Harvesting Profits From Emissions

Smart vapor recovery increases profits, not greenhouse gases

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Figure 1. Traditional VRU schematic.

This article was originally published in the May issue of COMPRESSORtech2. Get every issue in your inbox/mailbox and access to our digital archives with a free subscription.

By Lou Heavner and Thomas Hoopes

Impact of environmental regulations on oil and gas operations

The U.S. oil and gas industry has been drilling for hydrocarbons trapped under the earth’s surface for ore than a century. Although existence of unconventional hydrocarbon reservoirs such as oil shale, shale oil, shale gas, coal bed methane, heavy oil/tar sands, bitumen, methane hydrates, etc., has been known for a long time, extraction of hydrocarbon from them has been uneconomical. Recently, however, advances in horizontal drilling and fracking technology whereby water, mixed with sand and chemicals, is injected underground at high pressure to release trapped oil and gas has changed the economics of drilling for oil and gas products. Dramatic increases in domestic energy production has made the United States one of the leading energy producers in the world.

Concurrent with the increase in domestic production, emissions from the oil and gas sites are also rapidly increasing. In 2012, EPA issued 40 CFR 60, Subpart OOOO regulations (Quad O) for controlling volatile organic compounds (VOC) and hydrocarbon emissions from sources such as compressors, storage vessels, pneumatic controllers, equipment leaks, etc., commonly found at oil and gas sites. For example, a storage tank that emits 6 tpy (5.4 T/yr) of VOCs or greater must now be equipped with a control device to reduce the VOC emissions by at least 95%. To claim an exemption from Quad O, an owner/operator of the tank must demonstrate that emissions have dropped to less than 4 tpy (3.6 T/yr) without emissions controls for 12 consecutive months.

The next phase of environmental regulations finalized in 2016 targeted methane emissions. Methane, which is a primary component of natural gas, is a significant contributor to greenhouse gases (GHGs), with 25 times the heat-trapping potential of carbon dioxide (CO2). Goal of the proposed GHG regulation is to curb methane emissions by as much as 45 percent from 2012 levels by 2025.

Targeted sources of VOC and GHG emissions

As described earlier, it has been a common industry practice for an oil and gas site to flare or vent VOC emissions to the atmosphere, presumably because it was viewed as the least costly option. New Source Performance Standards (NSPS) Quad O, U.S. Environmental Protection Agency (EPA) and state regulators now require that VOCs in the form of fugitive emissions be controlled by a control device that captures and recovers 95% of the emissions. Fugitive emissions are unintended releases of gases such as equipment leaks, evaporation losses, etc. The previously vented or flared hydrocarbon emissions may now be economically recovered and put to profitable use by separating the high-value, Btu-rich Natural gas liquids (NGLs) from the recovered VOCs and distributing the high-value NGLs and natural gas products for sale via pipelines or may be used as on-site fuel. In some cases, the recovered VOCs may be properly disposed of as permitted waste.

Efforts to recover the fugitive emissions have largely focused on top tier emissions sources. The top tier fugitive emissions sources that contribute to a majority of site wide VOC and GHG emissions include equipment such as compressors, storage tanks and leaks from components such as valves, flanges, connectors, seals, pressure relief devices, etc. Leaks or fugitive emissions may also occur from equipment that is not operating correctly, such as an open thief hatch of a storage vessel or separator dump valves that are stuck open. Thus, control devices may be designed to capture and recover emissions from these top tier sources for providing maximum benefit. Commonly used control devices may include combustion devices (such as a vapor combustion unit, flares or incinerators) or vapor recovery unit (VRU).

Traditional VRU for recovering storage tank emissions

Traditional VRUs are designed to recover up to 95% of VOC emissions from sources such as storage tanks, compressors, product loading/unloading racks and others. Production storage tanks typically store liquid hydrocarbons such as oil, condensate, and/or produced water. Vapor is generated in these storage tanks due to flash losses that occur when liquid is transferred from a gas-oil separator at higher pressure to a storage tank at atmospheric pressure, working losses that occur when liquid in the tank is agitated, or standing losses that occur due to changes in atmospheric pressure and temperature. The vapor is typically described as a wet gas since it also includes a small amount of liquid hydrocarbons. Recovering VOC emissions in a wet gas stream may carry greater risk since wet gas may foul valves, damage seals and contaminate lube oil used in compressors.

Recovered vapor may include methane and other VOCs, aromatic hydrocarbons such as benzene, toluene, xylenes and ethylbenzene (BTEX), NGLs, hazardous air pollutants (HAPs) and some inert gases. The Btu content of the recovered vapor may be greater than 2000 Btu/scf (74,500 kJ/m3), which is about twice that of pipeline quality natural gas. Thus, the recovered vapor adds about 2 times the value compared to the natural gas product itself. If uncontrolled, it is estimated that a typical storage tank may vent between 5 and 500 Mcf (142 to 14,200 m3) of VOC emissions to the atmosphere each day. The vented gas may be easily and economically captured, recovered and sold for an incremental profit. In addition to storage tanks, VRUs can also be set up to capture VOC emissions from compressors, product loading/unloading racks, and other sources.

Figure 1 illustrates a traditional VRU that may include one or more storage tanks, a suction scrubber, a compressor to boost the pressure of recovered gas to match pipeline distribution requirements, a bypass valve designed to divert a portion of the discharge stream back to the suction scrubber. The suction scrubber is designed to separate condensate from the gas and drain the liquid back to the storage tank. A VRU controller that is typically based on programmable logic controllers (PLCs) is installed in an electrical control panel to regulate VRU process variables like tank pressure, outlet gas pressure, compressor operation, bypass valve operation and others.

Challenges associated with controlling emissions using a traditional VRU

Reliability and uptime of traditional VRUs has to be typically built into the system by selecting components that have duty cycles that match process conditions and by selecting components that have fewer moving parts and have fewer routine maintenance requirements. Selection of the compressor unit and robustness of the controls strategy are critical decisions for VRU selection since they have a significant impact on the reliability and hence operations and maintenance (O and M) expenses over the life cycle of these components.

During normal operation, the VRU controller detects pressure changes inside the storage tank and controls the compressor operation (on or off status) as the inside tank pressure exceeds or falls below a set point. When the compressor is on, it passes the captured VOC vapors through the suction scrubber. Any liquid hydrocarbon is knocked out and returned to the storage tank, while the captured vapor is compressed for pipeline distribution. Since the inside pressure of the storage tank fluctuates due to various types of losses, the compressor is subject to frequent on/off operation, or else it must continuously recirculate a recycle gas stream. Selection of a compressor unit that is not designed for frequent on/off operation may reduce the reliability of the traditional VRU and increase life-cycle costs.

As described earlier, contamination of the lube oil used in a compressor by presence of wet gas is a critical issue since operating a compressor with contaminated lube oil may result in loss of oil viscosity and cause catastrophic failure of the compressor. Many operators/owners of traditional VRUs have to carry an onsite ‘day tank’ to frequently replace the contaminated lube oil or install a lube oil monitoring system both of which increase the O and M expenses. Oil-free or dry-seal type compressors may be available but they carry a substantial price premium and may have a limited range of operation.

Also, compressors that use rotating components such as pistons, screws, etc., are susceptible to more wear and tear and vibrations. The presence of vibrations may have a negative impact on other skid-mounted components such as valves, pumps, sensors, etc.

VRU controller may be typically packaged along with other VRU components, mounted on a skid and installed on site by the VRU supplier. While the VRU controller may be programmed for providing basic control functions, adding more complex control requirements such as adaptive control strategies based on wet gas detection above a threshold, or integration of VRU operation with wellhead automation or tank manager may become difficult.

Smart Vapor Management vapor recovery solution

Figure 2 illustrates a Smart Vapor Management (SVM) vapor recovery solution that is designed to incorporate advanced temperature and pressure control strategies to eliminate hydrocarbon dilution of the compressor oil system.

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Figure 2. Smart vapor management (SVM) system.

The SVM draws vapor from one or more storage tanks, and includes a suction scrubber, a scroll compressor to boost the pressure of recovered gas to match pipeline distribution requirements, a bypass valve designed to divert a portion of the discharge stream back to the suction scrubber, a heated multistage gas/oil stabilizer, and an oil cooler. The suction scrubber is designed to separate condensate from the gas and drain the liquid back to the storage tank. A remote operations controller (ROC) may be installed in a control panel to regulate SVM process variables like tank pressure, outlet gas pressure, compressor operation, bypass valve operation and others.

A key component of the SVM is a scroll compressor that compresses vapor using two spiral elements, one of which is stationary and the other moves in an eccentric motion. The scroll compressor is designed for frequent on/off operation saving valuable horsepower over traditional VRU technology, which requires recycling. Due to its variable speed operation, the duty cycle may be adjusted from 0% to 100%. This ensures that a constant storage tank pressure is maintained, independent of gas volume output. The scroll compressor has very low vibrations and noise since it has very few moving or rotating components.

The scroll compressor unit has low O and M expenses and has zero leaks or emissions due to its hermetically sealed design that eliminates need for shaft seals, drive belts, drive couplings, lube points or a system oil pump.

Modular design of the SVM can be designed to recover up to 530 Mcfd (15 Mm3/d) of rich gas vapor with discharge pressures of up to 190 psig (1411 kPa).

Figure 3 illustrates a P and ID diagram for controlling an SVM. A unique heated multistage horizontal gas/oil stabilizer and oil cooler are used in a closed loop to protect scroll compressor lube oil from hydrocarbon dilution. This eliminates the need for installing day tanks for oil. Inlet gas composition may be used to optimally control the variable speed of the scroll compressor.

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Figure 3. Piping and instrumentation diagram for controlling an SVM.

Advanced control strategies for the SVM described above are implemented in a remote operations controller (ROC). The ROC also performs data capture, storage, and transmission (SCADA) and includes a 32-day EPA report accessible by SCADA or USB download directly from the local display. The ROC is fully integrated with an application software suite for oil and gas production and transmission applications. ROC also supports a local or remote display to interact with the SVM. Since the same ROC unit can be, and often is, used as a platform to automate other production well sites and well pads, it is much easier to achieve true site-wide, as well as upstream and midstream integration.

Having access to real-time SVM information boosts profitability and accelerates decision making while improving health, safety and environment for all employees. Smart instruments may be used to continuously monitor operating conditions of critical assets such as high-pressure pumps and compressors. These instruments wirelessly communicate the asset’s condition in real-time to a local or remote operator. A change in vibration pattern or a bearing temperature profile of a pump or a compressor may be measured by the smart instrument and used by a predictive maintenance application to automatically alert an operator before a failure occurs.

table
Table 1. Smart vapor vs. traditional VRU.
Benefits of using smart vapor recovery solution vs. traditional VRUs

Some oil and gas companies view installation of a traditional VRU as an unavoidable expense to remain in compliance with the environmental regulations. VRUs are often purchased on a piecemeal basis for local, standalone (non-integrated) operation. The VRUs typically contain disparate measurement and control technology that may be difficult to standardize and integrate across multiple sites.

Leading oil and gas companies view an SVM solution as a strategic investment to harvest VOC emissions that pays for itself in a short time interval. Standardization and integration of site-wide, as well as upstream and midstream solutions builds a business infrastructure that is used to gain market share and reduce costs. Table 1 compares the benefits delivered by a Smart Vapor Recovery Solution compared to a traditional VRU installed at an oil and gas site.

Gross revenues per year may be estimated by using Equation 1.

Gross revenues per year are defined by the following equation (1):
GR/Y = (QxPx365) + NGL
Where: Q = Rate of vapor recovery (Mcf per day); P = Price of natural gas; and NGL = Value of natural gas liquids sold

Thus, sale of NGLs in the recovered vapor can now directly add to company profits while concurrently reducing up to 95% of VOC and GHG emissions.

Conclusions

As the oil and gas industry shifts focus due to the changing market conditions, there is renewed interest in exploring smart investment options that lower operating costs, improve health, safety and the environment, and deliver fast payback from small capital investments. A strategy used by leading oil and gas companies is to leverage the standardization and integration knowledge and experience of leading automation suppliers to build on their expertise in oil and gas production, processing and transmission solutions to deliver increased profits while simultaneously achieving substantial decreases in hydrocarbon emissions.

About the authors: Lou Heavner is a control engineer with Emerson’s Automation Solutions and has been with the company for more than 30 years. Contact him at: lou.heavner@emerson.com. Thomas Hoopes is director of marketing and business development for Vilter Mfg. LLC and has more than 30 years of experience working with compressors in gas compression and refrigeration. Contact him at: thomas.hoopes@emerson.com.