Many hydrocarbon wells are unable to produce at commercially viable levels without assistance in lifting the formation fluids to the earth's surface. Various forms of artificial lift are used to produce from these types of wells. Typical forms of artificial lift include Hydraulic Jet Pump (HJP), Gas Lift (GL), Gas Assisted Plunger Lift (GA-PL), Reciprocating Rod Pump (RRP), and Hydraulic Piston Pump (HPP).
For example, a well that produces oil, gas, and water may be assisted in the production of fluids with a reciprocating pump system, such as sucker rod pump systems. In this type of system, fluids are extracted from the well using a downhole pump connected to a driving source at the surface. A rod string connects the surface driving force to the downhole pump in the well. When operated, the driving source cyclically raises and lowers the downhole pump, and with each stroke, the downhole pump lifts well fluids toward the surface.
Different forms of artificial lift may be more suited to produce the well throughout its life. Transitioning from one form of lift to another can be very costly especially when the transition requires operators to re-complete the well and to install appropriate equipment. The costs associated with such requirements typically discourage operators from transitioning from one form of lift to another. Consequently, many wells may not be updated with appropriate lift system so the wells are not produced at their optimum levels.
The subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.
According to the present disclosure, a completion apparatus is useable for artificial lift with production tubing in a wellbore. The apparatus comprises a downhole assembly, a packer, a bypass, at least one isolation, and lift equipment. The downhole assembly is disposed on the production tubing in the wellbore and defines a throughbore. The packer is disposed on the downhole assembly and seals the annulus downhole of the production port.
A production port defined on the assembly uphole of the packer communicates the throughbore with an annulus of the wellbore. The bypass is disposed on the downhole assembly uphole of the packer also. The bypass communicates with the throughbore between the packer and the production port and communicates with the annulus.
The at least one isolation is disposed on the downhole assembly and selectively prevents and allows communication via one or both of the production port and the bypass, as discussed later. Finally, the lift equipment is selectively insertable into the throughbore and configures the downhole assembly for a number of forms of artificial lift, including, but not limited to, gas lift, hydraulic lift with a hydraulic jet pump, plunger lift, gas-assisted plunger lift, mechanical lift with a reciprocating rod pump, and hydraulic lift with a hydraulic piston pump. Additionally, the lift equipment selectively insertable into the throughbore can configure the downhole assembly for normal production, if possible from the formation.
According to the present disclosure, a method completes a wellbore for multiple forms of artificial lift. The method comprises: disposing a downhole assembly on production tubing in the wellbore, the downhole assembly defining a throughbore and defining a production port communicating the throughbore with an annulus of the wellbore, the downhole assembly having a bypass communicating with the throughbore between the packer and the production port and communicating with the annulus; sealing a packer on the downhole assembly in the annulus downhole of the production port; and configuring the downhole assembly for any selected one of the multiple forms of artificial lift. This is done by: selectively preventing and allowing communication with at least one isolation via one or both of the production port and the bypass; and selectively inserting lift equipment into the throughbore configured for the selected form of artificial lift.
In the method, selectively inserting the lift equipment into the throughbore can comprise one or more of: inserting multiple components of the lift equipment integrated together; running more than one component of the lift equipment together at a same time into the throughbore; and running one or more components of the lift equipment in the throughbore using one of wireline, slickline, and coiled tubing.
Selectively inserting the lift equipment into the throughbore can comprise selectively sealing one or more components of the inserted lift equipment with one or more of a plurality of bore seals disposed in the throughbore. As such, the downhole assembly can include a plurality of bore seals disposed in the throughbore that selectively seal with the inserted lift equipment. For example, a first bore seal can be disposed in the throughbore downhole of the communication of the bypass; a second bore seal can be disposed in the throughbore between the production port and the communication of the bypass; and a third bore seal can be disposed in the throughbore uphole of the production port.
In one embodiment, the at least one isolation comprises at least one sleeve insert selectively insertable into the throughbore and sealable therein relative to one or both of the production port and the bypass. For example, one sleeve insert of shorter length can isolate the production port and seal with the first and second bore seals. Another sleeve insert could be used to then isolate the bypass. Alternatively, one sleeve insert of greater length can isolate both the production port and the bypass and can seal with the bore seals.
In another embodiment, the at least one isolation comprises at least one sliding sleeve movably disposed in the throughbore between open and closed conditions relative to one or both of the production port and the bypass. As with the sleeve insert, one or more of such sliding sleeves can be used to isolate one or both of the production port and the bypass. For the bypass, however, one form of the at least one isolation can include a check valve or a rupture disk controlling communication via the bypass. In another alternative, an injection valve can also be disposed on the downhole assembly adjacent the bypass and can communicate a capillary string from surface with the annulus of the wellbore.
In the method, selectively preventing and allowing communication with the at least one isolation via one or both of the production port and the bypass comprises one of: selectively inserting at least one sleeve insert into the throughbore and sealable therein relative to one or both of the production port and the bypass; moving at least one sliding sleeve insert in the throughbore between open and closed conditions relative to one of the production port and the bypass; controlling communication via the bypass with a check valve; and controlling communication via the bypass with a rupture disk.
The assembly can be configured for gas lift or gas-assisted lift. For this, the downhole assembly comprises a gas lift valve disposed thereon and controlling communication between the annulus and the throughbore. For example, to configure the downhole assembly for gas lift, the at least one isolation prevents the communication via both the bypass and the production port.
In the method, configuring the downhole assembly for gas lift can comprises: configuring conduction of production fluid with the at least one isolation by preventing the communication via both of the production port and the bypass; and controlling communication of gas from the annulus into the production fluid in the throughbore.
The gas lift valve can be integrated into a gas lift mandrel of the assembly disposed on the production tubing. Other forms of gas lift valves and mandrel could be used. Moreover, for other forms of artificial lift besides gas lift or gas assisted lift, the gas lift valves may be removable and replaced with dummy valves, the gas lift valves may remain on the assembly but the lift operation may not expose the valve to an operational pressure differential, or the remaining gas lift valves can be independently isolated.
The downhole assembly can be configured for hydraulic lift using a hydraulic jet pump. To do this, the at least one isolation prevents the communication via the bypass and allows the communication via the production port. The hydraulic jet pump is inserted in the throughbore and has an inlet receiving production fluid from the downhole throughbore. A standing valve can be disposed at the inlet of the hydraulic jet pump.
In the method, configuring the downhole assembly for hydraulic lift can comprise: configuring conduction of production fluid with the at least one isolation by preventing the communication via the bypass and allowing the communication via the production port; inserting a hydraulic jet pump in the throughbore, the hydraulic jet pump having an inlet receiving production fluid from the downhole throughbore, an input receiving power fluid from the uphole throughbore, and an outlet for mixed production and power fluid, the outlet port in communication with the annulus via the production port; and positioning a standing valve at the inlet of the hydraulic jet pump.
The hydraulic jet pump can be operated under to flow schemes. In one example, the hydraulic jet pump has an input receiving power fluid from the uphole throughbore, and has an outlet in communication with the annulus via the production port for discharging mixed production and power fluid. In a reverse scheme, the hydraulic jet pump has an input in communication with the annulus via the production port for receiving power fluid, and has an outlet in communication with the throughbore uphole for discharging mixed production and power fluid.
The downhole assembly can be configured for plunger lift. To do this, the at least one isolation prevents the communication via both the bypass and the production port. The lift equipment includes a plunger assembly inserted in the throughbore and having an inlet receiving production fluid from downhole. A standing valve can be disposed at the inlet of the plunger assembly.
The plunger lift arrangement can be further assisted with gas, when the downhole assembly comprises a gas lift valve disposed thereon and controlling communication between the annulus and the throughbore. The plunger assembly can be inserted in the throughbore adjacent the gas lift valve. An inlet of the plunger assembly can receive production fluid from downhole and can be exposed to injected gas from the gas lift valve.
In the method, configuring the downhole assembly for gas-assisted plunger lift can comprise: configuring conduction of production fluid with the at least one isolation by preventing the communication via both the bypass and the production port; controlling communication of gas from the annulus into the production fluid in the throughbore with a gas lift valve disposed on the downhole assembly; inserting a plunger assembly in the throughbore adjacent the gas lift valve and having an inlet receiving production fluid from downhole; and positioning a standing valve at the inlet of the plunger assembly.
The downhole assembly can be configured for mechanical lift using a reciprocating rod pump. To do this, the at least one isolation allows the communication via both the bypass and the production port. The lift equipment includes an inlet inserted in the throughbore and sealed in fluid communication with the production port. The reciprocating rod pump is inserted in the throughbore uphole of the production port and receives production fluid from the production port via the inlet.
In the method, configuring the downhole assembly for mechanical lift can comprise: configuring conduction of production fluid with the at least one isolation by allowing the communication via both the bypass and the production port; inserting an inlet in the throughbore and sealed in fluid communication with the production port; and inserting a reciprocating rod pump in the throughbore uphole of the inlet to receive the production fluid from the production port via the permeable conduit.
The inlet can include a permeable conduit, a plug, and a holddown. For example, the permeable conduit is inserted in the throughbore adjacent the production port. The plug disposed on a downhole end of the conduit is sealed in a lower seal bore of the throughbore, and the holddown disposed on an uphole end of the conduit is sealed in an upper seal bore of the throughbore.
In another way to configure the downhole assembly for mechanical lift using a reciprocating rod pump, the at least one isolation allows the communication via both the bypass and the production port. The lift equipment includes an inlet inserted in the throughbore and sealed in fluid communication with the production port. An anchor is inserted in the throughbore uphole of the inlet, and the reciprocating rod pump is inserted in the throughbore uphole of the anchor and receives production fluid from the production port through the inlet and the anchor.
In the method, configuring the downhole assembly for mechanical lift can comprise: configuring conduction of production fluid with the at least one isolation by allowing the communication via both the bypass and the production port; inserting an inlet in the throughbore and sealed in fluid communication with the production port; inserting an anchor in the throughbore uphole of the inlet; and inserting a reciprocating rod pump in the throughbore uphole of the anchor to receive the production fluid from the production port through the inlet and the anchor.
The inlet for this configuration can include a permeable conduit inserted in the throughbore adjacent the production port and can include a plug disposed on a downhole end and sealed in a lower seal bore of the throughbore.
The downhole assembly can be configured for hydraulic lift using a hydraulic piston pump. To do this, the at least one isolation prevents the communication via the bypass and allows the communication via the production port. The hydraulic piston pump is inserted in the throughbore and has an inlet receiving production fluid from the downhole throughbore. An input of the pump receives power fluid, and an outlet for mixed production and power fluid is in communication with the production port. A standing valve can be disposed at the inlet of the hydraulic piston pump.
In the method, configuring the downhole assembly for hydraulic lift can comprise: configuring conduction of production fluid with the at least one isolation by preventing the communication via the bypass and allowing the communication via the production port; inserting a hydraulic piston pump in the throughbore, the hydraulic piston pump having an inlet receiving production fluid from the downhole throughbore, an input receiving power fluid, and an outlet for mixed production and power fluid, the outlet port in communication with the production port; and positioning a standing valve at the inlet of the hydraulic jet pump.
In another way to configure the downhole assembly for hydraulic lift using a hydraulic piston pump, the at least one isolation allows the communication via both the bypass and the production port. An inlet is inserted in the throughbore and is sealed in fluid communication with the production port. The hydraulic piston pump is inserted in the throughbore uphole of the inlet. The hydraulic piston pump receives production fluid from the production port via the inlet. An outlet for mixed production and power fluid is in fluid communication with the uphole throughbore. The pump include an input for power fluid, and a second conduit disposed in the uphole throughbore communicates with the input. A standing valve can be disposed at the inlet of the pump.
In the method, configuring the downhole assembly for hydraulic lift can comprise: configuring conduction of production fluid with the at least one isolation by allowing the communication via both the bypass and the production port; inserting an inlet in the throughbore and sealed in fluid communication with the production port; inserting a hydraulic piston pump in the throughbore uphole of the inlet, the hydraulic piston pump receiving production fluid from the production port via the inlet, an input for power fluid, and an outlet for mixed production and power fluid, the outlet in fluid communication with the uphole throughbore; positioning a standing valve at the inlet of the hydraulic piston pump; and positioning a second conduit in the uphole throughbore to communicate with the input of the hydraulic piston pump.
The foregoing summary is not intended to summarize each potential embodiment or every aspect of the present disclosure.
The bottom hole assembly 20 disposed on the production tubing in the wellbore defines a throughbore 32 and defines a production port 34 communicating the throughbore 32 with the annulus 14. A packer 16 disposed on the assembly 20 seals the annulus 14 downhole of the production port 34. A bypass 40 disposed on the assembly 20 communicates with the throughbore 32 between the packer 16 and the production port 34 and communicates with the annulus 14. The bypass 40 in the form of a snorkel tube can extend uphole toward the production port 34.
The assembly 20 is capable of transitioning from one form of lift to another, throughout the life of the well, without needing to recomplete the well. To do this, at least one isolation (not shown) disposed on the downhole assembly can selectively prevent and allow communication via one or both of the production port 34 and the bypass 40. Additionally, lift equipment (not shown) is selectively insertable into the throughbore 32 and configures the assembly for a selected form of artificial lift, as well as for normal production if possible.
A typical well may start its life with a high production rate produced by the natural flow of produced fluids from the well. As the formation is depleted, the production rate falls so that early forms of artificial lift are needed. Eventually, later forms of artificial lift may then be needed during the life of the well. The bottom hole assembly 20 can be configured with lift equipment that can follow a progression of artificial lift suited to the lift of the well. For example, the bottom hole assembly 20 can configured to start with a Hydraulic Jet Pump (HJP) and can then be transitioned to Gas Lift (GL), then to Gas assisted Plunger Lift (GA-PL), and then finally to Reciprocating Rod Pump (RRP) or Hydraulic Piston Pump (HPP) without pulling the tubing and only utilizing wireline or other deployment procedures to run and retrieve downhole equipment. The bottom hole assembly 20 can be configured for these and other forms of artificial lift.
The historical solution for the changing needs of a well is to recomplete the well based on the particular forms of lift required for the well. The disclosed system, however, can transition from one form of lift to another without needing to re-complete (pull the tubing) the well. In this way, the assembly 20 not only saves installation costs, but provides the option to deploy appropriate lift equipment suitable for the well to perform at an optimum level.
As shown in
Once set, the packer 16 and production equipment 30 remains downhole while other components of the completion 10 are transitioned to configure the completion for different forms of artificial lift. For example, the production equipment 30 of the bottom hole assembly 20 is configurable for different forms of lift operations depending on the needs of the well. Communication via the various snorkel tube 40, the production port 34, and the gas lift valve 100 between the throughbore 32 and the annulus 14 depends on the particular configuration of lift equipment (not shown) disposed in the equipment's throughbore 32.
Further details of the lift equipment (not shown) and configurations of the production equipment 30 are provided below. For its part, various types of surface equipment 60 connected to the production equipment 30 can be interchanged at surface as suited for the lift equipment (not shown) configured for the different forms of artificial lift. For example, the surface equipment 60 can include a pump jack for reciprocating rod lift, a lubricator for plunger lift, a gas injection system for gas lift, and a hydraulic system for hydraulic lift.
In general, the production equipment 30 can include an integrated component combining one or more of the packer 16, the snorkel tube 40, the production port 34, the gas lift valve 100, and other related elements together. Alternatively, the production equipment 30 can comprise a number of interconnected components. For example,
With a general understanding of the completion 10, the bottom hole assembly 20, and the production equipment 30,
The production equipment 30 includes the throughbore 32 having one or more production ports 34 communicating with the annulus 14. The production equipment 30 includes the snorkel tube 40 that extends uphole in the annulus 14 from the throughbore 32. A plurality of internal bore seals 50a-c are disposed in the throughbore 32 relative to the one or more ports 34 and the bypass (e.g., snorkel tube 40). In particular, a first (lower) bore seal 50a is disposed in the throughbore 32 downhole of the snorkel tube 40, a second (intermediate) bore seal 50b is disposed between the snorkel tube 40 and the ports 34, and a third (upper) bore seal 50c is disposed uphole of the ports 34.
The longitudinal distances between the bore seals 50a-c will depend on the particular implementation, diameter of the wellbore, diameter of the production tubing, the size of lift equipment to be disposed therein, etc. As one example for casing 12 having a diameter of 5½-in. and the equipment 30 having a diameter of 2⅞-in., the upper bore seals 50b-c can be spaced to accommodate lift equipment, such as a 2-ft. hydraulic jet pump and a 7-ft. hydraulic piston pump. As will be appreciated, the dimensions of the downhole assembly 20 can be suited for the particular needs of an implementation.
As depicted, the production equipment 30 can be integrated tubing having the above features form as part of it. Alternatively and as is common, the production equipment 30 can include a plurality of interconnected housings, components, tubulars, and the like properly connected together to produce a tubular body. Accordingly, any conventional arrangement of elements can be combined together to facilitate manufacture and assembly of the production equipment 30.
The bore seals 50a-c can include polished bores for engaging seals of lift equipment (not shown) inserted therein. In some implementations, the bore seals 50a-c may include seal rings, nipples, latch profiles, seats, and the like for engaging the lift equipment (not shown) removably inserted in the equipment's throughbore 32. As one example, a profile 33, such as an X-lock profile, may be provided in the throughbore 32 to lock a sleeve, a plug, a component of the disclosed equipment, or the like in place. For example, the profile 33 can be used to lock a sleeve (140:
At the uphole end, the production equipment 30 includes the gas lift valve 100. Typically, the gas lift valve 100 can be an external valve positioned on a tubing mandrel for controlling communication from the annulus 14 into the tubing mandrel, which communicates with throughbore 32. Such an external gas lift valve 100 can be installed at surface and run downhole with the production equipment 30. As an alternative, a side pocket mandrel can be disposed on the production equipment 30 and can hold a removable gas lift valve 100 therein. These and other forms of gas lift valves 100 can be used. Moreover, although only one gas lift valve 100 is shown, a given implementation may have multiple gas lift valves 100 along the production equipment 30.
According to the present disclosure, the production equipment 30 can be configured for hydraulic lift using a hydraulic jet pump (HJP). For example,
The lift equipment includes isolation 110 that selectively prevents and allows communication via one or both of the production port 34 and the bypass (snorkel tube 40). In particular, an isolation sleeve 110 is inserted in the throughbore 32 and seals with the lower and intermediate bore seals 50a-b to seal off communication of the throughbore 32 with the snorkel tube 40. The isolation sleeve 110 can include external seals or surfaces for sealing with the bore seals 50a-b. To run the sleeve 100 into place, the sleeve 100 can have profiles or other features for running with wireline or the like.
The lift equipment includes a standing valve 120 installed uphole of the isolation sleeve 110 to seal with the intermediate bore seal 50b, and includes the hydraulic jet pump 130 installed uphole of the standing valve 120 to seal with the upper bore seal 50c. The standing valve 120 can be installed on the hydraulic jet pump 130 and can be run in with it. Additionally, the isolation sleeve 110 can be run in place together with the other components of the standing valve 120 and pump 130 as a unit.
Finally, the gas lift valve 100 can be already installed as part of the bottom hole assembly 20. Alternatively, should the valve 100 be removable in a side pocket mandrel, either the valve 100 is installed in the side pocket, or a dummy valve or blank is installed for simply closing off fluid communication.
During the hydraulic lift operation as best shown in
At the hydraulic jet pump 130 (shown in detail in
At the same time, the gas lift valve 100, which operates as a check valve, prevents the power fluid PF in the throughbore 32 from passing to the uphole annulus 14a. The mixed fluid in the uphole annulus 14a is at a lower pressure than the power fluid PF so the gas lift valve 100 remains closed. For its part, the standing valve 120 prevents escape of production fluid from the hydraulic jet pump 130 downhole in the absence of sufficient fluid level.
In the previous arrangement, the jet pump 130 operated with the power fluid PF communicated from uphole down the throughbore 32 so that the mixed fluid MF traveled up the annulus 14a. A reverse operation can also be used. In particular, the jet pump 130 can be installed in the throughbore 32, and power fluid PF can be communicated from uphole down the annulus 14a where it can the enter the jet pump 130 through the port 34.
As before, production P rising up the throughbore 32 from downhole also enters the jet pump 130 and the two fluids mix therein. Finally, the mixed fluid MF then travels uphole to surface through the throughbore 32.
For this arrangement, it may be desirable to have a lock profile (see e.g., profile 33 in
For the arrangement in which the power fluid is communicated down the annulus 14a, modifications may be necessary given the presence of the one or more gas lift valves 100 of the assembly 20. A number of options are available. For example, the one or more gas lift valves 100, which may take the form of insertable gas lift valves installing in side pocket mandrels, may be replaced with dummy valves to prevent communication of power fluid in the annulus 14a to the throughbore 32.
In another option, each of the gas lift mandrels having an integrated gas lift valve 100 (as in
According to the present disclosure, the production equipment 30 can be configured for gas lift. For example,
The isolation sleeve 140 can include external seals or surfaces for sealing with the bore seals 50a-c. To run the sleeve 140 into place, the sleeve 140 can have profiles or other features for running in with wireline or the like. As shown, this second sleeve 140 can be an elongated sleeve to replace any shorter first sleeve (110) used in other configurations. As an alternative, of course, any shorter first sleeve (110) can remain in place to seal off the snorkel tube 40, and another shorter second sleeve can be run in place to seal off the production ports 34.
Finally, the gas lift valve 100 can be already installed as part of the bottom hole assembly 20. Alternatively, should the valve 100 be removable in a side pocket mandrel, the valve 100 can be installed in the side pocket. Any other suitable type of gas lift valve 100 can be used to fit the particular implementation.
As an aside, the assembly 20 configured as in
During the gas lift operation as best shown in
At the gas lift valve 100 (shown in detail in
According to the present disclosure, the production equipment 30 can be configured for plunger lift as well as gas-assisted plunger lift. For example,
During the plunger lift operation as best shown in
The plunger 152 initially rests on the bottomhole bumper 154 at the base of the production equipment 30. Typically, the production P includes gas, oil, and water and lacks sufficient pressure to rise to the surface. Therefore, gas is produced at surface while the deployed plunger 152 rests at the bumper 154 above a standing valve 120, which prevents escape of fluid. As the gas is produced to a sales line 159, liquids may accumulate in the throughbore 32, creating back-pressure that can slow gas production through the sales line 159. Using sensors (not shown), the controller 158 operates a valve at the wellhead to regulate the buildup of gas in the production equipment 30.
Sensing the slowing gas production, the controller 158 shuts-in the well at the wellhead to increase pressure in the well as high-pressure gas accumulates in the throughbore 32. When a sufficient volume of gas and pressure are reached, the gas pushes the plunger 152 and the liquid load above it to the surface so that the plunger 152 essentially acts as a piston between liquid and gas in the production tubing.
Eventually, the gas pressure buildup pushes the plunger 152 upward to the lubricator/catcher 156 at the wellhead. The column of fluid above the moving plunger 152 likewise moves up the tubing to the wellhead so that the liquid load can be removed from the well. As the plunger 152 rises, for example, the controller 158 allows gas and accumulated liquids above the plunger 152 to flow through upper and lower outlets 157a-b. The lubricator/catcher 156 eventually captures the plunger 152 when it arrives at the surface, and the gas that lifted the plunger 152 flows through the lower outlet 157b to the sales line 159. Once the gas flow stabilizes, the controller 158 again shuts-in the well and releases the plunger 152, which drops back downhole to the bumper 154. Ultimately, the cycle repeats itself.
The plunger 152 may cycle normally without gas assistance. However, gas assist can be provided from the upper annulus 14a if needed through the gas lift valve 100. Accordingly, the surface equipment at the lubricator 156 can include a gas injection system for injecting gas into the annulus 14a for entry into the throughbore 32 through the gas lift valve 100. This injected gas in the throughbore 32 can assist with the cycling of the plunger 152. As depicted in
As shown, the plunger 152 can have a solid or semi-hollow body, and the plunger 152 can have spirals, fixed brushes, pads, or the like on the outside of the body for engaging the tubing. Any other suitable type of plunger lift assembly 150 can be used to fit the particular implementation. For example, a two piece plunger can be used, or plungers with different external sealing profiles can be used. The bumper 154 can be integrated with the standing valve 120.
Depending on the bore seal, any latch profiles, or seats provided in the throughbore 32, the bumper 154 can install in the throughbore 32 with conventional components. Briefly, the bumper 154 can install in the production equipment 30 using wireline procedures. As shown in the example of
According to the present disclosure, the production equipment 30 can be configured for mechanical lift using a reciprocating rod pump (RRP). For example,
In general, isolation allows the communication via the production ports 34 and the snorkel tube 40, but separates them. In particular, a perforated subcomponent, permeable conduit, screen, or the like 160 has a plug 162 at its lower end and has a holddown 164 at its uphole end. The perforated sub 160 extends from the reciprocating rod pump 170 disposed uphole in the production equipment 30. The plug 162 seals with the intermediate bore seal 50b, and the holddown 164 seals with the upper bore seal 50c. Accordingly, the perforated sub 160 communicates with the production ports 34.
Meanwhile, the snorkel tube 40 communicates the upper annulus 14a with the throughbore 32 downhole of the plug 162, and the upper annulus 14a communicates with the production port 34 for delivery to the reciprocating rod pump 170. In this way, production fluid downhole of the packer 16 can collect in the upper annulus 14a. The snorkel tube 40 helps to separate gas and liquid in the production fluid so the liquid will tend to collect in the lower part of the annulus 14a, while the gas collects further uphole, where it can be removed at surface.
Finally, the gas lift valve 100 can be already installed as part of the bottom hole assembly 20. Alternatively, should the valve 100 be removable in a side pocket mandrel, either the valve 100 is installed in the side pocket, or a dummy valve or blank is installed for simply closing off fluid communication.
The jet pump and gas lift operations discussed previously in
In the present embodiment, the snorkel tube 40 is the form of bypass that provides the downhole gas separation for the rod pump 170. Production is diverted into the snorkel tube 40 above the packer 16. Fluids exiting the tube 40 separate in the annulus 14a with the gases rising and the liquids fallings. The liquids then reenter the throughbore 32 through the production port 34 and flow past the standing valve 120 to the pump's intake.
Other bypass components could be used to separate gas and liquid in place of (or in addition to) the snorkel tube 40. For example, a concentric arrangement having inner and outer tubulars, such as shown in
As shown in
Meanwhile, reciprocal movement of a string 176 of sucker rods induces reciprocal movement of the plunger 174 for lifting production fluid to the surface. Reciprocated by rod string 176 from the surface pumping unit 178, such as a pump jack, the plunger 174 with its traveling valve 175 lifts a column of production fluid up the throughbore 32, while the standing valve 173 maintains entering production fluid in the barrel 172 in which the pump 174 reciprocates. The standing and traveling valves 173 and 175 can each be a check valve (i.e., one-way valve) having a ball and seat.
As the surface pumping unit 178 reciprocates, for example, the rod string 176 reciprocates in the production tubing 30 and moves the plunger 174. The plunger 174 moves the traveling valve 175 in reciprocating upstrokes and downstrokes. During an upstroke, the traveling valve 175 closed. Movement of the closed traveling valve 175 upward reduces the static pressure within a pump chamber (the volume between the standing valve 173 and the traveling valve 175 that serves as a path of fluid transfer during the pumping operation). This, in turn, causes the standing valve 173 to open so that the lower ball lifts off the lower seat. Production fluid P is then drawn upward into the chamber.
On the following downstroke, the standing valve 173 closes as the standing ball seats upon the lower seat. At the same time, the traveling valve 175 opens so fluids previously residing in the chamber can pass through the valve 175 and into the plunger 174. Ultimately, the produced fluid P is delivered by positive displacement of the plunger 174 into the barrel 172. The moved fluid then moves up the wellbore production equipment 30. The upstroke and downstroke cycles are repeated, causing fluids to be lifted upward through the wellbore. To convey the fluid, production tubing 30 extends from a wellhead WH downhole. At the surface, the wellhead WH receives production fluid and diverts it to a flow line outlet.
According to the present disclosure, the production equipment 30 can be configured for hydraulic lift using hydraulic piston pump (HPP). For example,
In particular, isolation in the form of an isolation sleeve 110 has been positioned at the lower and intermediate bore seals 50a-b to seal off communication of the throughbore 32 with the snorkel tube 40. A standing valve 120 installs uphole of the isolation sleeve 110 and seals with the intermediate bore seal 50b, and the hydraulic piston pump 190 installs uphole of the standing valve 120 and seals with the upper bore seal 50c.
The standing valve 120 can be a separate component, which is installed after the equipment 30 has been installed and may not be attached to the hydraulic piston pump pump 190. Alternatively, the standing valve 120 can be installed on the hydraulic piston pump 190 and run in with it. Additionally, the isolation sleeve 110 can be run in place together with the other components of the standing valve 120 and pump 190.
Finally, the gas lift valve 100 can be already installed as part of the bottom hole assembly 20. Alternatively, should the valve 100 be removable in a side pocket mandrel, either the valve 100 is installed in the side pocket, or a dummy valve or blank is installed for simple closing off fluid communication.
During the hydraulic pump lift operation shown in more detail in
Briefly, the hydraulic piston pump 190 includes an engine barrel 191 in which an engine piston 192 can reciprocate. A reversing valve 193 is movably disposed in the engine piston 192 to control fluid communication to a pump barrel 194. For its part, the pump barrel 194 has a pump piston 195 that can reciprocate by the movement of the engine piston 192. A transfer valve 196 disposed in the pump piston 195 can capture fluid in the pump barrel 194 for eventual discharge through a discharge valve 197 at the outlet 199.
During operation, the engine barrel 191 receives pressurized power fluid from an input 198 exposed to the throughbore 32 uphole. The pressurized power fluid then drives both upstrokes and downstrokes in the pump 190 shown respectively in
After each upstroke (
Additionally, in this configuration of
In previous embodiments, removable isolation sleeves 110 and 140 have been used as isolation to isolate fluid communication through the bypass 40 and/or the production port 34. As an alternative, sliding sleeves can be incorporated in the production equipment 30 downhole and can be shifted to control communication through the snorkel tube 40 and/or the production port 34 for the isolation as needed. For example,
The production equipment 30 includes the throughbore 32 having one or more production ports 34 communicating with the annulus 14. The production equipment 30 includes the snorkel tube 40 that extends uphole in the annulus 14 from the throughbore 32. A plurality of internal bore seals 50b-c are disposed in the throughbore 32 relative to the one or more ports 34 and the snorkel tube 40.
A sliding sleeve 115 is disposed on the production equipment 30 to selectively open/close fluid communication through the production ports 34. The sliding sleeve 115 can be manipulated using a shifting tool or the like to configure fluid communication through the ports 34 depending on the lift operation to be performed. In general, the sliding sleeve 115 can be used in place of the isolation sleeve of previous embodiments.
As depicted, the production equipment 30 can be integrated components having the above features formed as part of it. Alternatively and as is common, the production equipment 30 can include a plurality of interconnected housings, components, tubulars, and the like properly connected together to produce a tubular body. Accordingly, any conventional arrangement of elements can be combined together to facilitate manufacture and assembly of the production equipment 30.
Again, the bore seals 50a-c can include polished bores for engaging seals of lift equipment (not shown) disposed therein. In some implementations, the bore seals 50a-c may include seal rings, nipples, latch profiles, seats, and the like for engaging the lift equipment (not shown) removably disposed in the equipment's throughbore 32.
At the uphole end, the production equipment 30 includes the gas lift valve 100. Typically, the gas lift valve 100 can be an external valve positioned on a tubing mandrel for controlling communication from the casing annulus 14 into the tubing mandrel, which communicates with production throughbore 32. Such an external gas lift valve 100 can be installed at surface and run downhole with the production equipment 30. As an alternative, a side pocket mandrel can be disposed on the production equipment 30 and can hold a removable gas lift valve 100 therein. These and other forms of gas lift valves 100 can be used. Moreover, although only one gas lift valve 100 is shown, a given implementation may have multiple gas lift valves 100 along the production equipment 30.
As will be appreciated with the benefit of the above description, the bottom hole assembly 20 of
Other forms of isolation can be provided for the production port 34 as well as the bypass 40. In another modification depicted in
In yet another modification depicted in
Finally, in the embodiment depicted in
As shown in
The foregoing description of preferred and other embodiments is not intended to limit or restrict the scope or applicability of the inventive concepts conceived of by the Applicants. It will be appreciated with the benefit of the present disclosure that features described above in accordance with any embodiment or aspect of the disclosed subject matter can be utilized, either alone or in combination, with any other described feature, in any other embodiment or aspect of the disclosed subject matter.
In exchange for disclosing the inventive concepts contained herein, the Applicants desire all patent rights afforded by the appended claims. Therefore, it is intended that the appended claims include all modifications and alterations to the full extent that they come within the scope of the following claims or the equivalents thereof.