Patent Application
20080196880
This invention relates to electric submersible pump and motor assembly that can be deployed down a well.
Electrical submersible pumps are commonly used in oil and gas wells for producing large volumes of well fluid. An electrical submersible pump (hereinafter referred to “ESP”) normally has a centrifugal pump with a large number of stages of impellers and diffusers. The pump is driven by a downhole motor, which is a large three-phase motor. A seal section separates the motor from the pump to equalize the internal pressure of lubricant within the motor to the pressure of the well bore. Often, additional components will be included, such as a gas separator, a sand separator and a pressure and temperature measuring module.
An ESP is normally installed by securing it to a string of production tubing and lowering the ESP assembly into the well. Production tubing is made up of sections of pipe, each being about 30 feet in length. The well will be ‘dead’, that is not be capable of flowing under its own pressure, while the pump and tubing are lowered into the well. To prevent the possibility of a blowout, a kill fluid may be loaded in the well, the kill fluid having a weight that provides a hydrostatic pressure significantly greater than that of the formation pressure. During operation, the pump draws from well fluid in the casing and discharges it up through the production tubing. While kill fluid provides safety, it can damage the formation by encroaching into the formation. Sometimes it is difficult to achieve desired flow from the earth formation after kill fluid has been employed. The kill fluid adds expense to a workover and must be disposed of afterward. EPS's have to be retrieved periodically, generally around every 18 months, to repair or replace the components of the ESP. It would be advantageous to avoid using a kill fluid. However, in wells that are ‘live’, that is, wells that contain enough pressure to flow or potentially have pressure at the surface, there is no satisfactory way to retrieve an ESP and reinstall an ESP on conventional production tubing.
Coiled tubing has been used for a number of years for deploying various tools in wells, including wells that are live. A pressure controller, often referred to as a stripper and blowout preventer, is mounted at the upper end of the well to seal around the coiled tubing while the coiled tubing is moving into or out of the well. The coiled tubing comprises steel tubing that wraps around a large reel. An injector grips the coiled tubing and forces it from the reel into the well. The preferred type of coiled tubing for an ESP has a power cable inserted through the bore of the coiled tubing. Various systems are employed to support the power cable to the coiled tubing to avoid the power cable parting from the coiled tubing under its own weight. Some systems utilize anchors that engage the coiled tubing and are spaced along the length of the coiled tubing. Another uses a liquid to provide buoyancy to the cable within the coiled tubing. In the coiled tubing deployed systems, the pump discharges into a liner or in casing. A packer separates the intake of the pump from the discharge into the casings. Although there are some patents and technical literature dealing with deploying EPS'S on coiled tubing, only a few installations have been done to date, and to date they have only been installed inside large casings, where the oil can flow around the outside of the motor and the pump intake is on the housing diameter.
Further when a well operator wishes to take measurements of the well, the well may be killed and electric submersible pump removed so that sensing equipment can be lowered down the well to take readings; once the readings have been taken, the sensors are removed and the electric submersible pump. Alternatively, a Y-tool system may be used, where the production tubing includes a bifurcation, with the ESP placed in the offset branch of the tubing so that logging tools can be lowered past the ESP, as is well known in the art.
It is an objective of this invention to be able to provide an electric submersible pump that can conveniently be lowered through a well.
Another objective is to be able to provide an ESP that may be used without killing the well it is to be deployed in. Another objective is to allow convenient sensing to be carried out in a well with an electric submersible pump in it.
According to the invention there is provided an assembly for downhole applications, comprising an electric motor, a pump, driven by the electric motor, the pump having a pump inlet, and the assembly having an assembly opening, the assembly being suspended from and lowered through the well on a deployment tube, the electric motor and the pump both being hollow such that a bore passes from the tube through the motor and the pump to the assembly opening at the bottom of the assembly such that a device suspended on a wireline or coiled tube may be lowered through the deployment tube and pass through the electric motor and pump to the part of the well below the pump inlet.
Well bores may be inclined away from the vertical, and indeed can even have horizontal regions. The words ‘above’ ‘beneath’, ‘higher’ ‘lower’ and similar terms are intended to indicate position along the well bore from the surface, even where the well bore may in fact be horizontal, so if a first element is ‘beneath’ a second element, where the well is horizontal this could mean simply that the first element is further along the well bore from the surface than the second element.
The following FIGS. will be used to describe embodiments of the invention which are given as examples and not intended to be limiting.
Referring to
The motor 10 drives the pump 20 such that well fluid is drawn into the pump inlet 22, out of the pump into the assembly's bore 25 through a bore port 23, up the bore 25, and through the pump outlet 24. Alternatively, fluid may be pumped to the surface through the tube 90, in which case the packer 30 may be dispensed with. The specific operation of the pump is described below.
This bore 25 is dimensioned to enable logging tools or other devices 95 to be lowered down the tube from the surface, and pass through the center of the motor and pump and out through the assembly opening 21. For a tool to pass through the assembly opening, the dockable plug 92 must be removed. This may be accomplished for example by retrieving the plug with a wireline fishing tool; the dockable plug 25 may have a latching means so as to be relatively easy to remove in a downward direction but immovable in an upward direction. The tool 95 may be lowered down the coiled tube on a wireline 98, or if necessary on narrower coiled tubing, depending on the tool's purpose. The tool 95 is lowered with a plug 97 which as well as external seal 93 also has an internal dynamic seal 96 through which the wireline or coiled tubing extends, so that after the plug has docked to seal the bore of the assembly the logging tool or other device may continue to be lowered past the electric submersible pump. This arrangement enables the pump to run while the lower zone is being logged, or serviced by coiled tubing. Other benefits of this assembly are no rotating seal is required, no thrust bearing is required, and the oil compensation chamber 94 requires only non-rotating seals.
Referring to
The motor and pump shown in
As the pump sleeve 53 rotates, the portion of the elliptical cammed surfaces 54 that the cylinder pins 55 engage in rises and falls, causing each cylinder 56 to rise and fall within its chamber 57.
Pump inlet 22 leads to an inlet passage 26 which in turn communicates with the top and bottom of each chamber 57 via non-return valves such that fluid may flow from the inlet passage 26 to the chambers but not vice versa. Outlet ports 58 also communicate with the top and bottom of each chamber via non-return valves such that fluid may flow from the chambers through the outlet ports to the assembly's bore 25 but not vice versa.
As each cylinder rises or falls, one end of each chamber is under compression while the other is under expansion. Fluid is therefore drawn from the inlet passage into the expended end of the chamber, while fluid is forced through an outlet port 58 into the bore from the compressed end of the chamber. Each revolution of the rotating sleeve 53 causes the cylinder to rise and fall once, so each end of the chamber undergoes compression and expansion during a full cycle.
Referring now to
However, the top and bottom ends of chamber 57 are connected to a passage 61, similarly the top and bottom ends of chamber 67 are connected to a passage 63. Passage 61 and passage 63 are linked by a passage 62, and passage 63 also leads to an outlet passage 64 which terminates at lower outlet port 26 opening into the annulus 70 between the assembly and the production tubing. Again, the top and bottom ends of the chambers 57 and 67 are linked to the passages 61, 62, 63 and 64 by non-return valves, such that while the rotating sleeve causes the cylinders 56 to rise and fall, fluid is drawn from the inlet passage 26 when the end of a chamber is under expansion, while when the end of a chamber is under compression fluid is forced into the passages 61, 62, 63, 64 and ultimately vented through port 26 into annuls 70.
It will be realized that different arrangements of cylinders an passages could be used to effect the invention, or even a different type of pump such as an impeller pump could be adapted.
Alternative embodiments using the principles disclosed will suggest themselves to those skilled in the art upon studying the foregoing description and the drawings. It is intended that such alternatives are included within the scope of the invention, which is limited only by the claims.
| Number | Date | Country | Kind |
|---|---|---|---|
| 0701061.4 | Jan 2007 | GB | national |
