SRI/USEPA-GHG-VR-19 

September 2002 

Environmental Technology 

Verification Report 

COMM Engineering, USA

Environmental Vapor Recovery Unit (EVRUTM)

Prepared by: 

Greenhouse Gas Technology Center

Southern Research Institute

Under a Cooperative Agreement With 

U.S. Environmental Protection Agency 
EPA REVIEW NOTICE 

This report has been peer and administratively reviewed by the U.S. Environmental Protection Agency, and 

approved for publication. Mention of trade names or commercial products does not constitute endorsement or 

recommendation for use. 
SRI/USEPA-GHG-VR-19 

September 2002

 Greenhouse Gas Technology Center

 A U.S. EPA Sponsored Environmental Technology Verification ( ) Organization 

Environmental Technology Verification Report 

COMM Engineering, USA 

Environmental Vapor Recovery Unit (EVRU�) 

Prepared by:

Greenhouse Gas Technology Center

Southern Research Institute

PO Box 13825

Research Triangle Park, NC 27709 USA

Telephone: 919/806-3456

Under EPA Cooperative Agreement CR 826311-01-0

U.S. Environmental Protection Agency

Office of Research and Development

National Risk Management Research Laboratory

Air Pollution Prevention and Control Division 

Research Triangle Park, NC 27711 USA 

EPA Project Officer: David A. Kirchgessner 
TABLE OF CONTENTS

Page 

1.0 INTRODUCTION....................................................................................................................................................................1-1

1.1 BACKGROUND ................................................................................................................ 1-1

1.2 EVRU TECHNOLOGY DESCRIPTION ............................................................................. 1-2

1.3 TEST FACILITY DESCRIPTION....................................................................................... 1-4

1.4 PERFORMANCE VERIFICATION PARAMETERS ........................................................... 1-7

2.0 VERIFICATION RESULTS.................................................................................................................................................2-1

2.1 TEST RESULTS................................................................................................................. 2-1

2.2 GAS RECOVERY RATE.................................................................................................... 2-1

2.2.1 EVRU Performance Trends ..................................................................................... 2-2

2.2.2 Vent Gas Composition and Air Pollutant Recovery Rate............................................ 2-7

2.3 ANNUAL GAS SAVINGS AND EMISSION REDUCTIONS .............................................. 2-9

2.4 VALUE OF RECOVERED GAS....................................................................................... 2-11

2.5 EVRU TOTAL INSTALLED COST.................................................................................. 2-11

3.0 DATA QUALITY ASSESSMENT.......................................................................................................................................3-1

3.1 DATA QUALITY OBJECTIVES........................................................................................ 3-1

3.2 RECONCILIATION OF DQOS AND DQIS ........................................................................ 3-6

3.2.1 Gas Recovery Rate.................................................................................................. 3-6

3.2.1.1 Motive Gas Flow Rate............................................................................... 3-6

3.2.1.2 Discharge Gas Flow Rate .......................................................................... 3-7

3.2.2 Annual Gas Savings and Emission Reductions .......................................................... 3-7

3.2.3 Value of Gas Recovered ........................................................................................ 3-10

4.0 ADDITIONAL INFORMATION SUPPLIED BY COMM...........................................................................................4-1

5.0 REFERENCES..........................................................................................................................................................................5-1

i 
Appendix A 

Appendix B 

Appendix C 

Appendix D 

Appendix E 

Appendix F 

Figure 1-1

Figure 1-2

Figure 1-3

Figure 1-4

Figure 2-1

Figure 2-2

Figure 2-3

Figure 2-4

Figure 2-5

Table 2-1

Table 2-2

Table 2-3

Table 2-4

Table 2-5

Table 3-1

Table 3-2

Table 3-3

Table 3-4

Table 3-5

APPENDICES 

Page 

Pre-Test Motive Gas Samples.........................................................................A-2

Pre-Test Vent Gas Samples............................................................................A-3

Vent Gas Samples Collected During Testing....................................................A-4

Pre-Test Discharge Gas Samples ....................................................................A-5

Discharge Gas Samples Collected During Testing............................................A-6

Flow Through Comparison Results Between Turbine Meter

and Orifice Meter..........................................................................................A-7

LIST OF FIGURES 

Page 

The COMM EVRU..................................................................................1-3

Simplified Diagram of a Conventional VRU System...................................1-4

The COMM EVRU Installation and GHG Center Measurement

Instruments at the Test Site .......................................................................1-5

The Installed COMM EVRU System.........................................................1-6

Relationship Between Vent Gas Recovery Rate and Oil Production Rate .....2-4

Relationship Between Vent Gas Recovery Rate and Ambient Temperature ..2-5

Time Series Plots of Key Performance Data...............................................2-6

Motive-to-Vent Gas Ratio vs. EVRU Suction Pressure ...............................2-7

Gas Recovery Rate vs. EVRU Suction Pressure..........................................2-8

LIST OF TABLES 

Page 

Summary of Test Results ..........................................................................2-2

Summary of Daily Operational Conditions.................................................2-3

Normalized Average Vent Gas Composition...............................................2-9

Annual Emission Reduction Estimates..................................................... 2-11

Total Installed Costs for the EVRU System at the TFE Site....................... 2-12

Data Quality Objectives............................................................................3-2

Measurement Instrument Specifications and Data Quality Indicator

Goals.......................................................................................................3-3

Summary of QA/QC Checks.....................................................................3-5

Audit Gas Analysis Results .......................................................................3-9

GC/FID Calibration Results.......................................................................3-9

ii 

1.0 INTRODUCTION 

1.1 BACKGROUND 

The U.S. Environmental Protection Agency’s Office of Research and Development (EPA-ORD) operates 

the Environmental Technology Verification (ETV) program to facilitate the deployment of innovative 

technologies through performance verification and information dissemination. The goal of ETV is to 

further environmental protection by substantially accelerating the acceptance and use of improved and 

innovative environmental technologies. Congress funds ETV in response to the belief that there are many 

viable environmental technologies that are not being used for the lack of credible third-party performance 

data. With performance data developed under this program, technology buyers, financiers, and permitters 

in the United States and abroad will be better equipped to make informed decisions regarding 

environmental technology purchase and use. 

The Greenhouse Gas Technology Center (GHG Center) is one of six verification organizations operating 

under the ETV program. The GHG Center is managed by EPA’s partner verification organization, 

Southern Research Institute (SRI), which conducts verification testing of promising GHG mitigation and 

monitoring technologies. The GHG Center’s verification process consists of developing verification 

protocols, conducting field tests, collecting and interpreting field and other data, obtaining independent 

peer-review input, and reporting findings. Performance evaluations are conducted according to externally 

reviewed verification Test and Quality Assurance Plans (Test Plan) and established protocols for quality 

assurance. 

The GHG Center is guided by volunteer groups of stakeholders. These stakeholders offer advice on 

specific technologies most appropriate for testing, help disseminate results, and review Test Plans and 

Verification Reports (Report) and Verification Statements. The GHG Center’s Executive Stakeholder 

Group consists of national and international experts in the areas of climate science and environmental 

policy, technology, and regulation. It also includes industry trade organizations, environmental 

technology finance groups, governmental organizations, and other interested groups. Industry-specific 

stakeholders provide guidance on GHG Center’s verification testing strategies related to their area of 

expertise. They also peer-review key documents prepared by the GHG Center. 

The GHG Center’s Oil and Natural Gas Stakeholder Group has voiced support for the ETV program 

mission, and has identified a need for independent third-party verification of cost effective methane (CH4) 

and carbon dioxide (CO2) emission reduction. The GHG Center has conducted several verifications 

applicable to the oil and natural gas production, processing, and transmission sectors. This Report 

documents the testing plans for a new technology that recovers and utilizes vapors from crude oil storage 

tanks employed in the production and processing sectors. 

Approximately 252,000 natural gas production wells and 575,000 crude oil wells exist in the United 

States. Most of these operations produce large volumes of relatively low-pressure vent gas from different 

process equipment. According to two separate EPA methane emissions inventory estimates, about 30 

billion cubic feet (Bcf) of CH4 is annually vented from crude oil storage tanks (EPA 1999, ICF 1997). 

This is the most significant source of vented emissions from the production sector, representing between 

35 and 44 percent of total emissions. A large fraction of the gas is CH4 (30 to 60 percent), and the 

remaining gas species include non-methane organic compounds and hazardous air pollutants (HAPs). 

Depending on the site’s size and emission potential, the low-pressure gas can be either disposed of (e.g., 

vented or flared), or recovered and used. 

1-1
Disposal options are relatively easy to implement and can reduce hazardous and toxic air pollutants. 

However, disposal options do not make use of the high energy content associated with the gas, they 

produce large volumes of GHG and other emissions, and when flared, the aesthetic quality of 

communities is lowered. Many sites use vapor recovery units (VRUs) to capture hydrocarbon vapors that 

normally vent from production area oil storage tanks. A booster compressor pressurizes the recovered gas 

and supplies it to a natural gas sales pipeline. VRUs are most often used when the recovered gas can be 

sold for the value of CH4 (natural gas) and other hydrocarbons in the vapor. 

COMM Engineering, USA (COMM), located in Lafayette, Louisiana, has requested that the GHG Center 

perform an independent verification of their Environmental Vapor Recovery Unit (EVRU�) at a gas and 

condensate production facility operated by TotalFinaElf E&P, USA, Inc. (TFE) near McAllen, Texas. 

The EVRU collects low-pressure vent gas from the site’s condensate storage tanks. The recovered gas is 

pressurized and injected into a natural gas pipeline for sale. The EVRU verification test quantified vent 

recovery rate, emission reductions, total installed cost, and annual gas savings. 

The test was conducted in partnership with EPA’s Natural Gas STAR Program, which is managed by the 

EPA Office of Air and Radiation (EPA-OAR) under a partnership between EPA and the oil and natural 

gas industry. The program maintains a membership of over 90 partner companies, which are committed 

to implementing cost-effective CH4 reduction technologies. The EVRU verification test was executed to 

provide objective performance data to this industry group, as well as to the GHG Center's Oil and Gas 

Stakeholder Group. 

The Test Plan, titled Test and Quality Assurance Plan for the COMM Engineering, USA Environmental 

Vapor Recovery Unit (EVRUTM) (SRI 2002), provides the verification test design, measurement, and 

quality assurance/quality control (QA/QC) procedures. It can be downloaded from the GHG Center's 

Web site (www.sri-rtp.com). The Test Plan describes the experimental design, rationale, testing and 

instrument calibration procedures planned, and specific QA/QC goals and procedures. The Test Plan was 

reviewed and revised based on comments received from COMM, TFE, and the EPA Quality Assurance 

team. The Test Plan meets the requirements of the GHG Center’s Quality Management Plan (QMP), and 

satisfies the ETV QMP requirements. In some cases, deviations from the Test Plan were required. This 

Report discusses these deviations, and the alternative procedures selected for use. 

The remaining discussion in this section describes the EVRU technology, summarizes performance 

parameters that were verified and their testing strategy, and includes a description of the TFE test facility. 

Section 2.0 presents the test results, and Section 3.0 assesses the data quality of each verification 

parameter. Section 4.0, submitted by COMM, presents additional information regarding the EVRU 

technology. Information provided in Section 4.0 has not been independently verified by the GHG Center. 

1.2 EVRU TECHNOLOGY DESCRIPTION 

The EVRU is a non-mechanical eductor or a jet pump that captures low-pressure hydrocarbon vapors. It 

requires high-pressure motive gas to entrain the low-pressure vapors emanating from condensate storage 

tanks. The combined discharge gas stream exits at an intermediate pressure, which can be used on site as 

fuel or re-pressurized with a booster compressor and injected into a natural gas transmission line for sale. 

It is a closed loop system designed to reduce or eliminate emissions of greenhouse gases (CH4 and CO2), 

volatile organic compounds (VOCs), HAPs, and other pollutants present in vent gas. 

1-2
Figure 1-1 is a schematic of the EVRU. The core element is an eductor system which operates on the 

venturi principle. The EVRU contains flow safety valves, flow control mechanisms, pressure sensing, 

and temperature sensing devices which allow the system to operate under varying vent gas flow rates. 

Pressure and temperature isolating valves (not shown) are also installed in the motive gas line to allow 

replacing or repairing EVRU components. 

FIGURE 1-1. THE COMM EVRU 

Pressure Temp 

Indicator Indicator 

( typ.) ( typ.) 

Flow 

Safety 

Valve 

(typ .) 

Flow 

Control 

Valve 

( typ.) 

PI TI 

High-Pressure 

Motive Gas 

(~ 850 psig) 

PI 

TI 

PI TI 

Discharge 

Gas 

(~ 40 psia) 

EVRU Suction 

Pressure 

(-0.05 to 0 psig) 

Low-Pressure

Vent Gas from

Tanks

(0.10 to 0.30 psig) 

The facility’s existing dehydrated high-pressure natural gas pipeline supplies motive gas. A pressure 

sensor monitors the motive gas pressure; its output signal controls the valve and regulator which maintain 

the gas flow at the design pressure (typically range of 600 to 850 pounds per square inch, gauge [psig]). 

The motive gas flows through a venturi orifice situated in a mixing chamber, and creates a differential 

pressure within the EVRU jet pump. The mixing chamber contains a port which allows low-pressure vent 

gas (0.1 to 0.3 psig) to be drawn into the chamber due to the partial vacuum created by the motive gas as 

it expands through the eductor nozzle. The low-pressure vent gas drawn into the eductor mixing chamber 

combines with the motive gas, and exits the eductor discharge line at an intermediate pressure (i.e., less 

than the inlet motive gas but greater than the low-pressure gas being drawn into the mixing chamber). 

The ratio of motive gas to vent gas typically ranges from 3.7 to 5.7 scfm/scfm or 2.0 to 3.0 lb/lb. 

At the test facility, a pipeline conveys the discharge gas to a booster compressor which compresses the 

gas to meet high-pressure natural gas pipeline specifications. Discharge gas pressure and temperature 

sensors assist operators with the control of the mixed fluid departing the eductor. All process streams 

contain flow safety devices to prevent backflow (e.g., into the tanks) and over-pressurizing of all 

components upstream of the flow safety devices. Pressure and temperature isolating valves (not shown) 

are provided in all process streams to replace or repair the flow sensors. 

Depending on the volume of low-pressure gas to be recovered, multiple eductor jet pumps may be 

installed in the EVRU system. When connected in series, the discharge line is connected to the inlet line 

1-3
of a succeeding jet pump prior to discharge to a booster compressor. When connected in parallel, several 

different sized jet pumps or combinations are brought on line depending on the available flow of lowpressure gas. This parallel system was employed at the TFE site. 

1.3 TEST FACILITY DESCRIPTION 

The TFE – El Ebanito site is an exploration and production (E&P) facility that handles separation of 

natural gas and crude oil condensate product, gas compression, and gas dehydration from wells located 

within a 5-mile radius. It is located approximately 30 miles northwest of McAllen, Texas. In a typical 

year, daily crude oil production ranges between 900 and 1,200 barrels per day. 

Prior to using the EVRU, the TFE test site employed a conventional VRU system (Figure 1-2) to recover 

vent gas from five fixed roof crude oil stock tanks (400 barrels capacity) and two gun barrel tanks (750 

barrels capacity). In the conventional VRU system, hydrocarbon vapors are drawn out of the tanks under 

low-pressure, and are first piped to a separator (suction scrubber) to collect any liquids that condense. 

The liquids are then recycled back to the storage tanks, and the vapors are pulled into a booster 

compressor which provides a low-pressure suction for the VRU system. The vapors are then metered and 

routed to a pipeline for sale. Gas recovery efficiencies of 90 to 98 percent have been reported for a 

typical VRU system (EPA 1995). However, recurring mechanical failures in the existing VRU at the test 

site have resulted in periodic downtimes, lost product, increased operation and maintenance requirements, 

and higher emissions due to venting during downtime. TFE operators have reported that their 

conventional VRU system was down 10 to 15 percent of the time and may have recovered less than 90 

percent of the gas while operating. During downtimes, the vapors from the storage tanks were vented 

directly to the atmosphere. For these reasons, the site has elected to evaluate the EVRU and serve as the 

host facility for this verification. 

Figure 1-2. Simplified Diagram of a Conventional VRU System 

Vent to

Atmosphere

Vent Gas Vapor 

Suction 

Line 

Condensate

Return

Crude Oil 

Storage Tank 

Suction 

Scrubber 

Liquid Transfer Pump 

Pressurized

Gas to Sales

Pipeline

Booster Compressor 

Existing vent lines bring the vapors from all seven tanks into a common header (6-inch diameter) which 

was connected to a 2-inch suction line of the EVRU. The manifold and EVRU skid were located near 

1-4
these tanks. A 2-inch diameter pipeline was used to supply motive gas to the EVRU. The motive gas line 

includes a pressure regulator and a flow controller to maintain a design pressure of 850 psig. A 4-inch 

diameter pipeline, operating at approximately 40 pounds per square inch, absolute (psia), conveyed the 

discharge gas to the facility’s booster gas compressor, located approximately 25 feet away. The booster 

compressor pressurized the gas and injected it into the sales gas pipeline. A schematic of the EVRU 

installation and the GHG Center measurement instruments is shown in Figure 1-3, and a picture of the 

installed system at TFE is shown in Figure 1-4. 

Figure 1-3. The COMM EVRU Installation and GHG Center Measurement Instruments 

at the Test Site 

Low-Pressure Vent Gas (CH 4, VOCs, HAPS) 

Tmotive 

P 

Rosemount 

Pressure 

Sensor 

Tdisch 

American 

Gas 

Turbine 

Meter 

Qdisch 

C 

Natural Gas 

Compressor 

Flow 

Safety 

Valve 

( typ.) 

Discharge Gas 

Sampling Port 

Natural Gas 

Dehydrators 

From 

Oil/Gas/Water 

Separators 

Flow 

Control 

Valve 

(typ .) 

EVRU Motive 

Gas (~850 psi) 

High Pressure Natural Gas (~1,070 psig ) 

Natural Gas Sales Pipeline 

EVRU 

EVRU 

Recovered 

Gas (-0.6 -0.3 

psig) 

EVRU 

Discharge Gas 

(~40 psia) 

Tank Pressure Relief Safety Vent 

Vent Gas 

Sampling Port 

Qmotive 

Rosemount 

Integral 

Orifice Meter 

Rosemount 

RTD 

Pressure 

Regulator 

(~850 psig ) 

T 

Omega 

Thermocouple 

Pdisch 

Rosemount 

RTD 

Rosemount 

Orifice 

Meter 

Pressure 

Sensor 

To Vent 

During EVRU 

Downtimes 

Gun Barrel Tanks 

Condensate Storage Tanks 

The EVRU’s primary purpose is to collect and transfer low-pressure vent gas for use. The quality and 

quantity of gas evolving from each stock tank varies according to many factors, including condensate 

production rate and composition, how long it stays in the tank (i.e., how frequently the inventory turns 

over), separator operating conditions, ambient temperature, and atmospheric pressure. 

The secondary purpose of the EVRU is to control stock tank pressure changes caused by flash gas being 

released from the stored condensate, and working and standing losses due to condensate transferring 

activities. The tanks must be maintained at a slightly positive pressure to avoid air contamination or overpressurization during all phases of a typical tank duty cycle. Each tank is equipped with a pressure relief 

vent (PRV) which automatically activates when the tank pressure exceeds approximately 4 oz (or 0.25 

psig) above atmospheric levels. The gas is directly vented to the atmosphere until the pressure decreases 

to the specified levels. 

1-5
Figure 1-4. The Installed COMM EVRU System 

The EVRU is designed to maintain internal tank pressures to range between 0.10 and 0.30 psi over local 

atmospheric pressure. A pressure sensor, located inside one of the five stock tanks, continuously 

monitors the tank operating pressure. This pressure reading was interpreted by the EVRU programmable 

logic controller (PLC), and used to control the two separate eductors. 

The eductors are configured in a parallel orientation, and are designed to recover a total of 300 thousand 

standard cubic feet per day (Mscfd) or 208 standard cubic feet per minute (scfm) vent gas. Note that gas 

industry standard conditions are 60 degrees F, 14.7 psia. The primary eductor, with a capacity of 200 

Mscfd (139 scfm), operates continuously to maintain tank pressures below 3.2 oz (0.20 psig). When a 

new inventory of condensate enters the tanks and the pressure begins to build up over 3.2 oz, a secondary 

eductor becomes operational. The secondary eductor, with a capacity of 100 Mscfd or 69 scfm, recovers 

gas to maintain the tank pressure to less than 4.8 oz (0.33 psig). It turns off automatically when the tank 

pressure drops below 1.6 oz (0.10 psig), and the primary eductor is the only unit operating. The design 

motive-to-vent gas ratio for the test site is approximately 5.2 scfm/scfm or 2.8 lb/lb. The EVRU eductors 

are controlled with the use of a PLC, which continuously monitors critical operating parameters. In the 

event the EVRU is unable to maintain the required tank pressure and the pressure begins to build up, 

some of the vent gas will escape through the PRVs to the atmosphere or flare. 

1-6
1.4 PERFORMANCE VERIFICATION PARAMETERS 

The verification test design was developed to evaluate EVRU performance. Prior to installation, all tank 

hatches were sealed and standard industry leak checks were performed by TFE operators to ensure the 

tanks and the entire gas piping network system was leak tight. The test strategy comprised of collection 

of a series of 1-minute averages of the motive gas flow rate, discharge gas flow rate, EVRU suction 

pressure, discharge gas temperature and pressure, and ambient conditions. The GHG Center’s data 

acquisition system (DAS) recorded all continuously monitored performance data. Gas samples of the 

discharge and vent gas were collected throughout the test period, and sent to a laboratory for 

compositional and heating value analysis. Figure 1-3 illustrates the locations of all measurement 

instruments and gas sampling ports. 

The specific verification parameters that were addressed during the field test are discussed below, along 

with the method of determination. The Test Plan provides detailed testing and analysis methods. 

Gas Recovery Rate 

Two independent flow meters were installed within the EVRU pipeline to measure the motive gas and 

EVRU discharge gas flow rates. Both meters were sized to measure the range of gas flow rates expected 

during normal operations at the test facility. Continuous flow measurements data were averaged in 1­

minute time increments, and recorded for 8 days. The difference between the two flow readings 

represented the gas recovery rate of the EVRU as described in Equation 1. 

Qrecovered ,i = Qdisch,i - Qmotive,i (Eqn. 1) 

Where:

Qrecovered,i = Gas recovery rate for minute i, scfm

Qdisch,i = Discharge gas flow rate for minute i, scfm

Qmotive,i = Motive gas flow rate for minute i, scfm

Using the 1-minute gas recovery rates, a daily average gas recovery rate, was computed for each 24-hour 

measurement period. The overall average gas recovery rate, reported in units of thousand cubic feet per 

day (Mscfd) was computed, and represented the arithmetic average of the daily average gas recovery 

rates. The proportion of CH4 and HAPS present in the recovered gas (measured by gas samples collected 

during testing) times the daily average recovery rate represented an estimate of the overall average 

recovery rates for these pollutants. 

It was anticipated that the individual daily average gas recovery rates would be normally distributed and 

fall within a range of values (confidence interval) around the mean. After one week of testing, a 90 

percent confidence interval for the daily average results was to be calculated. If the confidence interval 

was less than 30 percent of the overall average gas recovery rate, it would be concluded that no 

significant flow variability was present that would require further characterization, and testing would be 

terminated. Alternatively, if significant variability was observed and the confidence interval exceeded the 

set criteria, testing would be extended to a maximum of 28 days. As shown later in the results Section 

2.0, the data completeness criteria were met after 8 days of testing was completed. The overall average 

for this time period is used to report the EVRU performance results. 

1-7
The type of instrument used to measure motive gas flow rate was a Rosemount Model 3095 Integral 

orifice meter. This meter uses three different sensors (temperature sensor, differential pressure across an 

orifice, and absolute pressure) to measure mass flow rates, corrected to standard conditions, in units of 

scfm. Site specific natural gas composition, as measured immediately prior to testing, was programmed 

into the meter to enable real-time flow measurements. All components of the orifice meter assembly, 

including the sensors and orifice plate, were verified with NIST traceable standards, and met the accuracy 

and precision specifications. The entire orifice meter assembly was certified with an accuracy of ± 1.0 of 

reading by the manufacturer. 

The type of instrument initially planned to be used for discharge gas flow measurements was an integral 

orifice meter, similar to the model used for motive gas flow rate. However after installation of the orifice 

meter, the pressure drop across the discharge line resulted in an over-pressurization of the entire EVRU 

system. The pressure increase was caused by a sudden contraction of the 4-inch discharge line into a 2­

inch meter loop (Figure 1-4) which was used to house the orifice meter. Due to the negative disturbances 

caused on the operation of the EVRU, the orifice meter assembly was disabled, and an American Meter 

Company Model GTS-4 rotary turbine, already installed in the discharge line by TFE operators, was used 

to measure discharge gas flow. This arrangement represents a modification to the original Test Plan. 

The turbine meter was calibrated with a NIST traceable volume prover prior to installation in the field, 

and was certified with an accuracy of ± 1.0 percent of reading. The turbine meter measures flow rates in 

units of actual cubic feet per minute (acfm). In order to calculate EVRU gas recovery rates (Equation 1), 

the turbine meter readings must be converted to standard conditions. This was accomplished by 

simultaneously measuring discharge gas temperature and pressure at the same time as discharge gas flow 

rates. The pressure measurements were performed with a Rosemount pressure transmitter, and the 

temperature measurements were performed with a Rosemount RTD. Both instruments were installed 

directly in the 4-inch discharge line according to the American Gas Association’s (AGA) procedures for 

sensor location (AGA 1996). 

Gas samples were collected from the vent gas stream (i.e., EVRU suction) and the EVRU discharge 

stream, and analyzed in accordance with American Society of Testing and Materials (ASTM) Method 

D1945 and Gas Processors Association (GPA) Method 2286 to determine concentrations of CH4, nonCH4 hydrocarbons (NMVOC), and BTEX (benzene, toluene, ethylbenzene, and xylenes) (ASTM 2001a). 

Gas density, compressibility and heating value analyses were performed according to ASTM Method 

3588 (ASTM 2001b). The discharge gas heating values were used to assign an industry-accepted 

monetary value of the gas recovered and subsequently sold. Four gas samples from the discharge stream 

and four samples from the vent gas stream were collected during the test. 

Annual Gas Savings and Emission Reductions 

The 1-minute gas recovery rate measurements (discussed above) were also used to determine the total 

volume of gas recovered by the EVRU over the verification period. It was calculated as the integral of 

individual 1-minute flow measurements over the testing time (i.e., the area of a curve represented by flow 

rate and time). The total gas recovered during the verification period was reported in units of standard 

cubic feet (scf). 

To estimate annual gas savings, the total gas recovered was extrapolated for a period of 1 year following 

the verification period. The host site operator was consulted, and it was determined that the oil 

production rate, EVRU operational availability, and other operating conditions that existed since the field 

testing would persist over the year. For this case, the total recovered gas was extrapolated to yield an 

annual estimated gas savings in units of standard cubic feet per year (scfy) as given in Equation 2: 

1-8
Est. AGR = (TGR) + (Qrecovered, overall avg)(No. Days Remaining In Year) (OA) (Eqn. 2) 

Where:

Est. AGR = Estimated annual gas recovered with the EVRU, scfy

Qrecovered, overall avg = Overall average daily gas recovery rate, scfd

TGR = Total gas recovered during testing, scf

OA = EVRU operational availability, %

Annual gas savings is simply a comparison between the estimated annual gas recovered with the EVRU 

system and two baseline scenarios. The first baseline scenario assumes that no recovery system is in 

place, and the vent gas is simply released to the atmosphere. In this case, annual gas savings will be equal 

to the annual gas recovered. The second baseline scenario evaluates the annual gas savings for the test 

site (i.e., conventional VRU is used to recover vent gas). The GHG Center consulted with TFE operators 

to define the percent of time the VRU system was down. The annual gas savings for the test site is 

computed by multiplying the annual gas recovered times the percent down time. In this case, the use of 

the EVRU will eliminate the gas previously vented to the atmosphere during VRU downtime. 

Annual emission reduction estimates for methane and HAPs were determined by multiplying the annual 

gas savings with the pollutant concentrations (determined from vent gas sample analysis). Emission 

estimates are reported as maximum potentital reductions, assuming all the recovered gas is vented directly 

to the atmosphere. Emission reduction estimates are also reported for the site condition, in which 

incremental savings, incurred during downtimes of conventional EVRU, are realized with the EVRU 

system. 

Value of Recovered Gas 

To estimate the cash value associated with the annual gas savings ($), the annual gas saved value, as 

determined above, was multiplied by site specific market price for the recovered gas. Consultations with 

the host site indicated that gas is currently valued at about $2.85 per million Btu (MMBtu). This price, 

multiplied by the lower heating value of the vent gas recovered, was used to compute the monetary value 

of the recovered gas. 

Total Installed Cost 

The capital and installation costs of the EVRU were verified for the test site. Capital costs were verified 

by obtaining cost data from COMM and TFE, and included all equipment and accessory items attributed 

to the installation. Labor hours associated with the installation, setup, and shakedown of the EVRU were 

also verified. The total installed cost reported is the sum of the capital equipment, accessory items, and 

labor costs. Costs associated with GHG Center measurements instruments are not included in this figure. 

1-9

2.0 VERIFICATION RESULTS 

2.1 TEST RESULTS 

Installation, startup, and shakedown activities for the EVRU began on March 18, 2002, and were 

completed on March 22, 2002. The system was reported to be functioning properly by COMM on May 

25. Verification testing occurred between June 23 and July 1, 2002, approximately 30 days after the 

EVRU began unattended operations. 

During all test periods, the site’s crude oil production proceeded normally. EVRU motive gas pressure 

exceeded specified set points during the first days of testing, which caused some operating inefficiency. 

Late in the test campaign, the discharge gas booster compressor failed for about 16 hours. The GHG 

Center did not include the data collected during that period in the analysis. Consequently, approximately 

86 percent of all the collected data are considered valid and used here to report performance results. 

The performance results for the verification parameters are reported as follows: 

Section 2.2 Gas Recovery Rate

Section 2.3 Annual Gas Savings and Emission Reductions

Section 2.4 Value of Recovered Gas

Section 2.5 Total Installed Cost

2.2 GAS RECOVERY RATE 

This section discusses the EVRU vent gas recovery rate, which is based on the difference between the 

discharge gas and motive gas flow rate measurements (Equation 1). All flow rates in this section have 

been standardized for temperature (60 °F), pressure (14.73 psia), and gas compressibility factor (as 

required). 

Table 2-1 shows the daily average discharge gas, motive gas, and vent gas flow rates. The overall 

average vent gas recovery rate was 175 Mscfd for the testing period. Table 2-1 also presents the 

calculated variability and confidence interval of the flow rate measurements. Based on the Test Plan, it 

was expected that 90 percent of the individual daily average recovery rates would be within 0.30 times 

(30 percent) of the overall average recovery rate or about 52 Mscfd. In essence, this was the maximum 

variability allowed in the dataset to report EVRU performance results. The actual testing duration lasted 

a total of 8 days, with over 85 percent of the 1-minute test data defined as valid measurements. The 90 

percent confidence interval half width for the overall average vent gas recovery rate during this period 

was 25 Mscfd, which indicates that the overall average recovery rate for the site during any given day will 

fall within a range of 150 to 200 Mscfd. 

The daily average motive gas required to recover the vent gas varied between 635 and 775 Mscfd. The 

overall average motive-to-vent gas volume ratio during the test period was 4.2 scfm/scfm (or 2.2 lb/lb) , 

and ranged from a low of 3.1 to a high of 6.7 scfm/scfm. The overall average ratio is slightly less than the 

5.2 (by volume) or 2.8 (by mass) design ratio reported by COMM. 

The higher motive-to-vent gas ratio, often exceeding 10 scfm/scfm, was largely influenced by the lack of 

control of the motive gas pressure during the first 3 days of the testing period. On June 26, COMM 

2-1
installed an alternate controller (Proportional Plus Reset Controller by Fisher) to better control the motive 

gas pressure. The new controller contained two capillaries which were connected to the high pressure 

supply side (~1050 psig) and the motive gas side, each located upstream and downstream of the pressure 

regulator, respectively. The controller senses the two pressures, and adjusts the regulator to maintain 850 

psig pressure on the downstream side. Once the motive gas pressure was stabilized to 850 psig, the 

overall average motive-to-vent gas volume ratio decreased to approximately 3.8 scfm/scfm. Performance 

trends associated with these conditions are discussed in the following subsections. 

Table 2-1. Summary of Test Results 

Test Day 

Oil 

Production 

Rate 

(bbl/day) 

Daily Average Flow Rate 

Average 

Motive-toVent Gas 

Ratio 

(scfm/scfm) 

Vent 

Gas:Oil 

Production 

Ratio 

(scf/bbl) 

Day Time 

Period 

Number 

Of 

Valid 

1-minute 

Data 

Discharge 

Gas 

(scfd) 

Motive 

Gas 

(scfd) 

Vent 

Gas 

(scfd) 

6/23-24/02 2 PM - 2 PM 1,408 1,067 928,663 760,881 167,744 4.5 157 

6/24-25/02 2 PM - 2 PM 1,262 984 834,197 684,126 150,778 4.5 153 

6/25-26/02 2 PM - 2 PM 1,395 961 809,994 689,709 120,866 5.7 126 

6/26-27/02 2 PM - 2 PM 1,146 1,051 931,306 710,436 220,720 3.2 210 

6/27-28/02 2 PM - 2 PM 1,416 920 921,849 698,739 223,933 3.1 243 

6/28-29/02 2 PM - 2 PM 1,400 1,019 923,278 719,022 204,395 3.5 201 

6/29-30/02 2 PM – 2 PM 710 1,002 924,935 774,633 150,308 5.2 150 

6/30-7/1/02 2 PM – 8 AM 1,061 925 794,850 634,535 160,095 4.0 173 

Cumulative 9,798 7,928 7,069,072 

scf 

5,672,080 

scf 

1,398,838 

scf 

Average 1,225 991 883,634 709,010 174,855 4.2 177 

Std. Deviation 248 54 59,507 44,309 37,322 0.9 39 

90% Confidence Interval 39,869 29,686 25,005 

2.2.1 EVRU Performance Trends 

Table 2-2 provides a summary of the operating conditions encountered during the test period. This data 

and the 1-minute average measurements data were used to identify potential trends and relationships 

between vent gas recovery rate and oil production rate, ambient temperature, motive gas pressure, EVRU 

suction pressure, and motive gas flow rate. 

Figure 2-1 shows the relationship between the daily average vent gas recovery rate and the daily total oil 

production levels. The oil production levels and the gas/oil separator pressures were relatively consistent 

throughout the test period. A direct relationship between oil production rate and the vent gas recovery 

2-2
rate was expected given that an increase in oil production should lead to more generation of vent gas and 

hence additional vent gas to be recovered. However, such trends were not observed with a limited 

dataset, and the variability in gas recovery rate was primarily due more to the operation of EVRU and not 

the site operating conditions. On average, approximately 177 ± 39 Mcf vent gas was recovered per barrel 

of oil processed at the test site. 

Table 2-2. Summary of Daily Operational Conditions 

Day 

Oil 

Production 

Rate 

(bbl/day) 

Discharge 

Gas 

Pressure 

(psia) 

EVRU 

Suction 

Pressure 

(psig) 

Seperator 

Pressure 

(psia) 

Ambient 

Temp 

(°F) 

Discharge 

Gas Temp 

(°F) 

Vent Gas 

Temp 

(° F) 

6/23-24/02 1,067 37.59 -0.056 - 83.38 59.97 89.36 

6/24-25/02 984 37.67 0.014 - 86.07 64.44 90.59 

6/25-26/02 961 37.60 0.089 72 86.58 63.99 90.20 

6/26-27/02 1,051 37.80 -0.317 - 84.80 69.51 89.77 

6/27-28/02 920 37.52 -0.353 72 85.76 70.19 88.72 

6/28-29/02 1,019 37.83 -0.240 - 77.21 62.50 85.33 

6/29-30/02 1,002 37.90 0.006 - 79.26 58.36 81.86 

6/30-7/1/02 925 37.07 -0.112 72 78.73 60.24 80.43 

Average 991 37.62 -0.121 72 82.72 63.65 87.03 

Std Dev 54.10 0.26 0.164 0 3.75 4.35 3.99 

Figure 2-1 shows the relationship between the daily average vent gas recovery rate and the daily total oil 

production levels. The oil production levels and the gas/oil separator pressures were relatively consistent 

throughout the test period. A direct relationship between oil production rate and the vent gas recovery 

rate was expected given that an increase in oil production should lead to more generation of vent gas and 

hence additional vent gas to be recovered. However, such trends were not observed with a limited 

dataset, and the variability in gas recovery rate was primarily due more to the operation of EVRU and not 

the site operating conditions. On average, approximately 177 ± 39 Mcf vent gas was recovered per barrel 

of oil processed at the test site. 

2-3
Figure 2-1. Relationship Between Vent Gas Recovery Rate and Oil Production Rate 

0 

50,000 

100,000 

150,000 

200,000 

250,000 

Vent Gas Recovery (scfd) 

0.00 

200.00 

400.00 

600.00 

800.00 

1,000.00 

1,200.00 

Oil Production Rate (bbl/day) 

6/24-25/02 6/25-26/02 6/26-27/02 6/27-28/02 6/28-29/02 6/29-30/02 6/30-7/1/02 D a y 

Vent Gas Recovery (scfd) Oil Production Rate (bbl/d) 

Figure 2-2 shows a plot of the vent gas recovery rate as a function of ambient temperature for June 24. 

As shown in this dataset and similar trends observed for other testing days, the highest vent gas recovery 

period corresponds to the highest daily temperature period. This is consistent with increase in flash gas 

and working losses expected at elevated ambient temperatures. The data also show that the EVRU is 

capable of accommodating typical daily variations in vent gas volumes. 

Figure 2-3 shows time series plots of motive gas flow rate, vent gas recovery rate, and EVRU suction 

pressure. In the initial days of testing, the motive gas pressure was significantly higher than the 850 psig 

design pressure. This operating condition increased the EVRU suction pressures to greater than 0.2 psig, 

and resulted in lower volume of recovered gas. It is expected that during these high pressure conditons, 

the entire EVRU piping network became overpressurized, and may have caused the tank pressures to 

exceed the setpoint. Under these conditions, it is likely that the gas uncollected by the EVRU may have 

escaped through the PRVs. 

2-4
Figure 2-2. Relationship Between Vent Gas Recovery Rate and Ambient Temperature 

6/24/2002

Ambient Temperature (F) 

120 300 

100 250 

Temperature 

80 200 

Recovery Rate 

60 150 

40 100 

20 50 

0 0 

Vent Gas Recovery Rate (scfm) 

6/23/02 12:00 AM 6/23/02 12:00 PM 6/24/02 12:00 AM 6/24/02 12:00 PM 6/25/02 12:00 AM 6/25/02 12:00 PM 6/26/02 12:00 AM 

Figure 2-4 shows the relationship between the motive-to-vent gas ratio as a function of vent gas pressure, 

and Figure 2-5 shows a similar plot, except that the vent gas recovery rate is shown as a function of 

EVRU suction pressures. The data in these figures are based on 1-minute measurements data collected 

during the +900 psig motive gas pressure condition, and after the motive gas pressure was stabilized to 

850 psig. The figures show that there is a systematic relationship between the EVRU suction pressure, 

gas recovery rate, and motive gas flow rate. The relationship also depends upon whether the primary 

eductor operates alone or in conjunction with the secondary eductor. Note that the secondary eductor 

never operated alone during the tests. 

2-5
Figure 2-3. Time Series Plots of Key Performance Data 

Booster 

Motive Gas Pressure : Motive Gas Pressure: Comp. Motive Gas Pressure: 

~ 850 psig 

600 

> 900 psig ~ 850 psig Failing 

Motive Gas 

Flow Rate 

Suction 

Pressure 

Vent Flow 

Rate 

1 

0.8 

500 

0.6 

0.4 

EVRU Suction Pressure (psig)

400 

Flow Rate (scfm)

0.2 

300 0 

-0.2 

200 

-0.4 

-0.6 

100 

-0.8 

0 -1 

6/23/02 12:00 6/24/02 12:00 6/25/02 12:00 6/26/02 12:00 6/27/02 12:00 6/28/02 12:00 6/29/02 12:00 6/30/02 12:00 7/1/02 12:00 7/2/02 12:00 

PM PM PM PM PM PM PM PM PM PM 

Day 

At the 850 psig condition, motive gas flows generally varied between 350-380 scfm with one eductor 

operational and 530-565 scfm with both units operating. The EVRU recovered between 100 and 140 

scfm gas with the primary eductor operating, and between 140 and 180 scfm with both eductors 

operating. These recovery capacities are consistent with the design values described in Section 1.3. It is 

concluded that when the system is operating at design motive gas pressures, the vent gas recovery rate is 

consistent with design flow capacities, and clearly responsive (by about 30 scfm; Figure 2-4) to the 

cycling of the second eductor unit. The average motive-to-vent gas ratio was 3.2 scfm/scfm with one 

eductor operating, and 3.5 scfm/scfm with two eductors operating. 

At the 950 psig condition, the motive gas flow rate generally varied between 340-350 scfm with one 

eductor operational and 500-530 scfm with both eductors operating. With the primary eductor operating, 

the motive-to-vent gas ratio was 3.2 scfm/scfm (similar to the 850 psig condition). However, when both 

eductors are in operation, the motive-to-vent gas ratio increases dramatically to 6.1 scfm/scfm, which 

equates to significantly less gas to be recovered. In this case, the gas recovery rate was relatively low and 

variable. Based on these observations, it is clear that at higher motive gas pressures, the system is unable 

to recover the volume ratio of vent gas. Eventually, the system is unable to perform as designed, and the 

EVRU suction pressure, which is directly related to the tank pressure, begins to build up and pressurize 

the entire piping network. The verification test revealed that continuous and proper control of the motive 

gas pressure is essential to achieving best performance from the EVRU system. 

Although this verification did not address long-term EVRU reliability, failure of external devices such as 

the booster compressor (Figure 2-3) may have more impact than failure of EVRU components. The 

eductors themselves have no moving parts. The other active components, such as pressure sensors and 

control valve actuators, are well-accepted designs whose operating reliability data would be available 

from their manufacturers. 

2-6
Figure 2-4. Motive-to-Vent Gas Ratio vs. EVRU Suction Pressure 

Motive / Vent Gas Ratio (scfm/scfm)

20 

18 

16 

14 

12 Both Eductors Operating, 

> 900 psig Motive Pressure

10 

8 

6 Both Eductors Operating, 

~ 850 psig Motive Pressure

4 

2

Primary Eductor Operating, Primary Eductor Operating, 

~ 850 psig Motive Pressure > 900 psig Motive Pressure

0

-0.8 -0.7 -0.6 -0.5 -0.4 -0.3 -0.2 -0.1 0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 

EVRU Suction Pressure (psig) 

Finally, as discussed previously, the EVRU is designed to maintain a slightly negative pressure on the 

suction side (-0.5 and 0.0 psig). The data show that the maximum volume of gas can be recovered when 

the suction pressures are maintained at this level. Over 70 percent of the data were within the optimum 

vent gas pressure range, accounting for over 80 percent of the vent gas recovered. 

Primary eductor operations comprised 25 percent of the collected data and accounted for 25 percent of the 

vent gas recovered. The remaining 75 percent of the collected data (and vent gas recovered) was due to 

both eductors operating together. 

2.2.2 Vent Gas Composition and Air Pollutant Recovery Rate 

Vent gas compositional analysis was conducted on gas samples collected from the EVRU suction line to 

determine methane, BTEX, and total HAP concentrations. A total of four vent gas samples were 

collected during the test period. Each of these samples showed an unusually high concentration of 

nitrogen and oxygen. For these four samples, the oxygen averaged 3.17 mole percent and the nitrogen 

averaged 14.5 mole percent (Appendix C). Such concentrations were unexpected, as vent gas must be 

free of air to avoid explosive conditions. The data were compared to the preliminary vent gas data taken 

prior to the start of the test period (Appendix B), and it showed that vent gas should have no oxygen and a 

very low concentration of nitrogen. This is supported by the fact that the EVRU contains an oxygen 

alarm which shuts down the system if concentrations exceed 2.5 percent. No shutdowns due to oxygen 

exceedances occurred during the tests. 

2-7
Vent Gas Recovery Rate (scfm) 

Figure 2-5. Gas Recovery Rate vs. EVRU Suction Pressure 

Both Eductors Operating, 

200 ~ 850 psig Motive Pressure Both Eductors Operating, 

> 900 psig Motive Pressure 

180 

160 

140 

120 

100 Primary Eductor Operating, 

~ 850 psig Motive Pressure 

80 

Primary Eductor Operating, 

> 900 psig Motive Pressure 60 

40 

20 

0 

-0.8 -0.7 -0.6 -0.5 -0.4 -0.3 -0.2 -0.1 0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 

EVRU Suction Pressure (psig) 

During testing, it is likely that air contaminated the vent gas samples. This is indicated by the oxygen and 

nitrogen content in some of the samples as analyzed. The Test Plan specified that the field personnel 

would close the sample cylinder valve while a partial vacuum remained in the cylinder. The laboratory 

recommended this practice to minimize the possibility that heavy hydrocarbons might condense in the 

cylinder. The GHG Center suspects that the partial vacuum was responsible for air in-leakage while the 

valves were being operated. This could also have occurred while the test operator was disconnecting the 

cylinder from the sampling port or during transport. The GHG Center hasn’t had this problem in the past 

when the cylinders were left at elevated pressures. 

Ultimately, the contamination source cannot be confirmed. The GHG Center received the lab results after 

the field campaign had concluded, so re-sampling was not an option. Consultation with the laboratory 

and site operators indicate that such contamination is relatively common. It is standard industry practice 

to normalize the concentrations to expected nitrogen levels in these situations. Appendix C provides the 

raw and normalized vent gas analyses based on the nitrogen (and oxygen) concentrations of the 

preliminary vent gas data. 

The average normalized vent gas compositions over the course of the testing period are shown in Table 2­

3. For each compound, the mole percent, mole fraction, and weight percent are given. These data are 

used to report daily average methane, BTEX, and HAP recovery rates in volume and mass basis. 

2-8
Table 2-3. Normalized Average Vent Gas Composition a 

Component Mole Percent Weight 

Percent 

Volumetric 

Flow Rate 

(Mscfd) 

Mass Flow Rate 

(lb/hr) 

Nitrogen 0.06 0.05 0.11 0.34 

Oxygen 0.00 0.000 0.00 0.00 

Carbon Dioxide 0.25 0.31 0.44 2.14 

Methane 50.25 22.09 87.86 154.72 

Ethane 10.33 8.51 18.06 59.61 

Propane 11.70 14.14 20.46 99.02 

Isobutane 5.62 8.95 9.83 62.69 

n-Butane 6.17 9.83 10.79 68.83 

Isopentane 3.59 7.09 6.28 49.71 

n-Pentane 2.62 5.18 4.58 36.28 

Hexanes Plus 9.41 23.85 16.45 167.03 

TOTAL 100.00 100.00 174.86 700.37 

Benzene 0.579 1.239 1.01 8.68 

Toluene 0.424 1.071 0.74 7.50 

EthylBenzene 0.034 0.099 0.06 0.69 

Xylenes (Total) 0.082 0.239 0.14 1.67 

BTEX 1.119 2.648 1.96 18.54 

n-Hexane 1.161 2.742 2.03 19.20 

C9 Naphalenes 0.111 0.350 0.19 2.45 

HAPS 2.390 5.740 4.18 40.19 

Higher Heating Value 2089 Btu/ft3 

Lower Heating Value 1919 Btu/ft3 

a Represents average results of four samples collected, see Appendix C. Average total mass flow was 16,809 

lb/day or 700.3 lb/hr; average total volumetric flow was 174.855 Mscfd; average total molecular weight was 

36.49 lb/lb b

 BTEX compounds are benzene, toluene, ethyl benzene, and xylenes c

 HAP compounds include the BTEX compounds, n-hexane, and C9 Naphthenes, as defined in 40 CFR Park 63 

2.3 ANNUAL GAS SAVINGS AND EMISSION REDUCTIONS 

Annual gas savings represent an estimate of the total volume of gas that can be recovered with the EVRU 

system in one year. As discussed in Section 1.4, the computation for this verification parameter requires 

assigning an operational availability to the EVRU. 

The GHG Center has verified that during the test period, the EVRU operated continuously with the 

exception of 4.3 hours required to replace the original motive gas pressure regulator. The downtime 

related to the failure in the booster compressor (about 14.8 hours) is unrelated to the performance of the 

EVRU, and is not used to estimate EVRU operational availability. At the time of writing this report, 

2-9
approximately 5 months had elapsed since the test was completed. During this time, the EVRU had 

logged no downtime, and according to the TFE operators, the system thus far has been “maintenance 

free”. Based on this information and the data collected during the verification period, the operational 

availability of the EVRU system for the first 5 months of operation is computed to be 99.91 percent. It is 

assumed that this availability is likely to persist throughout the year, as the EVRU contains few moving 

parts which would wear out and require maintenance. Consequently, the annual gas recovered value is 

computed as follows in Equation 3: 

Est. AGR = TGR EVRU operating + TGR booster comp. down + Q recovered, overall avg (OA) (Days) (Eqn. 3) 

TGR booster comp. down = Q recovered, overall avg (OA) (BDT) 

Where: 

Est. AGR = Estimated annual gas recovered with the EVRU, scfy 

TGR EVRU operating = Total gas recovered while EVRU operating, scf 

TGR booster comp. down = Total gas that could be recovered if the booster compressor was operating, scf 

Q recovered, overall avg = Overall daily average vent gas recovery rate, scfd 

OA = Estimated EVRU operational availability, 99.91 % 

Days = Number of days remaining in year, 357 days 

BDT = Total time the booster compressor was not operating, 0.6 days 

For estimation purposes, the above calculation reimburses the gas lost during booster compressor 

downtimes. Annual gas savings is computed as the difference between the annual gas recovered with the 

EVRU and the gas recovered with two baseline management practices. In the first baseline scenario, it is 

assumed that no recovery system is in place, and all of the vent gas would be released to the atmosphere. 

The second baseline scenario represents the test site. According to TFE operators, the existing VRU 

system was not operational approximately 10 percent of the time (876 hrs/yr). When this VRU was 

down, uncollected gas was simply vented to the atmosphere. Therefore, use of the EVRU will eliminate 

those emissions previously vented to the atmosphere during VRU downtime. Annual gas savings for the 

test site is simply the total gas recovered with the EVRU times 0.10. The following discussion 

summarizes the results. 

It is estimated that 63.9 million standard cubic feet per year (MMscfy) gas can be recovered with the 

EVRU. For a site that vents gas directly to the atmosphere, annual gas savings will also be 63.9 MMscfy. 

For the test site, whose operational availability of the conventional VRU system is 90 percent, the annual 

gas savings are much lower (6.4 MMscfy). The GHG Center recognizes that some sites which employ 

conventional VRUs may experience fewer downtimes than the test site. For such facilities, replacement 

of the VRU with EVRU may not result in significant gas savings. 

Table 2-4 summarizes the annual emission reduction estimates for the two baseline scenarios. These 

results were computed by multiplying the annual gas savings estimate (described above) with methane 

and HAP concentration levels. Annual emission reduction for other hydrocarbons is also presented. 

2-10
Table 2-4. Annual Emission Reduction Estimates 

Baseline Recovery System 

Vent Gas Is Released to Atmosphere 

Test Site: Conventional VRU With 

a Gas Compressor is Used 

(operational availability = 90 %) 

MMscfy Tpy MMscfy Tpy 

Methane 32.1 678 3.2 67.8 

HAPs 1.5 176 0.2 17.6 

Other Hydrocarbons 30.1 2,203 3.0 220.3 

2.4 VALUE OF RECOVERED GAS 

Industry standard practice is to value the gas in terms of price per million BTU (MMBtu) heat content. 

This allows consistent billing over a range of gas blends. The normalized, average lower heating value 

(LHV) of the vent gas was 1919 BTU/scf. At the average daily vent gas production rate of 174,855 scfd, 

this would amount to 3.35 x 108

 Btu/day, or 335 MMBtu/day. TFE valued the host site’s gas at an 

average $2.85 per MMBtu for the various gas blends it supplied to customers during June, 2002. This 

means that the vent gas would be valued at $956 per day, or $349,318 per year at that production rate with 

the measured LHV. 

For reference, Appendix D provides the pre-test discharge gas composition. Appendix E shows the 

composition during the test campaign. Similar to the vent gas samples, the test run discharge gas samples 

were contaminated with air. When the contaminated gas samples are normalized to average oxygen and 

nitrogen content as seen in the pre-test samples, carbon compound concentrations and heating values are 

consistent for a gas mixture containing approximately 3.2 parts natural gas to 1 part vent gas by volume. 

2.5 EVRU TOTAL INSTALLED COST 

The capital costs and total installed costs of the EVRU system are presented in Table 2-5. These costs 

reflect the total costs required for the installation and configuration of the system installed at the TFE-El 

Ebanito site. Costs associated with the GHG Center measurement instruments are not included in these 

estimates. 

Capital cost items include engineering design of the EVRU system, EVRU fabrication, motive gas and 

spool fabrication, commissioning and startup, and equipment transportation and delivery to the site. 

Installation costs associated with fabrication, start-up, and shakedown activities are also detailed in the 

table. 

The total installed costs for the EVRU are estimated to be $107,958. As previously discussed, the value 

of the recovered gas is $349,318. The EVRU has operated at the host site maintenance-free for about 6 

months. Given this, a simple payback period of 0.3 years is estimated for a site without a currently 

installed VRU. If an existing VRU is on site, payback would be much higher, and would need to account 

for potential maintenance expenses for the VRU. 

2-11
Table 2-5. Total Installed Costs for the EVRU System at the TFE Site 

Item Costs ($) 

Engineering design of EVRU 8,000 

EVRU Fabrication (including labor and materials) 49,160 

Motive Gas Spool Fabrication & Misc. (COMM) 2,500 

Commissioning and startup 8,450 

Equipment transportation and delivery 1,400 

Total EVRU Capital Costs 69,510 

Summary of EVRU Installation Costs 

Date Activity Labor 

(man-hrs) 

Hourly 

Rate ($) 

Labor 

Costs ($) 

Materials 

Costs ($) 

5/13/2002 Digging out 6-inch line from tank 

battery to EVRU 100 32 3,200 2,770 

5/14/2002 Fabrication work, digging out 6-inch 

line from tank battery to EVRU 100 32 3,200 0 

5/15/2002 

Install 6-inch replacement section, 

continue fabrication, set EVRU in 

place 

100 33 3,300 1,020 

5/16/2002 Installation and connections for EVRU 100 33 3,300 0 

5/17/2002 

Install flowline and hookup to EVRU 

and tank battery, install makeup gas to 

tanks, install controller and blowcase 

195 28 5,550 3,500 

5/18/2002 Finish installation of EVRU, back fill 

ditches, start up EVRU 80 36 2,850 0 

5/20/2002 Equipment costs 0 0 0 2,891 

6/11, 6/13, 

and 6/19/02 

Painting, backfilling, and finishing 

work 71 24 1,683 0 

6/20 and 

6/21/02 

Install blowcases on EVRU suction and 

tank battery 140 28 3,884 0 

6/22/2002 Painting, backfilling, and finishing 

work 42 31 1,300 0 

Total Labor and Materials Installation Costs 928 na 28,267 10,181 

Total Cost of EVRU System Installed and Commissioned at TotalFinaElf Facility 107,958 

Note: Labor rates vary widely depending on personnel used including laborers, mechanics, welders, heavy machine 

operators, etc. Values represented here are average rates for personnel involved in installation during a particular day. 

Installation materials cost consists mainly of fabrication piping, fittings, valves, controllers, and two blowcases. 

2-12
3.0 DATA QUALITY ASSESSMENT 

3.1 DATA QUALITY OBJECTIVES 

For verifications conducted by the GHG Center, measurement methodologies and instruments are 

selected to ensure that a stated level of data quality occurs in the final results. Data quality 

objectives (DQOs) are specified for key verification parameters before testing commences. 

These objectives must be achieved in order to draw conclusions with the desired level of 

confidence. 

The process of establishing DQOs starts with identifying the measurement variables that affect 

the verification parameter. The errors associated with each measurement variable must be 

accounted for to determine their cumulative effect on the data quality of each verification 

parameter. For example, determination of the gas recovery rate parameter requires measurement 

of discharge gas flow rate and motive gas flow rate. Thus, the error in gas recovery rate value is 

affected by the performance of the turbine and the orifice flow meters. The measurement errors 

for instruments are stated in terms of accuracy, precision, and completeness, and are defined as 

Data Quality Indicator (DQI) goals. Achievement of each DQI goal ensures that DQOs for each 

verification parameter are satisfied. 

Table 3-1 presents the DQOs for the verification parameters, the actual error achieved, and the 

method of reconciliation. Table 3-2 summarizes the measurment (i.e., DQI) goals and the actual 

errors achieved. Table 3-3 summarizes the QA/QC activities that were performed to reconcile the 

DQOs and DQIs. The reconciliation process consisted of: 

• Performing independent performance checks in the field with certified 

reference materials 

• Following approved reference methods 

• Factory calibrating the instruments with NIST traceable standards prior to 

use 

• Conducting sensor diagnostics in the field to ensure that the instruments are 

installed and operated correctly 

The following discussion illustrates that most DQI goals were achieved, and for all of the 

verification parameters, the DQOs were met. Further discussion of these data quality results is 

provided below. 

3-1
Table 3-1. Data Quality Objectives 

Objective Required Achieved Method of Reconciliation 

Gas Recovery Rate ± 20 % ± 9.68 % 

Error propagation of motive 

gas flow rate, discharge gas 

flow rate, discharge gas 

temperature, and discharge gas 

pressure measurements 

Duration of Testing 

At least 1 week of testing 

having 90% of daily 

average gas recovery rates 

within 0.30 times the 

overall average gas 

recovery rate OR a 

maximum of 28 days of 

testing 

8 Days 

Calculation of 90% confidence 

interval using the average 

daily gas recovery rates. 

Annual Gas Savings ± 20 % ± 9.68 % 

Error propagation of motive 

gas flow rate, discharge gas 

flow rate, discharge gas 

temperature, and discharge gas 

pressure measurements 

Emission Reductions Not specified ± 9.74 % 

Error propogation of gas 

recovery rate and methane 

concentration measurements 

Value of Gas Recovered ± 20 % ± 9.68 % 

Error propagation of motive 

gas flow rate, discharge gas 

flow rate, discharge gas 

temperature, and discharge gas 

pressure measurements and 

LHV analysis. 

3-2
Table 3-2. Measurement Instrument Specifications and Data Quality Indicator Goals 

Site Measurements Accuracy Completeness 

Measurement Variable 

Instrument 

Type / 

Manufacturer 

Instrument 

Range 

Range 

Observed in 

Field 

Goal Actual How Verified / 

Determined Goal Actual 

Motive Gas Standard Gas 

Flow Rate 

Integral Orifice 

Meter/ 

Rosemount 

3095 

200 to 600 scfm 210 to 584 scfm ± 1.0 % reading ± 1.92 % reading 

3 point 

calibration of 

static pressure, 

differntial 

pressure, and 

temperature 

sensors 

Flow through 

comparison 

check with 

turbine meter 

90% of daily 1­

minute 

measurements 

data must be 

valid 

86% of possible 

1-minute data 

were valid 

Vent Gas 

Vent Gas 

Temperature 

Type K 

Thermocouple / 

Omega 

0 to 200 oF 20 to 96 oF ± 0.10 % 

reading ± 1.3 % reading 

8 point 

calibration 

check with 

reference 

standard 

90% of daily 1­

minute 

measurements 

data must be 

valid 

86% of possible 

1-minute data 

were valid 

EVRU Suction 

Pressure 

Pressure 

Transmitter / 

Rosemount 

3051 

-50 to 50 in. 

H2O 

-17 to 18 in. 

H2O 

± 0.08 % 

reading 

± 0.036 % 

reading 

5 point 

calibration 

check with 

reference 

standard 

(continued) 

3-3
Table 3-2. Measurement Instrument Specifications and Data Quality Indicator Goals (continued) 

Site Measurements Accuracy Completeness 

Measurement Variable 

Instrument 

Type / 

Manufacturer 

Instrument 

Range 

Range 

Observed in 

Field 

Goal Actual How Verified / 

Determined Goal Actual 

Discharge Gas 

Actual Gas 

Flow Rate 

Rotary Turbine 

Gas Meter / 

American Gas 

Meter Co. 

GTS-4 

0 to 300 acfm 147 to 291 acfm ± 1.5 % reading ± 0.30 % 

reading 

5 point 

calibration 

check with 

reference 

standard 

90% of daily 

1-minute 

measuremen 

ts data must 

be valid 

86% of possible 1­

minute data were 

valid 

Gas Pressure 

Integral Orifice 

Meter/ 

Rosemount 

3095 absolute 

pressure sensor 

0 to 800 psia 32.89 to 38.86 

psia Not specified ± 0.023 % FS 

4 point 

calibration 

check with 

reference 

standard 

Gas 

Temperature 

Integral Orifice 

Meter/ 

Rosemount 

3095 

temperature 

sensor 

-40 to 1200 oF 40 to 84 oF Not specified ± 0.006 % FS 

4 point 

calibration 

check with 

reference 

standard 

Vent and 

Discharge Gas 

Sampling 

Component 

concentrations 

Gas 

Chromatograph 

/ HP 589011 

0 to 100 % for 

each component 

Discharge 

methane ranged 

from 68 to 84 % 

± 3.0 % error 

ASTM D1945 

Repeatability 

Specifications 

(see Test Plan) 

± 0.61 % 

average error, 

± 0.64 % 

average 

repeatability 

Comparison 

with certified 

audit 

concentration 

and Duplicate 

analysis of audit 

sample Minimum 3 

valid gas 

samples per 

week 

4 discharge gas 

samples and 4 vent 

gas samples were 

collected including 

1 audit sample from 

each location. The 

laboratory 

normalized aircontaminated 

samples to zero O2 

and expected N2 

values 

Lower Heating 

Value 

Calculated using 

composition 

analysis 

not applicable 

Discharge 

methane ranged 

from 68 to 84 % 

± 0.2 % ± 0.61 % 

Average 

difference 

between audit 

gas reference 

concentration 

and measured 

concentration 

Ambient 

Meteorological 

Conditions 

Ambient 

Temperature 

Vaisala Model 

HMD 60UO/YO 

transmitter 

-40 to 140 oF ± 0.9 oF ± 0.9 oF ± 0.13 oF 

1 point 

calibration 

check with 

reference 

standard 

95% of daily 

1-minute 

measuremen 

ts data must 

be valid 

89% of possible 1­

minute data were 

valid 

3-4
Table 3-3. Summary of QA/QC Checks 

Measurement 

Variable QA/QC Check Frequency Expected or Allowable Result Results Achieved 

Discharge Gas Flow 

Rate 

Turbine flow meter calibration by 

manufacturer * Beginning of test ± 1.5 % reading ± 0.30 % reading 

Pressure sensor calibration by 

manufacturer Beginning of test Not specified ± 0.023 % FS 

Temperature sensor calibration by 

manufacturer Beginning of test Not specified ± 0.006 % FS 

Motive Gas Flow 

Rate 

Calibration of absolute pressure 

sensor, differential pressure sensor, 

and temperature sensor by 

manufacturer 

Beginning of test ± 1.0 % reading ± 1.0 % reading 

Field verification – flow through 

comparison test with turbine meter* During Test 

Percent difference 

between orifice 

meter and turbine 

meter should be less 

than ± 1.5 % 

± 1.92% reading 

Sensor diagnostics Beginning and end 

of test Pass Passed all sensor diagnostic checks 

Vent and Discharge 

Gas Composition 

Independent performance check 

with blind audit sample* 

Two times during 

test period 

± 3.0 % for each 

target gas 

constituent 

Overall average ± 

0.61 % 

(See Section 3.2.2) 

Duplicate analysis performed by 

laboratory * 

At least twice 

during test period 

and on one blind 

audit sample 

Analysis values 

should be within 

ASTM D1945 

repeatability 

specifications 

Overall average ± 

0.64 % 

(See Section 3.2.2) 

Confirm canister is fully evacuated Before collection 

of every sample 

Canister pressure 

< 1 psia 

All sample 

canisters used 

< 1 psia 

Calibration with gas standards by 

laboratory 

Prior to analysis of 

each lot of samples 

± 1.0 % for each gas 

constituent 

(C1 - C12) 

See Table 3-5 

Ambient 

Meteorological 

Conditions 

Instrument calibration by 

manufacturer * Beginning of test Temperature: ± 0.9 o

F 

Temperature: 

± 0.13 o

F 

Reasonableness checks At least once 

during test period 

Recording should be 

comparable with 

portable humidity 

and temperature 

sensor 

Recording 

comparable with 

portable 

temperature sensor 

Vent Gas 

Temperature 

Instrument calibration by EPA with 

NIST traceable standard* Beginning of test ± 0.10 % reading ± 1.3 % FS 

EVRU Suction 

Pressure 

Instrument calibration by 

manufacturer * Beginning of test ± 0.08 % reading ± 0.036 % reading 

Reasonableness checks Throughout test 

Readings should be 

less than 0.3 psig on 

vent gas and 

approximately 40 

psia on discharge 

gas 

Most readings 

were within 

specified range for 

vent gas. All 

readings were 

within specified 

range for discharge 

gas 

* Results of these QA/QC checks are used to reconcile data quality indicators 

3-5
3.2 RECONCILIATION OF DQOS AND DQIS 

Table 3-2 summarizes the range of measurements observed during the verification test and the 

completeness goals and completeness achieved. Completeness is defined as the number of valid data 

points expressed as a percentage of the total number of readings possible during the data collection day. 

The completeness goals for the verification test were to collect 90 percent of the 1-minute averages for 

the flow measurement variables, collect 3 valid gas samples, and collect 95 percent of the 1-minute 

averages for meteorological data. 

About 86 percent of the possible 1-minute data points that could be collected in an 8 day test period were 

determined to be valid. The remaining data were invalidated due to the failure of the site’s booster 

compressor, which was not related to the performance of the COMM EVRU. The completeness goal for 

vent gas and discharge gas samples were exceeded, as four samples were collected from each gas stream. 

3.2.1 Gas Recovery Rate 

Gas recovery rate is defined as the difference between the discharge gas and motive gas compensated 

flow rates. The DQO for this verification parameter was to achieve an overall error of ± 20 percent. The 

sources of uncertainty (or measurement error) which contribute to this error include individual instrument 

errors for the motive gas and discharge gas flow rates. 

The overall error of the motive gas flow measurement was determined to be ± 1.92 percent, and the 

overall error for the discharge gas flow measurement was ± 1.02 percent. The measurement errors 

associated with the motive and discharge gas flow instruments contribute to the error in the vent gas 

recovery rate computation. Using error propagation techniques described in the test plan, the actual error 

for the vent gas recovery rate was determined to be ± 9.68 percent, which is well below the ± 20 percent 

stated in the Test Plan. Therefore the DQO for gas recovery rate was achieved. 

3.2.1.1 Motive Gas Flow Rate 

The Test Plan specified the use of an integral orifice meter (Rosemount Model 3095) to measure the flow 

of motive gas to the EVRU. The integral orifice meter was factory calibrated prior to installation in the 

field, and the calibration records were reviewed to ensure the ± 1.0 percent instrument accuracy goal was 

achieved. The primary method of reconciling the accuracy goal for the motive gas rate was the factory 

calibration of the integral orifice meter components which include the temperature sensor, differential 

pressure sensor, and absolute pressure sensor. A pretest factory calibration certificate was obtained for 

the three sensors, and each met the specified ranges. Consequently, Roesmount certified the meter to be 

accurate within ± 1.0 percent. 

A field verification of this meter was performed by isolating the vent gas line from the EVRU, and natural 

gas was allowed to flow through the orifice meter (located in the motive gas line) and the turbine meter 

(located in the discharge line). By doing this, the same volume of gas was flowing through each of the 

meters. Appendix F summarizes the results for three flow comparison tests. The absolute percent 

differences were ± 1.11, ± 2.73, and ± 5.13 percent at 550, 390, and 200 scfm, respectively. 

During the test motive gas flow rates ranged between 327 and 613 scfm. Thus, the data quality results of 

the flow are considered representitive of actual flow conditions observed during testing. These data are 

used to reconcile the orifice meter error. The results indicate an average negative bias of about 1.92 

percent, which is higher than the ± 1.0 percent factory calibration error. Consequently, the motive gas 

flow rates are assigned with a ± 1.92 percent measurement error. 

3-6
3.2.1.2 Discharge Gas Flow Rate 

As described earlier in Section 1.0, the discharge gas flow rate was not measured using the Rosemount 

integral orifice flow meter. An American Meter Company Model GTS-4 rotary turbine type gas meter 

was used as a replacement. The turbine meter measures gas flow in actual cubic feet (acf), therefore the 

discharge gas flow rate was converted to standard cubic feet (scf) using the measured gas pressure, 

temperature, and compressibility factor. The measurement errors for these variables were used to 

propagate the error for the gas recovery rate. 

The turbine meter readings were converted to standard conditions using Equation 4: 

V = V �

�

� Pg �

�

�

�

� 520 ��

�

� Zstd �� (Eqn. 4) g Ł 14.73łŁ

� Tg ł�

Ł

� Zg ł�

Where: 

V = Discharge gas flow rate, scfm 

Vg = Turbine meter reading, acfm 

Pg = Discharge gas pressure, psia 

Tg = Discharge gas temperature, R (°F + 460) 

Zstd = Compressibility factor at standard conditions from discharge gas analysis 

Zg = Compressibility factor at actual conditions 

Prior to testing, the turbine meter was calibrated with a volume prover at five flow levels that were within 

the meter’s operating range. The average percent difference between the meter readings and the reference 

readings was determined to be ± 0.30 percent, and this value was assigned as the turbine meter error. 

A pressure transducer and RTD were installed in the discharge line following American Gas Association 

procedures for sensor location (AGA 1996). These sensors were taken from the Rosemount gas flow 

meter previously installed on the discharge meter loop. Both sensors were factory calibrated with NIST 

traceable standards. The average results of a four point calibration check was determined to ± 0.023 

percent for the pressure sensor and ± 0.006 percent for the temperature sensor. 

Measurement error associated with the compressibility factor was reconciled by comparing analytical 

results of an audit gas submitted to the laboratory. As discussed later in Section 3.2.2, the overall average 

percent difference between the reference concentrations and the measured concentrations was ± 0.61 

percent, and this value was assigned as the gas compressibility error. 

The overall error in discharge gas flow measurement is ± 1.02 percent. This is based on error propagation 

of turbine meter error (± 0.30 percent), pressure (± 0.023 percent), temperature (± 0.006 percent), and 

compressibility factor (± 0.61 percent). 

3.2.2 Annual Gas Savings and Emission Reductions 

Annual gas savings are based on gas recovery rates, actual oil production rates during the testing period, 

and the projected annual oil production rate. As discussed earlier, the error in the gas recovery rate is ± 

9.68 percent. The oil production rates (actual and projected) were obtained directly from the site and are 

assumed to be accurate. Consequently, the error in annual gas savings is estimated to be ± 9.68 percent. 

3-7
Methane and HAP emission reductions are determined by multiplying the annual gas savings by the 

concentration of each pollutant. The error in this verification parameter is estimated to be ± 9.74 percent. 

This is based on the error associated with annual gas savings (discussed above), and vent gas 

compositional analysis results. 

Four vent gas samples, four discharge gas samples, and two audit gas samples were collected using same 

sampling procedures. The audit gas samples were collected during two different days from an identifical 

gas cylinder of certified concentration. The audit gas is an independent Natural Gas GPA Reference 

Standard manufactured by Scott Specialty Gases with a certified accuracy of ± 2 percent. All gas samples 

collected in the field, were submitted to Core Laboratories in Houston, Texas for composition, heating 

value, and compressibility factor analysis. Duplicate analysis was performed on one vent gas sample, one 

discharge gas sample, and one audit gas sample. 

As discussed earlier, the vent and discharge gas samples contained fairly high concentrations of nitrogen 

and oxygen. Because of these high concentrations, it is believed that there was air leakage into the 

canisters during the sample collection. Core Laboratories was able to normalize the vent and discharge 

gas data based on zero percent oxygen. After normalization, the vent and discharge gas concentrations 

were similar to pre-test samples. Therefore, the normalized vent and discharge samples collected during 

the verification test were used to quantify methane, BTEX, and HAP emissions. The duplicate analysis 

results for the vent and discharge gas samples were invalidated due to erroneous nitrogen levels in the 

samples. The data quality results presented here are based on the performance of the audit gas analysis. 

Table 3-4 summarizes the results of the two audit gas samples. Sample number 2 was invalidated because 

it is suspected that, similar to vent gas and discharge gas samples, air contamination occurred during 

sampling. For sample Number 1, duplicate analysis resulted in a repeatability (precision) of ± 0.8 percent 

for CH4. The duplicate analysis did not meet the DQI goals of ± 0.1 percent for compounds with 

concentrations greater than 10 mole percent. The maximum analytical error between the certified CH4 

concentration and the measured CH4 concentration was ± 1.1 percent. This value is assigned as the error 

associated with methane concentration measurements, and is used to compute errors in emission reduction 

estimates. 

The higher than expected error in concentration measurements are believed to result from poor sampling 

procedures in the field. They are not expected to be significantly affected by the analytical error of the 

laboratory, because as shown in Table 3-5, comparison with a continuous calibration standard (performed 

immediately prior to duplicate analysis) indicates a very close agreement among all gas species. 

3-8
Table 3-4. Audit Gas Analysis Results 

Gas 

Component 

Certified 

Component 

Concentratio 

n (mole %) 

Analytical 

Result (mole 

%) 

Absolute 

Differencea 

Combined 

Sampling 

and 

Analytical 

Error b

 (%) 

Duplicate 

Analytical 

Result (mole 

%) 

Analytical 

Repeatability c

(%) 

Audit Gas Sample 1 

Nitrogen 5.00 6.23 1.23 24.6 6.22 0.2 

Methane 70.50 69.69 0.81 1.1 70.28 0.8 

Ethane 9.01 9.02 0.01 0.1 9.04 0.2 

Propane 6.03 6.09 0.06 1.0 6.06 0.5 

n-Butane 3.01 2.99 0.02 0.7 2.98 0.3 

Isobutane 3.01 3.02 0.01 0.3 3.00 0.7 

n-Pentane 1.01 1.02 0.01 1.0 1.01 1.0 

Isopentane 1.01 1.01 0.00 0.0 1.00 1.0 

Average 0.13 0.61 0.64 

Audit Gas Sample 2 

Nitrogen 5.00 7.02 2.02 40.4 

Methane 70.50 74.91 4.41 6.3 

Ethane 9.01 6.91 2.10 23.3 

Propane 6.03 3.69 2.34 38.8 

n-Butane 3.01 1.42 1.59 52.8 

Isobutane 3.01 1.39 1.62 53.8 

n-Pentane 1.01 0.58 0.43 42.6 

Isopentane 1.01 0.79 0.22 21.8 

Average 1.82 34.20 

a Certified Concentration – Measured Concentration b (Certified Concentration – Measured Concentration) / Certified Concentration * 100 c (Measured Concentration – Duplicate Analysis Result) / Measured Concentration * 100 

Table 3-5. GC/FID Calibration Results 

Gas 

Component 

Certified 

Component 

Concentration 

(mole %) 

Analytical Result 

(mole %) 

Absolute 

Differencea 

Analytical Error 

(%) 

Audit Gas Sample 1 

Nitrogen 5.000 5.000 0.00 0.000 

Methane 70.4870 70.487 0.00 0.000 

Ethane 9.002 9.002 0.00 0.000 

Propane 6.003 6.003 0.00 0.000 

n-Butane 3.010 2.990 0.020 0.660 

Isobutane 3.001 3.020 0.019 0.006 

n-Pentane 1.000 1.000 0.000 0.000 

Isopentane 0.998 1.000 .0020 0.002 

a Certified Concentration – Measured Concentration 

3-9
3.2.3 Value of Gas Recovered 

The value of gas recovered in units of U.S. dollars per year, is the industry cost of natural gas multiplied 

by the annual cubic feet of gas saved. The industry average natural gas price was obtained through 

telephone conversations with the site manager and is assumed to be accurate. The natural gas price is a 

function of the heating value of the gas saved. The data quality of the gas recovered will depend on the 

data quality of the lower heating value (LHV) measurements. The DQI goal for LHV analysis is defined 

to be ± 0.2 percent, and propagated with the ± 20 percent gas recovery rate error to yield an overall ± 20 

percent error in the value of gas recovered. 

The natural gas price is a function of the heating value of the gas saved. The lower heating value was 

calculated using the normalized discharge gas sample results. The error in the heating values is directly 

related to the concentration measurements. As discussed earlier, the total error in compositional analysis 

is determined to be ± 0.61 percent (based on audit gas results). This equates to about a ± 7 Btu/ft3

 error in 

discharge gas heating values. The natural gas sales price is not expected to be affected by this variability. 

The Test Plan specified a DQO of ± 20 percent for the annual cubit feet of gas saved. Actual error for 

this parameter was ± 9.68 percent (Section 3.2.2). 

3-10
4.0 ADDITIONAL INFORMATION SUPPLIED BY COMM 

Note: This section provides an opportunity for COMM Engineering to provide additional comments 

concerning the EVRU system and its features not addressed elsewhere in this Verification Report. The 

GHG Center has not independently verified the statements made in this section. 

The Oil & Gas Industry is constantly moving toward new parameters at an ever-increasing pace. 

Stringent legislation and environmental regulation plus a general commitment to achieving efficient, cost 

reducing operations dictated change, while influencing government granted concessions. COMM 

Engineering, USA has utilized these new parameters as a departure point to develop processes and 

technologies that are unique in the industry. 

Our mission is to revolutionize the meaning of energy efficiency and environmental benefits through 

innovative technological systems that are breaking the barriers of conventional operations. The vision of 

COMM Engineering, USA can be witnessed by some of our latest developments. 

COMM Engineering’s Environmental Vapor Recovery Unit (EVRUTM) patented process utilizes 

supersonic velocities (kinetic energy) in place of shaft work to recover vent gases and boost them to a 

pressure that can be utilized or sold. Some of the benefits of the EVRUTM are listed below: 

• Low capital and operational costs versus conventional mechanical vapor recovery units 

(VRU) 

• No outside electrical power or fuel required to operate the EVRUTM. Because it does not 

require fuel or electricity it is ideal for remote locations. 

• System is closed loop, therefore no added emissions for the facility 

• Meets all regulatory requirements for vapor control and there is no increase in the 

facility’s emissions due to fuel consumption from a conventional VRU. 

• The EVRUTM is compact. Deck space, which is at a premium, is not wasted. The system 

can be installed in the pipe rack above the vessels. 

• No moving parts. With no moving parts there is nothing to wear out. Low- to nomaintenance costs. 

• The EVRUTM is scalable. This allows the unit to accommodate increasing or decreasing 

production rates. 

• The EVRUTM can be designed to operate in series. This style of operation allows the 

EVRUTM to boost the recovered gas to higher pressures in defined steps more efficiently. 

This technology can be applied to many other processes outside of traditional vapor recovery. Each 

EVRUTM is designed to meet the customer’s unique requirements. This allows the unit to be the most 

efficient technology for recovering what was previously thought to be a lost product. 

4-1

5.0 REFERENCES 

AGA 1996. Measurement of Gas by Turbine Meters, Transmission measurement Committee Report No. 

7, Catalog No. XQ0585, American Gas Association, Arlington, VA. 1996. 

ASTM 2001a. Standard Test method for Analysis of Natural Gas by Gas Chromatography. ASTMD1945-96ei, American Society for Testing and Materials, West Conshohocken, PA. 2001. 

ASTM 2001b. Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative 

Density of Gaseous Fuels. ASTM-D3588-98, American Society for Testing and Materials, West 

Conshohocken, PA. 2001. 

CFR Title 40 Part 63. National Emission Standards for Hazardous Air Pollutants For Source Catagories. 

Federal Register, U.S. Environmental Protection Agency Code of Federal Regulations (CFR), 

Washington, DC. June 17, 1999. 

EPA 1995. Compilation of Air Pollutant Emission Factors. Volume I: Stationary Point and Area 

Sources, Fifth Edition, AP-42, Section 7.1, Organic Liquid Storage Tanks. U.S. Environmental 

Protection Agency, Office of Air Quality Planning and Standards, Research Triangle Park, NC. 1995. 

EPA 1999. Methane Emissions From the U.S. Petroleum Industry. EPA-600/R-99-010, Environmental 

Protection Agency, Office of Research and Development, Research Triangle Park, NC. February, 1999. 

GPA 2000. 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. 2000. 

ICF 1997. Estimates of Methane Emissions From the U.S. Oil Industry (Draft). ICF Kaiser International, 

Inc., Fairfax, VA. November 1997. 

SRI 2002. Test and Quality Assurance Plan, COMM Engineering, USA Environmental Vapor Recovery 

Unit (EVRUTM), SRI/USEPA-GHG-QAP-19, Greenhouse Gas Technology Center, Southern Research 

Institute, Research Triangle Park, NC. April 2002. 

5-1

APPENDICES 

Page 

Appendix A Pre-Test Motive Gas Samples...................................................................A-2 

Appendix B Pre-Test Vent Gas Samples......................................................................A-3 

Appendix C Vent Gas Samples Collected During Testing..............................................A-4 

Appendix D Pre-Test Discharge Gas Samples ..............................................................A-5 

Appendix E Discharge Gas Samples Collected During Testing......................................A-6 

Appendix F Flow Through Comparison Results Between Turbine Meter 

and Orifice Meter ....................................................................................A-7 

A-1
Appendix A

Pre-Test Motive Gas Samples

Sample Date: 2/9/02a 5/8/02 

Compound Units 

Oxygen mol % <0.01 <0.01 

Nitrogen mol % 0.080 0.094 

Carbon Dioxide mol % 0.154 0.318 

Methane mol % 88.284 87.145 

Ethane mol % 6.802 7.248 

Propane mol % 2.411 2.779 

Isobutane mol % 0.609 0.756 

n-Butane mol % 0.562 0.656 

Isopentane mol % 0.257 0.273 

n-Pentane mol % 0.183 0.184 

Hexanes Plus mol % 0.658 0.547 

Total 100 100 

Relative Density 0.665 

Compressibility Factor 0.9970 

Higher Heating Value (Dry/Real) Btu/scf 1162 1171 

Lower Heating Value (Dry) Btu/scf 

a

 This gas composition was programmed into Rosemount motive gas flow meter 

A-2
Appendix B

Pre-Test Vent Gas Samples

Sample Date: 2/9/02 

Compound Units 

Oxygen mol % <0.01 

Nitrogen mol % 0.063 

Carbon Dioxide mol % 0.124 

Methane mol % 56.903 

Ethane mol % 12.233 

Propane mol % 10.381 

Isobutane mol % 4.549 

n-Butane mol % 4.848 

Isopentane mol % 2.992 

n-Pentane mol % 2.180 

Hexanes Plus mol % 5.727 

Total 100 

Higher Heating Value (Dry/Real) Btu/scf 1850 

A-3
Appendix C

Vent Gas Samples Collected During Test

As Received Normalized to 0 % O2 and 0.63 % N2 

Sample Date: 6/22/02 6/26/02 6/28/02 6/30/02 Average 6/22/02 6/26/02 6/28/02 6/30/02 Average 

2:24 PM 11:00 AM 12:40 PM 3:00 PM 2:24 PM 11:00 AM 12:40 PM 3:00 PM 

Compound Units 

Nitrogen mol % 33.02 4.70 16.21 4.26 14.55 0.063 0.063 0.063 0.063 0.06 

Oxygen mol % 7.83 0.68 3.77 0.95 3.31 0.000 0.000 0.000 0.000 0.00 

Carbon Dioxide mol % 0.26 0.13 0.23 0.13 0.19 0.44 0.14 0.29 0.14 0.25 

Methane mol % 37.28 46.84 39.71 36.94 40.19 62.97 49.47 49.6 38.96 50.25 

Ethane mol % 4.77 10.09 7.94 12.02 8.71 8.06 10.66 9.92 12.67 10.33 

Propane mol % 4.26 12.00 8.61 15.34 10.05 7.20 12.68 10.75 16.17 11.70 

Isobutane mol % 2.14 5.73 4.3 7.05 4.81 3.62 6.05 5.37 7.43 5.62 

n-Butane mol % 2.49 6.22 4.85 7.45 5.25 4.21 6.57 6.06 7.85 6.17 

Isopentane mol % 1.67 3.47 2.99 3.94 3.02 2.82 3.67 3.73 4.15 3.59 

n-Pentane mol % 1.27 2.49 2.22 2.78 2.19 2.15 2.63 2.77 2.93 2.62 

Hexanes Plus mol % 5.01 7.65 9.17 9.14 7.74 8.47 8.07 11.45 9.64 9.41 

2,2-Dimethylbutanemol % 0.151 0.276 0.260 0.309 0.249 0.255 0.292 0.325 0.326 0.300 

2-Methyl Pentanemol % 0.553 0.994 0.973 1.026 0.887 0.934 1.050 1.215 1.082 1.070 

3-Methyl Pentanemol % 0.503 0.813 0.804 0.957 0.769 0.850 0.859 1.004 1.009 0.930 

n-Hexanemol % 0.623 1.032 1.052 1.126 0.958 1.052 1.090 1.314 1.187 1.161 

Methylcyclopentanemol % 0.392 0.622 0.659 0.698 0.593 0.662 0.657 0.823 0.736 0.720 

Benzenemol % 0.312 0.480 0.546 0.568 0.477 0.527 0.507 0.682 0.599 0.579 

Cyclohexanemol % 0.442 0.684 0.764 0.787 0.669 0.747 0.723 0.954 0.830 0.813 

2-Methyl Hexanemol % 0.199 0.306 0.356 0.339 0.300 0.336 0.323 0.445 0.357 0.365 

3-Methyl Hexanemol % 0.156 0.233 0.273 0.264 0.232 0.264 0.416 0.577 0.477 0.434 

Dimethylcyclopentanexmol % 0.109 0.161 0.189 0.188 0.162 0.184 0.000 0.000 0.000 0.046 

n-Heptanemol % 0.282 0.409 0.506 0.488 0.421 0.476 0.432 0.632 0.515 0.514 

Methylcyclohexanemol % 0.402 0.572 0.725 0.697 0.599 0.679 0.604 0.905 0.735 0.731 

Trimethylcyclopentanesmol % 0.047 0.065 0.077 0.074 0.066 0.079 0.069 0.096 0.078 0.081 

Toluenemol % 0.241 0.306 0.427 0.409 0.346 0.407 0.323 0.533 0.431 0.424 

2-Methylheptanemol % 0.068 0.092 0.145 0.045 0.088 0.115 0.097 0.181 0.047 0.110 

3-Methylheptanemol % 0.004 0.006 0.010 0.008 0.007 0.007 0.006 0.012 0.008 0.008 

Dimethylcyclohexanesmol % 0.100 0.133 0.220 0.184 0.159 0.169 0.140 0.275 0.194 0.194 

n-Octanemol % 0.111 0.143 0.258 0.209 0.180 0.188 0.151 0.322 0.220 0.220 

EthylBenzenemol % 0.020 0.019 0.041 0.030 0.028 0.034 0.020 0.051 0.032 0.034 

Xylenes (Total)mol % 0.082 0.077 0.054 0.040 0.063 0.139 0.081 0.067 0.042 0.082 

C9 Naphthenesmol % 0.026 0.054 0.080 0.229 0.097 0.044 0.057 0.100 0.241 0.110 

C9 Paraffinsmol % 0.054 0.058 0.139 0.106 0.089 0.091 0.061 0.174 0.112 0.110 

N-nonanemol % 0.050 0.051 0.324 0.229 0.164 0.084 0.054 0.405 0.241 0.196 

Decanes Plusmol % 0.083 0.058 0.285 0.129 0.139 0.140 0.061 0.356 0.136 0.173 

Total 100.00 100.00 100.00 100.00 100.00 100.003 100.01 100.00 100.00 100.000 

Relative Density 1.061 1.245 1.262 1.389 1.239 1.112 1.261 1.333 1.412 1.280 

Compressibility Factor 0.99517 0.98824 0.98938 0.98495 0.98944 0.98992 0.98715 0.98497 0.98359 0.98641 

Higher Heating Value (Dry/Real) Btu/ scf 1091 1980 1751 2204 1756 1835 2068 2164 2290 2089 

Lower Heating Value (Dry) Btu/ scf 999 1818 1610 2027 1613 1682 1898 1989 2106 1919 

A-4
Appendix D 

Pre-Test Discharge Gas Samples 

Sample Date: 6/4/02 6/4/02 6/5/02 6/5/02 6/6/02 6/6/02 Average 

Sample Time: 7:30 am 4:00 pm 8:00 am 3:00 pm 7:30 am 2:30 pm 

Compound Units 

Oxygen mol % <0.01 <0.01 <0.01 <0.01 <0.01 <0.01 

Nitrogen mol % 0.14 0.16 0.09 0.15 0.13 0.36 0.17 

Carbon Dioxide mol % 0.12 0.1 0.11 0.09 0.09 0.13 0.11 

Methane mol % 79.45 78.04 80.44 79.33 86.89 78.62 80.46 

Ethane mol % 8.18 8.18 8.03 8.17 7.17 8.05 7.96 

Propane mol % 4.77 4.77 4.46 4.66 2.83 4.49 4.33 

Isobutane mol % 1.82 1.86 1.63 0.18 0.77 1.82 1.35 

n-Butane mol % 1.81 1.94 1.62 1.84 0.7 1.82 1.62 

Isopentane mol % 0.93 1.05 0.84 1 0.3 1 0.85 

n-Pentane mol % 0.66 0.77 0.59 0.73 0.21 0.72 0.61 

Hexanes Plus mol % 2.12 3.13 2.19 3.85 0.91 2.99 2.53 

Total 100 100 100 100 100 100 100 

2,2-Dimethylbutane mol % 0.075 0.091 0.068 0.086 0.024 0.087 0.07 

2-Methyl Pentane mol % 0.25 0.345 0.229 0.323 0.085 0.316 0.26 

3-Methyl Pentane mol % 0.24 0.274 0.217 0.271 0.072 0.265 0.22 

n-Hexane mol % 0.28 0.365 0.268 0.354 0.099 0.347 0.29 

Methylcyclopentane mol % 0.167 0.221 0.16 0.218 0.061 0.209 0.17 

Benzene mol % 0.145 0.203 0.206 0.25 0.044 0.2 0.17 

Cyclohexane mol % 0.19 0.264 0.186 0.261 0.07 0.245 0.20 

2-Methyl Hexane mol % 0.085 0.112 0.075 0.117 0.035 0.109 0.09 

3-Methyl Hexane mol % 0.062 0.09 0.062 0.094 0.027 0.086 0.07 

Dimethylcyclopentanes mol % 0.044 0.064 0.043 0.066 0.019 0.056 0.05 

n-Heptane mol % 0.11 0.172 0.113 0.188 0.054 0.163 0.13 

Methylcyclohexane mol % 0.16 0.243 0.165 0.271 0.072 0.224 0.19 

Trimethylcyclopentanes mol % 0.018 0.031 0.02 0.035 0.009 0.032 0.02 

Toluene mol % 0.098 0.162 0.113 0.198 0.05 0.153 0.13 

2-Methylheptane mol % 0.025 0.046 0.027 0.058 0.017 0.045 0.04 

3-Methylheptane mol % 0.013 0.024 0.014 0.031 0.009 0.022 0.02 

Dimethylcyclohexanes mol % 0.026 0.049 0.027 0.061 0.018 0.046 0.04 

n-Octane mol % 0.038 0.081 0.047 0.104 0.032 0.078 0.06 

Ethyl Benzene mol % 0.005 0.01 0.007 0.017 0.004 0.011 0.01 

Xylenes (Total) mol % 0.027 0.068 0.042 0.474 0.028 0.068 0.12 

C9 Naphthenes mol % 0.009 0.025 0.015 0.04 0.007 0.023 0.02 

C9 Paraffins mol % 0.016 0.039 0.023 0.061 0.016 0.042 0.03 

n-Nonane mol % 0.013 0.048 0.024 0.078 0.014 0.049 0.04 

Decanes Plus mol % 0.029 0.101 0.039 0.191 0.042 0.114 0.09 

Total 2.125 3.128 2.19 3.847 0.908 2.99 2.53 

Total HAP 0.555 0.808 0.636 1.293 0.225 0.779 0.72 

Relative Density 0.783 0.820 0.773 0.815 0.676 0.810 0.77932 

Compressibility Factor 0.99556 0.99498 0.99566 0.99489 0.99684 0.99514 0.99551 

Higher Heating Value (Dry/Real) Btu/scf 1359 1415 1343 1404 1195 1395 1351.9 

Lower Heating Value (Dry) Btu/scf 1236 1288 1221 1279 1082 1270 1229 

A-5
Appendix E 

Discharge Gas Samples Collected During Test 

As Received Normalized to 0 % O2 and 0.17 % N2 

Sample Date: 6/22/02 6/26/02 6/28/02 6/30/02 Average 6/22/02 6/26/02 6/28/02 6/30/02 Average 

Sample Time: 12:45 PM 11:15 AM 12:30 PM 2:50 PM 12:45 PM 11:15 AM 12:30 PM 2:50 PM 

Compound Units 

Oxygen mol % 0.45 0.3 0.02 1.05 0.46 0.00 0.00 0.00 0.00 0.00 

Nitrogen mol % 8.68 1.62 2.06 5.56 4.48 0.17 0.17 0.17 0.17 0.17 

Carbon Dioxide mol % 0.91 0.09 0.09 0.1 0.30 1.00 0.09 0.09 0.11 0.32 

Methane mol % 67.93 83.68 77.58 77.01 76.55 74.63 85.17 79.09 82.32 80.30 

Ethane mol % 8.71 6.8 7.7 7.09 7.58 9.57 6.92 7.85 7.58 7.98 

Propane mol % 5.73 3.3 4.67 3.89 4.40 6.29 3.36 4.76 4.16 4.64 

Isobutane mol % 2.87 1.09 1.83 1.34 1.78 3.15 1.11 1.87 1.43 1.89 

n-Butane mol % 2.81 1.03 1.89 1.34 1.77 3.09 1.05 1.93 1.43 1.88 

Isopentane mol % 0.89 0.49 1.01 0.66 0.76 0.98 0.50 1.03 0.71 0.81 

n-Pentane mol % 0.89 0.35 0.74 0.46 0.61 0.98 0.36 0.75 0.49 0.65 

Hexanes Plus mol % 0.13 1.25 2.41 1.5 1.32 0.14 1.27 2.46 1.60 1.37 

Total 100 100 100 100 100 100 100 100 100 100 

Relative Density 0.822 0.710 0.800 0.758 0.773 0.807 0.705 0.797 0.742 0.76258 

Compressibility Factor 0.99606 0.99669 0.99569 0.9965 0.99624 0.99550 0.99661 0.99557 0.99621 0.99597 

Higher Heating Value (Dry/Real) Btu/scf 1247 1214 1351 1209 1255 1370 1236 1377 1293 1319 

Lower Heating Value (Dry) Btu/scf 1134 1101 1228 1098 1140 1246 1121 1252 1173 1198 

A-6
Appendix F

Flow Through Comparison Results Between Turbine Meter and Orifice Meter

Percent Differencea 

Discharge Turbine Turbine Orifice Between Turbine Meter 

Ambient Gas Discharge Meter Flow Meter Flow Meter Flow Reading and Orifice Meter 

Date Time Temp. Pressure Gas Temp. Rate Rate Rate Reading 

(F) (psia) (F) (acfm) (scfm) (scfm) (%) 

6/23/02 12:10 PM 89.91 37.19 54.95 217.83 558.13 550.53 1.36 

6/23/02 12:11 PM 90.15 37.11 55.04 218.35 558.11 550.37 1.39 

6/23/02 12:12 PM 90.90 38.02 55.13 212.39 556.08 550.68 0.97 

6/23/02 12:13 PM 91.48 38.05 55.35 214.17 560.99 552.44 1.52 

6/23/02 12:14 PM 91.52 37.69 55.52 214.58 556.58 550.70 1.06 

6/23/02 12:15 PM 91.27 36.17 55.57 222.65 554.09 552.42 0.30 

6/23/02 12:16 PM 90.75 38.15 55.57 211.95 556.40 550.52 1.06 

6/23/02 12:17 PM 90.10 37.55 55.44 215.08 555.82 553.70 0.38 

6/23/02 12:18 PM 89.97 35.77 55.31 226.39 557.44 552.53 0.88 

6/23/02 12:19 PM 89.76 37.85 55.20 217.71 567.49 551.43 2.83 

6/23/02 12:20 PM 89.73 37.59 54.88 213.54 553.12 551.48 0.30 

6/23/02 12:21 PM 89.75 37.70 54.67 215.98 561.22 552.41 1.57 

6/23/02 12:22 PM 90.31 36.19 54.72 223.69 557.98 552.29 1.02 

6/23/02 12:23 PM 90.41 37.46 54.89 215.42 556.03 553.14 0.52 

6/23/02 12:24 PM 90.29 38.00 55.11 214.55 561.47 553.11 1.49 

Average 90.42 37.37 55.16 216.95 558.06 551.85 1.11 

6/23/02 12:40 PM 90.87 33.55 55.99 170.21 392.66 381.49 2.85 

6/23/02 12:41 PM 91.36 33.36 56.39 169.31 387.99 380.23 2.00 

6/23/02 12:42 PM 91.10 33.26 56.26 170.14 388.85 380.71 2.09 

6/23/02 12:43 PM 90.55 34.54 56.33 164.30 389.95 380.53 2.42 

6/23/02 12:44 PM 90.63 33.46 55.86 171.52 394.73 381.39 3.38 

6/23/02 12:45 PM 90.73 31.67 56.07 177.13 385.62 382.24 0.88 

6/23/02 12:46 PM 90.74 35.73 55.76 161.21 396.18 380.73 3.90 

6/23/02 12:47 PM 90.41 32.23 55.68 179.51 398.02 380.97 4.29 

6/23/02 12:48 PM 90.21 34.52 55.62 162.63 386.29 379.93 1.65 

6/23/02 12:49 PM 90.14 33.55 55.38 169.54 391.51 381.32 2.61 

6/23/02 12:50 PM 90.24 32.12 55.48 176.94 391.08 381.60 2.42 

6/23/02 12:51 PM 90.32 32.58 55.60 173.37 388.65 381.62 1.81 

6/23/02 12:52 PM 90.14 35.40 55.29 159.86 389.59 382.39 1.85 

6/23/02 12:53 PM 90.17 31.73 55.27 181.26 395.92 381.87 3.55 

6/23/02 12:54 PM 90.20 33.56 55.35 173.26 400.31 381.06 4.81 

6/23/02 12:55 PM 90.29 33.81 54.90 168.61 392.77 382.37 2.65 

6/23/02 12:56 PM 90.56 33.80 55.01 168.29 391.83 381.54 2.63 

6/23/02 12:57 PM 90.80 36.48 54.98 156.04 392.13 380.28 3.02 

6/23/02 12:58 PM 90.43 32.26 55.24 177.74 394.75 382.70 3.05 

Average 90.52 33.56 55.60 170.05 392.04 381.31 2.73 

6/23/02 1:03 PM 89.84 28.41 62.87 110.02 212.05 197.13 7.03 

6/23/02 1:04 PM 89.85 26.82 61.68 117.33 214.00 199.28 6.88 

6/23/02 1:05 PM 89.82 27.27 69.78 114.83 209.71 200.30 4.49 

6/23/02 1:06 PM 89.92 29.15 65.68 107.13 210.74 198.44 5.83 

6/23/02 1:07 PM 90.20 26.86 62.89 114.98 209.52 198.37 5.32 

6/23/02 1:08 PM 90.61 27.56 63.07 109.35 204.39 198.76 2.76 

6/23/02 1:09 PM 91.22 28.52 61.56 109.15 211.75 198.19 6.40 

6/23/02 1:10 PM 91.04 26.61 63.23 116.24 209.69 200.31 4.47 

6/23/02 1:11 PM 90.52 29.73 63.50 103.04 207.59 198.97 4.15 

6/23/02 1:12 PM 91.01 26.02 63.35 120.26 212.10 199.06 6.15 

6/23/02 1:13 PM 91.56 28.56 63.75 107.53 207.99 199.04 4.30 

6/23/02 1:14 PM 91.65 29.25 63.89 107.48 212.86 198.04 6.96 

6/23/02 1:15 PM 91.16 25.56 63.75 122.88 212.74 197.82 7.01 

6/23/02 1:16 PM 91.13 29.46 63.95 103.82 207.09 198.60 4.10 

6/23/02 1:17 PM 91.07 25.94 63.56 118.45 208.18 198.74 4.54 

6/23/02 1:18 PM 90.60 28.96 63.65 104.08 204.20 198.63 2.73 

6/23/02 1:19 PM 90.71 27.95 63.38 113.50 215.02 198.42 7.72 

6/23/02 1:20 PM 91.42 26.26 63.26 120.84 215.11 199.15 7.42 

6/23/02 1:21 PM 91.73 28.53 63.44 109.99 212.65 198.18 6.81 

Average 90.79 27.76 63.70 112.15 210.39 198.71 5.53 

a

 = 100 * (Turbine Meter Reading - Orifice Meter Reading) / Turbine Meter Reading 

A-7