The petroleum industry has a growing number of artificial-lift choices for producing wells more efficiently.
Some new choices combine traditional lift methods, while others involve new technologies for both pumping and controlling pump efficiency.
One option under development in 1999 combines downhole separators and pumps. In these installations the pump functions for both lifting fluid to the surface as well as injecting fluid, typically water, into other zones downhole without first bringing fluid to surface.
Artificial lift is an essential part of oil field operations because most reservoirs, except when first drilled, have insufficient energy to flow fluids to surface. Even some gas wells have artificial lift installed downhole to unload accumulated water that would prevent gas from entering the wellbore.
Dewatering coal bed methane wells is another artificial-lift application. Most coal bed methane wells do not produce gas unless large amounts of water are first removed from the coal seams.
One artificial lift equipment manufacturer estimated that 80% of the world`s producing oil wells require some form of artificial lift. In North America this is almost 90%.
Traditional artificial lift
The industry`s six main types of artificial lift include sucker-rod beam pumps, progressing cavity pumps (PCPs), electrical submersible pumps (ESPs), hydraulic lift (jet or piston), gas lift, and plunger lift. Various variants of these types exist.
Table 1 shows one manufacturer`s breakdown of typical characteristics and installation ranges for each system. The manufacturer pointed out that solutions and requirements must still be evaluated well by well.
Pumps reciprocated with beam and sucker rods are the most common. One estimate is that, within the US, more than 400,000 wells (about 82% of all US wells) produce with beam pumps.
Some rough estimates indicate the other artificial lift methods in the US breakdown as follows: ESPs 4%, hydraulic lift 2%, plunger 1%, gas lift 10%, and other 1%.
Sucker-rod beam pump systems have many variants besides the conventional pumping units. Available are long, slow-stroke units and nitrogen over hydraulic units. The surface units have various unique designs, as shown by Fig. 1, of some units in the Daqing field in northern China.
The rods themselves are available in various grades, sizes, and materials such as steel or fiberglass. In China, hollow sucker rods provide a means to run a heating cable downhole for lowering the viscosity of the heavy oil produced in the Liaohe oil fields.
Technology advances also address the need to lower the cost of powering artificial lift systems. For sucker-rod pumping, a properly operating timer or pump-off-control (POC) can reduce both electrical and maintenance costs.
In Canada, PanCanadian Petroleum Ltd. in 1999 was testing microturbine generators for supplying power for wells equipped with PCPs. The turbines burn about 9 Mcfd of natural gas and provide about 28 kw of power, enough to run two PCPs.
A US Department of Energy field study showed that power requirements of beam pumping units can be reduced by making such electrical and mechanical modifications as:
- Checking the service conductor sizing and losses.
- Replacing one well`s motor with a smaller-sized unit to better match the motor system`s capability with the well requirements.
- Adding capacitors to correct the power factor.
- Inspecting and lubricating gearboxes and bearings and replacing worn parts.
- Dynamically balancing the unit.
- Inspecting and tightening belts and replacing worn belts.
- Inspecting and adjusting the seal of the packing head.
- Adjusting stroke length.
Trends
One trend in artificial lift at the end of the 1990s was the combining of existing technologies in one well such as a PCP with gas lift, ESP with gas lift, ESP with hydraulic pump, gas lift with plunger lift, jet pump with gas lift, ESP with PCP, and beam pump with gas lift.
The PCP with gas lift combination is primarily applicable in heavy oil production to lighten the column of produced fluid. Likewise, in the ESP with gas lift combination, lift gas is injected above the ESP to lighten the column of produced fluid. One estimate is that the column head can be reduced by 40%, which would greatly increase ESP performance.
In the ESP with hydraulic pump application, a downhole separator removes the gas below the ESP and vents it to the annulus. Then a hydraulic pump, above the ESP and driven by the fluid discharged by the ESP, takes the gas from the annulus and mixes it with the produced fluid in the tubing, again lightening the produced fluid column. The ESP efficiency is improved by removing the gas below it and lightening the column above it.
Gas lift combined with plunger lift aims at improving the lift efficiency of intermittently producing wells by preventing liquid fall-back because of gas breakout before the produced fluid reaches the surface. In this case the plunger forms an interface between the lift gas and the fluid slug, providing a seal between the liquid slug and lift gas.
The jet pump with gas lift combination is typically used with a concentric string of coiled tubing inside jointed production tubing. Power fluid is injected down the coiled tubing. At the bottom of the tubing, the jet pump mixes the power fluid with the produced fluid, and the fluid stream enters the annulus between the tubings. Lift gas is injected above the jet pump, again to lighten the produced fluid column and improve pump efficiency.
In heavy oil applications, the ESP with PCP combination (ESPCP) allows the use of the PCP, with its solids handling capabilities, in highly deviated or horizontal wells. The PCP in this case is driven by a downhole ESP motor instead of by a top-drive with rotating sucker rods.
Lift gas injected above a reciprocating sucker-rod pump will also lighten the produced fluid column and may reduce pump discharge pressures by 20-30%, thus also reducing the size of the surface equipment.
Other innovations
One recent design for pumps, such as those installed in the North Sea`s Captain field, relies on a turbine drive for powering a hydraulic pump (Fig. 2). The turbine drive allows high running speeds, and variable-speed operations while eliminating all downhole electrical equipment.
Coiled tubing offers a new option for deploying ESP pumps at less cost because workover rigs are not required for either running or retrieving the pump. In this case, the electric cable is either strapped to the outside of the tubing or run inside it.
One new use for ESPs is as downhole injection pumps, especially where surface pumps have some possibility of being stolen or are an eyesore on the environment.
Downhole oil-water separators (DOWS) provide a way to reduce the energy because the water is separated out and disposed of downhole without having to lift it all the way to surface. Because water is the largest waste stream associated with oil and gas production, its removal downhole can lower overall producing costs.
A number of DOWS types were being tested in 1999. One study indicated that 50% of the installations studied in North America had increased oil production after downhole separators were installed.
Hydrocyclones and gravity separators are the two types of DOWS being tested. Hydrocyclone separators have been paired with ESPs, sucker-rod beam pumps, and PCPs. Gravity-type separators have used only beam pumps.
The challenge has been to build separators and pumps that work together in a confined space in a bottomhole environment. To fit into 51/2-in. or 7-in. casing, DOWS are designed as long, slender devices that may be 100 ft long.
One version is the triple-action pumping system (TAPS) being tested by Texaco Exploration & Production Inc. in New Mexico.
According to Texaco, TAPS is capable of economically separating and injecting water downhole while producing only a fraction of the water to surface with the hydrocarbons. Texaco says TAPS has extended the applicability of DOWS to "hard-rock country" where high injection pressures are common.
In TAPs, a series of three sucker-rod pumps actuate the injection and production cycles (Fig. 3). An injection packer between the production and disposal zones serves as a tubing anchor and as a boundary between the two cycles. A purge valve mounted below the packer prevents injection water from flowing back when the tubing string is unlatched from the packer`s on-off tool.
In a variant on gas lift, surface-controlled downhole hydraulic-actuated valves have been placed in wells to allow gas-cap gas to enter the tubing and lighten the produced fluid column once water production starts to hinder oil flow. Norsk Hydro Production AS installed such valves in five Troll field wells off Norway and planned to install them in about 50 more wells. It expected the wells to increase oil recovery from a relatively thin oil column underlying a very large gas field by as much as 5%, or 200 million bbl.
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Beam units for reciprocating downhole sucker-rod pumps come in various shapes and sizes. The units shown in these photos pump oil from the Daqing oil field in northern China (Fig. 1).
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Weir Group PLC`s downhole turbine-driven hydraulic pumps add to producers` lists of artificial-lift options (Fig. 2).
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