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Downhole hydraulic pump installations
Hydraulic pumping is a proven method of artificial lift — adding energy to move the fluids to the surface after reservoir pressure is no longer sufficient to do so. The key component of a hydraulic pumping operation is the downhole pump. The two basic types of installations are the “fixed”-pump and the “free”-pump design. In the fixed installation, the downhole pump is attached to the end of a tubing string and run into the well. Free-pump installations are designed to allow the downhole pump to be circulated into and out of the well inside the power-fluid string, or it can also be installed and retrieved by wireline operations.
In the fixed-insert (or tubing-conveyed) design, the pump typically lands on a seating-shoe in the larger tubing. Power fluid is normally directed down the inner tubing string, and the produced fluids and return power fluid flow to the surface inside the annulus between the two tubing strings, as shown in Part A of Fig. 1. These systems provide a passage for free gas in the annular space between the outer tubing string and the inside of the well casing, but to take full advantage of this gas-venting passage, the pump should be set below the perforations. The power-fluid string is usually ¾-in., 1-in., or 1¼-in. nominal tubing or 1-in., 1¼-in. or 1½-in. coiled tubing. The fixed-pump system is used mainly to fit a large-diameter downhole pump into restricted casing sizes and still retain the gas-vent feature. It also can be used to lift one or both zones of a dual well with parallel strings.
In the fixed-casing design, the tubing with the pump attached to its lower end is seated on a packer, as shown in Part B of Fig. 1. With this configuration, the power fluid is directed down the tubing string, and the mixed power fluid and the produced well fluids return to the surface in the tubing/casing annulus. Because the well fluids enter the pump from below a packer, the pump must handle all the free gas. This type of installation is normally used with large-diameter high-capacity pumps in wells with little free gas, and if space permits, a gas-vent string can be run from below the packer to the surface. As with the fixed-insert design, this installation is no longer common, and both have been largely supplanted by the various free-pump installations. Note that in both of the fixed-type installations, when using a reciprocating piston pump, the power fluid mixes with the produced fluid after passing through the pump.
The free-pump feature is one of the most significant advantages of hydraulic pumping systems. Free-pump installations permit circulating the pump to the bottom, producing the well, and circulating the pump back to the surface for repair or size change. Fig. 2 shows pump in-and-out operations for a typical free-pump installation. They require that a bottomhole assembly (BHA) be run in on the tubing string. The BHA consists of a seating shoe and one or more sealbores above it and serves as a receptacle for the pump itself. BHAs are of robust construction and use corrosion-resistant sealing bores to ensure a long life in the downhole environmental conditions. The extensions needed on the BHA also can be adapted with different metallurgy to accommodate a changing environment. Once run in on the tubing string, the BHA normally remains in place for years, even though the downhole pump may be circulated in and out numerous times for repair or resizing. As shown in Fig. 3, a wireline-retrievable standing valve is landed in the seating shoe below the pump. The pump is run in the hole by placing it in the power-fluid string and pumping fluid down the tubing. When the pump reaches bottom, it enters the sealbores, begins stroking or jetting, and opens the standing valve. During normal pumping, this valve is held open by well fluid drawn into the pump suction. During pump-out, the normal flow of fluids is reversed at the surface with appropriate valving and pressure applied to the discharge flow path of the pump. This reversal of flow closes the standing valve and permits the pump to be circulated to the surface—a process that normally takes 30 minutes to 2 hours, depending on depth, tubing size, and the circulating flow rate.
The benefits of being able to circulate the downhole pump in and out of the well include reduced downtime and the ability to operate without a pulling unit for tubing, cable, or rod removal. Another significant advantage is that pressure and temperature recorders can be mounted on the pump to monitor downhole conditions with different pumping rates. At the conclusion of the test, circulating the pump to the surface also retrieves the recorder. Substituting a dummy pump for the normal production unit can be used to check for leakage of tubing pressure. Steaming, acidizing, or chemical treatment of the formation can be done if the pump is circulated out and the standing valve retrieved on wireline. A flow-through blanking tool may be run instead of the pump for such treatment if isolation of the power fluid and discharge flow paths is desired.
The casing-free installation, shown in Part C of Fig. 1, is attractive from an initial cost standpoint because it uses only one string of tubing. At first glance, it seems to be the same as the fixed-casing design, but the crucial difference is that instead of being attached to the end of the power-fluid string, the pump fits inside it to allow circulation into and out of the well. For a given diameter pump, this requires a larger-diameter string that reduces the annular flow path for the discharge fluids, but in most cases, a more than adequate flow area remains. Nominal tubing as small as 1½ in. can be run in systems with 2 ⅞-in.-outside-diameter (OD) tubing used as casing, and coiled tubing as small as 1¼ in. can be run in systems with 2 ⅜-in.-OD tubing used as casing. In the 1½-in. and 1¼-in. nominal-size tubing, only the jet pump can be used, while in 2 ⅜-in.-OD or larger tubing, either jet or reciprocating pumps are suitable. Usually, 2 ⅜-in.-OD power-fluid tubing is used in 4½-in.-OD or larger casing, 2 ⅞-in.-OD tubing in 5½-in.-OD casing or larger, and 3½-in.-OD tubing in 6 ⅞-in.-OD casing or larger. Because the BHA sits on a packer, the pump must handle all the gas from the well in addition to the liquids, even though a gas-vent string can be run if gas interference limits pump performance. In both the vented and unvented systems, the power fluid mixes with the produced fluids and returns to the surface. In wells where the produced fluid should be kept off the casing wall or where gas venting is desired, the parallel-free installation should be considered. This installation, which requires two parallel tubing strings, normally does not require a packer. As shown in Part D of Fig. 1, the BHA is suspended on the power-fluid string, and the return is either screwed into the BHA or is run separately with a landing spear that enters a bowl above the BHA. The tubing/casing annulus serves as a gas vent passage, and to take full advantage of this, the unit should be set below the perforations. In wells with corrosive gas and/or liquid, it may be undesirable to use the casing for return of gas or to have the liquid in the casing annulus. In such cases, a packer can be installed; however, the pump must handle all the gas and produced liquids.
Open and closed power-fluid systems
All installations discussed so far are open power-fluid (OPF) types, which means that all the power fluid and the produced fluid are mixed together after leaving the downhole pump and return to the surface together in a common flow passage. Jet pumps are inherently OPF pumps because the energy transfer depends on mixing the power fluid with the produced fluid. All reciprocating piston pumps (not jets) keep the power and produced fluids separate during the energy transfer process because there is a separate piston for each fluid. If the BHA has appropriate sealbores and passages to keep the two fluids separated, the power fluid can return to the surface in a separate tubing string, thus creating a closed power-fluid system.
Considerations for a reverse-flow system for a jet-pump installation are the need to keep produced fluid off the casing, help minimize fluid friction losses, and aid in drillstem testing or unloading of wells. A reverse-flow installation is shown in Fig. 4. It uses the tubing/casing annulus for power fluid and the tubing string, which contains the pump, and is used for the combined power fluid and production. This protects the casing with inhibited power fluid and is most useful when severe corrosion is anticipated. In permanent installations, heavy wall casing should be a consideration to avoid casing burst conditions when power-fluid pressure is applied. In reverse-flow installations, the pump is run and retrieved on wireline in most cases but can be pumped in and out with a pusher-type locomotive.
Hydraulic pumps lend themselves to solution of the complex problem of the production of two separate zones or reservoirs in a single wellbore. To meet the artificial-lift requirements of the two distinct zones, two downhole pumps are usually required. It would be highly unusual if the same power-fluid pressure and rate were required for each zone; consequently, a separate power-fluid line for each pump is usually required. A number of completion configurations are possible, but small casing sizes and high gas/liquid ratios may severely hinder dual-well operation.
Downhole pump accessories
A number of accessories are available for downhole pumping systems.
Free-pump systems require swab cups and a standing valve to accomplish the pump-in and pump-out operations. The swab cups are carried on a mandrel, extending above the pump, which may contain a check valve to limit the amount of fluid by passing the pump as it is circulated to the surface. If the pump does not enter a lubricator on the wellhead, the check valve may include a valve bypass that is actuated when the pump enters the wellhead catcher to prevent excessive pressure buildup. Two examples of swab cup assemblies are shown in Fig. 1. Jet pumps usually use the simpler system.
Standing valves are necessary in free-pump systems to create a "U" tube and prevent the circulating fluid from flowing back into the reservoir. During pumping operations, the standing valve is opened by flow from the formation to the pump suction; whenever the pump is shut down, the standing valve closes. In some cases, the standing-valve ball is held open by a small magnet to prevent it from cycling during reciprocating pump-stroking reversals. When the downhole pump is unseated, fluids attempting to flow back into the formation wash the ball off the magnet and onto the seat. The standing valve is wireline-retrievable and includes a provision for draining the tubing before attempting to pull it. In most cases, the standing valve forms the no-go and bottom seal for the pump. Some jet-pump installations, however, use high-flow designs that do not serve as a pump seat. An example of each type is shown in Fig. 2.
To obtain producing bottomhole pressures (BHPs) at several different withdrawal rates, downhole pressure recorders are often run in conjunction with hydraulic pumps, hung below the standing valve. While this arrangement provides not only pressure drawdown but also pressure-buildup data, it has the disadvantage of requiring wireline operations to run and retrieve the recorder. Some reciprocating pumps can be run with a pressure recorder attached, which eliminates the wireline operations but does not permit observation of pressure buildup because the recorder is above the standing valve. Virtually all jet pumps can be run with recorders attached, and very smooth recordings are obtained.
Dummy pumps are sometimes run to blank off one or more tubing strings so that they may be checked for leaks. If the dummy pump has a fluid passage in it, the terms "flow-through dummy" or "blanking tool" are often used. These tools are useful for acidizing or steaming.
Screens and filters
To protect the downhole pump from trash in the well, various types of screens and filters are sometimes run. Because circulating pumps in and out of a well may dislodge scale and corrosion products in the tubing, a starting filter can be attached to the swab-cup assembly to filter the power fluid. Because this must be a relatively small filter, it will eventually plug up, and an automatic bypass arrangement is provided. This system collects foreign material during the crucial startup phase with a newly installed pump. For long-term operation, power-fluid and pump intake screens or strainers are used, which exclude large-diameter objects that could damage or plug the pump.
In some areas, subsurface safety valves are required. When a packer is set and the bottomhole assembly (BHA) is above it, a wireline-retrievable safety valve can be installed between the standing valve and the packer to isolate the formation. The safety valve is normally closed unless the pump supplies high-pressure fluid to it by way of a control line run from the main power-fluid tubing just above. The pump discharge pressure provides the reference pressure to the safety valve. When the pump is on bottom and power-fluid pressure is applied to it, the safety valve opens to allow well fluid to enter the pump. Most safety valves will not hold pressure from above, so the standing valve is still necessary for circulating the pump in and out of the well. Fig. 3 illustrates this type of installation.
Noteworthy papers in OnePetro
Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read
Bradley, H. B., & Gipson, F. W. (1992). Petroleum engineering handbook. Richardson, TX, U.S.A: Society of Petroleum Engineers. WorldCat
Frick, T. C., & Taylor, R. W. (1962). Petroleum production handbook. Dallas, Tex: Society of Petroleum Engineers of AIME. WorldCat
Pugh, Toby. (2014). Overview of Hydraulic Pumping. Weatherford. iBook.
Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro