Vapor Recovery Fundamentals

1. Flash Gas Generation

Flash gas is the primary source of vapor at upstream oil and gas tank batteries. When crude oil or condensate exits a separator operating at elevated pressure and enters a storage tank at atmospheric pressure, dissolved light hydrocarbons come out of solution. This phenomenon occurs because the solubility of light gases (methane, ethane, propane) in crude oil decreases as pressure decreases. The result is a rapid release of hydrocarbon vapor as the liquid equilibrates to the lower storage pressure.

Thermodynamic Basis

The flash gas rate can be estimated using the concept of solution gas-oil ratio (GOR). The Vasquez-Beggs correlation is widely used in the industry to predict the amount of gas dissolved in crude oil at given pressure, temperature, and composition conditions. The flash gas released at the storage tank equals the difference between the solution GOR at separator conditions and the solution GOR at tank conditions (approximately atmospheric pressure).

The Vasquez-Beggs correlation estimates the solution GOR as a function of pressure, temperature, gas specific gravity, and API gravity:

Reid Vapor Pressure (RVP)

The Reid vapor pressure is a standard laboratory measurement (ASTM D323) that indicates the volatility of crude oil at 100°F. Crudes with higher RVP contain more dissolved light hydrocarbons and will produce more flash gas when entering a storage tank. RVP values for typical production crudes range from 2 psia (heavy, weathered crude) to 12 psia or higher (light, volatile crude from high-pressure reservoirs). Permian Basin crude typically has an RVP of 6 to 10 psia, while Eagle Ford condensate can exceed 10 to 14 psia.

Factors Affecting Flash Gas Rate

2. Vapor Sources at Tank Batteries

While flash gas is the dominant vapor source, storage tanks at oil and gas facilities generate vapors from several additional mechanisms. A thorough VRU sizing analysis must account for all vapor sources to ensure the compressor is adequately sized for peak and sustained conditions.

Flash Losses

Flash losses occur when crude oil or condensate enters a tank from a higher-pressure upstream vessel. This is the largest single source of tank vapors, typically accounting for 70 to 90 percent of total emissions from a tank battery. The flash gas rate is directly proportional to the oil throughput and the gas-oil ratio at flash conditions. For a 500 BPD lease with a flash GOR of 400 SCF/bbl, the flash gas rate is approximately 8,300 SCFH.

Working Losses

Working losses occur during tank filling and emptying operations. When oil is pumped into a tank, the rising liquid level compresses the vapor space and displaces saturated vapors through the tank vent. Conversely, when oil is pumped out, the falling liquid level creates a vacuum that draws air into the tank through the vent. The incoming air mixes with hydrocarbon vapors, and when the tank is next filled, this mixture is pushed out as working loss. Working losses depend on the number of fill and drain cycles per day, tank size, and the number of tanks in the battery. For a typical lease operation cycling two tanks, working losses add approximately 5 to 10 percent above the flash gas rate.

Breathing Losses

Breathing losses, also called standing losses, result from daily temperature fluctuations. As ambient temperature rises during the day, the vapor space gas expands and is partially expelled through the tank vent. As temperature falls at night, the vapor space contracts and draws in air. This diurnal breathing cycle generates small but continuous emissions. Breathing losses are typically 2 to 5 percent of the flash gas rate for a properly sized tank. In regions with large daily temperature swings (such as West Texas, where temperatures can vary 30 to 40 degrees between day and night), breathing losses can approach 5 to 8 percent of flash gas.

Loading Losses

When trucks or railcars are loaded with crude oil from the tank battery, the filling action displaces vapors from the transport vessel. If the transport vessel is not equipped with a vapor return line connected to the VRU system, these loading vapors are typically vented to atmosphere. Loading loss rates depend on the loading rate, product vapor pressure, and whether submerged or splash loading is used. Splash loading (product falls through the vapor space) generates significantly more vapor than submerged loading (product enters below the liquid surface).

3. VRU Compressor Types

The vapor recovery unit is fundamentally a low-pressure gas compressor that takes suction from the tank vapor space (at or near atmospheric pressure) and compresses the recovered gas to a pressure suitable for injection into a sales gas pipeline, fuel gas system, or process vessel. Three main compressor technologies are used in VRU service, each with distinct advantages and limitations.

Rotary Vane Compressors

Rotary vane compressors are the most widely deployed VRU technology in the upstream oil and gas industry, particularly for small to medium installations (5 to 100 HP). The compressor consists of a cylindrical rotor with sliding vanes mounted eccentrically inside a cylindrical housing. As the rotor turns, the vanes extend outward by centrifugal force, creating compression chambers that decrease in volume as the rotor rotates. Key advantages include tolerance of liquid carryover (oil mist and condensed liquids that frequently accompany tank vapors), simple mechanical design with few moving parts, relatively low capital cost, and ability to handle variable inlet conditions. Rotary vane compressors typically achieve 60 to 70 percent polytropic efficiency and can deliver compression ratios up to 8:1 in a single stage.

Rotary Screw Compressors

Rotary screw compressors use two intermeshing helical rotors to compress gas. They offer higher efficiency (70 to 80 percent polytropic) compared to rotary vane units and are better suited for medium to large VRU installations (50 to 500 HP). Screw compressors can achieve higher compression ratios per stage (up to 10:1) and handle larger flow rates. However, they are less tolerant of liquid slugs and require better inlet scrubbing. The capital cost is higher than rotary vane units, but the improved efficiency reduces operating costs on larger installations where fuel or electricity represents a significant expense.

Gas Ejectors

Gas ejectors (also called jet compressors or eductors) use a high-pressure motive gas stream to entrain and compress the low-pressure tank vapors. The motive gas (typically high-pressure sales gas or fuel gas) is expanded through a converging-diverging nozzle, creating a low-pressure zone that draws in the tank vapors. The mixed streams then pass through a diffuser where velocity is converted back to pressure. Ejectors have no moving parts, require no electricity, and are virtually maintenance-free. However, they have low thermodynamic efficiency (typically 20 to 30 percent), require a reliable source of high-pressure motive gas, and add the motive gas volume to the total discharge stream. Ejectors are best suited for remote locations without reliable power supply or as a supplementary device to handle peak vapor loads.

VRU Type Comparison

4. Emissions Regulations

Vapor recovery from storage tanks is increasingly required by federal and state environmental regulations. The primary regulatory driver for VRU installation in the United States is the EPA New Source Performance Standards (NSPS) for the oil and gas sector. Understanding the regulatory requirements is essential for determining whether a VRU is mandatory and what level of emission control is required.

EPA NSPS Subpart OOOO (2012)

The original NSPS for the oil and natural gas sector was finalized in August 2012. Subpart OOOO established emission reduction requirements for storage vessels constructed, modified, or reconstructed after August 23, 2011 that have potential VOC emissions of 6 tons per year (tpy) or more. Affected storage vessels must reduce VOC emissions by at least 95 percent using a control device such as a VRU, enclosed combustor, or flare. The 6 tpy threshold applies to the individual vessel or group of vessels connected to a common vapor header.

EPA NSPS Subpart OOOOa (2016)

Subpart OOOOa updated and expanded the requirements of the original NSPS. It applies to facilities constructed, modified, or reconstructed after September 18, 2015. The 6 tpy VOC threshold and 95 percent control requirement remain the same, but OOOOa added requirements for methane emission reduction, extended applicability to additional equipment types, and strengthened monitoring and reporting requirements. OOOOa requires operators to conduct an initial determination of potential VOC emissions using the methodologies in 40 CFR 60.5395a (including API MPMS Chapter 19.4, EPA emission factors, or site-specific testing).

EPA NSPS Subpart OOOOb (2024)

The most recent update further expanded emission control requirements for both new and existing sources. OOOOb established presumptive standards for existing storage vessels and lowered emission thresholds in certain categories. The rule also strengthened requirements for monitoring, including adoption of optical gas imaging (OGI) and other advanced leak detection technologies. States have two years to develop implementation plans for existing sources under the OOOOb framework.

State Regulations

Several states have adopted regulations that are stricter than the federal NSPS. Texas TCEQ requires Permit by Rule (PBR) compliance under 30 TAC Chapter 106 or Standard Permit authorization, with site-specific emission limits that may require VRU installation even below the 6 tpy NSPS threshold. Colorado AQCC Regulation Number 7 requires 95 percent emission control for tanks with potential emissions of 2 tpy or more in the Denver-Julesburg Basin and other designated nonattainment areas. Wyoming DEQ, North Dakota NDIC, and Pennsylvania DEP all have additional or more stringent storage vessel emission requirements.

Emission Calculation Methods

5. VRU Sizing Methodology

Proper VRU sizing ensures reliable vapor recovery at all expected operating conditions while avoiding unnecessary capital expenditure. The sizing process follows a systematic approach from vapor rate determination through compressor selection and ancillary equipment specification.

Step 1: Determine Flash Gas Rate

Calculate or measure the flash gas rate using the Vasquez-Beggs correlation, API MPMS Ch. 19.4, process simulation, or site measurement. For new installations where site data is unavailable, the Vasquez-Beggs method provides an acceptable preliminary estimate when calibrated with the crude oil API gravity, RVP, upstream separator pressure, and tank conditions.

Step 2: Add Working and Breathing Losses

Add working and breathing losses as a percentage of the flash gas rate. A typical allowance is 5 to 15 percent, depending on the number of tanks, cycling frequency, and ambient temperature variation. For a two-tank battery with moderate cycling, use 8 to 10 percent as a reasonable estimate.

Step 3: Apply Safety Factor

Apply a 25 percent safety factor to the total calculated vapor rate to determine the design vapor rate for VRU compressor selection. This safety factor accounts for estimation uncertainty, seasonal variation, surge conditions, and future production increases. Industry practice typically uses 1.25 as the safety factor, though 1.5 may be appropriate for highly uncertain flash gas estimates.

Step 4: Establish Suction and Discharge Conditions

The suction pressure for a VRU is the tank vent pressure, which is typically set at 0.25 to 1.0 oz/in² (0.016 to 0.063 psig) above atmospheric pressure for API 650 atmospheric tanks. Converting to absolute pressure, the suction pressure is approximately 14.7 to 14.76 psia at sea level, or lower at higher altitudes. The discharge pressure is determined by the sales gas pipeline pressure or fuel gas system pressure, typically 50 to 300 psig at the point of connection.

Step 5: Calculate Compressor Horsepower

Use the polytropic compression equation to estimate the required compressor horsepower. The compression ratio determines whether single-stage or multi-stage compression is required (compression ratios above 4 to 5 per stage generally require two stages).

Step 6: Select Equipment

With the design flow rate, suction and discharge conditions, and horsepower requirement established, select the appropriate compressor type and frame size from manufacturer catalogs. Specify ancillary equipment including the inlet scrubber (liquid knockout drum), discharge cooler (if required), control panel, emergency shutdown system, and interconnecting piping. Consider redundancy requirements based on the consequence of VRU downtime (relief valve venting, environmental violations, revenue loss).

6. Economic Analysis

VRU installations are frequently justified on economics alone, independent of regulatory requirements. The recovered gas represents product that would otherwise be lost to atmospheric venting or flaring. The economic analysis compares the capital and operating costs of the VRU against the value of the recovered gas.

Revenue from Recovered Gas

The value of recovered gas depends on the volume recovered and the market price. At a gas price of $3.00/MCF and a recovery rate of 50 MCFD, the annual gas revenue is approximately $54,750 (assuming 95% uptime). For larger installations recovering 200 MCFD, the annual revenue exceeds $200,000. The gas value alone often justifies VRU installation with payback periods of 6 to 24 months for moderate-production leases.

Capital Costs

VRU capital costs depend on the compressor size, type, and ancillary equipment. Typical installed costs for upstream VRU packages range from $40,000 for a small 10 HP rotary vane unit to $500,000 or more for a large 200+ HP screw compressor installation with full controls, redundancy, and gas treatment. These costs include the compressor package, inlet scrubber, motor and controls, skid-mounted piping, electrical connections, commissioning, and startup assistance.

Operating Costs

Annual operating costs include electricity (or fuel gas for engine-driven units), lubricating oil, routine maintenance, and periodic overhaul. Electricity costs are typically the largest component: a 50 HP electric motor operating at $0.08/kWh and 95% uptime costs approximately $24,700 per year. Maintenance costs are typically estimated at 3 to 5 percent of capital cost per year. Total annual operating costs for a mid-size VRU installation are commonly $15,000 to $50,000.

Payback Period

The simple payback period is the time required for the cumulative net revenue (gas revenue minus operating costs) to equal the capital investment. For most upstream VRU installations, the payback period ranges from 6 months to 3 years. Installations with high throughput, high-RVP crude, and access to a sales gas pipeline typically achieve the shortest payback periods. Installations in areas with low gas prices, remote locations without pipeline access, or low-production marginal wells may have payback periods exceeding 5 years, making compliance-only minimal VRU packages more appropriate.

Economic Sensitivity

7. Installation & Operation

Proper VRU installation and operation are critical for achieving the designed recovery efficiency and maintaining regulatory compliance. Common installation and operational issues can significantly reduce VRU effectiveness if not addressed during design and commissioning.

Inlet Scrubber

A liquid knockout drum (inlet scrubber) upstream of the VRU compressor is essential. Tank vapors frequently carry entrained oil mist and condensed liquids, particularly during cool nighttime periods when the vapor dew point is approached. The scrubber separates these liquids before they reach the compressor, preventing damage (especially important for screw compressors that are less liquid-tolerant). The scrubber should be sized for the design vapor rate with a minimum residence time of 3 to 5 seconds. Accumulated liquids are typically drained back to the tank battery or to a slop tank.

Vapor Header Design

The vapor collection header connects each tank to the VRU compressor suction. The header must be sized to minimize pressure drop at the design flow rate, as any pressure drop between the tank and VRU suction reduces the effective suction pressure and the VRU's compression capacity. The header should slope continuously toward the scrubber to drain any condensed liquids. Low points that could trap liquid must be avoided. For tank batteries with more than 3 to 4 tanks, a larger trunk line with individual branch connections is recommended rather than daisy-chaining each tank in series.

Pressure Control

Tank pressure must be maintained within the narrow range between the VRU suction set point and the tank vent (pressure/vacuum relief) setting. If the VRU pulls too much suction, the tanks can experience vacuum conditions that may damage the roof structure of an API 650 atmospheric tank. If the VRU cannot keep up with vapor generation, the tanks will pressurize and vent through the pressure relief valve. A back-pressure regulator on the VRU suction or an automated bypass valve is typically used to maintain stable suction pressure. The VRU control system should monitor tank pressure and adjust compressor speed or bypass to maintain pressure within the safe operating range.

Emergency Bypass and Relief

An emergency bypass around the VRU allows tank vapors to vent through the normal pressure/vacuum relief system (typically a conservation vent) if the VRU shuts down unexpectedly. This bypass prevents overpressure of the tanks during VRU outages. Some installations include an enclosed combustor or flare as a backup control device during VRU maintenance periods to maintain NSPS compliance. The bypass should be sized for the maximum anticipated vapor rate without the VRU operating.

Monitoring and Reporting

NSPS OOOO/OOOOa requires periodic monitoring and recordkeeping for affected storage vessels and their control devices. VRU operators must maintain records of the control device type, installation date, design recovery efficiency, and any periods of deviation (when the VRU was not operating or operating below design efficiency). Continuous monitoring of key operating parameters (suction pressure, discharge pressure, flow rate, compressor run status) is recommended for early detection of performance issues.

8. Design Considerations

Designing a successful VRU installation requires attention to several practical engineering considerations that can significantly affect performance, reliability, and economics.

Altitude and Atmospheric Pressure

VRU installations at higher altitudes operate with lower atmospheric (and suction) pressure, which reduces the mass flow capacity of the compressor at a given volumetric capacity. At 5,000 ft elevation, atmospheric pressure is approximately 12.2 psia (compared to 14.7 psia at sea level), representing a 17 percent reduction. The compression ratio for a given discharge pressure increases proportionally, requiring more horsepower per unit of gas compressed. VRU sizing calculations must use the site-specific atmospheric pressure, not standard sea-level conditions.

Gas Composition Variability

Flash gas composition varies with crude oil properties, separator conditions, and ambient temperature. During cold weather, heavier components (propane, butane) condense out of the vapor phase, making the gas leaner (lower molecular weight, higher k value). During hot weather, more heavy ends remain in the vapor phase, making the gas richer (higher molecular weight, lower k value). The VRU compressor should be designed for the worst-case gas composition in terms of required horsepower and discharge temperature.

Discharge Temperature Limits

High compression ratios produce elevated discharge temperatures that can damage the compressor, degrade lubricating oil, and present a fire hazard. For rotary vane compressors, the maximum recommended discharge temperature is typically 350 to 400 degrees Fahrenheit. If the calculated discharge temperature exceeds these limits, interstage cooling or two-stage compression is required. The adiabatic discharge temperature can be estimated from the compression ratio and suction temperature using standard thermodynamic relationships.

Liquid Slugging Protection

Tank vapor streams can contain slugs of liquid during rainfall events, rapid temperature drops, or tank filling surges. A properly sized inlet scrubber with a high-level shutdown is the primary protection against liquid slugging. For rotary vane compressors, moderate liquid carryover can be tolerated, but sustained liquid flow will accelerate vane wear. For screw compressors, even small liquid slugs can cause catastrophic rotor damage. Liquid detection instrumentation (high-level float switch or capacitance probe) in the scrubber should be connected to the VRU shutdown system.

Redundancy and Reliability

The consequence of VRU downtime determines the appropriate level of redundancy. If VRU shutdown results in tank venting (atmospheric emissions and potential NSPS violation), a spare compressor or backup control device (flare or enclosed combustor) should be provided. For critical applications, a two-unit installation (one running, one standby) with automatic switchover ensures continuous vapor recovery. The annual availability target for a VRU system is typically 95 to 98 percent, which corresponds to 7 to 18 days of downtime per year for maintenance, repair, and unplanned outages.

References

1. EPA 40 CFR 60, Subpart OOOO — Standards of Performance for Crude Oil and Natural Gas Facilities (2012)
2. EPA 40 CFR 60, Subpart OOOOa — Standards of Performance for Crude Oil and Natural Gas Facilities for Which Construction, Modification, or Reconstruction Commenced After September 18, 2015
3. EPA 40 CFR 60, Subpart OOOOb — Standards of Performance for Crude Oil and Natural Gas Facilities (2024)
4. TCEQ 30 TAC Chapter 115 — Control of Air Pollution from Volatile Organic Compounds
5. GPSA Engineering Data Book, Chapter 7 — Separation Equipment
6. API MPMS Chapter 19.4 — Evaporative Loss Measurement
7. Vasquez, M.E. and Beggs, H.D. — Correlations for Fluid Physical Property Prediction, JPT (1980)
8. API Standard 2000 — Venting Atmospheric and Low-Pressure Storage Tanks

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