An electrical submersible pump (“ESP”) assembly for wells typically comprises a submersible motor that drives a pump, typically a centrifugal pump. The pump assembly is usually suspended on a string of tubing within the well. The power cable to the motor is strapped alongside the tubing. Periodically, the pump assembly has to be retrieved for maintenance or repair, and this step requires pulling the tubing. Pulling the tubing requires a workover rig and is time consuming, particularly for offshore installations.
In some cases a dual tandem pump assembly is used to provide more lift. Normally two pumps are connected together and driven by a single motor. The pumps thus operate in unison with each other. Repair or replacement of either pump requires pulling the tubing and the entire assembly.
Often a pressure and temperature sensor will be mounted to the base of the motor for sensing the pressure and temperature of the dielectric liquid within the motor. The power to the motor fluid sensor and the signals are superimposed on the ESP power cable. Another measuring tool comprises a reservoir sensor, which is an electrical device that senses various characteristics of the producing reservoir of the well on the exterior of the motor. These tools typically send signals up a dedicated communication line extending to the surface.
In this invention a capsule having an upper end for connection to a string of production tubing is lowered within casing of a well. An electrical submersible pump assembly is located within and suspended by the upper end of the capsule. A bulkhead is located within the capsule below the pump assembly. An electrically powered device is suspended by and below the bulkhead. A power lead extends from the electrically powered device through the bulkhead, alongside the pump assembly within the capsule and sealingly through the upper end of the capsule. The electrically powered device may be suspended below the capsule or contained within the capsule.
The electrically powered device may be a sensor for sensing reservoir characteristics or it may be a second submersible pump assembly. In one embodiment having two ESP's, the bulkhead divides the capsule into upstream and downstream chambers, each chamber containing one of the pump assemblies. The power cables for each motor pass through the capsule alongside the outlet. The two submersible pump assemblies may operate simultaneously or one may operate while the other is shut down.
The reservoir sensor unit may be suspended below the hanger or bulkhead. The power and signals for the reservoir sensor unit may be supplied via a dedicated sensor line to the surface, or the sensor line may only extend to the motor sensor. In the latter case, the reservoir sensor and the motor sensor may be superimposed on the ESP power cable.
Referring to
Capsule 15 is a cylindrical member of slightly smaller outer diameter than the inner diameter of casing 11 so that it can be lowered into casing 11 on tubing 13. Capsule 15 has an upper or downstream end with a hanger 17 that is rigidly secured to the lower end of tubing 13.
An optional upper or downstream sleeve valve 19 is secured into a downstream conduit 18 below upper hanger 17. Upper sleeve valve 19 has an interior that is communication with the interior of tubing 13 for discharging well fluid upward. Upper sleeve valve 19 has an open position in which ports 21 on its sidewall are exposed to the interior of capsule 15. Upper sleeve valve 19 has a closed position in which ports 21 are closed to the interior of capsule 15.
An upper or downstream ESP 23 is suspended on upper sleeve valve 19. Upper sleeve valve 19 may be a commercially available type that closes its ports 21 to the interior of capsule 15 when downstream ESP 23 is operating. When ESP 23 is not operating, upper sleeve valve 19 automatically opens its ports 21 to the interior of capsule 15. This type of valve, known as an annulus diverter valve, is used normally in tubing above submersible pumps in applications that are prone to significant sand production. Alternately, upper sleeve valve 19 could be hydraulically actuated or stroked between the open and closed positions by pressure supplied from the surface via a hydraulic line 24 that extends alongside tubing 13 and sealingly through upper hanger 17.
If upper sleeve valve 19 is not utilized, upper ESP 23 would connect directly to upper hanger 17. Upper ESP 23 is a conventional electrical submersible pump assembly, including a centrifugal pump 25, which is shown at the upper end of the assembly. Pump 25 has an intake 26 on its lower end and is made up of a large number of stages or impellers and diffusers. One or more seal sections 27 are connected to the lower end of pump 25. An electrical motor 29 is connected to the lower end of the seal section or sections 27. Motor 29 is preferably a three-phase alternating current motor. Motor 29 is filled with lubricant, and seal sections 27 equalize the interior pressure of the lubricant in motor 29 with the pressure in capsule 15.
Motor 29 has an electrical power lead 31 that extends upward alongside seal section 27 and pump 25 within capsule 15. Motor lead 31 extends through an upper penetrator or guide 33 in upper hanger 17. Upper penetrator 33 seals motor lead 31 in upper hanger 17. Above capsule 15, motor lead 31 joins a power cable (not shown) that is strapped alongside tubing 13 and extends to the surface.
A lower extension pipe 35 extends from the lower end of motor 29 to a lower hanger or bulkhead 37 located within capsule 15. Lower hanger 37 is sealed to the sidewall of capsule 15, defining an upper or downstream chamber 36 above lower hanger 37 and a lower or upstream chamber 38 below lower hanger 37. A downstream conduit or support tube 39 secured to the lower side of lower hanger 37 is illustrated in
A lower or upstream ESP 45 is secured to the lower end of lower sliding sleeve valve 41, and its weight is supported by upper hanger 17 through upper ESP 23 in this embodiment. Sleeve valve 41 also may be an annulus diverter type that automatically closes ports 43 when lower ESP 45 is operating and opens ports 43 when ESP 45 is not operating. Alternately, sleeve valve 41 could open and close ports 43 in response to hydraulic fluid pressure supplied from a line 44 extending to the surface. If desired, lower sliding sleeve valve 41 may be operated independently of upper sleeve valve 19 by a separate hydraulic line from the hydraulic line leading to upper sleeve valve 19. Alternatively, a single hydraulic line could control both sleeve valves 19, 41. For example, if lower ESP 45 is a back up to be operated only after upper ESP 23 fails, sleeve valve 41 could be connected to the same hydraulic line as upper sleeve valve 19 and operated in reverse to upper sleeve valve 19. That is, while only upper ESP 23 is operating, as illustrated in
If a lower sleeve valve 41 is not utilized, lower ESP 45 will be secured directly to support tube 39. Lower ESP 45 may be the same type as upper ESP 23, although it may be of a different length, if desired. Lower ESP 45 includes a centrifugal pump 47 with an intake 48. Discharge port 50 of lower ESP 45 is in extension pipe 35 in upper chamber 36. One or more seal sections 49 connect pump 47 to electrical motor 51. A motor lead 53 extends from the upper end of motor 51 through a lower hanger penetrator 55 in lower hanger 37. Penetrator 55 seals motor lead 53 within lower hanger 37. Lower ESP motor lead 53 extends alongside upper ESP 23 and through an upper penetrator 56 located within upper hanger 17 to a power cable (not shown) extending to the surface. Capsule 15 has an inlet 59 located below the lower end of lower ESP 45. Inlet 59 communicates well fluid in casing 11 to lower chamber 38 surrounding lower ESP 45. Optionally inlet 59 comprises a stinger that stabs into a packer (not shown). The packer isolates the well fluid below it from the fluid within casing 11 surrounding capsule 15 and production tubing 13.
In the embodiment of
To accommodate thermal growth of upper ESP 23 (
In a third embodiment (not shown), instead of lower hanger 37 (
In operation, upper and lower ESP'S 23, 45 are installed within capsule 15 while at the surface. The entire assembly then is lowered into the well on tubing 13. The upper ends of motor leads 31, 53 are connected to power cables (not shown), which are strapped alongside tubing 13. While being lowered, capsule 15 protects motor leads 31 and 53 against damage in the areas where they pass alongside upper seal section 27 and upper pump 25. Because both motor leads 31 and 53 pass alongside these components, the clearance within casing 11 can be quite small.
Once capsule 15 is at the desired depth, the operator has a choice of simultaneously operating both upper and lower ESP's 23, 45 as shown in
In the booster mode of
As illustrated in
Referring to
In another embodiment, which isn't shown, the lower end of capsule 15 terminates at lower hanger 37. Lower ESP 45 is not located within capsule 15, but is suspended by lower hanger 37. Lower ESP 45 may have a tail pipe or stinger in that instance that would sting into a packer (not shown).
Referring to
In this embodiment, the lower end of capsule 83 terminates at lower hanger 97. In this example, a downhole sensor 99 is suspended on a tubular member or stinger 100 that is mounted to lower hanger 97. Sensor 99 is a conventional electrical device that senses various characteristics of the reservoir, such as pressure and water/oil contact, and will be referred to herein as a reservoir sensor. Tubular member 100 has a length selected to place reservoir sensor 99 close to perforations 102 of the reservoir. The well fluid flows upward through tubular member 100 into the interior of capsule 83 and into pump intake 95. Tubular member 100 could sting into a packer, if desired.
Optionally ESP 89 also has a conventional ESP motor sensor 103 mounted at its base. ESP sensor 103 measures parameters of the well fluid inside capsule 83, such as intake and discharge pressure, motor temperature and vibration. ESP sensor 103 is connected electrically to the motor of ESP 89, and the signal of ESP sensor 103 may be sent via ESP motor lead 91 and power cable to the surface. At the surface, circuitry separates the signal of ESP sensor 103 from the electrical power and provides a display.
If such an ESP sensor 103 is utilized, preferably a sensor lead 101 leads from reservoir sensor 99 alongside conduit 100 and sealingly through lower hanger 97 to ESP sensor 103. In that way, the signal from reservoir sensor 99 is also superimposed on motor lead 91 and the power cable for reception at the surface. Alternately, reservoir sensor lead 101 could extend through upper hanger 88 and alongside tubing 85 to the surface as indicated by the dotted lines in
Although not shown, a dual ESP system could be employed in which the lower ESP is not located within a capsule, but is suspended below the capsule containing the upper ESP. This system could particularly be employed when a packer is not required. In addition, the capsule could be located within a subsea flowline rather than within a well, in which case the ESP or ESP's would be oriented approximately horizontal.
The invention has significant advantages. In the dual ESP environment, the operator can use one ESP until it breaks down, then operate with the second ESP. This substitution extends the time before the tubing must be pulled. The capsule supports the weight of the lower ESP or a downhole reservoir sensor, rather than imposing a load on the upper ESP. If desired, the dedicated line normally used for a downhole reservoir sensor could be eliminated and signals superimposed on the ESP power cable.
While the invention has been shown in only a few of its forms, it should be apparent to those skilled in the art that it is not so limited but is susceptible to various changes without departing from the scope of the invention.
This application claims priority to provisional application 60/802,626, filed May 23, 2006.
Number | Name | Date | Kind |
---|---|---|---|
5099920 | Warburton et al. | Mar 1992 | A |
6082452 | Shaw et al. | Jul 2000 | A |
6138758 | Shaw et al. | Oct 2000 | A |
6325143 | Scarsdale | Dec 2001 | B1 |
6412563 | St. Clair et al. | Jul 2002 | B1 |
6595295 | Berry et al. | Jul 2003 | B1 |
6691782 | Vandevier | Feb 2004 | B2 |
6964299 | Scarsdale | Nov 2005 | B2 |
20040060707 | Bearden et al. | Apr 2004 | A1 |
Number | Date | Country |
---|---|---|
2071766 | Sep 1981 | GB |
2345307 | Jul 2000 | GB |
Number | Date | Country | |
---|---|---|---|
20070274849 A1 | Nov 2007 | US |
Number | Date | Country | |
---|---|---|---|
60802626 | May 2006 | US |