Vapor Recovery Unit (vru) Illustration

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Executive Summary

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




Technology Background

Underground crude oil contains many lighter hydrocarbons in solution.When the oil is brought to the surface and processed, many of the dissolvedlighter 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:
1-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
2-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
3-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 2,000Btu per scf. Therefore, on a volumetric basis, the recovered vapors
can be more valuable than methane alone

.

Economic and Environmental Benefits:

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:
1-Btu natural gas.
Piped to natural gas gathering pipelines for sale at a premium as high
2-Used as a fuel for onsite operations.
3-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 methan VRUs also reduce the emissions of a potent greenhouse gas




Decision Process:

Step 1: Identify possible locationsfor 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 vapors along with an economic outlet for the collected product. The potential volume of vapors will depend on the makeup of the oil 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 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
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 onhow 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



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
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.





References


1-Bigelow, Tom and Renee Wash. 1983. "VRUs Turn Vented Gas
Into Dollars." Northeast Oil Reporter. October 1983. pp. 46-47


2-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

3-Dailey, Dirk, Universal Compression, personal contact.

4-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

5-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

6-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

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