Inverted shroud for submersible well pump

A well pump assembly includes rotary pump and a submersible motor. A shroud surrounds the pump intake and the motor. The shroud has an open upper end in fluid communication with the pump intake. A tubular member of smaller diameter is secured to and extends downward from a lower end of the shroud. The tubular member may have an open lower end for drawing well fluid along a lower flow path up the tubular member to the pump intake. An upper flow path at the upper end of the shroud may have a minimum flow area that is smaller than a minimum flow area of the lower flow path. The tubular member has a smaller outer diameter than an outer diameter of the shroud. The tubular member may have a closed lower end to define a debris collection chamber with a drain valve.

FIELD OF THE DISCLOSURE

This disclosure relates in general to submersible pumps for wells and in particular to an electrical submersible pump assembly mounted with a shroud assembly having an open upper end.

BACKGROUND

Electrical submersible pumps (ESP) are widely used to pump oil production wells. A typical ESP has a rotary pump driven by an electrical motor. A seal section is located between the pump and the motor to reduce the differential between the well fluid pressure on the exterior of the motor and the lubricant pressure within the motor. A drive shaft, normally in several sections, extends from the motor through the seal section and into the pump for rotating the pump. The pump may be a centrifugal pump having a large number of stages, each stage having an impeller and diffuser. The pump may be other types, such as a progressing cavity pump.

Many wells produce both gas and liquid, such as oil and water. Centrifugal pumps do not function well pumping gas. Some ESP installations have gas separators to remove gas from the well fluid prior to reaching the pump intake. The gas discharges into the well casing and flows up to the wellhead.

Another technique employs a shroud that surrounds the ESP and is supported by the tubing string. The shroud may have an open lower end that is placed below the lowest perforations or openings in the casing. The upper end of the shroud would be closed, requiring all of the well fluid to flow downward alongside the shroud to reach the open lower end. A closed upper end system is usually set below the perforations. As the well fluid flow turns down to flow toward the shroud inlet, some of the gas will separate. The shroud alternately may be inverted with a closed lower end and an open upper end. Typically, the open upper end is positioned above the casing perforations. This placement requires all of the well fluid to flow upward to the open upper end. As the well fluid turns to flow downward into the shroud to the pump intake, some of the gas separates.

The motor of an ESP in a shroud is typically below the pump. If within an inverted shroud, a recirculation tube may be attached to the pump and extend down below the motor to divert some of the well fluid being pumped below the motor. The diverted well fluid flows back alongside the motor to the pump intake, thereby cooling the motor.

While these types of shrouds work well, in some wells the perforations extend over a great distance. If so, it is difficult to position the shroud effectively above or below the perforations. In other wells, the casing perforations or openings may be in a horizontal section, making it difficult to install a shrouded ESP in the horizontal section. The horizontal section may have a smaller diameter casing or liner.

SUMMARY

The well pump assembly disclosed herein includes a pump having a pump intake and a discharge for connection to a string of tubing. A submersible motor is operatively engaged with the pump for driving the pump. A shroud surrounds the pump intake and the motor. The shroud has an open upper end in fluid communication with the pump intake for drawing well fluid along an upper flow path down the shroud into the pump intake. A tubular member extends downward from a lower end of the shroud below the motor. The tubular member has a smaller outer diameter than an outer diameter of the shroud and is in fluid communication with a portion of the shroud surrounding the motor.

In one embodiment, the tubular member has a lower portion that is open for drawing well fluid in. A gas anchor sleeve may surround the lower portion of the tubular member. The gas anchor sleeve has a closed lower end and an open upper end, requiring well fluid flowing up along a lower flow path to flow around the gas anchor sleeve then down between the gas anchor sleeve and the tubular member to reach the open lower portion of the tubular member.

In some of the embodiments, a recirculation tube extends downward within the shroud from a portion of the pump to a point below the motor and above the tubular member. The recirculation tube diverts a portion of the well fluid being pumped by the pump to below the motor.

The embodiments showing a gas anchor sleeve and a recirculation tube may also have a baffle located within the shroud below the recirculation tube and above the tubular member. The baffle is positioned to be struck by the well fluid flowing down the recirculation tube and direct the well fluid back upward.

In other embodiments, the tubular member has a closed lower end, defining a closed chamber for collecting debris from well fluid flowing in the upper end of the shroud. In those embodiments, the tubular member has a drain port. A normally closed valve is located in the tubular member for closing the drain port. The valve is operable to open the drain port while the pump and motor are being retrieved to drain the shroud.

In some of the embodiments, a cylindrical filter is mounted at the upper end of the shroud coaxial with a longitudinal axis of the shroud. The upper flow path leads through the filter.

A debris chamber may optionally be mounted to a lower end of the gas anchor sleeve for collecting debris from well fluid flowing in the upper end of the shroud and in the gas anchor sleeve. The debris chamber has a drain port and a normally closed valve.

For the embodiments having both upper and lower flow paths, a fluid restricting device may be mounted within the shroud above the pump to retard well fluid flow into the upper end of the shroud. Preferably, a minimum flow area of the upper flow path is located in the fluid restricting device and is less than a flow area of the upper flow path in the shroud between the fluid restricting device and the pump intake.

DETAILED DESCRIPTION OF THE DISCLOSURE

The foregoing aspects, features, and advantages of the present technology will be further appreciated when considered with reference to the following description of preferred embodiments and accompanying drawings, wherein like reference numerals represent like elements. In describing the preferred embodiments of the technology illustrated in the appended drawings, specific terminology will be used for the sake of clarity. However, it is to be understood that the specific terminology is not limiting, and that each specific term includes equivalents that operate in a similar manner to accomplish a similar purpose.

Referring toFIG. 1, a well has casing11cemented in place. Casing11has been perforated, resulting in perforations13along a section or sections that may be quite long, such as 500 feet to 2000 feet or more. Although shown as vertical, the sections containing perforations13could be inclined. Perforations13could be in a horizontal section of the well and could comprise openings from the well for admitting well fluid such as fractures in an open hole, uncased well. The well fluid will likely be a mixture of gas and liquid, such as oil and/or water.

A string of production tubing15is supported in casing11from a wellhead (not shown). Production tubing15may be sections of tubing secured together with threads, or it may be continuous coiled tubing.

Tubing15supports a shroud17, which is a cylindrical tubular member with an open upper end19. In this example, tubing15extends into shroud17a selected distance. A hanger21secures shroud17to tubing15. Hanger21has passages within in it to allow well fluid to flow through hanger21and downward in shroud17. Shroud17has a tubular adapter or junction23at is lower end that is illustrated as being generally conical and tapers from a larger diameter downward to a smaller diameter.

A dip tube25joins shroud17at junction23and extends downward. Dip tube25is also a cylindrical tubular member, but in the preferred embodiment, it has a smaller outer diameter than the minimum outer diameter of shroud17at any point along the length of shroud17. Dip tube25has an open lower end27. Junction23seals dip tube25to shroud17so that any well fluid flowing upward in shroud17must first flow through dip tube25. In the example shown the longitudinal axis28of dip tube25is offset from the longitudinal axis30of shroud17. Consequently, the larger upper end of junction23is laterally offset from the smaller lower end of junction23. However, longitudinal axis28could coincide with the longitudinal axis30.

The smaller outer diameter of dip tube25provides a greater flow area in an annulus A1between dip tube25and casing11than in an annulus A2between shroud17and casing11. The outer diameter of dip tube25may be in a range from about 50% to about 65% the outer diameter of shroud17in the preferred embodiment. For example, in a well with 7 inch outer diameter casing11, the outer diameter of shroud17might be 5½ inches, and the outer diameter of dip tube25between 2⅞ inches and 3½ inches. Casing11with a 7 inch outer diameter would have an inner diameter of about 6 inches, making annulus A-1in the range from 2½ inches to 3⅛ inches in total cross-sectional dimension. Annulus A-2would have a total cross-sectional dimension of only about ½ inch. Although there is no precise minimum size for the outer diameter of dip tube25, if made too small, the frictional losses of the fluid flowing up the dip tube25would create undesired pressure loss in the dip tube.

Shroud17and dip tube25comprise a continuous tubular member with openings at lower end27and upper end19to admit well fluid. Additionally, open lower end27is in fluid communication with open upper end19via the interior of shroud17and dip tube25. That is, there are no barriers within shroud17and dip tube25that completely block well fluid flowing into lower end27from contact with well fluid flowing into upper end19or vice-versa. Dip tube25could thus be considered to be a lower portion of shroud17.

Shroud17and dip tube25may be lengthy if perforations13extend over a long distance. However, it is not necessary that shroud upper end19be above the highest perforation13or that dip tube lower end27be below the lowest perforation13. It might be desirable in some wells for the combined shroud17and dip tube25to extend over a large portion of perforations13. In other wells, such as a vertical well with a horizontal lower section, all of the perforations13may be in the horizontal section while shroud17and dip tube25are entirely in the upper vertical section of the well. Furthermore, shroud17could be in the vertical section of the well, and most of the dip tube25installed in the horizontal section. In the example shown, some of the perforations13are above shroud upper end19and some approximately at or below dip tube lower end27. Shroud17may have a greater or lesser length than dip tube25. Normally, the combined shroud17and dip tube25extends several hundred feet.

Optionally, a gas anchor sleeve29may be mounted around a lower portion of dip tube25. If dip tube lower end opening27is below all of perforations13, gas anchor sleeve29may not be needed. A bracket31is illustrated as extending between an inner diameter of gas anchor sleeve29and the outer diameter of dip tube25to secure gas anchor sleeve29to dip tube25. Bracket31has openings through it to allow well fluid to flow downward in the annular space between dip tube25and gas anchor sleeve29. Gas anchor sleeve29is a tubular member similar to shroud17, and may even have the same outer diameter. Gas anchor sleeve29has an open upper end33and a closed lower end34. Open upper end33is above dip tube lower end27and below junction23. Closed lower end34is a short distance below dip tube lower end27. The annular flow area between dip tube25and gas anchor sleeve29is preferably at least equal to the cross-sectional flow area of dip tube open end27. Alternately, rather than the extreme lower end of dip tube25being open, the term “open lower end27” includes holes within the side wall of dip tube25at a point below gas anchor upper end33. If holes in the side wall of dip tube25are employed, the extreme lower end of dip tube25could be closed or joined to gas anchor lower end34. The length of gas anchor sleeve29may vary, but it is typically less than the length of dip tube25so as to provide a length of the larger dimension casing annulus A1as long as possible. Normally, the upper end33of gas anchor sleeve29will be above some of the perforations13.

Production tubing15also supports a pump that is at least partially inside shroud17, which in the embodiment shown is an electrical submersible pump assembly (ESP)35. ESP35includes a pump37, illustrated as a centrifugal pump, having a discharge connected to production tubing15for pumping well fluid up tubing15. An intake39of pump37is located below shroud upper end19. Pump37may be a centrifugal type or some other pump, such as a progressing cavity pump. A seal section41couples pump37to a motor43. Motor43is preferably a three-phase electrical motor filled with a dielectric lubricant. A power cable including a motor lead (not shown) is strapped along tubing15and extends within shroud17to motor43. Seal section41is a conventional device that reduces a pressure differential between the lubricant in motor43and the well fluid. The lower end of motor43may have a sensor unit mounted to it. Normally ESP35has a larger outer diameter than the inner diameter of dip tube25, and the lower end of ESP35will located near junction23.

A flow restrictor45optionally may be located within shroud17to provide a minimum flow area along an upper flow path down shroud17to pump intake39. Alternately, the minimum flow area could be the annular space between pump37and shroud17. In some instances, hanger21will serve as a flow restrictor and provide all the flow restriction needed, eliminating a need for a separate flow restrictor45. Flow restrictor45is schematically shown inFIG. 1as an immovable baffle that secures around production tubing15and has an outer diameter less than the inner diameter of shroud17. The annular space between the outer diameter of flow restrictor45and shroud17provides a minimum flow area for well fluid to flow downward, particularly liquid well fluid. Flow restrictor45could also have passages within it that allow well fluid to flow downward.

The flow area provided by flow restrictor45would normally be less than the annular flow area at any point along the upper flow path between the upper end19of shroud17and pump intake39. The minimum flow area in the upper flow path from shroud upper end19to pump intake39is preferably less than the minimum flow area in the lower flow path from gas anchor sleeve upper end33to dip tube open lower end27and up dip tube25.

In operation, the operator assembles gas anchor sleeve29with dip tube25and dip tube25with shroud17. The operator lowers ESP35into shroud17either after shroud17is fully assembled or while shroud17is being assembled. The operator secures shroud17to production tubing15with hanger21and lowers the entire assembly into casing11with production tubing15. The operator will position the assembly at a desired location relative to perforations13. Normally, the operator will want to place pump intake39as low as possible relative to perforations13, to assure a liquid level above pump intake39during operation. In some wells, some perforations13may be at or below gas anchor sleeve29and some above shroud upper end19. Casing11would normally have a static level of well fluid liquid that is above pump intake39, but the static level might not be above all of the perforations13. The lower end27of dip tube25will be submersed in the static liquid in casing11, and possibly the upper end19of shroud17will also be submersed in the static liquid in casing11, depending upon the well. Axis28of dip tube25could be offset from the axis of casing11or it could be generally centered.

The operator supplies electrical power to motor43via the power cable (not shown). Pump37will operate to draw well fluid into pump intake39. As illustrated, the well fluid contains gas (dotted arrows) and liquid (solid arrows). The gas and liquid tend to separate as the well fluid flows from perforations13, with gas flowing upward relative to the liquid because of its lighter gravity. Gas released in casing11will flow up to the wellhead and out a flow line. Some of the liquid will flow downward to gas anchor open upper end33. That well fluid, which is predominately liquid, flows up dip tube25to pump intake39. Well fluid flowing from perforations13below gas anchor open upper end33will encounter additional gas separation where the well fluid turns and flows downward into gas anchor open upper end33. The liquid tends to flow downward in gas anchor open upper end33, while the gas flows upward.

Liquid from perforations13above shroud17, if any, will flow downward into shroud open upper end19to pump intake39. Some of the liquid flowing from perforations13below shroud open upper end19but closer to shroud open upper end19than gas anchor29may flow upward in the annulus A2between shroud17and casing11along with the gas. That liquid would turn and flow downward into shroud open upper end19, further releasing gas.

Generally, the faster the flow rate, the more likely liquid will be entrained in the gas flow. An advantage of the larger casing annulus A1is that the flow speed through this area will be less than the flow speed through the smaller casing annulus A2. Consequently, liquid produced from perforations13in larger casing annulus A1is more likely to separate from the gas and flow downward, rather than upward. Liquid produced from perforations13in smaller casing annulus A2may be more likely to be entrained with and flow upward along with the gas until reaching shroud upper end19. Some of the liquid produced in perforations13in smaller casing annulus A2may flow upward, and some may flow downward.

Preferably, a greater flow speed of liquid (e.g. linear feet per second) occurs in the lower flow path from gas anchor open end33down and up through dip tube25to pump intake39than in the upper flow path down shroud upper end19to pump intake39. The greater flow speed assists in providing an adequate flow of liquid well fluid past motor43for cooling. The greater flow rate is assisted by making the minimum flow area along the lower flow path for liquid flowing up dip tube25greater than the minimum flow area for liquid flowing downward along the upper flow path and passing downward through flow restrictor47. The minimum flow area along the upper flow path could be at hanger21, at flow restrictor45, if employed, or in the annulus between pump37and shroud17. The minimum flow area along the lower flow path could be the annulus between dip tube25and gas anchor sleeve29, at bracket31or in the opening27in dip tube25.

Referring toFIG. 2, components discussed that are the same as in theFIG. 1embodiment may use the same numerals, but with a prime symbol. In the embodiment ofFIG. 2, gas anchor sleeve29is not used. One reason is that dip tube25′ extends lower than the lowest perforation13′, making it less likely for gas to enter dip tube25′. Flow restrictor47may provide a minimum flow area as does flow restrictor45.

In this embodiment, flow restrictor47is movable, having pivotal sections, making it operate similar to a check valve or a flapper valve. As indicated by the dotted lines, at least part of flow restrictor47pivots downward or moves to a more open position to allow downward well fluid flow. Flow restrictor47pivots upward to a more restrictive position to reduce upward flow of well fluid if the well fluid flowing pressure below flow restrictor47becomes greater than the pressure above. Normally, the flow would be only downward. However, a large gas bubble could possibly enter dip tube25′ and tend to blow the liquid in dip tube25′ and shroud17′ upward out of shroud17′. In response, flow restrictor47would move to the more restrictive position illustrated by the dotted lines, retarding upward flow of liquid. In the more restrictive position, flow restrictor47would not seal completely to shroud17′ so as to allow the gas bubble below to dissipate upward out of shroud17′. Pivotal flow restrictor47would also have to accommodate the power cable passing downward to motor43′. A pivotal restrictor47could alternately be employed in theFIG. 1embodiment in place of the immovable flow restrictor45.

In addition, in the second embodiment, a recirculation tube49provides enhanced cooling for motor43′. Recirculation tube49has an upper end extending through the housing of pump37′ at a selected point between intake39′ and the upper end of pump37′. Some of the liquid being pumped will be diverted out of pump37′ and down recirculation tube49. The lower end of recirculation tube49is below the lower end of motor43′. The recirculated well fluid flows back up shroud17′ past motor43′ to pump intake39′.

FIG. 3illustrates an alternate embodiment of the assembly ofFIG. 1. Components that are the same in both embodiments may employ the same reference numerals. A cylindrical upper filter51is located at the upper end of shroud17. Filter51is concentric with shroud axis28, and most of the well fluid flowing in the upper portion of shroud17will flow through upper filter51. If hanger21has openings, a filter (not shown) may also be combined with hanger21. A cylindrical, coaxial lower filter53is located at the upper end of gas anchor sleeve29. An additional lower filter55may be located at gas anchor sleeve bracket31.

Another tubular member, referred to herein as debris chamber57, extends downward from gas anchor sleeve29. Debris chamber57may have an outer diameter smaller than gas anchor sleeve29and approximately the same as dip tube25. Debris chamber57has a closed lower end59for collecting sand and other debris that is able to flow through lower filters53,55and upper filter51. The length of debris chamber57may vary, but typically would be greater than 10 feet.

A drain port61is located within debris chamber57, and in this example, drain port61is closer to the upper end of debris chamber57than lower end59. A drain valve63is normally closed and may be opened when shroud17is retrieved along with pump37, seal section41, and motor43. Preferably drain valve63is a type that is opened by dropping a bar down the open upper end of shroud17after pump37, seal section41and motor43have been removed and shroud17is suspended at the upper end of the well. After shroud17has been drained and completely removed from the well, a technician may open lower end59to remove collected sand and debris.

The embodiment ofFIG. 3may also have a recirculation tube65similar to recirculation tube49ofFIG. 2. The lower end of recirculation tube65is below motor43and above dip tube25. A bowl-shaped baffle67is mounted directly below the lower end of recirculation tube65. Baffle67has a concave portion that faces to re-direct well fluid being discharged by recirculation tube65back upward. The embodiment ofFIG. 3does not employ a barrier such as flow restrictor45ofFIG. 1.

FIG. 4illustrates an alternate embodiment of the assembly ofFIG. 2. Components that are the same in both embodiments may employ the same reference numerals. A cylindrical filter69similar to upper filter51ofFIG. 3is at the open upper end of shroud17′. Rather than dip tube25′ (FIG. 2), a debris chamber71extends downward from the lower end of shroud17′. Debris chamber71is a tubular member with a closed lower end73, similar to debris chamber57ofFIG. 3. Debris chamber71has a drain port75and drain valve77that function in the same manner as drain port61and drain valve63ofFIG. 3. Debris chamber71preferably has an outer diameter smaller than the outer diameter of shroud17′, such as less than 65% of that outer diameter.

Unlike the embodiment ofFIGS. 1-3, there is no lower flow path in the embodiment ofFIG. 4; all of the well fluid flows into the upper end of shroud17′. Also, there is no flow restrictor such as flow restrictor47ofFIG. 2.

FIGS. 5A, 5B and 5Ccomprise a more detailed drawing of an assembly that is similar to the one shown inFIG. 4. A well has conventional casing79and a string of production tubing81. Production tubing81supports a shroud83having an open upper end85. Hanger87connects shroud83to a portion of production tubing81and allows downward flow of well fluid in shroud83.

Production tubing81also supports within shroud83a pump89having an intake91. A seal section93connects to intake91and to an electrical motor95. A recirculation tube97extends from one of the stages of pump89to a point below motor95. A tubular member that serves as a debris chamber99extends downward from the lower end of shroud83. A threaded lower cap101closes the lower end of debris chamber99during operation. Debris chamber99has a drain port103and a drain valve105that function in the same manner as drain port61and drain valve63ofFIG. 3. If desired, a conventional tubing collar107may connect more than one section of conventional tubing together to make up a desired length for debris chamber99.