Some oil and gas industry analysts have estimated that heavy oil and bitumen represent more than two-thirds of the world's oil reserves. As global energy demands increase, demand for production from these hydrocarbons will naturally increase. However, compared to conventional oil (obtained from more traditional and easily accessible sources), synthetic crude from bitumen is expensive and complicated to produce. Unlike conventional crude oil, bitumen does not flow freely. At room temperature, bitumen flows like cold molasses.

The two largest known sources of bitumen (Alberta, Canada and Venezuela) each contain more petroleum than the proven conventional oil reserves of the Persian Gulf. In Canada, synthetic crude oil produced from bitumen accounts for about 28 percent of total oil production. Alberta's bitumen deposits were commonly known as tar sands, but industry and government now prefer the more descriptive term, oil sands.

As of January 2009, there were 91 active oil sands projects in Alberta. Of these, five were mining projects and the remaining projects employed various in-situ (in place) recovery methods.

Mineable bitumen deposits are located near the earth's surface and can be recovered by open-pit mining techniques. For every barrel of oil, about two tons of oil sands must be dug up, trucked and processed. Roughly 75 percent of the bitumen can be recovered from the mined sands. After processing, the remaining sand must be returned to the pit and the site reclaimed.

Most in-situ bitumen comes from deposits buried too deeply below the earth's surface for mining techniques to be practical. Effective production of these deposits requires specialized thermal recovery techniques and equipment. There are three commonly used thermal recovery methods for extracting heavy oil: steam assisted gravity drainage (SAGD), steam flooding and cyclic steam stimulation (CSS, sometimes referred to as huff ‘n' puff). New high temperature electric submersible pump (ESP) systems have proven effective in thermal recovery applications, especially in recent SAGD installations discussed below along with the steam flooding method.

Steam Assisted Gravity Drainage

SAGD (Figure 1) is an advanced form of steam stimulation in which a pair of horizontal wells is drilled into the target formation, one a few meters above the other. Low pressure steam is continuously injected into the upper (injector) wellbore to heat the oil and reduce its viscosity, causing the heated oil to drain via gravity into the lower (producer) wellbore, where it is pumped out. Thermally, SAGD is considered twice as efficient as the older CSS process, and it results in far fewer wells being damaged by high pressure.
High temperature ESPs have proven successful in SAGD applications. Key to the success is operating at elevated reservoir temperatures and lower bottomhole pressures that increase production rates and reduce the ratio of the steam injected to the oil produced. Generally, these drawdown pressures are lower than those typically generated by other types of artificial lift systems, resulting in faster recovery and improved financial performance.

Figure 1. SAGD production processFigure 1. SAGD production process

The SAGD production process involves four phases:
Start up/circulation. In this phase, steam is typically circulated for two to four months in both the injector and producer wellbores to heat up the region between the wells. The SAGD process can begin once the near well region is mobilized and there is fluid communication between the injector and producer.

Ramp up. This is the first stage SAGD recovery. Injection and production rates are increasing as the steam chamber grows to the top of the reservoir. Depending on oil viscosity and other operating conditions, this ramp-up or “soak” stage can take up to 18 months.

Plateau. This phase occurs when the steam chamber has reached the top of the reservoir and begins to spread laterally in the formation. This period is characterized by the best peak production rates (i.e., optimized production). Peak rate periods have been known to last as long as 60 months or more, depending on reservoir quality and thickness.

Wind down (or blow down). When the SAGD steam chamber is mature and recovery is greater than 45 percent, the operation goes into a wind-down mode. Production rates decline due to the shallower drainage angle of the chamber interface. The steam-to-oil ratio (SOR) increases due to lower bitumen rates and increase heat loss to the reservoir.

Use of the SAGD recovery process provides a number of advantages over other technologies. Higher bitumen recoveries are achieved using fewer wells. The continuous, lower-pressure thermal process minimizes the potential for impact on the subsurface environment. In addition, the surface disturbance of a SAGD project impacts a small portion of the overall lease area.

Steam Flooding

A steam flood is a method of thermal recovery in which steam generated at the surface is injected into the reservoir through specially distributed vertical injection wells (Figure 2). The steam enters the reservoir and heats the crude oil, reducing its viscosity. The hot water that condenses from the steam and the steam itself generate an artificial drive that sweeps oil toward strategically drilled producing wells (similar to water flooding). Steam flooding is sometimes called continuous steam injection or steam drive. High temperature ESP systems are commonly used in these applications.

Figure 2. Steam flooding production processFigure 2. Steam flooding production process

High Temperature ESPs

High temperature ESP systems have become the artificial lift technology of choice to cost effectively produce heavy oils in many SAGD and steam-flooding applications. ESPs are used in applications previously restricted to gas lift and other forms of artificial lift. New generation ESP components have been redesigned with harder stage and bearing materials to improve radial stability, with special coatings to help withstand corrosion/abrasion and improved insulation materials to endure extreme temperatures and improve reliability.

Extremely high bottomhole temperatures (BHTs) require special pump and lift system components that can tolerate heat. New generation, high temperature ESP systems are specifically designed for these critical environments. Each component of these systems (Figure 3 and Figure 4)—seal, pump, intake, motor, power cable and pothead connector—have been engineered and manufactured to ensure maximum reliability in high temperature conditions.

Extreme Operating Temperatures. Heavy oil production often does not provide enough cooling capacity for standard downhole ESP motors and other system components. Without a proper cooling mechanism, traditional ESPs can overheat and fail. High operating temperature ESP systems prolong run life because they are specifically designed to tolerate extreme BHTs. For example, ESP motors use special high temperature insulation rated up to 550 deg F (288 deg C).

Temperature Swings. In some regions, rapid temperature swings from subfreezing temperatures at the surface to more than 425 deg F (218 deg C) downhole represent a challenge to standard ESP systems. The new generation ESP systems incorporate special features like oversized oil reservoirs, parallel bladder systems in the seal and specialized high temperature insulation designed to tolerate wide swings in temperature. Flexible high temperature bladder designs help reduce the differential pressure between the well bore and the motor, thus allowing the mechanical seals and pothead area to operate more reliably. Other features related to temperature swings include: (1) locking rings to secure wear resistant hardened bearings, (2) expanded running clearances and (3) special attention to relative thermal expansion of mating materials.

Wide Flow Ranges. Wells produced with steam flooding may have unstable flow rates due to inconsistencies in the steam injection pattern. High temperature ESP systems include a specially designed bearing system that allows for thermal growth and wear resistance from abrasive production. The pump can operate across a wide range of flow rates and through unstable or intermittent flow.

Corrosion and Abrasion. Corrosive and abrasive elements are commonly found in heavy oil. Special coatings help protect the new generation ESP systems against these elements. Specialized mechanical seal designs enhance stability and reduce the use of elastomers.

Gas Exclusion. High volumes of gas are difficult for downhole pumps to handle. If pump performance declines due to high volumes of gas, pumping shuts down. Downhole gas separators and compressors have been used with some success. More recently, gas exclusion intakes (or “bottom feeders”) have been employed to block the entrance of free gas into the pump system. The gas excluders have self-orientating intake ports designed to direct fluid flow to the bottom side of the horizontal well bore, thus closing off possible entrance of gas into the system.

Conclusion

New generation ESP systems have improved the reliability and dramatically reduced the costs of producing bitumen and heavy oil, yet thermal recovery of these important hydrocarbon reserves is still considered expensive and complicated. With reduced global energy demand currently fed by unstable economies, many operators have delayed, deferred or are in the process of redefining their oil sands projects. Even with lower oil prices and lower expectations for increases in production, most forecasters see a sizable rise in oil sands activity during the next decade.

As operating costs decrease, economies stabilize and energy demands inevitably increase, the long term production potential of oil sands will undoubtedly regain attention. Thermal recovery techniques using high temperature ESP systems will continue to play a major role in the production process.

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Figure 3. High temperature downhole ESP system components

Figure 4. High temperature power cable—EPDM insulation with lead barrier, Teflon tape and bedding tape (left). High-temp motor lead extension with connector rated to 550 deg F (287 deg C) (right).


Figure 4. High temperature power cable—EPDM insulation with lead barrier, Teflon tape and bedding tape (left). High-temp motor lead extension with connector rated to 550 deg F (287 deg C) (right).