Lessons Learned 

from Natural Gas STAR Partners 

Installing Vapor Recovery Units on 

Storage Tanks 

Executive Summary 

There are about 500,000 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. In addition, the condensate liquids contained in 

produced gas that are captured by a mist eliminator filter/

coalescer ahead of the first compressor station in 

transmission pipelines are often directed to a storage tank 

as well. During storage, light hydrocarbons dissolved in

the crude oil or condensate—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 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 7,000 and 9,000 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 

storage tanks can save up to $606,800 per year and

payback in as little as two months. This Lessons Learned

study describes how partners can identify when and where 

VRUs should be installed to realize these economic and 

environmental benefits. 

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 high-pressure 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. The same

principles apply for condensate, which accumulates as a 

result of the conditions within the pipelines and is 

removed ahead of the first compressor station. The 

recovered condensate, which contains dissolved light

hydrocarbons, is routed to a storage tank where the

dissolved light hydrocarbons are emitted as vapors. 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 vapor released from the 

Method for Reducing 

Natural Gas Losses 

Volume of 

Natural Gas 

Savings 

(Mcf/yr) 

Value of Natural Gas Savings 

($/yr) 1 Payback (Months) 

$3 per 

Mcf 

$5 per 

Mcf 

$7 per 

Mcf 

$3 per 

Mcf 

$5 per 

Mcf 

$7 per 

Mcf 

Installing Vapor 

Recovery Units (VRUs) 

on Oil Production 

Storage Tanks 

4,900—96,000 $13,965— 

$273,600 

$23,275— 

$456,000 

$32,585— 

$638,400 

$35,738— 

$103,959 6 — 37 4 — 23 3 — 16 

1 Assumes 95% of the annual volume of gas lost can be recovered using a VRU. 

Implementation 

Cost ($) 

Other 

Costs 

($) 

$7,367— 

$16,839 

Economic and Environmental Benefits 

1 
 

 

 

Installing Vapor Recovery Units on Storage Tanks 

(Cont’d) 

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. 

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. 

Exhibit 1: Standard Stock Tank Vapor Recovery System 

2 
 

 

Installing Vapor Recovery Units on Storage Tanks 

(Cont’d) 

Economic and Environmental Benefits 

VRUs can provide significant environmental and economic 

benefits for oil and gas producers. The gases flashed from

crude oil or condensate and captured by VRUs can be sold

at a profit or used in facility operations. These recovered

vapors can be: 

Piped to natural gas gathering pipelines for sale at a

premium as high Btu natural gas. 

Used as a fuel for onsite operations. 

Piped to a stripper unit to separate NGLs and 

methane when the volume and price for NGLs are

attractive. 

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. 

Decision Process 

Companies using fixed roof storage tanks can assess the 

economics of VRUs by following five easy steps. 

Step 1: Identify possible locations for VRU 

installation. 

Virtually any tank battery is a potential site for a VRU. 

The keys to successful VRU projects are a steady source 

and adequate quantity of crude oil or condensate vapors 

along with an economic outlet for the collected product.

The potential volume of vapors will depend on the makeup

of the oil or condensate and the rate of flow 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 

Five Steps for Assessing VRU Economics: 

1. Identify possible locations for VRU installation; 

2.	 Quantify the volume of vapor emissions; 

3. Determine the value of the recovered emissions; 

4.	 Determine the cost of a VRU project; and 

5. Evaluate VRU project economics. 

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). 

This process is applicable to all compressor designs. The 

less common overhung compressors have a single seal, and

switching from wet to dry seals would yield half the 

savings of doing the same for a beam type compressor. 

The first approach analyzes API gravity and separator

pressure to determine GOR (Exhibit 2). These curves were

constructed using empirical flash data 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 

Exhibit 2: Estimated Volume of Storage Tank 

Vapors 

3 
 

 

Installing Vapor Recovery Units on Storage Tanks 

(Cont’d) 

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). 

Exhibit 3: Quantity (Q) of Hydrocarbon Vapor 

Emissions 

Given: 

API Gravity = 38° 

Separator Pressure = 40 psi 

Oil Cycled = 1,000 bbl/day 

Vapor Emissions rate = 43 scf/bbl (from Exhibit 2) 

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

The shortcoming of this approach is that it does not 

generate information about the composition of the vapors 

emitted. In particular, it cannot distinguish between VOC

and HAP, which can be significant for air quality

monitoring, as well as determining the value of the 

emitted vapors. 

The second approach is to use the software package E&P

Tank version 2.0. 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 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 the gas stream and resell the NGLs

and methane separately should also capture the full

Btu content value of the vapors. Exhibit 4 illustrates a

method of calculating the value of the recovered vapors 

using an average price of $7.00 per Mcf (for pipeline

quality natural gas at 1,000 Btu per scf). Where the 

Exhibit 4: Value of Recovered Vapors 

R = Q x P 

R = The gross revenue 

Q = The rate of vapor recovery (Mcf/day) 

P = The price of natural gas 

Calculate: 

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

P = $7.00/Mcf 

R = 41 Mcfd x $7/Mcf =

 $287/day

 $8,800/month 

$105,600/year 

4 
 

 

 

Installing Vapor Recovery Units on Storage Tanks 

(Cont’d) 

The average methane content of natural gas varies by natural gas 

industry sector. The Natural Gas STAR Program assumes the 

following methane content of natural gas when estimating 

methane savings for Partner Reported Opportunities. 

Production 79 % 

Processing 87 % 

Transmission and Distribution 94 % 

Methane Content of Natural Gas 

Btu content of the vapors is higher, the price per Mcf 

would be higher. 

Step 4: Determining 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. 

Nelson Price Indexes 

In order to account for inflation in equipment and 

operating & maintenance costs, Nelson-Farrar 

Quarterly Cost Indexes (available in the first issue of 

each quarter in the Oil and Gas Journal) are used to 

update costs in the Lessons Learned documents. 

The “Refinery Operation Index” is used to revise

operating costs while the “Machinery: Oilfield Itemized 

Refining Cost Index” is used to update equipment 

costs. 

To use these indexes in the future, simply look up the 

most current Nelson-Farrar index number, divide by 

the February 2006 Nelson-Farrar index number, and, 

finally multiply by the appropriate costs in the Lessons 

Learned. 

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 

Exhibit 5: Vapor Recovery Unit Sizes and Costs 

Design Capacity1 (Mcfd) Compressor Horsepower2 Capital Costs3 ($) Installation Costs3 

25 5—10 20,421 10,207—20,421 

50 10—15 26,327 13,164—26,327 

100 15—25 31,728 15,864—31,728 

200 30—50 42,529 21, 264—42,529 

500 60—80 59,405 29,703—59,405 

O&M Costs ($/year) 

7,367 

8,419 

10,103 

11,787 

16,839 

1

 Assumes design capacity is double average vapor recovery rate. 

2

 Assumes compressor discharge to a 100 psi or less sales line or fuel gas system. 

3

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

5 
 

 

 

Installing Vapor Recovery Units on Storage Tanks 

(Cont’d) 

produced. For instance, paraffin based oils can clog the 

VRUs and require more maintenance. 

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 simple payback and Internal Rate of Return

(IRR) for VRU sizes and costs listed in Exhibit 5. Using an

estimate of the value of recovered vapors of $7.00 per Mcf, 

the potential returns are attractive, particularly for the 

larger units. 

When assessing VRU economics, gas price may influence

the decision making process; therefore, it is important to 

re-examine the economics of installing vapor recovery

units as natural gas prices change. Exhibit 7 shows an

economic analysis of installing a 100 Mcfd vapor recovery 

unit at different gas prices. 

Lessons Learned 

The use of VRUs can profitably reduce methane emissions 

from crude oil storage tanks. Partners offer the following 

lessons learned: 

E&P software can be an effective tool for estimating

the amount and composition of vapors from crude oil

tanks. 

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 

Exhibit 6: Financial Analysis for VRU Project 

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 $7 per Mcf x 1/2 design capacity x 365 days 

3

 Based on 10 percent discount rate. 

4

 Calculated for 5 years. 

Design Capacity 

(Mcfd) 

Installation & 

Capital Costs1

 ($) O&M ($/Year) Value of Gas2 

($/Yr) Payback3

 (months) Internal Rate of 

Return4

 (%) 

25 35,738 7,367 30,300 19 58 

50 46,073 8,419 60,600 11 111 

100 55,524 10,103 121,360 6 200 

200 74,425 11,787 242,725 4 310 

500 103,959 16,839 606,810 3 567 

Exhibit 7: Gas Price Impact on Economic Analysis 

Value of Gas Saved 

Payback Period (Months) 

Internal Rate of Return 

(IRR) 

NPV (i=10%) 

$3/Mcf $5/Mcf $7/Mcf $8/Mcf 

$52,011 $86,686 $121,360 $138,697 

16 9 6 6 

70% 136% 200% 231% 

$93,947 $213,440 $332,934 $392,681 

$10/Mcf 

$173,371 

5 

294% 

$512,174 

6 
 

Installing Vapor Recovery Units on Storage Tanks 

(Cont’d) 

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 to 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. 

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 an estimated reduction in 

methane emissions of 21,900 Mcf per year from each

unit. At today’s gas price of $7 per Mcf, this corresponds

to approximately $153,300 in savings per unit, or

$1,226,400 for all eight units. The capital and 

installation costs were estimated to be $240,000 ($30,000

per unit) in 1996 or the equivalent of $324,000 ($40,500

per unit) in 2006 dollars. This particular project would

have realized a payback in just over 3 months in 2006. 

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. 

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 

7 
 

Installing Vapor Recovery Units on Storage Tanks 

(Cont’d) 

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. 

8 
Installing Vapor Recovery Units on Storage Tanks 

(Cont’d) 

United States 

Environmental Protection Agency 

Air and Radiation (6202J) 

1200 Pennsylvania Ave., NW 

Washington, DC 20460 

October 2006 

EPA provides the suggested methane emissions estimating methods contained in this document as a tool to develop basic methane emissions estimates only. As 

regulatory reporting demands a higher-level of accuracy, the methane emission estimating methods and terminology contained in this document may not conform to 

the Greenhouse Gas Reporting Rule, 40 CFR Part 98, Subpart W methods or those in other EPA regulations. 

9