Background

[0001] This disclosure relates to the field of pumping systems for deep oil-, gas and water transporting wellbores. More specifically, the present disclosure relates to describes a single-acting as well as a double-acting pump system where the main parts of the pump are replaceable without a need for retrieving tubulars in the wellbore to change out pump components.

[0002] A number of different types of pumps are known to be used in deep wellbores, for example sucker rod-driven pumps and electric submersible pumps. However, there is a need for a lower complexity pump that can be installed and retrieved by light well intervention, such as for example wireline, coiled tubing or self-positioning. See, for example, International Patent Application Publication No. WO/2012/170112.

[0003] There is also a need for wellbore pumps that do not utilize sucker rods reciprocated in the wellbore from the surface to the pump, particularly in highly inclined or deviated wellbores. In such wellbores, wear and tear on the sucker rods or production tubing may result in the need for frequent repairs.

[0004] Horizontal wellbores have become very common, and to achieve better fluid production rates and total fluid recovery, pumps are known to be placed into the horizontal section of such wellbores. Pumps using sucker rods are challenging in such conditions, mainly due to wear and tear as described above, but also due to differential pressure induced sticking between the sucker rods and the production tubing. A pump which does not use sucker rods to drive the pump clearly would have a number of advantages for such wellbore applications.

Brief Description of the Drawings

[0005] FIG. 1 shows an example embodiment of a wellbore tubing configured to receive a pump. The illustration is for a well producing gas, where the pump may be used to retrieve produced water accumulated in the bottom or the well. [0006] FIG. 2 illustrates a filter to prevent debris in a fluid entry into the pump can be installed by for example wireline, when the well has been completed with wellbore equipment as illustrated in FIG. 1. The filter is to be placed where the fluid intake to the pump is located, and would typically be deployed into the well by wireline or similar technique.

[0007] FTG. 3 illustrates an example embodiment of a pump shaft system with attached pistons installed into the wellbore, for example by wireline. The system can be locked in place into the preinstalled pump receiver.

[0008] FIG. 4 illustrates the shaft/pistons seal assembly of an example embodiment of a pump. A static piston seal is illustrated so that the inside of this can be understood, where a dynamic seal within the static piston seal can be observed.

[0009] FIG. 5 illustrates a wireline type plug installed above a fluid discharge port coupled to a tube transporting wellbore fluid to the surface. The area between the wireline plug and the top dynamic piston on the shaft/piston assembly creates a pump chamber for wellbore fluids to be pumped toward the surface.

[0010] FIG. 6 shows that by alternatingly pressurizing chambers above and below the static seal component, fluids trapped in the pump chambers will be pushed towards the surface through the discharge port and tube to surface.

[0011] FIGS. 7A and 7B show an example embodiment of a single acting pump with two power fluid lines and an extending lower rod.

[0012] FIG. 8 illustrates a variation of the pump system shown in FIGS. 7A and 7B that operates as a double acting pump.

[0013] FIGS. 9A and 9B illustrate a dual acting, dual power fluid line pump system.

[0014] FIG. 10 and FIG. 11 illustrate a single acting, dual power fluid line pump system in the upper and lower positions, respectively. This pump is not wireline replaceable.

[0015] FIG. 12 illustrates a hollow shaft pump that enables operation using only 1 power fluid line to drive the pump. Force required to return the dynamic pump element is obtained from the hydrostatic pressure of fluid in the well. By moving a standing valve to radial ports below a traveling valve along with a hollow shaft, the number of fluid lines required may be minimized.

[0016] FIGS. 13A, 13B, 13C and 13D illustrate a dual acting pump where a centrally located tube arrangement transports wellbore fluids from the pump intake to fluid compression chambers, whereafter fluid is discharged through a centrally located tube.

[0017] FIG. 14 illustrates a traveling piston and check valve system for the pump illustrated in FIGS. 13A through 13D.

[0018] FIGS. 15A and 15B illustrate a hydraulically operated pump having two power fluid lines extending to the pump from the surface

[0019] FIGS. 16A, 16B, 16C, 16D and 16E illustrate the sequential and repeated operation of the pump illustrated in FIGS. 15A and 15B.

[0020] FIGS. 17A, 17B and 17C illustrate a wellbore pump where produced fluids are discharged from the bottom of the pump, and where there is a function built in to dump any trapped gas from the pump chamber.

[0021] FIGS. 17D through 17H show additional features that may be used in some embodiments of a pump as shown in and explained with reference to FTGS. 17A, 17B and 17C.

[0022] FIG. 18 illustrates a pump as shown in FIGS. 17A through 17C, where the pump is extended by attaching a similar pump module below the pump of FIGS. 17A through 17C, thus doubling the fluid lift capacity of the pump.

[0023] FIG. 19 illustrates a pump as shown in FIG. 18 wherein a gas dump is provided for the hydraulic control lines.

Detailed Description

[0024] The present disclosure relates to a well pump where a production tubing forms the pump housing, while an inner pump system comprising, for example, pistons, check valves, etc., may be installed and retrieved by light well intervention. Such a well pump may provide significant cost savings in pump maintenance and repair. Such a pump may provide ready access to the wellbore below the pump for interventions such as well logging, among other intervention operations. This may be of particular interest for areas where heavy weight interventions, such as using a workover rig or the like to pull out and rerun the production tubing are very costly. Offshore small size production platforms, for example, may be one application where workover rig cost is important. Also, limited crane capacity, no cost efficient derrick available, etc., play a significant role in raising the cost. It should be noted that the pump described in this disclosure also can be deployed in a wellbore wherein the pump has an external housing, for example connected to the lower end of a tubular hung into the wellbore, where the tubular needs to be retrieved to surface to retrieve the pump.

[0025] Also, this disclosure describes variations of a hydraulic operated downhole pump, using one or two control lines from surface, as well as being single-acting and dual- acting.

[0026] The present disclosure also describes how trapped gas in a production fluid filled pump chamber can be released, to avoid or minimize risk of gas locking. In addition, the present disclosure describes how wellbore fluids can be kept and discharged from an area below a dynamic seal, to minimize exposure of seals and sealing area to abrasive particles, sand and debris.

[0027] FIG. 1 shows an example embodiment of a wellbore tubing 110 configured to receive components of a well fluid pump. The components will be explained in more detail with reference to FIG. 3. In the present example embodiment, the wellbore 101 may be used for producing gas. The pump may be used to lift produced water accumulated proximate the bottom of the wellbore 101. This is generally referred to as gas well dewatering or gas well deliquification.

[0028] The wellbore 101 may comprise a casing or liner 100 to hydraulically isolate formations outside the casing or liner 100, and to maintain mechanical integrity of the wellbore 101. In the present example embodiment a liner 100 extends from the bottom of the wellbore 101 to above the bottom of a surface casing 104. Perforations 102 may be made in the liner 100 within a formation that produces hydrocarbons such as natural gas. The wellbore tubing 110 may extend to the surface of the wellbore 101. The wellbore tubing 110 may comprise segments ("joints") shown at 11 OA and HOB each having a polished interior surface for receiving the pump components (FIG. 3). The upper polished joint 11 OA has an internal diameter which may be substantially the same as all the tubing 110 above the upper polished joint 110A. The lower polished joint HOB may be a smaller internal diameter than the upper polished joint 11 OA. The tubing 110 may comprise gas inflow ports 106 at a longitudinal position above the pump components when such components are locked in place inside the polished joints 110A, HOB.

[0029] A hydraulic control line 116 may be mounted on the exterior of the wellbore tubing 110 and may extend from a source of pressurized hydraulic fluid (not shown) at the surface to each of two power fluid inflow ports 114. The power fluid inflow ports 114 are used to route hydraulic fluid under pressure to the pump components described with reference to FIG. 3, where pressurized hydraulic fluid drives a shaft/piston system (FIG. 3) to travel up and down, resulting in the pumping of fluids to the surface through a discharge tube 108 mounted externally on the tubing 110. The discharge tube 108 may extend to the surface. The "housing" for the pump comprises the upper 110A and lower HOB polished joints of tubing.

[0030] The polished joints 11 OA, HOB may comprise well fluid inflow ports 112 at a convenient location at the connection between the upper 11 OA and lower HOB polished joints. As shown in FIG. 2, the well fluid inflow ports 112 may comprise internal screens or filters 118 to assist in excluding solids in the wellbore fluid from being drawn into and possibly damaging the pump components.

[0031] It should be understood that the gas inflow ports 106 could be located higher up in the wellbore tubing than as illustrated in FIG. 1 and FIG. 2. FIG. 2 also shows a possible embodiment wherein an annular seal and liner hanger 120 is disposed in an annular space between the surface casing 104 and the liner 100. FIG. 2 also shows a possible embodiment wherein an annular space between the tubing 110 and the interior of the liner 100 is sealed by an annular seal or packer 122. The packer 122 may comprise through ports for the hydraulic control line 116 and the discharge line 108.

[0032] The filter 118 may be installed and retrieved by, for example wireline, when the well has been configured with wellbore equipment as illustrated in FIG. 1. In other embodiments, a filter may be incorporated within or externally on the well fluid inflow ports 112.

[0033] FIG. 3 illustrates the pump components, i.e., a pump piston and shaft assembly

300 that may comprise external seals. The pump piston and shaft assembly 300 may be installed into a receiving location within the polished tubing joints 11 OA, HOB, for example, by wireline or slickline. The pump piston and shaft assembly 300 may be locked in place into the prcinstallcd pump receiver system (i.e., polished tubing joints 11 OA, HOB by the component containing a static piston and seal 306. Methods and apparatus for locking a component into place in a wellbore are well known in the art. One example may be the use of "jarring" (striking axially downward onto the pump piston and shaft assembly 300 to lock the static piston 306 in place, as well as shear loose (such as by breaking shear pins) a piston shaft (301 in FIG. 4) from the static piston 306 so that the piston shaft (301 in FIG. 4) can travel up and down when hydraulic power fluid is applied to each of the power fluid inflow ports (114 in FIG. 1). In some embodiments, the piston assembly may not need to be mechanically locked in position, because the hydrostatic pressure above the piston 302 may be sufficient, in additional to hydraulically locking the shaft assembly 300 in place by pressurizing the areas between the lower three seal arrangements 304, 306 and 308.

[0034] FIG. 4 shows the piston and shaft assembly 300 in more detail. The static piston

306 and its associated internal 306A and external 306B seals is illustrated so that the function of the static piston 306 can be better understood. The internal seal 306 A enables the shaft 301 to move up and down within the static piston 306 while preventing movement of fluid across the static piston 306 between the static piston 306 and the exterior of the shaft 301. The shaft 301 may comprise a top dynamic piston 302 having an external diameter and external seals 302 A to engage the interior of the upper polished joint (110A in FIG. 1). The shaft may comprise an intermediate dynamic piston 304 having an external diameter and seals 304 A to sealingly engage an interior of the lower polished joint (HOB in FIG. 1). Between the top dynamic piston 302 and the intermediate piston 304, the shaft may comprise a transverse flow port 303 to enable entry of fluid from an annular space between the top dynamic piston 302 and the intermediate dynamic piston 304 and within the polished joints (110A, HOB in FIG. 1) into the transverse flow port 303. The transverse flow port 303 is in fluid communication with a longitudinal flow port 307 which extends through the top dynamic piston 302. A check valve 305, such as a ball and ball seat check valve may be disposed within the longitudinal flow port 307 to constrain movement of fluid through the top dynamic piston 302 to only one direction. A check valve (not shown) may also be implemented in or externally to the fluid intake ports (112 in FIG. 1), preventing wellbore fluids trapped between seal stack 302 and 304 from exiting back to the wellbore. A lower dynamic piston 308 with associated external seals 308A may be disposed on the shaft 301 at or proximate the bottom end of the shaft 301. Referring back to FIG. 3, when hydraulic fluid is pumped into the one of the power fluid inflow ports 114, for example, into the one of the power fluid inflow ports in communication with an upper annular space 311, pressure is exerted by the hydraulic fluid between the static piston 306 and the intermediate dynamic piston 304. The exerted pressure causes the shaft (301 in FIG. 4) to move upwardly. The top dynamic piston 302 moves correspondingly with the shaft (301 in FIG. 4). As the top dynamic piston 302 moves upwardly with the shaft (301 in FIG. 4), fluid in the wellbore tubing 110 above the top dynamic piston 302 is lifted because the check valve (305 in FIG. 4) will close. The lifted fluid may enter the fluid discharge tube 108 wherein the lifted fluid may move to the surface through the discharge tube 108. To reverse motion of the shaft (301 in FIG. 4), hydraulic fluid may be pumped into the lower power fluid inflow port 114 thereby pressurizing an annular space 313 longitudinally disposed between the lower dynamic piston 308 and the static piston 306. Such pressure in the annular space 313 causes the lower dynamic piston 308 to move downwardly; the shaft (301 in FIG. 4) moves correspondingly. As the shaft moves downwardly, fluid may enter the tubing 110 through the fluid inflow ports 112. [0036] FIG. 5 illustrates that a wireline type plug 500 may be installed above an entry port 108A to discharge tube 108, whereby all fluid moved upwardly by the top dynamic piston 302 is constrained to enter the discharge tube 108. The volume between the wireline plug 500 and the top dynamic piston 302 on the piston and shaft assembly 300 thereby creates a defined pump chamber for wellbore fluids to be pumped towards the surface. The fluid discharge port 108A or discharge tube 108 may also be coupled to a check valve, preventing wellbore fluids flowing back to the wellbore fluid chamber between the wireline plug 500 and the top piston 302.

[0037] FIG. 6 shows that by alternatingly pressurizing the annular spaces above 313 and below 311 the static piston 306, the piston and shaft assembly 300 may be caused to move upwardly and downwardly, thereby alternatingly enabling well fluid to flow into the annular space between the intermediate dynamic piston 304 and the top dynamic piston 302, and moving the fluid into the discharge tube 108. As liquid is removed from the wellbore by operating the piston and shaft assembly 300 as explained above, the hydrostatic pressure bearing against the formation adjacent to the perforations 102 is correspondingly reduced. Reducing the hydrostatic pressure may enhance the capacity of the formation to produce gas at 504, wherein the gas may enter the tubing 110 through gas production ports 106 disposed above the plug 500. Such gas may enter the wellbore and flow upwardly in the annular space between the tubing 110 and the liner 100 (or casing if the wellbore is so configured.

[0038] FIGS. 7A and 7B show another example embodiment of a pump according to the present disclosure. The wellbore 101 may include a casing or liner 100 and a surface casing 104, similar to the wellbore shown in FIGS. 1 and 2. A wellbore tubing 110 may comprise well fluid inflow ports 112 and upper 11 OA and lower HOB polished joints of diameters as described with reference to FIG. 1. A pump piston and shaft assembly 700 may be inserted into the wellbore tubing 110 as explained with reference to FIGS. 3 and 4. In the present example embodiment there may be two hydraulic control lines 116A and 116B each having a respective power fluid inflow port 114 A, 114B. [0039] First referring to FIG. 7A, the pump piston and shaft assembly in the present example embodiment may comprise an upper shaft 701 coupled to a lower shaft 701 A. 'The lower shaft 701A may have a similar outer diameter as the shaft shown in FIG. 4. The lower shaft 701 A passes through a static piston 706 with internal and external seals substantially as explained with reference to FIG. 4. The static piston 706 may be positioned in the tubing 110 such that the power fluid inflow ports 114A, 114B are disposed on opposed sides of the static piston 706. An intermediate dynamic piston 704 may be secured to the upper end of the lower shaft 701 A. When power fluid (e.g., hydraulic fluid) is applied alternatingly to the power fluid inflow ports 114A, 114B, hydraulic pressure acts to move the intermediate dynamic piston 704 (and the lower shaft 701 A and upper shaft 701) upwardly, or the lower dynamic piston 708 (and the lower shaft 701 A and upper shaft 701) downwardly. Motion of the lower shaft 701 A and upper shaft 701 is used to move an upper dynamic piston 702 which may be configured substantially as explained with reference to the upper dynamic piston explained with reference to FIG. 4. In FIG. 7A, power fluid is applied to the upper power fluid inflow port 114B, and the intermediate dynamic piston 704 is moved upwardly as the power fluid pressurizes an upper annular space 713. As the upper dynamic piston 702 moves upwardly with the upper shaft 701, fluid may be moved through a check valve 705 disposed in the tubing 110 above the piston and shaft assembly 700. Thus in the embodiment of FIG. 7 A and 7B, pumped fluid may be lifted through the tubing 110 to the surface. At the same time, one or more integral check valve(s) 702A in the upper dynamic piston may close, thereby enabling wellbore fluid to be drawn into the wellbore fluid chamber between the upper piston 702 and the intermediate piston 704 below.

[0040] FIG. 7B shows the embodiment of FIG. 7A wherein power fluid is applied through hydraulic control line 116A and into the lower power fluid inflow port 114 A, the hydraulic fluid pressure acts against the lower dynamic piston 708, causing a lower annular space 711 to expand as the lower dynamic piston 708 is moved downwardly against the hydraulic fluid pressure. The lower shaft 701 A and upper shaft 701 move downwardly corresponding to the downward motion of the lower dynamic piston 708. [0041] Another example embodiment of a pump which is dual acting is shown in FIG. 8.

The wellbore 101 may be configured with a liner 100, tubing 110 and surface casing 104 substantially as explained with reference to FIG. 1. A piston and shaft assembly 800 may be inserted into and locked in place within the tubing 110 substantially as explained with reference to FIG. 3. The piston and shaft assembly 800 may comprise a shaft 801, an upper dynamic piston 802, an intermediate dynamic piston 804, a static piston 806 and a lower dynamic piston 806 similar in configuration to the shaft and piston assembly as explained with reference to FIGS. 3 and 4.

[0042] The fluid discharge line 108 in FIG. 8 may comprise an upper inflow port 808 A disposed longitudinally through the tubing 110 at a position just below the place within the tubing 110 wherein a dual opposed-polarity check valve 816 is disposed. The check valve 816 may be run into and set in place in the tubing 110, for example, by wireline or slickline. One discharge port of the check valve 816 is aligned with the upper inflow port 808A. One inlet port of the check valve 816 is aligned with a well fluid inflow port 809 coupled to an external well fluid inflow line 809A. A lower fluid inflow port 808B of the fluid discharge line 108 may penetrate the tubing 110 at a position just above the well fluid inflow ports 112. The lower fluid inflow port 808B may comprise a check valve 817 so that fluid flow is constrained to move only into the discharge line 108 by the action of the piston and shaft assembly 801 As power (hydraulic) fluid is alternatingly pumped into each of the power fluid inflow ports 114, annular spaces 811, 813 on opposed sides of the static piston 806 are alternatingly pressurized, thereby causing the piston and shaft assembly 801to move alternatingly upwardly and downwardly. Upward motion of the piston and shaft assembly 801 causes a first volume 822 disposed below the upper dynamic piston 802 to expand, thus drawing well fluid into the volume 822 through the well fluid inlet ports 112. At the same time, a second volume 820 between the upper dynamic piston 802 and the check valve 816 contracts, thus displacing the wellbore fluid in the second volume 820 through the check valve 816 and into the discharge line 108 through the upper fluid inflow port 808 A.

[0043] When motion of the piston and shaft assembly is reversed, the second volume 820 expands, thereby drawing wellbore fluid into the second volume 820 through the well fluid inflow port 809 from the well fluid inflow line 809A. Correspondingly, the first volume 822 decreases, thereby causing check valves 821 in the well fluid inflow ports 112 to close. The fluid is thus constrained to be moved into the discharge line 108 through the lower well fluid inflow port 808B. The check valve 816 prevents backflow of discharged well fluid through the upper well fluid inlet port 808A, thus the discharged wellbore fluid is constrained to move upwardly through the discharge line. Gas produced from the formation may enter the wellbore through gas production ports 106, substantially as explained with reference to FIG. 6. Another example embodiment of a well pump is shown in FIG. 9 A. FIG. 9 A, the pump piston and shaft assembly in the present example embodiment may comprise an upper shaft 901 coupled to a lower shaft 901 A. The lower shaft 901 A may have a similar outer diameter as the shaft shown in FIG. 4. The lower shaft 901 A passes through a static piston 906 with internal and external seals substantially as explained with reference to FIG. 4. The static piston 906 may be positioned in the tubing 110 such that the power fluid inflow ports 114 A, 114B are disposed on opposed sides of the static piston 906. An intermediate dynamic piston 904 may be secured to the upper end of the lower shaft 901 A. When power fluid (e.g., hydraulic fluid) is applied alternatingly to the power fluid inflow ports 114A, 114B, hydraulic pressure acts to move the intermediate dynamic piston 904 (and the lower shaft 901 A and upper shaft 901) upwardly, or the lower dynamic piston 908 (and the lower shaft 901 A and upper shaft 901) downwardly. Motion of the lower shaft 901 A and upper shaft 901 is used to move an upper dynamic piston 902 which may be configured substantially as explained with reference to the upper dynamic piston explained with reference to FIG. 7. In FIG. 9A, power fluid is applied to the upper power fluid inflow port 114B, and the intermediate dynamic piston 904 is moved upwardly as the power fluid pressurizes an upper annular space (713 in FIG. 7A). As the upper dynamic piston 902 moves upwardly with the upper shaft 901, a second volume 920 between the upper dynamic piston 902 and the check valve 905 contracts, such that wellbore fluid may be moved through a check valve 905 disposed in the tubing 110 above the piston and shaft assembly 900. Thus in the embodiment of FIG. 9A, pumped fluid may be lifted through the tubing 110 and into an upper fluid discharge line inflow port 908A. The upper dynamic piston 902 may comprise integral check valve(s) 902A such that when the second volume 920 contracts, and a volume below the upper dynamic piston 902 expands, well fluid may be drawn into the volume below the upper dynamic piston through the well fluid inflow ports 112. The drawn in wellbore fluid moves past the upper dynamic piston 902 into the second volume 920 through the integral check valve(s) 902A to be discharged through the check valve 905 and into the tubing 110 as explained above.

[0045] As the piston and shaft assembly 900 is moved downwardly, a first volume 922 disposed between the lower dynamic piston 908 and a dual check valve sub 909 contracts. Fluid in the first volume 922 is constrained by the dual check valve sub 909 to move into the well fluid discharge line 108. In the present example embodiment, the well fluid discharge line 108 extends to a discharge fluid port 908 A in the tubing 110 above the position of the check valve 905. When the piston and shaft assembly 900 moves upwardly, the first volume 922 expands, thus drawing wellbore fluid into the first volume through the dual check valve sub 909. Accordingly, the example embodiment of the wellbore pump shown in FIG. 9A is dual acting.

[0046] FIG. 9B shows another embodiment of a wellbore pump similar to that shown in

FIG. 9A. The embodiment of FIG. 9B comprises a well fluid discharge sub (with integral check valve) 909A coupled to the exterior of the tubing 110 such that discharged fluid from the contracting first volume (922 in FIG. 9A) moves into the well fluid discharge line 108. When the first volume (922 in FIG. 9A) expands, wellbore fluid may be drawn into the first volume through a replaceable (e.g., by wireline or slickline) intake check valve 909B disposed in the tubing 1 10 below the lower dynamic piston (908 in FIG. 9A). In other respects, the wellbore pump shown in FIG. 9B works substantially the same as the wellbore pump shown in FIG. 9A, but enables full bore through tubing access with wireline or slickline tools, etc. by having all pump components and check valve assemblies retrievable by, e.g., wireline or slickline first.

[0047] FIGS. 10 and 11 show another embodiment of a hydraulically operated wellbore pump that may be retrofit into an existing wellbore casing. A pump piston 1009 moves upwardly and downwardly inside a pump housing 1001. An inlet to a pump chamber formed between the pump piston 1009 and the housing 1001 is shown at 1002. A check valve 1008 closes on downward movement of the pump piston 1009 and opens on upward movement thereof. Well fluid may enter the pump 1000 through a check valve controlled fluid inlet 1002. Power fluid may be alternatingly applied to two power fluid ports 1004, 1006 to create pressure on opposed sides of a power piston 1014. The power piston may be coupled to the pump piston 1009 through an operating rod 1012. Thus, reciprocation of the power piston 1014 results in reciprocation of the pump piston 1009, thereby lifting wellbore fluid upwardly toward the surface. FIG. 10 shows the pump 1000 in its downstroke end position. FIG. 11 shows the pump 1000 in its upstroke position.

[0048] FIG. 12 shows his shows a single power line hydraulic pump which uses hydrostatic head of the fluid column to return the dynamic pump assembly (power piston 1014 and operating rod 1012) down. Well fluid path is the same as for the pump shown in FIG. 10 and FIG. 11. Due to the location of the standing valves and a hole 1012A in the operating rod 1012, an additional area and therefore force helps to push the power piston 1014 downward when hydraulic control pressure is relieved from the power fluid inlet port 1006.

[0049] FIGS. 13A through 13E show another example embodiment of a hydraulically operated wellbore pump. In the present example embodiment, and with reference to FIG. 13 A, the wellbore pump 1300 may be coupled at one longitudinal end to a lower end of a wellbore tubing 1302. The wellbore tubing 1302 may be jointed tubing, coiled tubing or any other suitable conduit for conducting pumped fluids 1301 from a wellbore (e.g., 101 in FIG. 1) to the surface. A tubing extension 1302A may be coupled to the other longitudinal end of the wellbore pump 1300.

[0050] The wellbore pump 1300 may be attached to the lower end of the wellbore tubing

1302 by an adapter or crossover sub 1304. The crossover sub 1304 may be connected to one end of a pump housing 1300A. The other end of the pump housing 1300 A may be coupled to one end of a pump power chamber 1305. The pump power chamber 1305 may comprise a power chamber cylinder 1305 A coupled to a lower end of the pump housing 1300A by an upper power chamber adapter 1324A. A lower end of the power chamber cylinder 1305 A may be coupled to a tubing extension 1302 A by a lower power chamber adapter 1324B. The tubing extension 1302A may comprise fluid inflow ports 1307 disposed at an axial position above the lower end of a fluid intake tube 1306 A.

[0051] The pump power chamber 1305 may comprise a power piston 1310 that sealingly engages an interior wall of the pump power chamber cylinder 1305 A. Hydraulic fluid under pressure may be provided alternatingly to each of a lower hydraulic control line 1318A coupled to the pump power chamber cylinder 1305 A to a position below the power piston 1310. In the present example embodiment, hydraulic fluid pumped through the lower hydraulic control line 1318A may enter the pump power chamber cylinder 1305 A through a lower power fluid inlet 1318B coupled to suitable passageways formed in the lower power chamber adapter 1324B. Correspondingly, an upper hydraulic control line 1316A may provide pressurized hydraulic fluid to a position above the power piston 1310, for example, through an upper power fluid inlet 1316B with suitable fluid passageways formed unto the upper power chamber adapter 1324A.

[0052] The fluid intake tube 1306A may sealingly pass through the power piston 1310 and be attached to the power piston such that movement of the power piston 1310 as a result or pressurizing each of the hydraulic control lines 1316A, 1318A will cause the fluid intake tube 1306A to move correspondingly. FIG. 13A shows the power piston 1310 in the downwardmost position.

[0053] The fluid intake tube 1306A may be attached to a pump piston 1308 disposed in the pump housing 1300 A. The pump piston 1308 may divide the interior of the pump housing 1300 A into an upper pump chamber 1301 A and a lower pump chamber 130 IB.

[0054] When hydraulic fluid 1317 is supplied to the upper hydraulic control line 1316A, causing the power piston 1310 to move downwardly, the intake tube 1306 A and the pump piston 1308 move correspondingly, thereby decreasing the volume of the lower pump chamber 130 IB. The pump piston 1310 may comprise internal fluid passages 1308C and check valves 1308A, 1308B, 1308D arranged such that downward motion of the pump piston 1310 will cause fluid in the lower pump chamber 130 IB to move into the passages 1308C in the pump piston 1310 and to be discharged through an upper discharge tube 1306. The upper discharge tube 1306 may extend longitudinally through the crossover sub 1304 and be sealingly engaged with the crossover sub 1304. Fluid 1301 discharged through the upper discharge tube 1306 may be constrained to move upwardly through the wellbore tubing 1302 by the action of a check valve 1304 A in the crossover sub 1304.

[0055] Conversely, when the power piston 1310 is caused to move upwardly by application of hydraulic power fluid 1317 to the lower power fluid inlet 1318B, the fluid intake tube 1306A, power piston 1310, pump piston 1308 and upper discharge tube 1306 move correspondingly. Thus, the upper pump chamber 1301 A volume decreases. One of the check valves 1308A in the pump piston 1308 constrains the fluid in the upper pump chamber 1301 A from entering the upper discharge tube 1306. At the same time, the fluid in the upper pump chamber 1301 A may move through the check valve 1304A in the crossover sub 1304 and thus move into the wellbore tubing 1302. As the lower pump chamber 1301B expands correspondingly, other check valves 1308D, 1308B in the pump piston 1310 enable wellbore fluid to be drawn into the lower pump chamber 130 IB through the fluid intake tube 1306 A.

[0056] By positioning well fluid inlet ports 1307 in the tubing extension 1302A above the position of the fluid intake tube 1306A, a solids trap 1320 may be formed. Solids may tend to settle by gravity and thus may be largely excluded from entering the fluid intake tube 1306A. A guide nose 1322 may be used on the end of the tubing extension 1302A in some embodiments.

[0057] FIG. 13B shows the power piston 1310 being moved upwardly and corresponding discharge of wellbore fluid from the upper pump chamber 1301 A through the check valve 1304A in the crossover sub 1304 and into the wellbore tubing 1302.

[0058] FIG. 13C shows the power piston 1310 close to its upwardmost position. FIG.

13D shows the power piston 1310 being moved downwardly, with corresponding discharge of fluid from the lower pump chamber 130 IB into the upper discharge tube 1306, and thus into the wellbore tubing 1302.

[0059] FIG. 14 shows the pump piston 1308 of the present example embodiment in more detail. The pump piston may comprise a fluid passageway 1308E to the fluid intake tube 1306A, wherein check valves 1308A, 1308D constrain movement of fluid from the fluid intake tube 1306 A to flow into the upper pump chamber 1301 A or the lower pump chamber 1301B depending on which pump chamber is expanding. A fluid passage 1308F connects the upper discharge tube 1306 using a check valve 1308B to the upper pump chamber 1301 A when its volume is reduced, thus moving wellbore fluid in the upper pump chamber 1301 A into the upper discharge tube 1306. Correspondingly, downward movement of the pump piston 1310 will cause the check valves 1308 A, 1308B, 1308D to move fluid from the lower pump chamber 1301B through the pump piston 1308 and into the upper pump chamber 1301 A, where the fluid will be discharged through the check valve 1304A in the crossover sub 1304.

[0060] Another embodiment of a hydraulically operated pump is shown in FIGS. 15A and 15B. Referring to FIG. 15A, a pump power piston and pump piston assembly 1500 is shown and includes a piston rod 1500B having fluid seals 1500A disposed at a longitudinal position intermediate an upper pump piston 1502 having seals 1502 A on its exterior surface and a lower pump piston 1 04 having seals on its exterior surface 1504 A coupled to the longitudinal ends of the piston rod 1500B.

[0061] FIG. 15B shows the pump power piston and pump piston assembly 1500 disposed in a pump body 1510 to form a wellbore fluid pump 1530. The pump body 1510 includes an upper cylinder 1 18A and a lower cylinder 1518B disposed on opposed longitudinal sides of a center passage 1510A through which the piston rod 1502 may move. Movement of the pump power piston and pump piston assembly 1 00 within the pump body 1510 may be caused by pumping hydraulic fluid under pressure through a first control line 1516A that connects to the upper cylinder 1518A between the fluid seals 1500A and the bottom of the upper piston 1502. Correspondingly, motion of the pump power piston and pump piston assembly in the other direction may be caused by supplying hydraulic fluid under pressure to the lower cylinder 1518B through a second control line 1516B.

[0062] Each of the upper pump piston 1502 and the lower pump piston 1504 may comprise wiper seals, 1502A and 1504B, respectively. Longitudinal ends of the pump body 1510 and the corresponding pump pistons 1502, 1504 may define an upper pump chamber 1510A and a lower pump chamber 1510B. A fluid intake for the lower pump chamber 1510B may be provided through a check valve 1520 which will admit fluid to the lower pump chamber 1510B when it is expanded. The check valve 1520 may cause fluid to be constrained to move through a discharge line 1 18, through a check ball 1514 and into the wellbore tubing 110. Correspondingly, the upper pump chamber 1510A may have a fluid intake line 1522 and a discharge through a port 1512 having a check ball 1512A therein. Enlargement and reduction of the volume of the upper pump chamber 1 10A by corresponding motion of the upper piston 1502 will cause fluid to be drawn into the upper pump chamber 151 OA and discharged therefrom, respectively.

[0063] FIGS. 16A through 16E show the wellbore fluid pump 1530 explained with reference to FIGS. 15 A and 15B in various stages of its operation to illustrate the operation of the wellbore fluid pump 1530. In FIG. 16A, the power piston and pump piston assembly (1500 in FIG. 15 A) is being moved downwardly by the action of hydraulic fluid. Arrows show the respective movements of fluid into, through and out of the sections of the wellbore fluid pump 1530 as explained with reference to FIG. 15B. FIG 16B shows the wellbore fluid pump power piston and pump piston assembly (1 00 in FIG. 15 A) continues to be moved downwardly by the action of hydraulic fluid. In FIG. 16C, the power piston and pump piston assembly (1500 in FIG. 15A) is at its lowermost position. FIG. 16D shows the power piston and pump piston assembly (1500 in FIG. 15 A) being moved upwardly by the action of hydraulic fluid under pressure. Finally, FIG. 16E shows the power piston and pump piston assembly (1500 in FIG. 15A) again in its upwardmost position.

[0064] FIG. 17A through 17C illustrate a wellbore fluid pump where produced fluids are discharged from the bottom of the pump, and where there is a function built in to dump any trapped gas from the pump chamber. This pump design may also ensure that solids, e.g., debris and sand within the produced fluids are kept below dynamic pump piston areas to increase the lifetime of fluid pressure seals and the surrounding sealing surfaces. A travelling power piston has a bore through it from its lower end and a relief valve included in the top of the power piston. In the case of gas being trapped within the wellbore fluid pump chamber, hydraulic power fluid pressure on the one of the control lines used to move the power piston upward in its bore is increased to a pressure higher than ordinary operating pressure after the power piston reaches the upper end of the piston bore. This increased pressure lifts the relief valve followed by opening a valve in a pump coupling disposed above the pump chamber, causing any trapped gas to exit from the pump chamber, through the piston assembly and the relief valves, and then into the tubular above the pump.

[0065] Referring first to FIG. 17A the wellbore fluid pump 1700 may comprise a pump housing 1706. The pump housing 1706 may have a substantially cylindrical bore 1706A on its interior surface. An upper end of the pump housing 1706 may be coupled to a wellbore tubing 110 by an upper adapter 1704. The upper adapter 1704 may comprise a seat 1714A for a ball type check valve 1714. The upper adapter 1704 may comprise an internal passage 1704B formed therein which connects a pumped fluid discharge line 1712 to the interior of the ball seat 1714A. When fluid is discharged through the pumped fluid discharge line 1712, such fluid flows through the internal passage 1704B to the ball seat 1714A and then flows upwardly through the wellbore tubing 110 to the surface.

[0066] A power chamber may be defined within the pump housing 1706 longitudinally between the connection of the pump housing 1706 to the upper adapter 1704, and a power fluid inlet port 1717 through the wall of the pump housing 1706. A part of the pump housing 1706 corresponding to the power chamber may have an enlarged internal diameter section 1706A corresponding to the length of the power chamber. A piston 1710 may be disposed within the pump housing 1706. An upper end of the piston 1710 may be in fluid communication with hydraulic power fluid that is moved under pressure into the pump housing 1706 above the top of the piston 1710 through a power fluid passage 1704C in the upper adapter. A first hydraulic control line 1716A is coupled to the power fluid passage 1704C to enable moving the piston 1710 downwardly in the pump housing 1706 by applying power fluid, e.g., hydraulic fluid under pressure to the power fluid passage 1704C. The bottom end of the piston 1710 may comprise a wiper 1720 or similar fluid seal. A pump chamber 1708 may be defined between the bottom end of the piston 1710 within the pump housing 1706 and a lower adapter 1720 coupled to the lower end of the pump housing 1706.

[0067] The lower adapter 1720 may include an intake check valve 1720A and a discharge check valve 1720B. As indicated by the arrow in the pump chamber 1720, when the piston 1710 is moved downwardly, the pump chamber decreases in volume and fluid flow opens the discharge check valve 1720B wherein discharged fluid enters the fluid discharge line 1712 and eventually into the wellbore tubing 110 through the upper adapter 1704 as explained above. The intake check valve 1720A closes during downward movement of the piston 1710. When hydraulic fluid under pressure is moved through a second hydraulic control line 1716B to the lower power fluid inlet port 1717, the piston 1710 is moved upwardly by such hydraulic fluid pressure. As the piston 1710 is moved upwardly, the intake check valve 1720 A opens and the discharge check valve 1720B closes, enabling wellbore fluid to be drawn into the pump chamber 1720 by increasing the volume of the pump chamber 1720.

[0068] The piston 1710 has a bore 1710B through it from its upper end to a position on the exterior surface of the piston below dynamic seals 17 IOC on the piston 1710. The bore comprises a relief valve 1710A in the bore 1710B proximate the top of the piston 1710. In the case of gas being trapped within the power chamber, hydraulic power fluid pressure on second control line 1716B (used to move the piston 1710 upward in the pump housing 1706) is increased to a pressure higher than ordinary operating pressure after the piston 1710 reaches the upper end of the pump housing 1706. This increased pressure lifts the relief valve 1710 followed by opening a corresponding relief valve 1704 A in the upper adapter 1704, causing any trapped gas to exit from the power chamber, through the piston 1710 and the relief valves 1710A, 1704A, and then into the tubular, e.g., the tubing 110 above the upper adapter 1704. [0069] FIG. 17B shows the piston 1710 being moved downwardly by applying hydraulic fluid under pressure to the first control line 1716A to discharge fluid from the pump chamber 1720. FIG. 17C shows the piston 1710 at its downwardmost position, whereupon hydraulic fluid under pressure is provided to the second control line 1716B to cause the piston 1710 to move upwardly. Upward movement of the piston 1710 will expand the pump chamber 1720 to draw wellbore fluids into the pump chamber 1720 through the intake check valve 1720 A.

[0070] In some embodiments, a guide nose 1720C may be coupled to the bottom of the lower adapter 1720.

[0071] Additional features of a well fluid pump as explained above with reference to

FIGS. 17A through 17C will now be explained with reference to FIGS. 17D through 17H.

[0072] Referring first to FIG. 17D, hydraulic control pressure applied to the power piston

1717 may be conducted to the radial clearance 1708B at the dynamic pump piston 1708. The hydraulic fluid may move through a hole 1708 A in the shaft 17 IOC and a small flow restriction device 1708D which allows a small volume of pressurised fluid to flow across the outer diameter of the pump piston 1708. The hydraulic fluid under pressure helps to flush any debris away from the pump cylinder bore 1708E and also act as a hydrostatic radial bearing. FIG. 17E shows a helical groove 1708F formed on the outer diameter of the pump piston 1708 to assist full cleaning of the pump cylinder bore 1708E.

[0073] Two different arrangements may be used in some embodiments. One embodiment may use a conventional metal plunger with only a metal to metal clearance. Some embodiments may use elastomeric seals or the like, located axially at each side of the discharge port, externally to the pump piston 1708.

[0074] Hydraulic fluid pressure feed to the clearance (1708B in FIG. 17D) may be on the downstroke to ensure positive pressure inside a seal chamber to ensure any solids are pushed out and therefore may help to decrease wear on the pump components. [0075] Referring to FIG. 17F, to improve reliability an intermediate seal chamber 1750 may be located between the power fluid chamber 1752 and pump chamber 1708. This provides clean fluid that acts as a further buffer to prevent contaminated fluid entering the power fluid chamber 1752 and associated components, including power piston 1710. A recirculation line located on the outer diameter of the pump allows fluid to recirculate during each stroke. An alternative arrangement uses gas in this chamber.

[0076] The recirculation line is shown at 1756 in FIG. 17G. The recirculation line 1756 may be formed in a chamber separation bulkhead 1758 disposed between the power fluid chamber (1752 in FIG. 17F) and the intermediate seal chamber 1750.

[0077] Referring to FIG. 17H, the power chamber 1752 in some embodiments may have a smaller diameter than the pump chamber 1708. This enables much lower flow pressure to the power fluid chamber 1752 and also helps with respect to fluid conduit sizes and friction loss due to power fluid flow. Surface pump requirements and cost are major factors in the design.

[0078] FIG. 18 shows a pump 1800 as illustrated in FIG. 17A, where the pump 1800 is extended by adding a second pump 1800A configured as explained with reference to FIG. 17A. Such addition may be made by substituting the lower adapter (1720 in FIG. 1) with another upper adapter 1804A (as explained with reference to FIG. 17A) on the bottom of the pump housing 1806. The second pump 1800A may be connected to the second upper adapter 1804A. The bottom of the second pump housing 1806A may have a lower adapter 1820 attached thereto as explained with reference to FIG. 17A. Such arrangement will double the fluid lift capacity of the pump. Also the lower chamber incorporates a trapped gas release function as described with reference to FIG. 17A. One or several additional pumps as illustrated can be coupled the same way (using additional upper adapters) in series below the upper pump 1800 for further fluid lift capability.

[0079] FIG. 19 illustrates a pump similar to the pump as explained with reference to

FIGS. 17A, 17B and 17C, where produced wellbore fluids are introduced into a chamber below a traveling piston. FIG. 19 illustrates that in the case where it is detected, determined or suspected that gas is trapped in a wellbore fluid chamber (1708 in FIG. 17A), both the second control line (1716B in FIG. 17A) as well as the first control line (1716A) can be pressurized at the same time. Such pressurization will cause a high pressure bleed valve 1822, set to an opening pressure larger than maximum operating pressure for moving the main pump piston (1710 in FIG. 17A), to open a bleed port from where the gas is present, to the outside of the pump.

[0080] The foregoing function can be implemented with the pump piston pushing wellbore fluids down as illustrated in FIG. 19, as well as in pumps with a piston that push wellbore fluids upwards.

[0081] Also illustrated is a function where pump power fluid can be used to flush clean the wellbore fluid chamber, by pressurizing the first control line (1716A in FIG. 17A) at a higher pressure than the pump operating pressure, so that a valve 1903 within the pump piston 1710 opens, allowing clean fluid at a high velocity to flow into the wellbore fluid chamber and exit through the discharge port. This valve 1903 can be mounted at any location in the piston 1710.

[0082] Although only a few examples have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the examples. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.

Claims

What is claimed is:

1. A wellbore pump, comprising:

a receptacle for a pump formed into a wellbore production tubing;

a pump comprising a seal engageable with an interior surface of the receptacle, the seal having a pump rod passing sealingly through the seal, the pump rod having a piston in sealing engagement with an interior of the tubing on each side of the seal;

a power fluid line having hydraulic connection to an interior of the production tubing above and below the seal;

a well fluid inlet port disposed between one of the pistons; and

a longitudinally spaced apart check valve disposed in the wellbore production tubing above an upper one of the pistons.

2. The wellbore pump of claim 1 wherein the check valve is disposed in a piston connected to the pump rod.

3. The wellbore pump of claim 1 further comprising a fluid inlet check valve in sealing engagement with the well fluid inlet port.

4. The wellbore pump of claim 1 further comprising a filter covering the well fluid inlet port.

5. The wellbore pump of claim 1 further comprising a well fluid discharge line in fluid communication with the interior of the production tubing above the longitudinally spaced apart check valve.

6. The wellbore pump of claim 5 further comprising an additional check valve disposed in the production tubing above the well fluid discharge line.

7. The wellbore pump of claim 6 further comprising well gas inlet ports in the production tubing at a position above the additional check valve.