Lessons 

Learned 

Executive Summary 

Emissions 

Source 

Oil Production 

Annual 

Lost (Mcf) 

4,900 – 96,000 

Method for 

Reducing Gas 

Loss 

Units (VRUs) 

Gas Saved 

($) 

$13,000 – 

$260,0001 

Capital and 

Installation 

Cost ($) 

$26,470 – 

$77,000 

Annual O&M 

Cost ($) 

$5,250 – 

$12,000 

Payback 

3 months to 

3.4 years 

1

From Natural Gas STAR Partners 

INSTALLING VAPOR RECOVERY UNITS ON CRUDE OIL 

STORAGE TANKS 

There are about 573,000 crude oil storage tanks in the United States. These tanks are used to hold oil for brief 

periods of time in order to stabilize flow between production wells and pipeline or trucking transportation sites. 

During storage, light hydrocarbons dissolved in the crude oil—including methane and other volatile organic compounds (VOC), natural gas liquids (NGLs), hazardous air pollutants (HAP), and some inert gases—vaporize or 

"flash out" and collect in the space between the liquid and the fixed roof of the tank. As the liquid level in the tank 

fluctuates, these vapors are often vented to the atmosphere. 

One way to prevent emissions of these light hydrocarbon vapors and yield significant economic savings is to 

install vapor recovery units (VRUs) on oil storage tanks. VRUs are relatively simple systems that can capture 

about 95 percent of the Btu-rich vapors for sale or for use onsite as fuel. Currently, between 8,000 and 10,000 

VRUs are installed in the oil production sector, with an average of four tanks connected to each VRU. 

Natural Gas STAR partners have generated significant savings from recovering and marketing these vapors while 

at the same time substantially reducing methane and HAP emissions. Partners have found that when the volume 

of vapors is sufficient, installing a VRU on one or multiple crude oil storage tanks can save up to $260,060 per 

year and payback in as little as three months. This Lessons Learned study describes how partners can identify 

when and where VRUs should be installed to realize these economic and environmental benefits. 

This is one of a series of Lessons Learned Summaries developed by EPA in cooperation with the natural gas industry on superior 

applications of Natural Gas STAR Program Best Management Practices (BMPs) and Partner Reported Opportunities (PROs). 

Storage Tanks 

Volume of Gas 

Vapor Recovery 

Value of 

Assumes a gas price of $3.00/Mcf times 95 percent of the annual volume gas lost. 
Technology 

Background 

Underground crude oil contains many lighter hydrocarbons in solution. 

When the oil is brought to the surface and processed, many of the dissolved 

lighter hydrocarbons (as well as water) are removed through a series of highpressure and low-pressure separators. The crude oil is then injected into a 

storage tank to await sale and transportation off site; the remaining hydrocarbons in the oil are emitted as vapors into the tank. These vapors are 

either vented, flared, or recovered by vapor recovery units (VRUs). Losses of 

the remaining lighter hydrocarbons are categorized in three ways: 

★ Flash losses occur when the separator or heater treater, operating at 

approximately 35 pounds per square inch (psi), dumps oil into the 

storage tanks, which are at atmospheric pressure. 

★ Working losses refer to the vapors released from the changing fluid 

levels and agitation of tank contents associated with the circulation of 

fresh oil through the storage tanks. 

★ Standing losses occur with daily and seasonal temperature changes. 

The volume of gas vapor coming off a storage tank depends on many factors. Lighter crude oils (API gravity>36°) flash more hydrocarbon vapors than 

heavier crudes (API gravity<36°). In storage tanks where the oil is frequently 

cycled and the overall throughput is high, more “working vapors” will be 

released than in tanks with low throughput and where the oil is held for 

longer periods and allowed to “weather.” Finally, the operating temperature 

and pressure of oil in the vessel dumping into the tank will affect the volume 

of flashed gases coming out of the oil. 

The makeup of these vapors varies, but the largest component is methane 

(between 40 and 60 percent). Other components include more complex 

hydrocarbon compounds such as propane, butane, and ethane; natural inert 

gases such as nitrogen and carbon dioxide; and HAP like benzene, toluene, 

ethyl-benzene, and xylene (collectively these four HAP are referred to as 

BTEX). 

VRUs can recover over 95 percent of the hydrocarbon emissions that accumulate in storage tanks. Because recovered vapors contain natural gas liquids (even after condensates have been captured by the suction scrubber), 

they have a Btu content that is higher than that of pipeline quality natural gas 

(between 950 and 1,100 Btu per standard cubic foot [scf]). Depending on 

the volume of NGLs in the vapors, the Btu content can reach as high as 

2,000 Btu per scf. Therefore, on a volumetric basis, the recovered vapors 

can be more valuable than methane alone. 

2 
Exhibit 1 illustrates a VRU installed on a single crude oil storage tank (multiple tank installations are also common). Hydrocarbon vapors are drawn out 

of the storage (stock) tank under low-pressure, typically between four 

ounces and two psi, and are first piped to a separator (suction scrubber) to 

collect any liquids that condense out. The liquids are usually recycled back 

to the storage tank. From the separator, the vapors flow through a compressor that provides the low-pressure suction for the VRU system. (To prevent 

the creation of a vacuum in the top of a tank when oil is withdrawn and the 

oil level drops, VRUs are equipped with a control pilot to shut down the 

compressor and permit the back flow of vapors into the tank.) The vapors 

are then metered and removed from the VRU system for pipeline sale or 

onsite fuel supply. 

3 

can be: 

★ 

Btu natural gas. 

★ Used as a fuel for onsite operations. 

★ Piped to a stripper unit to separate NGLs and methane when the volVRUs can provide significant environmental and economic benefits for oil 

and gas producers. The gases flashed from crude oil and captured by VRUs 

can be sold at a profit or used in facility operations. These recovered vapors 

Exhibit 1: Standard Stock Tank Vapor Recovery System 

Piped to natural gas gathering pipelines for sale at a premium as high 

ume and price for NGLs are attractive. 

Economic and 

Environmental 

Benefits 
Decision 

Process 

VRUs also capture HAPs and can reduce operator emissions below actionable levels specified in Title V of the Clean Air Act. By capturing methane, 

VRUs also reduce the emissions of a potent greenhouse gas. 

Companies using fixed roof crude oil storage tanks can assess the economics of VRUs by following five easy steps. 

Step 1: Identify possible locations 

for VRU installation. Virtually any Five Steps for Assessing VRU 

tank battery is a potential site for a Economics: 

VRU. The keys to successful VRU 1. Identify possible locations for VRU projects are a steady source and ade- installation; 

quate quantity of crude oil vapors 2. Quantify the volume of vapor emissions;

along with an economic outlet for the 3. Determine the value of the recovered 

collected product. The potential vol- emissions; 

ume of vapors will depend on the 4. Determine the cost of a VRU project; and 

makeup of the oil and the rate of flow 5. Evaluate VRU project economics. 

through the tanks. Pipeline connection costs for routing vapors off site 

must be considered in selecting sites for VRU installation. 

Step 2: Quantify the volume of vapor emissions. Emissions can either be 

measured or estimated. An orifice well tester and recording manometer 

(pressure gauge) can be used to measure maximum emissions rates since it 

is the maximum rate that is used to size a VRU. Orifice meters, however, 

might not be suitable for measuring total volumes over time due to the low 

pressures at tanks. Calculating total vapor emissions from oil tanks can be 

complicated because many factors affect the amount of gas that will be 

released from a crude oil tank, including: 

1. Operating pressure and temperature of the separator dumping the oil 

to the tank and the pressure in the tank; 

2. Oil composition and API gravity; 

3. Tank operating characteristics (e.g., sales flow rates, size of tank); and 

4. Ambient temperatures. 

There are two approaches to estimating the quantity of vapor emissions 

from crude oil tanks. Both use the gas-oil ratio (GOR) at a given pressure 

and temperature and are expressed in standard cubic feet per barrel of oil 

(scf per bbl). 

The first approach analyzes API gravity and separator pressure to determine 

GOR (Exhibit 2). These curves were constructed using empirical flash data 

4 
from laboratory studies and field measurements. As illustrated, this graph 

can be used to approximate total potential vapor emissions from a barrel of 

oil. For example, given a certain oil API gravity (e.g., 38°) and vessel dumping pressure (e.g., 40 psi), the total volume of vapors can be estimated per 

barrel of oil (e.g., 43 scf per bbl). Once the emissions rate per barrel is estimated, the total quantity of emissions from the tank can be determined by 

multiplying the per barrel estimate by the total amount of oil cycled through 

the tank. To continue the example above, assuming an average throughput 

of 1,000 barrels per day (bbl per day), total emissions would be estimated at 

43 Mcfd (Exhibit 3). 

5 

The shortcoming of this 

generate information about 

the composition of the 

vapors emitted. In particuwhich can be significant for 

air quality monitoring, as 

well as determining the 

value of the emitted vapors. 

Exhibit 3: Quantity (Q) of Hydrocarbon 

Given: 

API Gravity = 38° 

Separator Pressure = 40 psi 

Oil Cycled = 1,000 bbl/day 

Q = 43scf/bbl x 1,000 bbls/day = 43 Mcfd 

Exhibit 2: Estimated Volume of Storage Tank Vapors 

approach is that it does not 

lar, it cannot distinguish 

between VOC and HAP, 

Vapor Emissions 

Vapor Emissions rate = 43 scf/bbl (from Exhibit 2) 
The second approach is to use the software package E&P Tank version 2.0.1 

This is the modified version of the previous software; the American 

Petroleum Institute (API) introduced several changes in this model which 

made it more user-friendly. Partners in the Natural Gas STAR Program have 

recommended E&P Tank as the best available tool for estimating tank battery emissions. Developed by API and the Gas Research Institute (now the 

Gas Technology Institute), this software estimates emissions from all three 

sources—flashing, working, and standing—using thermodynamic flash calculations for flash losses and a fixed roof tank simulation model for working 

and standing losses. An operator must have several pieces of information 

before using E&P Tank, including: 

1. Separator pressure and temperature. 

2. Separator oil composition. 

3. Reference pressure. 

4. Reid vapor pressure of sales oil. 

5. Sales oil production rate. 

6. API gravity of sales oil. 

E&P Tank also allows operators to input more detailed information about 

operating conditions, which helps refine emissions estimates. With additional 

data about tank size, shape, internal temperatures, and ambient temperatures, the software can produce more precise estimates. This flexibility in 

model design allows users to employ the model to match available information. Since separator oil composition is a key input in the model, E&P Tank 

includes a detailed sampling and analysis protocol for separator oil. Future 

versions of the software are being developed to estimate emissions losses 

from production water tanks as well. 

Step 3: Determine the value of the recovered emissions. The value of 

the vapors recovered from VRUs and realized by producers depends on 

how they are used: 

1. Using the recovered vapors onsite as fuel yields a value equivalent to 

the purchased fuel that is displaced—typically natural gas. 

2. Piping the vapors (NGL-enriched methane) to a natural gas gathering 

pipeline should yield a price that reflects the higher Btu content per 

Mcf of vapor. 

3. Piping the vapors to a processing plant that will strip the NGLs from 

1

EPA has not conducted extensive reviews of E&P Tank and therefore cannot endorse 

the software as an accurate tool for estimating emissions. However, partners in the 

Natural Gas STAR Program have recommended E&P Tank as the best available tool for 

estimating vapor emissions from tanks. 

6 
the gas stream and resell the Exhibit 4: Value of Recovered Vapors NGLs and methane separately should also capture R = Q x P

the full Btu content value of R = The gross revenue 

the vapors. Exhibit 4 illus- Q = The rate of vapor recovery (Mcf/day) 

P = The price of natural gas trates a method of calculating the value of the recovered vapors using an averCalculate:

Q = 41 Mcfd (95% of 43 from Exhibit 3) 

P = $3.00/Mcf 

R = 41 Mcfd x $3/Mcf = age price of $3.00 per Mcf $123/day (which assumes 1,000 Btu $3,800/month

per scf). Where the Btu con- $45,600/year

tent of the vapors is higher,

the price per Mcf would be 

higher.

Step 4: Determine the cost of a VRU project. The major cost elements of 

VRUs are the initial capital equipment and installation costs and operating 

costs. 

VRU systems are made by several manufacturers. Equipment costs are 

determined largely by the volume handling capacity of the unit; the sales line 

pressure; the number of tanks in the battery; the size and type of compressor; and the degree of automation. The main components of VRUs are the 

suction scrubber, the compressor, and the automated control unit. Gas 

measurement is an add-on expense for most units. Prices for typical VRUs 

and related costs are shown in Exhibit 5. 

When sizing a VRU, the industry rule-of-thumb is to double the average daily 

volume to estimate the maximum emissions rate. Thus, in order to handle 

43 Mcfd of vapor (Exhibit 3), a unit capable of handling at least 86 Mcfd 

should be selected. 

Exhibit 5: Vapor Recovery Unit Sizes and Costs 

Capacity 

(Mcfd) 

Compressor 

Horsepower 

Capital 

Costs($) 

Installation 

Costs($) 

O&M Costs 

($/year) 

25 

50 

100 

200 

500 

5 - 10 

10 - 15 

15 - 25 

30 - 50 

60 - 80 

15,125 

19,500 

23,500 

31,500 

44,000 

7,560 - 15,125 

9,750 - 19,500 

11,750 - 23,500 

15,750 - 31,500 

22,000 - 44,000 

5,250 

6,000 

7,200 

8,400 

12,000 

Note: Cost information provided by Natural Gas STAR partners and VRU manufacturers. 

7 
Partners who have installed VRUs and VRU manufacturers report that installation costs can add as much as 50 to 100 percent to the initial unit cost. 

Installation costs can vary greatly depending on location (remote sites will 

likely result in higher installation costs) and the number of tanks (larger VRU 

systems will be required for multiple tanks). Expenses for shipping, site 

preparation, VRU housing construction (for cold weather protection), and 

supplemental equipment (for remote, unmanned operations) must also be 

factored in when estimating installation costs. 

Operations and maintenance (O&M) expenses vary with the location of the 

VRU (sites in extreme climates experience more wear), electricity costs, and 

the type of oil produced. For instance, paraffin based oils can clog the VRUs 

and require more maintenance. 

Finally, the cost of a pipeline to interconnect the tank battery site with a processing plant or pipeline is a factor in overall VRU economics. Such costs 

are highly site-specific and are not addressed here. 

Step 5: Evaluate VRU Project Economics. Installing a VRU can be very 

profitable, depending on the value of the recovered vapors in the local market. Exhibit 6 calculates the return on investment (ROI) for VRU sizes and 

costs listed in Exhibit 5. Even using a conservative estimate of the value of 

recovered vapors of $3.00 per Mcf, the potential returns are attractive, particularly for the larger units. 

Exhibit 6: Financial Analysis for VRU Project 

Capacity 

(Mcfd) 

Installation & 

Capital Costs1 

($) 

O&M 

($/Yr) 

Value of 

Gas2 

($/Yr) 

Payback3 Return on 

Investment 4 

(%) 

25 

50 

100 

200 

500 

26,470 

34,125 

41,125 

55,125 

77,000 

5,250 

6,000 

7,200 

8,400 

12,000 

13,000 

26,000 

52,015 

104,025 

260,060 

3.4 years 

1.7 years 

9 months 

6 months 

3 months 

14 

51 

106 

172 

322 

1 Unit cost plus estimated installation cost of 75% of unit cost. Actual costs might be greater depending 

on expenses for shipping, site preparation, supplemental equipment, etc. 

2 95% of total gas recovered at $3 per Mcf x 1/2 capacity x 365. 

3 Based on 10 percent discount rate. 

4 Calculated for 5 years. 

8 
One Partner’s Experience 

Chevron USA Production Company installed eight vapor recovery units in 1996 at 

crude oil stock tanks. As a result, Chevron has realized as estimated reduction in 

methane emissions of 21,900 Mcf per year from each unit. Assuming $3 per Mcf, 

this corresponds to approximately $65,700 in savings per unit, or $525,600 for all 

eight units. The capital and installation costs were estimated to be $240,000 

($30,000 per unit). The particular project realized a payback in less than one year. 

The use of VRUs can profitably reduce methane emissions from crude oil 

Lessons storage tanks. Partners offer the following lessons learned: 

Learned ★ E&P Tank software can be an effective tool for estimating the amount 

and composition of vapors from crude oil tanks. 

9 

★ Vapor recovery can provide generous returns due to the relatively low 

cost of the technology and in the cases where there are market outlets 

for the high BTU vapors. 

★ VRUs should be installed whenever they are economic, taking into 

consideration all of the benefits—environmental and economic. 

★ Because of the very low pressure differential between the storage tank 

and the compressor, large diameter pipe is recommended to provide 

less resistance to the gas flow. 

★ A VRU should be sized to handle the maximum volume of vapors 

expected from the storage tanks (a rule-of-thumb is double the average daily volume). 

★ Rotary vane compressors are recommended for VRUs to move the 

low volume of gas at low pressures. 

★ It is very important to choose reliable, sensitive control systems, 

because the automated gas flow valves must be opened and closed 

on very low pressure differences. 

★ Include methane emissions reductions from installing VRUs in annual 

reports submitted as part of the Natural Gas STAR Program. 
References Bigelow, Tom and Renee Wash. 1983. "VRUs Turn Vented Gas Into Dollars." 

Northeast Oil Reporter. October 1983. pp. 46-47. 

Choi, M.S. 1993. API Tank Vapors Project. Presented at the 1993 SPE 

Technical Conference, Houston, TX, October 3-6, 1993. SPE Technical 

Paper No. 26588. 

Dailey, Dirk, Universal Compression, personal contact. 

Evans, G.B. and Ralph Nelson. 1968. Applications of Vapor Recovery to 

Crude Oil Production. Hy-Bon Engineering Company. Midland, TX. SPE 

Technical Paper No. 2089. 

Griswold, John A., Power Services, Inc. and Ted C. Ambler, A & N Sales, 

Inc. 1978. A Practical Approach to Crude Oil Stock Tank Vapor Recovery. 

Presented at the 1978 SPE Rocky Mountain Regional Meeting, Cody, WY, 

May 7-9, 1978. SPE Technical Paper No. 7175. 

Henderson, Carolyn, U.S. EPA Natural Gas STAR Program, personal 

contact. 

Hy-Bon Engineering Company, Inc. 1997. Product Bulletin: Vapor Recovery 

Systems. 

Liu, Dianbin and J.V. Meachen Jr., 1993. The Use of Vapor Recovery Units 

in the Austin Chalk Field. Presented at the 1993 SPE Technical Conference, 

Houston, TX, October 3-6, 1993. SPE Technical Paper No. 26595. 

Lucas, Donald, David Littlejohn, Ernest Orlando, Lawrence Berkeley National 

Laboratory; and Rhonda P. Lindsey, U.S. Department of Energy. 1997. The 

Heavy Oil Storage Tank Project. Presented at the 1997 SPE/EPA Exploration 

and Production Environmental Conference, Dallas, TX, March 1997. SPE 

Technical Paper No. 37886. 

Martin, Mark, UMC Automation, personal contact. 

Moreau, Roland, Exxon-Mobil USA, personal contact. 

Motley, Jack, V.R. Systems, Inc., personal contact. 

Newsom, Vick L. 1997. Determination of Methane Emissions From Crude 

Oil Stock Tanks. Presented at the SPE/EPA Exploration & Production 

Environmental Conference, Dallas, TX, March 3-5, 1997. SPE Technical 

Paper No. 37930. 

10 
Presley, Charles, A.G. Equipment, personal contact. 

Primus, Frank A., Chevron USA, personal contact. 

Tims, Arnold, Hy-Bon Engineering Company, Inc., personal contact. 

Tingley, Kevin, U.S. EPA Natural Gas STAR Program, personal contact. 

U.S. Department of Commerce. 1993. Control of Volatile Organic 

Compound Emissions from Volatile Organic Liquid Storage in Floating and 

Fixed Roof Tanks. Available through NTIS. Springfield, VA PB94-128519. 

U.S. Environmental Protection Agency. 1996. Methane Emissions from the 

U.S. Petroleum Industry (Draft Document). DCN: 96-298-130-61-01. 

Visher, Stuart, A.C. Compressors, personal contact. 

Watson, Mark C. 1996. "VRU Engineered For Small Volumes." The American 

Oil & Gas Reporter (Special Report: Enhanced Recovery). March 1996. pp. 

115-117. 

Webb, W.G. 1993. Vapor Jet System: An Alternate Vapor Recovery Method.

Presented at the 1993 SPE/EPA Exploration & Production Environmental

Conference, San Antonio, TX, March 7-10, 1993. SPE Technical Paper No. 

25942. 

Weldon, R.E. Jr., 1961. "Could You Recover Stock Tank Vapors at a Profit?"

The Petroleum Engineer. May 1961. pp. B29-B33. 

Weust, John, Marathon Oil, personal contact. 

11 
United States 

Air and Radiation (6202J) 

W 

October 2003 

ashington, DC 20460 

1EPA

Environmental Protection Agency 

1200 Pennsylvania Ave., NW 

EPA430-B-03-015