days after sample collection. The samples will be analyzed and results reported to URS within 

seven days after receipt by the laboratory.

All samples collected in the field will be labeled to identify the gas well or oil lease site 

where it was collected, the date and time of collection, and the sampling personnel. Samples will 

be identified with sequential numbers beginning with H51C-001, H51C-002, etc.
Section B4

Revision 1

January 13, 2006

Page 1 of 1

B4. Analytical Methods

The compositional analysis of tank vent gas samples will be conducted according to Gas 

Processors Association (GPA) Method 2286 for quantification of speciated hydrocarbons 

including methane (C1) through C12 and benzene, toluene, ethylbenzene, and xylene (BTEX). 

During this analysis, the sample gas is heated to the gas temperature recorded during sample 

collection and injected into a gas chromatograph (GC) where it is split into three sections. The 

first section separates and detects oxygen, nitrogen, and methane using a thermal conductivity 

detector. The second section separates methane through n-pentane using a different column and 

a flame ionization detector (FID). The third section separates isopentane through dodecane using 

a third column and a second FID. The analytical results will be reported in units of mole percent

per reported compound. Details of GPA Method 2286 are provided in Appendix A
Section B5

Revision 1

January 13, 2006

Page 1 of 1

B5. Quality Control

The quality of field measurement data used for deriving emission factors will be 

controlled by measuring vent gas flow rates over approximately 24 hours using a measurement 

device capable of accurately measuring flow rates over the broad range likely to be encountered. 

The 24-hour measurement period will allow for averaging short-term fluctuations in vent gas 

flow rate caused by oil and condensate production cycles. Additionally, a portable hydrocarbon 

vapor analyzer will be used to screen the air around the storage tanks and pressurized vessels for 

leakage. URS will notify the site operating personnel of any measureable gas leakage and work 

with that individual to seal any leaks prior to conducting flow rate measurements. 

The quality of gas compositional measurements will be controlled by using standardized 

analytical methods appropriate for the type of samples that will be collected. Duplicate vent gas 

samples for compositional analysis will be collected at a minimum of three sites (at least 10% of 

all oil and gas production sites) to assess measurement precision. 

The greatest source of uncertainty in the calculated emission factors is likely to be the 

estimation of oil or condensate produced over the sampling period. The accuracy of the emission 

factors derived from these tests will be limited to how accurately the production volumes can be 

determined during the sampling episode. While such production information is readily available 

on a monthly or annual basis from the Texas Railroad Commission, accurate production data 

over a 24-hour period is generally not available, and will have to be estimated from reading the 

tank level gauges (if present), manually gauging the tank level, or from production meters at the 

site if available. The specific methods and instruments used to estimate daily throughput will be 

recorded in the field sampling log; however, the sensitivities of these devices to oil or condensate 

throughput over 24-hours is unknown. 
Section B6

Revision 1

January 13, 2006

Page 1 of 1

B6. Equipment Testing, Inspection, and Maintenance

All field measurement and sampling equipment will be inspected prior to use. 

Additionally, the analytical laboratory will maintain a Quality Program that delineates and 

verifies compliance with specifications for equipment inspection and maintenance.
Section B7

Revision 1

January 13, 2006

Page 1 of 1

B7. Instrument Calibration and Frequency

The gas chromatograph used for determination of vent gas composition will be calibrated 

at least once per week according to the GPA Method 2286 calibration procedures (see Appendix 

A). This method requires the determination of response factors using the peak area counts for 

each reported gas component based on the analysis a gas reference standard of known 

composition. Additional calibrations will be performed whenever a new column is installed or 

maintenance is performed. A continuing verification of instrument calibration will be performed 

daily in accordance with the laboratory Quality Program.

The vent gas flow measuring device will be tested prior to use to verify agreement to 

within ± 10% of comparative measurements using a standard flow measurement device.
Section B8

Revision 1

January 13, 2006

Page 1 of 1

B8. Inspection/Acceptance of Supplies and Consumables

Vacuum checks on all canisters used for sampling vent gas streams will be performed 

prior to use in the field. Canisters with initial vacuums less than 27 inches of mercury will not be 

used for collecting field samples. No other consumables or supplies will be used in this 

sampling program.

The laboratory will be responsible for procurement of appropriate analytical standards in 

accordance with the specifications of GPA Method 2286.
Section B9

Revision 1

January 13, 2006

Page 1 of 1

B9. Non-direct Measurements

Non-direct measurements collected at each field site will include the separator pressure, 

the API gravity of the oil or condensate produced, and the oil or condensate production rate for 

the time period in which vent gas flow rate measurements are made. Additionally, annual and 

monthly oil and condensate production data from east Texas counties will be obtained from the 

Texas Railroad Commission. 

The separator pressure and API gravity are two variables on which VOC emissions rates 

from storage tanks will depend most strongly. Therefore, these parameters will be recorded at 

each site and will be used to assess and document the representativeness of the measured 

emission factors. The API gravity of the oil or condensate will be obtained from site logs or by 

interviewing site operating personnel. Separator pressures will be obtained from site logs or 

separator pressure gauges. 

Oil and condensate production during vent gas flow rate measurements will be 

determined from site logs or from liquid flow metering devices at the site. Annual and monthly 

oil an condensate production rates will be used, along with derived emission factors, to estimate 

emissions for east Texas on a county-by-county basis. Oil and condensate production rates are 

available from the Texas Railroad Commission website at www.rrc.state.tx.us. 
Section B10

Revision 1

January 13, 2006

Page 1 of 2

B10. Data Management

Separator pressures, API gravities of the produced oil or condensate, and oil or 

condensate production rates will be recorded initially in a field logbook along with other 

information pertinent to identifying where and when field measurements and samples were 

collected and the weather conditions at the time. The field log notes will later be transferred to 

an electronic spreadsheet. Each data entry in the logbook and spreadsheet will be indexed 

according to the lease (site) name and number as described in the Texas Railroad Commission 

website. The gas or oil field from which the liquid hydrocarbon is produced will also be entered 

into these logs. At the completion of the project the electronic spreadsheet will copied to a 

compact disc and stored by URS for at least 10 years. A copy of the electronic log, minus the 

Lease name and number will be delivered to HARC. The log will contain entries for the 

following data fields:

• Lease (site) name;

• Lease number;

• County

• Oil or gas field name;

• API gravity of the oil or condensate;

• Separator pressure;

• Start and stop date/time of the flow rate measurement;

• Barrels of oil or condensate produced over the flow rate measurement period;

• Date/time of vent gas grab sample for compositional analysis;

• Vent gas sample identification number;

• Field sampling personnel;

• Ambient Temperature; 

• Ambient Pressure

• A simple schematic diagram of the tank battery operation, with processing equipment and 

showing the location of the sampling port;

• Temperature of liquid product (if available);

• The well type (i.e., oil, gas, or casinghead);

• The number of wells served by the tank battery;

• The temperature of product leaving the separator (if available);

• The number of tanks in the tank battery;

• The approximate tank dimensions (i.e., diameter and height);

• The type of tank (i.e., oil, condensate, saltwater, gun barrel);

• The color, approximate age, condition and construction (i.e., bolted or welded) of the 

tanks; and

• The approximate age of the processing equipment.

Vent gas flow rate measurements will be recorded continuously and logged as 1-minute 

averages on a portable data recording system. The data will be backed up on compact disc and 

later transferred to computer spreadsheet for calculating the average flow rate at each site. 

Laboratory data reports of vent gas composition will be generated in hardcopy and electronic 
Section B10

Revision 1

January 13, 2006

Page 2 of 2

formats. All flow rate measurement data will be indexed according to the lease name and 

number and the date/time of the measurement. The raw measurement data and spreadsheets will 

be stored by URS for at least 10 years after the completion of the project. Copies of all raw 

measurement data and spreadsheets, minus the lease name and number, will be delivered to 

HARC after the completion of this project.

Annual and monthly oil and condensate production data are permanently stored in a 

Texas Railroad Commission database, which is accessible online at www.rrc.state.tx.us. County 

totals for east Texas will be extracted from the online database and stored in a computer 

spreadsheet. 
Section C1

Revision 2

January 13, 2006

Page 1 of 1

C1. Assessments and Response Actions

No quality assurance audits of sampling or analysis activities are planned for this project. 

All data gathered and used as part of this project will be assessed for usability by the project QA 

coordinator, as described in Section D1 of this QAPP. 
Section C2

Revision 1

January 13, 2006

Page 1 of 1

C2. Reports to Management

Field sampling personnel will communicate with the URS Project Manager via telephone 

or email at least twice per week during the sampling effort to report on progress and any 

problems encountered.

Laboratory staff will report the results of analytical quality control checks with each data 

reporting package.
Section D1

Revision 1

January 13, 2006

Page 1 of 1

D1. Data Review, Verification, and Validation

Data review, validation, and verification procedures are presented in this section. Three 

types of data are collected for this project:

• Continuous vent flow rate data collected over 24 hours;

• Concentrations of VOC species in vent grab samples collected in whole air canisters; and

• Oil or condensate production rates for periods concurrent with vent flow rate testing.

Data validation will be performed for all measurement results under the supervision of the 

Project Manager, who will verify that the sampling and analysis data are complete for each test 

site. Data will be declared invalid whenever documented evidence exists demonstrating that a 

sampler or analyzer was not collecting data under representative conditions or was 

malfunctioning. 

The activities involved in validation of the data in general include the following:

• reviewing the site visit logs, calibration data, audit data, and project memoranda for 

indications of malfunctioning equipment or instrument maintenance events;

• reviewing the data packages from the analytical laboratory, which contains chain-ofcustody, instrument calibration, and QC check results; and

• examining the continuous flow rate data for spikes, anomalous results, unusually high 

rates of change, or measurement values that seem incongruous with normal measurement ranges 

and/or diurnal variations.

Analysis data for VOC speciation data are checked by both laboratory and project QA staff. The 

lab quality control information is reviewed, and the project team verifies any data flags or 

reported anomalies in the analyses. The lab records are also checked against the field records 

created by the network operator to ensure that there are no discrepancies. If all quality control 

criteria are met, the results are annotated as valid.

Data are never declared invalid solely because they are unexpected, but may be flagged as 

suspect and be subjected to further review until the cause for the apparent anomaly is 

determined. The results from all quality control and quality assurance checks are evaluated to 

determine if the data quality objectives for each measurement are being met. Evidence of 

overwhelming measurement bias, external influences on the representativeness of the data, or 

lack of reproducibility of the measurement data may be cause for the data to be judged invalid.

The final, validated data set is then produced and peer reviewed to ensure that limitations in use 

of any data are clearly communicated to the data users, and that the validation process was 

consistent with project requirements and URS standard procedures. 
Section D2

Revision 1

January 13, 2006

Page 1 of 1

D2. Verification and Validation Methods

The URS Project Manager will conduct the final review of the data and emission factor 

calculations prior to their being considered valid. Data from all the various sources, and 

emission factor calculation results, will be combined into a single spreadsheet to facilitate this 

review. Each row of the spreadsheet will represent a single oil or gas production site while the 

columns will represent all the different operating parameters (e.g., separator pressure, API 

gravity), measurement results, and derived emission factors. Graphical displays of each 

parameter will be made and any outlying data points will be investigated. 
Section D3

Revision 1

January 13, 2006

Page 1 of 1

D3. Reconciliation with User Requirements

Emission factors and the regional emissions inventory developed from this project are 

intended for use by the TCEQ to evaluate ozone control strategies for the DFW and HGB areas. 

To meet the user requirements, the data resulting from this project must be of known and 

defensible quality. The quality control and chain of custody procedures to be implemented 

during the sampling program are intended to help achieve this objective. Emission factors 

derived from the measurement data must also be representative of the thousands of oil and gas 

production sites in east Texas. While efforts will be made to sample at oil and gas production 

sites that are reasonably representative, site-to-site variations in emission factors cannot be 

controlled – they can only be assessed. Calculations of the emission factor standard deviations 

and mean confidence intervals for the sampled populations of sites, which will be included in the 

project draft and final reports, will be used to evaluate emission factor variability and the

representatives of the derived emission factors to broad regions or sub-regions of east Texas. 

Additionally, a follow up survey of the oil and gas production industry to assess the existing use 

of vapor recovery and other vent gas emission controls is recommended.