Downhole processing technology

Downhole processing necessitates small equipment sizes. The key operations needed are separation, injection, and pumping. A description of the technologies in each area suitable for downhole processing is provided below.

Gas/liquid separation and injection

The most common method of separating liquid (oil or water) and gas is by density difference. Because of the relatively large differences in density between liquids and gas, this separation is normally easier than oil/water separation, where the densities of the phases are much closer. In a conventional vessel, the force of gravity allows liquid droplets to settle from the gas within a designed residence time. Special internal vanes in the upper portion of the vessel may be used to promote droplet coalescence and improve gas quality. Sometimes antifoam chemicals are required to reduce foaming. In more compact separator designs, various cyclonic devices are used to impart a rotation on the fluid flow, effectively centrifuging the fluids and accelerating separation. Because of space limitations downhole, centrifugal separation, either by rotating or stationary blades, is usually required except for relatively low-rate wells.

Gas separation upstream of electric submersible pumps (ESPs) is conventional technology that has been practiced since these pumps were invented. Some of the power supplied to the pump is used to spin a rotor in the gas separator, which centrifuges the fluids and separates gas from the liquids. This is discussed in more detail in the section of the Handbook that addresses ESPs. Gravity separation of gas in the wellbore for rod pumping is also conventional and discussed elsewhere.

Newer gas/liquid separator designs have also been developed. The auger separator uses stationary auger blades to impart rotation for separation. As the fluid is forced to follow the path of the stationary auger blades, the rotation forces the liquid to the outside wall. Part of the gas is then drawn out of the center and ported to the annulus by a crossover tool. The advantage is that no moving parts are required and the equipment can be placed through tubing. A schematic of the auger separator downhole installation and a photo of the internals is shown in Fig. 1.

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  Fig. 1—Downhole auger separator.

Many downhole gas/water separator (DGWS) systems use rod pumps, ESPs, and progressive cavity pumping systems (PCPs) to inject water into the formation, usually below the production zone. In relatively low-rate wells, gravity separation of gas and water occurs in the annulus as formation fluids enter the wellbore. In rod-pump applications, the simplest water-injection device is a bypass tool in which the bottom end of an insert sucker-rod pump is seated (Fig. 2). The pumping action loads the tubing with water from the casing-tubing annulus. When the hydrostatic head in the tubing is great enough, the water drains into the disposal zone below the producing perforations and packer. Gas flows up the tubing-casing annulus.

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  Fig. 2—DGWS bypass tool.

Another rod-pump DGWS/injection system is the modified plunger pump (Fig. 3). This system consists of a short section of pipe with one to five ball-and-seat intake valves and an optional backpressure valve, run below a tubing pump in which the traveling valve has been removed from the plunger. On the upstroke, the solid plunger creates a lower-pressure area in the barrel, allowing the ball-and-seat valves to open and water to enter. On the downstroke, the plunger moves the fluid down and out of the barrel and into a disposal zone below the packer.

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  Fig. 3—DGWS modified plunger tool. .

ESPs are another alternative for water injection, and would be configured as a bottom-discharge system with the pump below the motor rather than in the conventional motor-on-bottom design. ESPs provide for very high disposal rates and are generally more economical in deeper wells. Another alternative is a rod-string-powered progressive cavity pump.

Downhole pumping of liquids is common with ESPs, jet pumps, and rod pumps. Now compression of gas downhole is being attempted as well. The subsurface processing and reinjection compressor (SPARC) is under development for downhole gas separation, compression, and reinjection. A turbo-expander is used to recover energy from part of the separated flow stream, and it uses that energy to compress the other fraction. Because of the small diameters available in a well, the rotational speeds of the turbine and compressor are very high—on the order of 100,000 rpm. Preliminary engineering has been done, engineering development of the components and control systems are ongoing, and field testing is planned.

Oil/water separation and injection

The most common application for downhole water/oil separation is water injection, either into the reservoir for enhanced recovery [waterflood or water-alternating-gas (WAG) miscible flood], or into a dedicated disposal zone which may lie either above or below the producing zone. Possible benefits of downhole disposal include the following:

• Reduced energy to pump water to the surface.
• Water-handling system debottlenecking without adding or modifying existing surface equipment.
• In some cases, lower chemical costs for scale inhibitors, corrosion inhibitors, and emulsion breakers.
• Less water handling on the surface, and therefore a lower risk of large surface spills.
• Increased oil rates and recovery through reduction of water coning from aquifer.

Bulk oil/water separation is predominantly based on density difference. Two basic types of downhole oil/water separation (DOWS) systems have been developed: hydrocyclone separation combined with a downhole ESPs or a rod pump, and gravity separation with production by rod pump. Although gravity separation in the wellbore may be possible for low-rate wells, hydrocyclones are far more effective compact separation devices because the rotation centrifuges the fluids, accelerating gravity separation beyond 1 “g.” The hydrocyclone systems can handle up to ten times the volume of water that can be handled with gravity systems, which have a limit of approximately 1,000 barrels of fluid per day (BFPD). The principles of hydrocyclone operation are the same as those for surface hydrocyclones, discussed in the separation section of the Handbook. The downhole challenge is not so much with the hydrocyclones, but with the passageways to port the separated fluids within a very confined tubing or casing diameter. The outlet streams from a hydrocyclone are a clean water stream and an oil stream with reduced water cut compared to the original fluid mixture. The water cut of the separated oil stream is typically in the range of 10 to 50%, vs. up to 90% for the original mixture.

A hydrocyclone system separates oil from water and uses one or two pumps to inject the water and lift the oil to surface. Two modes of operation are possible:

• the “pump-through” system (Fig. 4), in which reservoir fluids are pumped into the separator
• the “pull-through” system (Fig. 5), in which the reservoir provides the pressure to enable flow through the separator and the separated fluid volumes are pumped in their respective directions

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  Fig. 4—Pump-through system with booster pump.

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  Fig. 5—Pull-through system.

A second booster pump can be incorporated into the pump-through system, as shown in Fig. 4, to provide additional lift of fluids to surface. One advantage of pump-through systems is that free gas is dispersed, compressed, and put back into solution by the pump upstream of the separator. Another advantage is that one submersible pump may be sufficient, reducing equipment cost and simplifying controls. The advantage of pull-through systems is that emulsions are minimized because the fluid is not sheared by the pump before separation. Single-tube hydrocyclones have hydraulic capacities ranging from 500 to 2000 BFPD. For high flow-rate wells, several hydrocyclones can be combined, with the outlets from each flowing into manifolds, as shown in Fig. 6.

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  Fig. 6—Multistage pump-through system.

Gravity separation and reinjection systems are manufactured by a number of rod-pump suppliers. Separation of oil and water takes place in the annulus, and water is drawn off below the oil/water contact. A dual-action pumping system (DAPS) employs a rod pump with two pump assemblies and an injection valve (Fig. 7). On the upstroke, water is pulled into the tubing through the lower inlet valve, and oil/water is lifted up the tubing by the upper pump assembly. On the downstroke, oil/water is pulled into the upper pump assembly while water is pumped into the injection zone. A modification of this system (Fig. 8), the triple-action pumping system (TAPS), adds an additional pump assembly with a smaller plunger. TAPS permits injection at higher pressure and is a relatively simple and inexpensive system.

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  Fig. 7—Dual-action pumping system (DAPS).

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  Fig. 8—DOWS triple-action pumping system.

A special application of downhole water separation and reinjection is the deliberate production of water from an underlying aquifer to prevent water coning into the oil zone perforated interval. Perforating the aquifer zone in a dual completion and producing this water provides a hydraulic “sink,” depleting water pressure near the wellbore, and reducing the driving force for coning. This approach is applicable when water production is attributed to coning, but not when water production is caused by waterflooding. Physical models and reservoir simulation indicate that this can increase recovery by as much as 70%, as well as shorten recovery time significantly. The tradeoff for this is that more total water must be handled. Downhole reinjection into a separate disposal zone allows this additional water to be produced without having to be handled on the surface.

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See also

Downhole processing overview

Downhole processing candidate screening

Subsea processing overview

Subsea processing technology

PEH:Subsea and Downhole Processing