American Oil and Gas Reporter - May 2016 - 52

SpecialReport: Compression & Production Optimization
FIGURE 3
Storage Tank Vapor Control (Left)
And Three Stages of Vapor Control (Right)
Overpressure

Blanket Gas

Controlled &
Emergency
Venting

Leakage

Emergency
Vent

Air
Ingress
Ignition

Entrained Gas

Pressure Vacuum
Relief Vent

Natural Gas
NGLs
Intermediates
Pad

Pressure Vacuum
Relief Vent

Level

Emergency
Vacuum

Underpressure

variables shown on the left-hand side of Figure 3. Storage tank
filling and pump-out operations, various sources of natural gas,
flashing of light-end hydrocarbons, and leakage points make it
challenging to ensure controlled containment. Overpressuring increases natural gas losses normally used to generate production
revenue. Introducing oxygen and water into the head space as a
result of a temporary vacuum can lead to an explosive gas mixture forming in the tank and can reduce tank integrity because
of accelerated corrosion.
The image on the right-hand side of Figure 3 illustrates the
three primary control stages. The first stage of vapor control incorporates a supply gas pressure regulator to control the vapor
space during pump-out operations or when temperature changes
decrease the head pressure.
In the majority of upstream applications, the pressure vacuum relief vent initiates a controlled venting of gas because of increased head pressure from filling operations. A controlled release also will occur in situations where the head pressure is increasing because of changes in temperature, flashing, or unexpected entrained gas in the oil inflow. A controlled intake of atmospheric air is implemented to counter supply-regulator problems in meeting the gas demand, resulting in a vacuum.
An emergency pressure vacuum relief vent is the third component for vapor control, should abnormal operations or control
component failures result in a rapid change in pressure that exceeds tank design specifications, which typically would occur in
an emergency such as fire or lightning.
To establish an effective control regime, it is important to minimize any potential for the different components to overlap in their
control function. Field-based best practices show components with
low threshold operating pressures, accurate control, fast speed of
response, and operating stability provide reliable, sustainable vapor control. Ensuring each component is tested and/or certified
to meet minimum operational leak rates, in combination with selfreseating and sealing gauge hatches, also helps establish a stable control environment.
Natural gas vapor losses associated with flashing, ineffective
gas blanketing, and leak sources are hard to quantify. However,
utilizing a Bakken well pad configuration and production characteristics (36 tanks per pad and 40-degree API oil), the ASME
52 THE AMERICAN OIL & GAS REPORTER

2001 calculations for a small-bore gas orifice were used to determine losses based on an individual tank leakage rate equivalent to an 0.25-inch orifice plate. Depending on the tank head pressure, the lost revenue potential for the well pad can reach $400,000
annually, based on a market price of $3.00/Mcf, $267,000 at
$2.00/Mcf, and $534,000 at $4.00/Mcf.
VRU Technology
Increasing regulatory compliance and potential lost production has prompted a number of shale-play liquids operators to implement various technologies to recover the Btu-rich vapors from
storage tanks. This includes compression units to redirect the vapor into the natural gas sales pipeline.
Although the added revenue from vapor recovery units can be
significant, so can the potential total cost of ownership associated with conventional compression technology. System reliability or downtime, added operator intervention, ongoing repair and
replacement costs, and energy usage are some of the concerns expressed by operators in implementing a viable economic solution.
The added challenge of federal and state regulatory agencies
enforcing 95 percent recovery efficiencies and regulatory compliance reporting emphasize the need for viable vapor recovery
solutions.
Scroll compressor technology that is common in industrial refrigeration and air conditioning applications is making its way
into the shale oil and gas production segment as part of VRU systems (Figure 4). The compressor design consists of a fixed scroll
mounted on the compressor casing and an orbiting scroll that is
coupled to the crankshaft. The orbiting motion creates a series
of gas pockets travelling between the two scrolls. The outer pockets draw in the gas, which in turn, is compressed as it is moves
to the center of the scrolls.
This design reduces the number of moving parts, provides higher efficiency over its operating range, and allows operation under a 0-100 percent duty cycle. The hermetically sealed unit eliminates shaft seals, thereby providing a zero VOC emissions rating.
A scroll compressor-based VRU skid includes a number of
interesting design features, such as a heated multistage gas/oil
stabilizer to inhibit the dilution of lubrication oil with natural gas
liquids. Combining this feature with a low oil carryover (<1.0 parts
FIGURE 4
Vapor Recovery Unit Design
Sales Gas Pipeline
Equalization
Valve

Pressure
Regulation Valve

Suction
Scrubber
Oil Tank

Blow
Case

Scroll
Compressor

Heat
Exchange

BackPressure
Check
Valve

American Oil and Gas Reporter - May 2016

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