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Barnett Shale: Technical Questions Answered

Answers to questions on air quality and gas and oil operations in the Barnett Shale area.

 

IR Cameras

In what counties has the TCEQ deployed the infrared gas-imaging camera to study emissions from individual tanks or tank batteries associated with upstream oil and gas production, and over what time frame?

There are three programs in the agency that conduct studies or investigations using the infrared hydrocarbon gas-imaging camera system. The three programs are the Monitoring Operations Program and the Field Operations Regional Offices both in the Office of Compliance and Enforcement and the Air Quality Division in the Chief Engineer’s Office. In total, the agency has conducted infrared gas-imaging camera (IR camera) surveys at oil and natural gas sources in 58 Texas counties, which are listed below. In most cases, the surveys were conducted around individual tanks or tank batteries, with some surveys being conducted at natural gas compressor stations.

The Monitoring Operations Program has been conducting ambient monitoring surveys of oil and natural gas sources using IR cameras. Surveys have been conducted in the following counties: Aransas, Brazoria, Calhoun, Chambers, Denton, Ector, El Paso, Galveston, Glasscock, Gregg, Harris, Howard, Jefferson, Jim Wells, Johnson, Kleberg, Limestone, Midland, Nueces, Orange, Rusk, San Patricio, Smith, Tarrant, Victoria, and Wise.

The agency’s regional offices have also been conducting ambient monitoring surveys of oil and natural gas sources using handheld IR cameras. In the DFW Region, the TCEQ has deployed the IR camera to study emissions in Hood, Johnson, Navarro, Palo Pinto, Parker, and Tarrant counties during two separate time frames: December 5–20, 2008, and May 8–June 11, 2009.

In the Amarillo region, the IR camera has been deployed to study emissions in Carson, Dallam, Gray, Hartley, Hemphill, Hutchinson, Moore, Potter, Randall, and Wheeler counties from May 1, 2008, through September 15, 2009.

The Midland region has deployed the IR camera in Andrews, Crane, Ector, Howard, Midland, Pecos, Sterling, and Winkler counties from September 12, 2007, through September 29, 2009.

The Houston region has been deploying the IR camera continuously from July 2006. The IR camera has been used at sites in Brazoria, Chambers, Fort Bend, Galveston, Harris, Liberty and Montgomery counties.

In the Corpus Christi region, the IR camera was deployed at sources in Calhoun, Jim Wells, Nueces, Refugio, and San Patricio counties from August 2006 through September 2009.

Since 2005, the Air Quality Division in the Chief Engineer’s Office has conducted numerous studies that used the IR camera system—both helicopter mounted and hand held. In July 2005, the Gulf Coast Survey was conducted in Chambers, Galveston, Harris, Hardin, Liberty, and Jefferson counties. In a July 2007 aerial survey project, the following Gulf Coast and Dallas–Fort Worth–area (DFW) counties were surveyed: Brazoria, Chambers, Galveston, Harris, Liberty, Orange, San Patricio, Denton, Johnson, Parker, and Tarrant. A June 2009 aerial survey was conducted in the following Tyler-Longview-Marshall-area counties: Gregg, Harrison, Panola, Rusk, Smith, Upshur, and Wood.  Finally, in August 2009, an aerial survey was conducted in the Gulf Coast area again, this time in Jefferson, Harris, and Nueces counties.

How many different upstream oil or condensate tanks or tank batteries has the TCEQ analyzed with an infrared gas-imaging camera? What percentage of the facilities evaluated indicated the presence of VOC, methane, or other fugitive emissions?

The table below gives the best available estimation of the number of upstream oil and natural gas tank batteries that the TCEQ has surveyed with the IR camera system. Also included is the estimated percentage of tank batteries that had visible emissions. This percentage of visible emissions is based on the fact that the IR camera cannot speciate the compounds or quantify the amount being emitted; it is assumed that any visible emissions are in the general group of hydrocarbons, which would include methane, ethane, and volatile organic compounds (VOCs).

Agency Program

Total sites surveyed

Percentage with visible emissions

Monitoring Operations

150

75%

                                  Field Operations Regional Offices

Dallas/Fort Worth

12

100%

Amarillo

175

95%

Midland

150

100%

Houston

46

90%

Corpus Christi

25

95%

                            Air Quality Division (helicopter surveys)

2005 Gulf Coast survey

500 tanks

50 tanks for 10%

2007 Gulf Coast survey

64 sites with visible emissions—total number surveyed is unknown

2007 DFW survey

93 sites with visible emissions—total number surveyed is unknown

2009 Tyler/Longview survey

49 sites with visible emissions—total number surveyed is unknown

2009 Gulf Coast survey

10 sites with visible emissions—total number surveyed is unknown—mainly an industrial source survey

When conducting a survey at an oil or natural gas tank storage battery with a handheld IR camera, due to the close proximity of the IR camera to the equipment, normally some level of visible emissions is noted. Visible emissions detected by the IR camera do not necessarily indicate that the source is not operating correctly or not operating within its authorization. Typically, the absence of visible emissions normally indicates an inactive site. When visible emissions are detected by the IR camera, further investigation may indicate emissions from equipment that is designed to vent hydrocarbons as a means of pressure relief, while at other times the images indicate hydrocarbons emitted from unauthorized sources such as open hatches, leaks, or ruptures, or loss of system integrity. As stated above, the IR camera cannot speciate the compounds or quantify the amount being emitted; therefore by itself the camera cannot be used to determine if the site is in compliance with its authorizations.

What is the minimum concentration of hydrocarbons in air that the infrared camera can detect being released? Please estimate the minimum mass of hydrocarbons released, in pounds per hour, that this minimum detectable concentration would represent from a typical condensate tank. To the extent possible, please giveestimates of the relative quantities of VOCs, methane, and other hydrocarbons in those emissions.

The IR camera technology offers a unique technological advancement in pollution detection and has proved highly effective in the detection of hydrocarbon emissions. However, the IR camera system is not considered a quantitative or a qualitative tool. While the technology is not capable of measurements, and results do not lend themselves to interpretation in terms of concentration, minimum detection limits have been estimated by the IR camera manufacturers and EPA.  Results vary dramatically due to the following factors:

  • The relative temperatures of the gas under observation and the background.
  • The relative IR absorption coefficient of the specific gas or gases being observed.
  • Atmospheric conditions such as rain, fog or high humidity, wind, blown dust etc.
  • The physical characteristics of the emission themselves—volumetric flow, orifice size and location, presence of steam or particulate matter.
  • Physical and thermal conditions at the site—distance from the camera, reflected and radiated heat, masking by steam and particulate matter etc.
  • Operator dependent parameters such as use of temperature sensitivity range (high, mid, low), manual or auto tune, high-sensitivity mode if the camera is so equipped, polarity, lens focal length (e.g. 25, 50 or 100 mm telephoto), the age and condition of the camera’s eyepiece, state of operator fatigue (optical and general),  operator training, experience and effort, etc.

In light of the stated limitations, a reasonable estimate of the technology’s current minimum detection limit (best conditions assumed) ranges from 0.001 pounds per hour to approximately 0.22 lb/hr. The low end of this assessment is based on the manufacturer’s estimates, while the high end is based on the expectations of the new EPA alternative work practice. This number will vary significantly with the relative absorption coefficient of target compounds, the actual temperature difference, and other potential interferences as described above.  As an example of this variability, the table below is information obtained from the manufacture of the FLIR GasFindIR camera.  Independent laboratory (third-party) testing determined that the GasFindIR cameras can detect the following gases at the minimum detected leak rate (MDLR)" "

Minimum Detected Leak Rate


Hydrocarbon Compound
Minimum Detected Leak Rate MDLR Converted to Pounds/Hour

1-Pentene

5.6 g/hr 

0.012

Benzene

3.5 g/hr 

0.008

Butane

0.4 g/hr 

0.001

Ethane

0.6 g/hr 

0.001

Ethanol

0.7 g/hr 

0.002

Ethylbenzene  

1.5 g/hr

0.003

Ethylene

4.4 g/hr 

0.010

Heptane

1.8 g/hr

0.004

Hexane

1.7 g/hr

0.004

Isoprene

8.1 g/hr 

0.018

Methyl ethyl ketone

3.5 g/hr

0.008

Methane

0.8 g/hr 

0.002

Methanol

3.8 g/hr

0.008

Methyl isobutyl ketone

2.1 g/hr 

0.005

Octane

1.2 g/hr

0.003

Pentane

3.0 g/hr

0.007

Propane

0.4 g/hr

0.001

Propylene

2.9 g/hr

0.006

Toluene

3.8 g/hr

0.008

Xylene

1.9 g/hr

0.004

In practice, the TCEQ has informally evaluated IR camera images collected as part of a study to evaluate the upstream oil and gas flash emissions model. IR camera images were captured from 36 upstream oil and gas tank batteries at varying distances under varying conditions.  On average, these tank batteries, which had source testing performed, had emissions rates that ranged from 1.5 to 408 pounds per hour. Although differences between flow rate and intensity were noted among the images, no correlation between the hydrocarbon emissions rate and image intensity or image dynamics was readily observed.

As to estimating hydrocarbons, as previously discussed the current IR technology is not capable of measuring or estimating these values. This sort of analysis is best achieved via chemical sampling and analytical methodologies, such as gas capture in canisters and analysis via gas chromatograph and/or GC/Mass Spectroscopy, or other real-time vapor recovery and analysis methods. Another, less desirable, option may be production data that indicate the relative quantities of these compounds within the product.

Oil or condensate composition depends upon the formation from which it is obtained and the associated gas’s characteristics, such as whether the gas does or does not contain significant quantities of entrained liquids (“wet” versus “dry” gas). However, a typical gas composition obtained from the Gas Processors Association, by well type, is reproduced below for reference.

 

Typical Raw Gas Compositions  

 

 

Casinghead

Gas Well

Condensate

 

(Wet) Gas

(Dry) Gas

Well Gas

 

mole %

gallons/1000 ft3

mole %

gallons/1000 ft3

mole %

gallons/1000 ft3

Carbon Dioxide

0.63

 

 

 

 

 

Nitrogen

3.73

 

1.25

 

0.53

 

Hydrogen Sulfide

0.57

 

 

 

 

 

Methane

64.48

 

91.01

 

94.87

 

Ethane

11.98

 

4.88

 

2.89

 

Propane

8.75

2.399

1.69

0.463

0.92

0.252

iso-Butane

0.93

0.303

0.14

0.046

0.31

0.101

n-Butane

2.91

0.914

0.52

0.163

0.22

0.069

iso-Pentane

0.54

 

0.09

 

0.09

 

n-Pentane

0.8

 

0.18

 

0.06

 

Pentanes or greater

 

0.777

 

0.203

 

0.103

Hexanes

0.37

 

0.13

 

0.05

 

Heptanes plus

0.31

 

0.11

 

0.06

 

 

 

 

 

 

 

 

Total

100

4.393

100

0.875

100

0.525

Source: Gas Processors Association, "The Gas Processing Industry: Its Function and Role in Energy Supplies"

 

 

At the April 20 hearing, Mr. Sheedy indicated the TCEQ was following up with 20 of the facilities that were analyzed with the IR camera by contacting the facility owners in order to quantify emissions and, potentially, pursue voluntary actions to reduce emissions.  What was the outcome of these efforts? Specifically, please indicate the amount of emissions ultimately determined to be released at these facilities, and any steps already taken, or commitments made, by facility owners to reduce emissions, including any estimates of emissions expected to be reduced through these actions.

As commented in the question above, the Chief Engineer’s Office conducted an aerial survey of the Gulf Coast and North–Central Texas areas in 2007, using an IR camera.  Results of the imaging showed that 64 sites in the Gulf Coast area and 93 sites in the North–Central area had visible emissions.  The agency’s initial course of action was to work with the oil and gas industry through respective industry groups, selecting 10 sites in the North–Central area and 10 sites in the Gulf Coast area to investigate and collect data.  The agency contacted the owners of the sites and requested data on production, operations, oil and condensate composition, and what action they have taken or will take to address and possibly mitigate future VOC emissions.  Responses to the request were minimal or delayed, so a second round of requests was issued. From the initial 20 sites, seven sites with insufficient response to the first data request received a letter from OCE, our enforcement office, requesting cooperation. Ten sites with sufficient responses received letters from CEO requesting verification of emissions estimates.  Three sites that produced only salt water were given more time to respond, due to the unique nature of that operation.

Results of the data review showed that nine companies own or operate the 20 sites. Some of the companies have conducted testing to determine composition of oil-condensate-saltwater tank contents and supplied this information to the agency. Where sufficient data was supplied, estimates indicated that most of the sites exceeded permit-by-rule limits:

  • Six sites did not submit initial data sufficient for emission estimation
  • 14 sites had emissions that were over the PBR emissions limits
  • All companies modified their operation to reduce their emissions below PBR emissions limits
    • Most reductions were achieved by decreased production
    • 10 sites achieved the reductions through actual operation or maintenance changes.

The agency is planning to work with the involved companies to conduct storage-tank emission testing, with the goal of using this direct measurement information along with the data previously collected to help improve the calculations used to determine the emissions from these sources.

The following table summarizes the emissions data for the 20 sites that were selected from the 2007 aerial survey.  The emissions information contained in the table was developed using information supplied by the site operators and calculated using the factor developed from “VOC Emissions from Oil and Condensate Storage Taniks” (HARC 51C) August 31, 2007, and company-estimated emissions.

 

 

Operations

Estimated VOC emissions

 

Reported oil/condensate production (bbl/day)

Company Estimated VOC (tpy)

TCEQ estimate VOC (tpy)*

 

Site

Area

    2007

   2009

      2007

2009

2007

2009

Summary of Company Response

1

JL Martin 1H

DFW

---

---

---

---

---

---

No condensate produced. Discussed possible options to minimize venting

2

Bonds Ranch Rd

DFW

---

---

---

2.425 VOC
40 THC flash**

---

---

No condensate produced. Plume due to separator liquid dump valve struck open. Corrected

3

Gertrude McPeek

DFW

---

---

---

---

---

---

No condensate produced. Company conducting analysis of saltwater

4

McCutchin 2H

DFW

---

---

---

---

---

---

Water production too high for separator, due to work over on adjacent well.

5

RBR A 1H

DFW

4

3

---

---

24

18

Company conducting analysis

6

JW Hodges & Greystone

DFW

---

---

---

---

---

---

No condensate produced. 

7

Jones 1H

DFW

---

---

---

---

---

---

No condensate produced.

8

Johnson D1H and D2H

DFW

7

5

---

---

42

30

 

9

Moncrief 14H

DFW

42

4

1.47 mscf/d
25.6 tpy***

0.15 mscf/d
2.6 tpy***

254

24

Emissions due to open hatches, pumpers instructed to keep hatches closed.

10

Moncrief 17H

DFW

23

3

0.54 mscf/d
9.4 tpy***

0.07 mscf/d
1.2 tpy***

139

18

Emissions due to separator carry0over from newly completed well.  Separator operation adjusted.

11

Bell Valley 1

Corpus

24

---

---

---

145

---

Company conducting new sampling

12

Narrow road GU1

Corpus

20

---

---

---

121

---

Company conducting new sampling

13

Valley 1

Corpus

5

---

---

---

30

---

Company conducting new sampling

14

Apex GU1

Corpus

28

---

---

---

169

---

Company conducting new sampling

15

Franks Field

HGB

25

---

8

---

151

---

 

16

Alta Loma

HGB

82

---

4.88

---

495

---

Analysis being performed, will send.

17

Trust

HGB

95

---

15.22

---

574

---

Analysis being performed will send.

18

Butts

HGB

45,000 (saltwater)

---

6.302

---

85

---

Saltwater disposal only, sampled at pump discharge

19

Curkeet

HGB

27,000 (saltwater)

---

10.504

---

42

---

Saltwater disposal only, sampled at pump discharge

20

Wooster

HGB

7,658 (saltwater)

---

1.72

---

26

---

Saltwater disposal only, sampled at pump discharge

Since several sites claimed no condensate production, there were not sufficient data to perform an VOC estimate using the E&P Tanks program.

---No results have been entered, because sufficient data was not made available to calculate an estimate.  In some cases, additional sampling may still occur.
*  TCEQ estimates based on HARC 51C VOC emission factors for condensate production of 33.1 lb VOC/bbl condensate, with the exception of #18, 19, and 20.  Saltwater disposal emissions based on company reported concentrations of hydrocarbons in saltwater.
**  Company calculated total hydrocarbon flash emissions.  It is unknown what portion may be VOC flash.
*** Ideal-gas law used to convert company reported volume emissions to mass emissions.

Has the TCEQ initiated any enforcement actions or investigations, issued notices of violation, as a result of the information collected with the infrared camera? 

No enforcement actions (notices of violation or notices of enforcement) have been directly issued based on the information collected with the IR camera.  As previously discussed, the IR camera only demonstrates the presence or absence of a hydrocarbon and does not quantify or qualify the gases detected.  The information collected with the IR camera, however, has led to follow-up investigations, which have led or may lead to enforcement actions and subsequent emission reductions. The amount of emissions reduced from these investigations cannot be quantified at this time.

Has the TCEQ refined the methods used to inventory emissions from tanks used in upstream oil and gas production subsequent to obtaining the videos taken with the infrared camera? If so, how do the total emissions estimated using the refined methodology compare to estimates derived using prior methods?

As a direct result of the 2005 passive infrared camera aerial surveys, the TCEQ, in conjunction with the Houston Advanced Research Center (HARC), developed a project to test emissions from storage tanks used in the upstream oil and gas industry.  This project, known as HARC 51C, developed average emissions factors to quantify upstream oil and gas storage tank emissions for the state’s area source inventory.

The TCEQ used the HARC 51C emissions factors in conjunction with available production data to revise upstream oil and gas storage tank emissions in the area source inventory.  Based on the HARC 51C emissions factors, VOC emissions from condensate storage tanks in the area source inventory increased by a factor of 11 and VOC emissions from crude oil storage tanks in the area source inventory increased by a factor of 3, which increased the annual inventory by 620,000 tons. This 620,000-ton increase assumes that 25 percent of the sources had some type of control.

H51C Final Report " " for the project.

These emissions inventory projects resulted in new guidance for point source EI development that published in 2005.  The TCEQ annually updates and publishes Emissions Inventory Guidelines (RG-360A), a comprehensive manual that explains all aspects of the point source EI process. Guidance on upstream oil and gas storage tanks was revised in 2005 to emphasize that direct measurement of storage tank emissions is the most preferred emissions determination method and to stress the importance of using site-specific data (versus default data) in emissions determinations. The 2009 version of the storage tank guidance will remove one of the previously accepted equations as an allowed determination method for estimating flash loss emissions.  The Air Permits Division has also published guidance on preferred calculation methods, paralleling the EI guidance. 

 

Methane

Using the best available data, please estimate the total amount of methane, quantified in scf, released from storage tanks or tank batteries used in upstream oil and gas production in Texas. Separately, please estimate the total amount of VOC, quantified in barrels of oil and/or condensate, released from storage tanks or tank batteries used in upstream oil and gas production in Texas.

Based on methane and VOC sampling data contained in “VOC Emissions from Oil and Condensate Storage Tanks” (HARC 51C), the August 31, 2007, final report prepared for the Houston Advanced Research Center, potential methane and VOCs released from storage tanks in upstream oil and gas production are listed in the table below. 

 

     Potential Methane and VOC Emissions from Oil and Natural Gas Production Tanks

 

2008 Crude Oil Production

2008 Condensate Production

2008 Annual production in barrels per year

351,492,019

50,905,249

Cubic feet of methane per barrel of liquid produced

15

58

Cubic feet per year of methane statewide

5,272,380,285

2,952,504,442

Tons per year of VOC statewide

281,194

847,572

Equivalent barrels of petroleum**

1,912,882

6,726,765

All emissions estimates assume no control of tank emissions. 
Crude oil and condensate production numbers are from the Texas Railroad Commission.  
** Assumptions
42 gallons of petroleum in a barrel
1 gallon of crude oil weighs 7 pounds
1 gallon of condensate weighs 6 pounds
1 pound of VOC has the energy equivalent of1 pound of liquid petroleum

 

Permitting

What permit requirements or other emissions limitations apply to the owner of an oil or condensate tank or tank battery in Texas?

(1) Permit by Rule (PBR)—owners or operators of an oil or condensate tank or tank battery may qualify for PBR 106.352, contained in 30 TAC Chapter 106, Subchapter O.  Other related equipment at oil and gas sites covered by this PBR may include heaters, dehydration units, tank vents including flash, process fugitives, and loading operations. Operators often also claim PBR 106.512 for engines and turbines used for oil and gas compression, and PBR 106.492 for flares, which control process and emission event releases. Emissions from all related equipment under PBR must be less than 25 tons per year (tpy) of volatile organic compounds (VOCs), particulate matter (PM10), and sulfur dioxide (SO2); and less than 250 tpy each of nitrogen oxide (NOx) and carbon monoxide (CO).

PBR 106.352 PBR requires that any tank or tank battery that handles sour gas or liquids (greater than 24 parts per million by volume of hydrogen sulfide) must be located at least 1/4 mile from any off-site receptor and must be registered with the TCEQ.

Claims under PBR do not require individual evaluations of best available control technology (BACT) or off-property health impacts evaluation. 

(2) Oil and gas standard permit—the owner or operator can register for an oil and gas standard permit under 116.620, contained in 30 TAC Chapter 116, Subchapter F, if the tank or tank battery cannot qualify for PBR 106.352, or if the tank or tank battery handles sour gas and is located less than 1/4 mile from an off-site receptor.  The Oil and Gas standard permit was written with specific conditions to ensure compliance with best available control technology and off-property health impacts. 

To ensure protection of the public health and welfare, applicants are required to demonstrate compliance with the emission limitations of PBRs 106.261 and 106.262, which establish short-term and annual emission limits for contaminants that do not have an established national ambient air quality standard. This demonstration requires a speciated VOC analysis from all emission sources.

Examples of control requirements in the oil and gas standard permit:
(A) Fixed-roof tanks must be smaller than 25,000 gallons or the vapor pressure of the stored compound must be less than 0.5 psia at maximum short-term storage temperature. If emissions from a fixed-roof tank exceed 10 tpy of VOC, the tank emissions must be controlled with a destruction device, vapor-recovery system, or equivalent control method.

(B)  Tanks greater than 25,000 gallons are required to have floating roofs or else emissions must be routed to a destruction device, vapor-recovery system, or equivalent control method.

(C) Glycol dehydration units emitting uncontrolled emissions greater than 10 tpy of VOCs must be controlled using a condenser and a separator (or flash tank), destruction device, vapor-recovery system, or equivalent control device.

(D) Facilities located less than 500 feet from the nearest off-plant receptor are required to implement a leak deection and repair (LDAR) program when fugitive emissions are equal to or greater than 10 tpy of VOC.

(E) Facilities located greater than 500 feet from the nearest off-plant receptor are required to implement an LDAR program when fugitive emissions are greater than or equal to 25 tpy of VOCs.

(3) New-source-review (NSR) Permit—owners or operators of a tank or tank battery that does not qualify for a PBR or the oil and gas standard permit can submit a new-source-review permit application under 30 TAC 116.

The NSR permit requires public notice, BACT emission controls, and evaluation of off-property health impacts.

(4) Federal Standards— The tank or tank battery and associated facilities may also be subject to federal  regulations, including but not limited to 40 CFR 60 (New Source Performance Standards), subparts K, Ka, Kb, KKK, IIII, and JJJJ; 40 CFR 61 (National Emissions Standards for Hazardous Pollutants), subpart HH. 

(5) Federal Major Sources—Depending on the potential emissions and locations, these sites may also require federal preconstruction permits, including Prevention of Significant Deterioration or Nonattainment New Source Review permits.

If determined to be a major source, as defined in 30 TAC 122.10, of air contaminants, sites may also need to obtain a federal operating permit under 40 CFR Part 70, Title V which may consist of a general operating permit or a site operating permit.

 

 

Payback Period

Making reasonable assumptions to define a typical oil producing well in East Texas and a typical condensate-producing gas well in Texas, please estimate the simple payback period in months if a commercially available vapor-recovery unit were installed on tanks servicing these typical wells.

In the absence of a typical oil producing or condensate producing well, published reports and case studies were evaluated to identify reportable pay-backs. The Environmental Protection Agency’s Natural Gas Star program has developed a Lessons Learned report to showcase the benefits of installing vapor recovery units. EPA documented paybacks between three and 19 months with an assumed $7.00/Mcf gas price. However, current natural gas spot price is around $3.70/Mcf as of mid-October, so payback would be expected to be much longer. Furthermore, the payback timeline could be extended further if there is not a natural gas field gathering pipeline located near the crude oil storage tanks, because of necessity of a delivery means for any recovered gas.

The Environmental Technology Verification Program at EPA evaluated the Eductor Vapor Recovery Unit from COMM Engineering. The $108,000 EVRU recovered 175 Mscf/day.  Assuming a prices value of $5.46 per Mscf, the total value of recovered gas was estimated at $650,000 per year for an approximate two-month payback.

Many factors affect the overall cost and payback of installing a vapor recovery unit. In an effort to help facilities work through the factors necessary to identify potential pay-back, the EPA’s Natural Gas Star program developed an Economic Analysis Tool " " to estimate costs and assumptions. The tool allows users to define certain assumptions and calculates a payback timeframe.