Production System Cuts Flaring,Venting

When oil and natural gas prices are high, oil and gas companies need to operate as efficiently and economically as possible. That's also true—maybe more so—when prices are low.

Operators cannot be wasteful in either scenario. Some onshore wells that require hydraulic stimulation, particularly shale plays including Eagle Ford and Niobrara, produce API gravity crude of 40° or higher, which can contain natural gas liquids (NGLs) that turn to vapor as they move from high wellhead pressures of several thousand pounds-per-square-inch (psi) to atmospheric pressure in storage tanks, resulting in a loss of total production.

"While the industry has been able to capture higher value per Btu as a result of the shift from dry gas drilling to shale and tight oil," says Brian A. Matusek, vice president, global business development at Cameron International Corp., "we are still losing significant dollars as a result of vaporization of some of those light hydrocarbons at atmospheric pressures."

Working with a company called CrossStream, Cameron is about to release its patent-pending ECO2 (Economical and Ecological) Production System. The company tested its prototype system and presently is building several units for field testing.

Using a three-phase separator (oil, gas and water), a stabilizer and a natural gas-powered generator, Cameron is able to produce higher gravity oils and NGLs without the release of volatile organic compounds (VOC). Cameron is looking at two specific outcomes with the ECO2 Production System:

• From an ecological standpoint, eliminate flaring or venting vapors into the atmosphere.
• From a financial standpoint, higher revenues are imperative whether commodity prices are high or low.

Typically, vapors from a storage tank need to be controlled. That control method includes flaring the vapors, or utilizing a vapor recovery unit to recompress them to a higher pressure and subsequently move them to a pipeline for transport.

"With ECO2, we are not allowing the vapors to be generated," Matusek explains. "We are keeping them under pressure until we get to a point where we can economically collect and sell them."

"The stabilizer that we offer works in conjunction with the CrossStream unit, which is the measurement point in the skid," says Bob Carey, business development manager for CAMSHALE Services at Cameron. "We pull the water, measure the natural gas and keep the oil and NGLs in a pressurized state that results in accurate measurement. From that point it goes into a portable stabilizer that brings the oil to 9 RVP (Reid Vapor Pressure) so it remains in a liquid state and does not vaporize."

Centralized processing

The system is a way to bridge initial production to a centralized gathering system. Advantages of pressurized liquids are accurate measurement and control of pressure. As a result, the liquid hydrocarbons can be pumped several miles from the well site.

"Rather than having the limitation of three-phase flow through a pipeline and locating the production pods several hundred yards from the well pad," says Terrance Tschatschula, technical consultant, "we can locate a centralized processing facility miles away. We are not limited to using a system next to the well pad.

"The centralized facility is a stabilization facility," Tschatschula adds. "Once the operator has his own centralized gathering system, we can remove the stabilizer and each additional well that comes on stream will only need a production system that can be fed into the centralized gathering system.

"Because the central processing facility is a stabilizer," Tschatschula continues, "the operator is able to build a 20,000-barrel (bbl.) per day stabilizer rather than having individual stabilizers at each well pad."

A related reason for using the system is truck transport of oil and NGLs, Carey says. As a truck's tank heats up during its journey from storage tank to refiner, the tank contains less oil than when it began due to vaporization. Stabilization of the oil and NGLs eliminates that issue. Pumping the oil production into a gathering system also significantly reduces truck traffic on lease roads.

In one instance, Tschatschula notes, a truck owner was transporting a 200 bbl. load of condensate from the Granite Wash. "When the truck arrived at its delivery point, only about 160 bbl. remained. About 40 bbl. had vaporized and been vented from the truck tank.

"A lot of other issues regarding production of oil and gas center around storage tanks," Tschatschula says. "For example, new standards issued by the U.S. Environmental Protection Agency (EPA), implemented on August 16, 2012, address emissions of VOCs from storage tanks. Another issue is the visibility of drilling or production sites in populated areas.

"With this system," he continues, "we eliminate storage tanks at the well site. These tanks can then be located at a more convenient secluded area so they are not visible to the general public. Truck traffic can be better controlled."

Multiple wells or a single well can be put into one production system. "That decision will be driven by the needs of the operator," Tschatschula says, "whether they want to know what is happening with each individual well or whether they want the lowest cost-per-well separation, which means we put multiple wells into one unit in order to reduce equipment costs."

System specifications

The system is significantly smaller than a typical production system at a well site. The standard system can be transported on two skids. It includes a patent-pending, CrossStream Integrated Production Unit (CIPU), an oil stabilizer and electrical power generator. The CIPU, contained on an 8-by-20-foot skid, provides liquids measurement. When used with a stabilizer, it retains NGLs beginning with first production. When the producer completes its pipeline gathering system, the oil stabilizer and storage tanks are removed from the well site.

The CIPU includes a three-phase separator, 42-inch diameter vessel, a dual-pump system for redundancy, a skid-mounted control system and historical data capture. "The system is automatic," Carey says. "Software control is mounted on the production system and can be monitored remotely via Internet."

The CIPU features a 1,440 psi maximum allowable working pressure (MAWP), 1,000 bbl. per day maximum oil capacity, 2,000 bbl. per day total fluid capacity and 5 million cubic feet per day maximum gas capacity. The oil stabilizer has a 300 psig MAWP—although other options are available—a packed stabilizer column, and a line heater. The standard system has a 1,000 bbl. capacity, which can be increased.

How it works

How a typical, multi-well pad with related production infrastructure might look. Source: Cameron

The initial ECO2 production system reduces the need for onsite equipment at the well site. Source: Cameron

When a gathering goes into operation, the stabilizer and storage tanks can be removed, leaving less equipment on the well pad. Source: Cameron

The CIPU operates as a typical three-phase separator for oil, gas and water. A guided-wave radar level transmitter sends an analog signal to the programmable logic control (PLC) to maintain the pump speed to keep oil at the optimal level. The pump maintains the oil above the bubble point, which significantly reduces vaporization that typically occurs when the pressure drops.

To assure constant pressure on the pump discharge, a back pressure control valve is used, providing flow at a constant pressure level through the meter and normalizing liquid density. A result, according to Cameron, is a highly accurate measurement that normally would not occur with high-gravity oil production. These measurements are relayed to the PLC for archiving and transmitted for daily production reads.

After passing through the metering system, oil is pumped to the stabilizer skid, which includes a natural gas heater that is fueled from the wellhead. Heated oil is flowed through a packed column where the more volatile hydrocarbons from the oil are removed. Stabilized oil is pumped to storage tanks, resulting in emission rates consistent with API 25° gravity crude. Rich gas from the stabilizer column is then sent via pipeline to a gas plant for processing.

Under the ideal scenario, the operator would use an ECO2 production system while constructing a gathering system for delivery of crude and NGLs to a centralized stabilizer facility. Because the oil and NGLs are pressurized, the central stabilizer is located miles from the well pad and processes liquid from multiple wells. When the gathering system is operational, the stabilizer and storage tanks are removed from the well pad, leaving the CIPU and generator, resulting in less equipment on location and a smaller footprint.

The system can be configured for numerous scenarios. For example, a condensate gathering system, according to Cameron, allows all condensate to be moved to a central site through a small-diameter pipeline. The production system measures and samples condensate from each well. New high-pressure and older low-pressure wells each access the system because the condensate is pumped from each CIPU. Although new high-pressure condensate retains NGLs, it can be transported to the central location as a single-phase fluid. All flared volumes are eliminated.

A high-pressure gas-gathering system directs the gas into the gathering system while the well is choked, eliminating the need for compression during high-volume flow. The high-pressure line eliminates significant compression horsepower and associated costs, maintenance and fuel, and allows for about one-third of the gas reserves to move to market without compression. The gas is consolidated at a central compression facility for treating, if necessary. A large portion of NGLs remain in the condensate, avoiding high-pressure gas system slugging.