Lessons
Learned
NaturalGas
EPA POLLUTION PREVENTER
From Natural Gas STAR Partners
INSTALLING VAPOR RECOVERY UNITS ON CRUDE OIL
STORAGE TANKS
Executive Summary
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 com-
pounds (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 $260,060 per
year and payback in as little as three months. This Lessons Learned study describes how partners can identify
when and where VRUs should be installed to realize these economic and environmental benefits.
Emissions
Source
Oil Production
Storage Tanks
Annual
Volume of Gas
Lost (Mcf)
4,900-96,000
Method for
Reducing Gas
Loss
Vapor Recovery
Units (VRUs)
Value of
Gas Saved
($)
$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
0
'Assumes a gas price of $3.00/Mcf times 95 percent of the annual volume gas lost.
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).
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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 hydro-
carbons 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 fac-
tors. 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 accu-
mulate in storage tanks. Because recovered vapors contain natural gas liq-
uids (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.
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Exhibit 1 illustrates a VRU installed on a single crude oil storage tank (multi-
ple 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 compres-
sor 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.
Economic and
Environmental
Benefits
Exhibit 1: Standard Stock Tank Vapor Recovery System
Vent Line
Back Pressure l
Valve-
Control
Pilot
Sales
icondensate Transfor RumP Electric Driven
| Return Rotary Compressor
VRUs 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
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 vol-
ume and price for NGLs are attractive.
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Decision
Process
VRUs also capture HAPs and can reduce operator emissions below action-
able 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 econom-
ics of VRUs by following five easy steps.
Five Steps for Assessing VRU
Economics:
1.
2.
3.
4.
5.
Identify possible locations for VRU
installation;
Quantify the volume of vapor emissions;
Determine the value of the recovered
emissions;
Determine the cost of a VRU project; and
Evaluate VRU project economics.
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 ade-
quate quantity of crude oil vapors
along with an economic outlet for the
collected product. The potential vol-
ume of vapors will depend on the
makeup of the oil and the rate of flow
through the tanks. Pipeline connec-
tion 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
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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 dump-
ing 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 esti-
mated, 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 2: Estimated Volume of Storage Tank Vapors
Vapor Vented from Tanks- SCF/BBL - GOR
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O O O OW O O O O O O O
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^
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j^£i^— -
ji
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^
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^"^
.
10 20 30 40 50 60 70 80
Pressure of Vessel Dumping to Tank (Psig)
The shortcoming of this
approach is that it does not
generate information about
the composition of the
vapors emitted. In particu-
lar, 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.
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 = 43scf/bbl x 1,000 bbls/day = 43 Mcfd
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The second approach is to use the software package E&P Tank version 2.O.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 bat-
tery 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 cal-
culations 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 tempera-
tures, the software can produce more precise estimates. This flexibility in
model design allows users to employ the model to match available informa-
tion. 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
1EPA 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.
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Exhibit 4: Value of Recovered Vapors
R = QxP
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 = $3.00/Mcf
R = 41 Mcfd x $3/Mcf =
$123/day
$3,800/month
$45,600/year
the gas stream and resell the
NGLs and methane sepa-
rately should also capture
the full Btu content value of
the vapors. Exhibit 4 illus-
trates a method of calculat-
ing the value of the recov-
ered vapors using an aver-
age price of $3.00 per Mcf
(which assumes 1,000 Btu
per scf). Where the Btu con-
tent of the vapors is higher,
the price per Mcf would be
higher.
Step 4: Determine the cost of a VRU project. The major cost elements of
VRUs are the initial capital equipment and installation costs and operating
costs.
VRU systems are made by several manufacturers. Equipment costs are
determined largely by the volume handling capacity of the unit; the sales line
pressure; the number of tanks in the battery; the size and type of compres-
sor; and the degree of automation. The main components of VRUs are the
suction scrubber, the compressor, and the automated control unit. Gas
measurement is an add-on expense for most units. Prices for typical VRUs
and related costs are shown in Exhibit 5.
When sizing a VRU, the industry rule-of-thumb is to double the average daily
volume to estimate the maximum emissions rate. Thus, in order to handle
43 Mcfd of vapor (Exhibit 3), a unit capable of handling at least 86 Mcfd
should be selected.
Exhibit 5: Vapor Recovery Unit Sizes and Costs
Capacity
(Mcfd)
25
50
100
200
500
Compressor
Horsepower
5-10
10-15
15-25
30-50
60-80
Capital
Costs($)
15,125
19,500
23,500
31,500
44,000
Installation
Costs($)
7,560-15,125
9,750-19,500
11,750-23,500
15,750-31,500
22,000-44,000
O&M Costs
($/year)
5,250
6,000
7,200
8,400
12,000
Note: Cost information provided by Natural Gas STAR partners and VRU manufacturers.
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Partners who have installed VRUs and VRU manufacturers report that instal-
lation 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 pro-
cessing 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 mar-
ket. 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 $3.00 per Mcf, the potential returns are attractive, par-
ticularly for the larger units.
Exhibit 6: Financial Analysis for VRU Project
Capacity
(Mcfd)
25
50
100
200
500
Installation &
Capital Costs1
($)
26,470
34,125
41,125
55,125
77,000
O&M
($/Yr)
5,250
6,000
7,200
8,400
12,000
Value of
Gas2
($/Yr)
13,000
26,000
52,015
104,025
260,060
Payback3
3.4 years
1.7 years
9 months
6 months
3 months
Return on
Investment 4
(%)
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.
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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.
Lessons
Learned
The use of VRUs can profitably reduce methane emissions from crude oil
storage tanks. Partners offer the following lessons learned:
* E&P Tank 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 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 aver-
age 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.
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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.
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Oil Stock Tanks. Presented at the SPE/EPA Exploration & Production
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Paper No. 37930.
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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
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Visher, Stuart, A.C. Compressors, personal contact.
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Weust, John, Marathon Oil, personal contact.
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&EPA
United States
Environmental Protection Agency
Air and Radiation (6202J)
1200 Pennsylvania Ave., NW
Washington, DC 20460
EPA430-B-03-I
October 2003
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