Discharge pressure actuated pump

[0001] This application is a continuation-in-part application of: U.S. patent application Ser. No. 11/530,848, filed Sep. 11, 2006, the entirety of which is incorporated herein by reference.

[0002] Embodiments of the invention are related to pumps and more particularly to single conduit pumps for use in locations remote from the pump's discharge including being located in wellbores, the pumps being actuated remotely such as by cycling pressure at the discharge of the pump.

[0003] Pumps are well known to move fluids from at least a first location to a second location. A large number of pump configurations are known, each with particular advantages and disadvantages and which may have been designed for particular uses in a variety of fluid-moving industries.

[0004] It is well known to provide pumping apparatus situated in subterranean wellbores for pumping fluid therefrom to the surface. Conventionally, a prime mover, such as an electric motor, has been located at the pump or mechanically connected thereto so as to permit actuation of pumps, such as a rod pump or progressive cavity pump, to lift liquids such as produced fluids and accumulated fluids therefrom. In the case of wellbores, particularly those situated in remote locations, it is desirable to situate the pump within the wellbore and to actuate the pump remotely. Typically, many of the pumps known in the art require two conduits, one to provide a motive force to operate the pump, such as in the case of hydraulic-actuated pumps, and the second to permit production of the fluids to surface.

[0005] In the case of said wellbores, it is known to provide remotely actuated pumps, such as those which are actuated by sonic or acoustic pressure waves (U.S. Pat. No. 4,295,799 to Bentley, U.S. Pat. No. 1,730,336 to Bellocq, U.S. Pat. Nos. 2,444,912, 2,553,541, 2,553,542, 2,553,543, and 2,953,095, to Bodine Jr.)

[0006] Further it is known to provide remotely actuated pumps which are actuated by alternately applying and releasing pressure at discharge of the pump. One such pump is taught in U.S. Pat. No. 4,390,326 to Callicoate which teaches an annular external piston and an internal piston movable in concentric annular and internal chambers. The internal chamber has an inlet end and an outlet end fit with one-way valves. The internal piston divides an internal barrel into a lower chamber and an upper chamber. The lower chamber has an inlet valve and an outlet valve through which pumped fluid is transferred to the upper chamber. The upper chamber has an outlet valve through which fluids are transferred into conduit thereabove. As the pump is stroked, fluid from below the pump is sucked into the lower chamber on the upstroke. On the downstroke, the fluid in the lower chamber is transferred to the upper chamber through the valve positioned therebetween. On the next upstroke, while fluid is being drawn into the lower chamber, the fluid in the upper chamber is transferred from the space above, through the upper chamber's outlet valve, while the external piston causes the fluid in the space above to be pumped to surface. Pressure is applied cyclically to the conduit causing the pistons to be moved downhole. An energy storing means, such as a spring, returns the pistons uphole as the pressure is relieved at the conduit discharge.

[0007] Remotely actuated pumps are particularly advantageous for use in oil wells to produce hydrocarbons to surface and for deliquification of gas wells, wherein the pump can be situated at or near the perforations, and can be actuated to pump accumulated liquids such as water and condensate, to the surface which, if left to accumulate in the conduit through which the gas is produced causes backpressure on the formation which impedes gas flow and which may eventually kill gas production.

[0008] In the case of deliquification of gas wells, conventionally beam pumps or hydraulic pumps, including piston downhole pumps and jet pumps have been used, as have electric submersible pumps and progressive cavity pumps however the cost of these pumps is relatively high. Regardless the use, providing power for actuation of such pumps in remote locations, size of the pumps and interference due to produced gas during use in deliquification have typically been problematic.

[0009] Further, other technologies such as foam lift, gas lift and plunger lift have been used to deliquify gas wells. In some of the known technologies, the gas well must be shut-in for at least a period of time to permit sufficient energy to be built up to lift the accumulated fluids which results in, at best, a cyclic production of gas from the wellbore.

[0010] Clearly, there is interest in a large variety of fluid-moving industries or technologies, including pumping apparatus, which have relatively low power requirements, are capable of being remotely actuated and which have a relatively high pumping efficiency. Of particular interest are pump apparatus for use in producing fluids from wellbores, including but not limited to deliquifying of gas wells to improve and maintain production therefrom.

[0011] Generally, a fluid apparatus for moving fluid from a fluid source to a discharge incrementally pumps a differential volume of fluid due to a chamber having a variable volume formed between two connected pistons which are moveable axially within a pump barrel of stepped diameter.

[0012] In a broad aspect of the invention, a fluid apparatus comprises: a pump barrel having a first barrel section in fluid communication with a fluid source and a second barrel section in fluid communication with a discharge conduit, the first barrel section having a diameter greater than the second barrel section, the first and second barrel sections being fluidly connected therebetween; a first piston housed in the first barrel section for axial movement therein; a second piston housed in the second barrel section for axial movement therein; means connecting between the first and second pistons for concurrent axial movement within the pump barrel between an inlet position and a discharge position, the first and second pistons being spaced apart for forming a chamber of variable volume therebetween; biasing means for biasing the first and second pistons to the discharge position; an inlet check valve to permit fluid to move from the fluid source to the variable volume chamber; and an outlet check valve to permit fluid to move from the variable volume chamber to the discharge conduit, wherein when an actuating pressure sufficient to overcome the biasing means is applied to the second piston through the discharge conduit, the outlet valve closes and the first and second pistons move to the inlet position and increase the variable volume chamber by a differential volume, opening the inlet valve and permitting the flow of the differential volume of fluid from the fluid source through the inlet valve into the variable volume chamber; and when the actuating pressure is released, the biasing means returns the first and second pistons to the discharge position for displacing the differential volume of fluid from the variable volume chamber, closing the inlet valve and opening the outlet valve for discharging the differential volume of fluid through the outlet valve to the discharge conduit.

[0013] In embodiments of the invention, the biasing means can be housed within the variable volume chamber or in the pump barrel below the first piston and is connected between the pump barrel and one of either the first or second piston.

[0014] The inlet and discharge valves are positioned at an inlet end and a discharge end, respectively, of the pump pistons or alternately at an inlet and discharge end of a bypass passageway fluidly connected to the variable volume chamber.

[0015] Embodiments of the invention are used to move fluid from a source location to a discharge location and may be particularly advantageous for remote actuation in wellbores for deliquifying wellbores having an accumulation of liquid therein which reduces or potentially stops wellbore production.

[0016] Therefore in another broad aspect of the invention, a method for producing accumulated liquids from a gas well comprises: positioning a fluid apparatus in the wellbore and forming an annulus therebetween, the apparatus having a pump barrel having a first barrel section in fluid communication with a fluid source and a second barrel section in fluid communication with a discharge conduit, the first barrel section having a diameter greater than the second barrel section, the first and second barrel sections being fluidly connected therebetween; a first piston housed in the first barrel section for axial movement therein; a second piston housed in the second barrel section for axial movement therein; means connecting between the first and second pistons for concurrent axial movement within the pump barrel between an inlet position and a discharge position, the first and second pistons being spaced apart for forming a chamber of variable volume therebetween; biasing means for biasing the first and second pistons to the discharge position; an inlet check valve to permit fluid to move from the fluid source to the variable volume chamber; and an outlet check valve to permit fluid to move from the variable volume chamber to the discharge conduit, wherein when an actuating pressure sufficient to overcome the biasing means is applied to the second piston through the discharge conduit, the outlet valve closes and the first and second pistons move to the inlet position and increase the variable volume chamber by a differential volume, opening the inlet valve and permitting the flow of the differential volume of fluid from the fluid source through the inlet valve into the variable volume chamber; and when the actuating pressure is released, the biasing means returns the first and second pistons to the discharge position for displacing the differential volume of fluid from the variable volume chamber, closing the inlet valve and opening the outlet valve for discharging the differential volume of fluid through the outlet valve to the discharge conduit; producing gas to surface through the annulus, liquid accumulating in the wellbore adjacent the distal end of the conduit; cyclically applying an actuating pressure at the discharge conduit such that when the force of the actuating pressure is greater than the force exerted by the biasing means and a force of pressure at the fluid source, the discharge valve operates to the closed position, the first and second pistons move to the inlet position and the inlet valve operates to the open position for charging the accumulated fluids from the wellbore into the variable volume chamber; and releasing the actuating pressure so that the first and second pistons are urged to return to the discharge position, the inlet valve moving to the closed position, the discharge valve moving to the open position and pumping the differential volume from the variable volume chamber through the discharge valve to the discharge conduit.

[0042] Embodiments of the invention are disclosed herein in the context of a fluid device, or pump, particularly useful in the production of fluids through a single discharge conduit extending from surface to a subterranean zone of interest. Description in this context is in no way intended to limit the scope of the invention to fluid devices for use in a subterranean wellbore, the device being equally applicable for remotely actuating and pumping fluids from any fluid source to a discharge in a variety of contexts, including from a sump, lake or pipeline.

[0043] Having reference to FIGS. 1A-1D, 2A-2D, 3A-3D, 4A, 4B, 5 and 6A-6D and in a wellbore context, a subterranean zone of interest or fluid source F (FIG. 5) is located remote from the surface where the fluid, such as a liquid, is to be produced. A discharge conduit 1 having a liquid discharge end 2 at surface 3 extends downhole to an inlet end 4 in fluid communication with the fluid source F. A fluid apparatus or pump 10, according to an embodiment of the invention, is fluidly connected at the inlet end 4 for pumping liquid from the fluid source F to surface 3 as a result of an actuating pressure P being applied to the discharge conduit 1, typically at surface 3.

[0044] Having reference to FIGS. 1A-1D and 2A-2D, the pump 10 comprises a pump barrel 11 having a first barrel section 12 and a second barrel section 13 the first and second sections 12,13 being fluidly connected therebetween. The first barrel section 12 is in fluid communication with the fluid source F and the second barrel section 13 is in fluid communication with the discharge conduit 1. A diameter of the first barrel section 12 is greater than the diameter of the second barrel section 13. A pump piston comprises a first piston 14 housed within the first barrel section 12 for axial movement therein, and a second piston 15 housed within the second barrel section 13 for axial movement therein. The first and second pistons 14,15 are connected therebetween and spaced apart by a connector such as a rod 16, forming a variable volume chamber 17 therebetween which changes volume as the pistons 14,15 are actuated to concurrently move axially within the barrel sections 12,13. As the pistons 14,15 move towards the first barrel section 12, the variable volume chamber 17 increases in volume and as the pistons 14,15 move towards the second barrel section 13, the variable volume chamber 17 decreases in volume.

[0045] More particularly, a differential volume is created when the connected pistons 14,15 are actuated to move toward the first larger diameter barrel section 12 which permits a larger volume of fluid to enter the variable volume chamber 17 than the chamber 17 will contain when the connected pistons 14,15 are subsequently actuated to move toward the second smaller diameter barrel section 13. Reciprocating movement or stroking of the pump pistons 14,15 in the pump barrel 11 creates the differential volume which is forcibly discharged from the variable volume chamber 17 to the discharge conduit 1 on each pump stroke.

[0046] More specifically, an inlet one way or check valve 18 is positioned at an inlet end 20 of the pump barrel 11 to permit the flow of fluid from the fluid source F into the variable volume chamber 17. A discharge one way or check valve 19 is positioned at a discharge end 21 of the pump barrel 11 to permit the flow of fluid from the variable volume chamber 17 to the discharge conduit 1.

[0047] Having reference again to FIGS. 1A-1D and 2A-2D and in one embodiment, the inlet check valve 18 is located in the first piston 14, and the discharge check valve 19 is located in the second piston 15. In one embodiment, the inlet check valve 18 and the discharge check valve 19 are ball valves.

[0048] In use, to actuate the pump 10, pressure is cyclically exerted at a discharge end 22 of the discharge conduit 1. The connected first and second pistons 14,15 are actuated to move from an idle position (FIGS. 1A, 2A, 3A and 6A) to a first inlet position (FIGS. 1B, 2B, 3B and 6B) wherein the first and second pistons 14,15 are moved toward the inlet end 20 of the pump barrel 11, typically a downhole movement in the context of a wellbore pump. To complete the pumping cycle, the first and second pistons 14,15 move to a second discharge position (FIGS. 1C, 2C, 3C and 6C), returning to the discharge end 21 of the pump barrel 11.

[0049] In the idle and discharge positions, fluid pressure at the inlet check valve 18 causes the inlet check valve 18 to close. As the first and second pistons 14,15 are moved to the first inlet position, the volume in the variable volume chamber 17 becomes larger. The inlet check valve 18 opens to permit fluid L from the fluid source F adjacent the inlet end 20 of the pump barrel 11 to be sucked into the variable volume chamber 17 through the inlet check valve 18.

[0050] Optionally, the inlet and discharge valves 18, 19 can form the pistons 14,15 which sealably engage the barrel 11 or the inlet and discharge valves 18,19 can be supported in a piston housing. As shown, each piston 18, 19 comprises a cylindrical housing 23 having ports 24 formed therein for conducting fluids from the inlet and discharge check valves 18, 19 through the pistons 14,15.

[0051] Biasing means 25 acting between the pump pistons 14,15 and pump barrel 11 to store energy as the first and second pistons 14,15 are moved downhole to the inlet position. Preferably, the biasing means 25 is a spring, pressurized bellows, elastomeric element or the like. As shown, examples of the spring 25 include a spring washer, such as a Belleville spring (FIGS. 1A-4A.), or, as schematically represented in FIG. 4B, a coil spring or as shown in FIGS. 6A-6D a compressible liquid spring.

[0052] Thus, when the force of the actuating pressure P applied to the discharge conduit 1 and acting at the second piston 15 exceeds the combined force of the pressure at a fluid source F and the spring 25 biasing, the pistons 14,15 are caused to move to the inlet position, typically downhole in the context of a wellbore. Release of the actuating pressure P permits the spring 25 to release stored energy and causes the pistons 14,15 to move to the discharge position, typically uphole in the context of a wellbore.

[0053] As the pistons 14,15 are caused to move to the discharge position, the volume of the variable volume chamber 17 becomes smaller resulting in a differential volume, being the difference in volume of the variable volume chamber between the inlet and discharge positions. The inlet check valve 18 is caused to close and as the volume of the variable volume chamber 17 becomes smaller, the discharge check valve 19 is opened and the differential volume is discharged into the discharge conduit 1. Cyclically repeating the application and the release of pressure P at the discharge end 22 of the discharge conduit 1, results in fluids being pumped from the fluid source F, through the pump 10 and into the discharge conduit 1 for eventual transport to a discharge 2, such as at surface 3.

[0054] In an embodiment of the invention a hydraulic circuit (not shown) may be used to apply actuating pressure P at the discharge end 22. Alternately, actuating pressure P may be applied using a positive displacement pump, such as a plunger pump (not shown).

[0055] In one embodiment of the invention shown in FIGS. 1A-1C, the biasing means 25 is housed in the pump barrel 11 between the first piston 14 and a stop 26 formed adjacent the inlet end 20 of the pump barrel 11. An inlet port 27 is formed in the stop 26 to permit fluid L from the fluid source F to enter the pump 10. As the pistons 14,15 are moved to the inlet position, the biasing means 25 is compressed by the pistons 14,15 against the stop 26, thereby storing energy in the biasing means 25. When the actuating pressure P is released at the discharge end 22 of the discharge conduit 1, the biasing means 25 acts between the stop 26 and the pistons 14, 15 to move the pistons 14,15 to the discharge position. Preferably, the biasing means is a spring 25.

[0056] In one embodiment as shown in FIGS. 2A-2C, the biasing means 25 is positioned in the variable volume chamber 17 between the second piston 15 and a stop 28 formed adjacent a lower end 29 of the second barrel section 13. One or more ports 30 are formed in the stop 28 to permit passage of the rod 16 and for the flow of fluids L therethrough between the first and second pump sections 12,13. Further, the rod 16 is hollow to aid in moving fluids from the inlet valve 18 to the discharge valve 19.

[0057] In one embodiment shown in FIGS. 3A-3D, the pump barrel 11 further comprises a bypass passageway 40 for forming a second chamber 41 which is fluidly connected to the variable volume chamber 17. The inlet valve 18 is positioned at an inlet end 42 of the second chamber 41 in fluid communication with the fluid source F. The discharge valve 19 is positioned at a discharge end 43 of the second chamber 41 in fluid communication with the discharge conduit 1. A port 44 is formed between the variable volume chamber 17 and the second chamber 41 and between the first and second pistons 14,15. As actuating pressure P is applied at the discharge end 22 of the discharge conduit 1 and the discharge valve is in the closed position, the pistons 14, 15 are caused to move to the inlet position and the inlet valve 18 is opened for admitting fluid L to the second chamber 41 and through port 44 to the variable volume chamber 17. As the actuating pressure P is released at the discharge end 22 of the discharge conduit 1, the inlet valve 18 is caused to close, the pistons 14,15 are biased to the discharge position by the biasing means 25 and the discharge valve 19 opens for discharging the differential volume of fluid from the second chamber 41 into the discharge conduit 1. Ports 24 are not required in the pistons 14,15 in this embodiment as fluid flow is directed through port 44.

[0058] The biasing means 25, like the previous embodiments, may be housed in the same manner in the variable volume chamber 17 or in the pump barrel 11 below the first piston 14.

[0059] As shown in FIGS. 6A-6D and in an embodiment of the invention wherein the biasing means 25 is a compressible liquid spring, the liquid spring comprises a sealed, pressurized spring chamber 50 which is operatively connected to the first and second pistons 14,15 for compressing and releasing a compressible fluid FC stored therein. One such suitable fluid FC is silicone however any compressible fluid may be used which is suitable to meet the desired design specifications.

[0060] In one embodiment shown in FIGS. 6A-6D, the sealed pressurized spring chamber 50 is formed within or in an extended portion of the pump barrel 11 and spaced below the first piston 14. An upper wall 51 of the spring chamber 50 comprises a port 52 through which a displacing element 53, such as a spring rod, protrudes, operatively connected to and extending downwardly from the first piston 14. The port 52 further comprises a chamber seal 54 which seals about the spring rod 53 which reciprocates therethrough. The inlet 27 for fluid communication with the fluid source F is formed in the first barrel section 12 between the first piston 14 and the upper wall 51 of the spring chamber 50.

[0061] Similarly, in embodiments of the invention, the spring 25 shown in FIGS. 2A-3D could be substituted with a compressible fluid FC, the second barrel portion 13 being sealed at the stop 28 for forming the pressure chamber 50, the compressible fluid FC being compressed upon movement of the first and second pistons 14, 15 to the inlet position.

[0062] As the first and second pistons 14,15 are caused to move to the inlet position, as previously described by cyclical application of pressure at surface, the spring rod 53 is moved into the fluid FC in the spring chamber 50 and acts to displace and compress the fluid FC sealed within the chamber 50, storing energy therein. As pressure is released at surface, the first and second pistons 14,15 are biased to the discharge position as a result of release of the energy stored in the fluid FC and acting upon the spring rod 53.

[0063] Actuation of the pump 10 is accomplished remotely through the application and release of pressure at the discharge 21 and therefore a prime mover is not required to be situated at or near the pump in the wellbore. Further, where a plurality of wells are situated in close proximity, the plurality of wells could be connected hydraulically to a single source of cyclic pressure for operating the plurality of wells.

[0064] Where the fluid source F is positioned substantially vertical and up to about a 60 degree inclination relative to the discharge 21, ball and seat valves are suitable for use as the inlet and discharge check valves 18,19. However, where the fluid source F is positioned substantially horizontal to the discharge 21, such as in a horizontal pipeline, spring loaded check valves may be more suitable for use as the inlet and discharge valves 18,19.

[0065] One particular use as shown in FIG. 5, wherein embodiments of the invention are particularly well suited, is the deliquification of gas wells. A distal end of a single conduit, such as a tubing string 114, is fit with a pump 110 according to an embodiment of the invention. The pump 110 is lowered into a wellbore 111 of a gas well and forms an annulus 112 between the conduit 114 and the wellbore 111. The discharge end 122 of the conduit 114 is positioned at surface 3. The pump 110 is positioned adjacent a zone of interest 115 where liquid L co-produced from the gas-producing formation accumulate and, which if left in the wellbore 111, would eventually hinder or stop gas production. Gas G is typically produced through the annulus 112 from the zone of interest 115 to surface 3. The inlet end 4 of conduit 114 is typically positioned below perforations in the zone of interest. The inlet end 4 of conduit 114 typically extends below the inlet end 20 of the pump 110 sufficient to urge the liquid L to enter the pump 110 while the gas G is directed to the annulus 112.

[0066] Actuation pressure P is cyclically applied and released at the discharge end 122 of the conduit 114 such as through a hydraulic circuit or a positive displacement pump. The actuation pressure P acts at piston 15 of the pump 110. The pump 110 is actuated, as discussed herein, to produce accumulated liquids L to surface 3 through the conduit 114 thereby reducing any hydrostatic head caused by the accumulation of the liquids L in the wellbore 111 and permitting production of the gas G through the annulus 112.

[0067] Actuation of the pump 110 can be continuous or intermittent. If operated continuously, the pump 110 removes even small accumulations of liquid L. Alternatively, the pump 110 can be operated intermittently on a fixed (similar to continuous) or a dynamically controlled periodic basis. Typically, a controller would activate the pump 110 either at regular predetermined intervals based on historical liquid accumulation for a particular reservoir type, or dynamically in response to a remote sensor which is able to sense a predetermined volume of fluid accumulation. In either case, actuation of the pump 110 would typically require very low power, such as can be provided by, for example, a natural gas powered engine in remote locations not accessible to a utility grid or using an electric motor where electricity is available. Further, an accumulator on a hydraulic circuit or a flywheel on a plunger pump drive may be used to conserve energy.

[0068] Mechanical Biasing Means

[0069] A variety of configurations of embodiments of the pump 110 disclosed herein have been modeled for use in wellbore casings of different diameter. Various configurations using Belleville springs are shown in Table A.

[0070] Embodiments of the invention using Belleveille springs as the biasing means may be more suitable for shallower pump applications to avoid excessive spring height required to achieve a desired stroke for deeper well pumps within the confines of the narrow pump diameter required for wellbore applications.

[0071]

TABLE A
	Units	1	2	3	4	5
Outlet barrel bore API	inches	1.5	2.25	1.5	2.25	1.5
Inlet barrel bore API	inches	2.25	2.75	2.75	3.25	3.25
Outlet barrel bore, metric	mm	38.1	57.15	38.1	57.15	38.1
Inlet barrel bore, metric	mm	57.15	69.85	69.85	82.55	82.55
Outlet barrel x-section area	mm2	1140	2564	1140	2564	1140
Inlet barrel x-section area	mm2	2564	3830	3830	5349	5349
Ratio of inlet to outlet areas		2.250	1.494	3.361	2.086	4.694
Depth of pump	m	500	500	500	500	500
Static head on pump w. water column	Bar	50	50	50	50	50
Static force on outlet piston	N	5695	12814	5695	12814	5695
Pressure applied at surface	Bar	80	90	130	150	100
(target ~3x static at pump)
Additional force on outlet piston	N	9112	23066	14808	38443	11391
Total force on outlet piston	N	14808	35880	20503	51258	17086
Ratio static to pressurized P at pump		2.60	2.80	3.60	4.00	3.00
Belleville spring #		D5025425	D633135	D63313	D80364	D80363
Height	mm	3.9	4.9	4.8	6.2	5.7
Thickness	mm	2.5	3.5	3	4	3
Cone height (H-t)	mm	1.4	1.4	1.8	2.2	2.7
# disks per stack		2	3	2	3	2
Height of one disk stack	mm	6.4	11.9	7.8	14.2	8.7
75% force, one stack	N	9063	15025	12356	21400	11919
75% force, stacked disks	N	18126	45075	25072	64200	23838
(max deflection)
75% deflection, one disk stack	mm	1.05	1.05	1.35	1.65	2.025
Static (initial) deflection	mm	0.330	0.299	0.307	0.329	0.484
One disk stack
Ratio, initial to 75% deflection		0.314	0.284	0.227	0.200	0.239
Total deflection with applied pressure	mm	0.858	0.836	1.104	1.317	1.451
Ratio, operating to 75% deflection		0.82	0.80	0.82	0.80	0.72
(target 80%)
Effective stroke one disk stack	mm	0.528	0.537	0.797	0.988	0.968
Target stroke length	mm	500	500	750	500	750
Volume of fluid pumped per stroke	mm3	712196	633063	2017889	1392739	3157403
Volume of fluid pumped per stroke	bbls/d	0.712	0.633	2.018	1.393	3.157
Cycles per minute		6.0	6.0	6.0	6.0	6.0
Volume of fluid pumped per day	m3/d	6.2	5.5	17.4	12.0	27.3
Volume of fluid pumped per day	bbls/d	38.8	34.5	109.8	75.8	171.9
# disk pairs to achieve target stroke		947	931	941	506	775
length
Total # disks		1894	2793	1882	1518	1550
Total disk height	mm	6062	11074	7337	7186	6743

[0072] As discussed above, the volume of the variable volume chamber 17 is greater when the pistons 14,15 are in the inlet position than when the pistons 14, 15 are in the discharge position. Various arrangements can result in this characteristic including the embodiments of FIGS. 1A-3D wherein the first piston 14 and first barrel section 12 have a larger diameter than the second piston 15 and second barrel section 13. A connecting rod 16 fixes the spacing of the first and second pistons 14,15. An advantage includes maximizing the barrel diameter for inserting into a wellbore or other annular constraint at the fluid source F.

[0073] Another example of an arrangement causing a differential swept volume includes replacing the fixed connecting rod 16 with an axial movement multiplier between the first and second pistons 14,15 such that the axial movement of the first piston 14 is augmented relative to the second piston 15. A simple mechanical lever with an offset fulcrum would suffice.

[0074] Further, the inlet and discharge valves 18,19 can be integrated with the pistons 14,15, as shown in FIGS. 1A-2C or as shown in FIGS. 3A-3C, one or both can be located in a second chamber 41 positioned along a sidewall of the pump barrel 11 and fluidly connected thereto through a port 44 between the first and second pistons 14,15 to the variable volume chamber 17 therebetween.

[0075] Compressible Liquid Biasing Means

[0076] As shown in FIGS. 6A-6D and in an embodiment of the invention, a liquid spring can be used as the biasing means 25.

[0077] A compressible fluid FC, such as silicone or any other suitable compressible fluid, may be used. In an embodiment of the invention, silicone was selected as it is a low viscosity fluid and is chemically inert, non-flammable and is thermally stable. An interpolation of available data was performed to determine compressibility of silicone under operating pressure of from about 70 barg (1015 psi) to about 415 barg (6020 psi), assuming approximately linear compressibility properties. The data is shown in FIG. 7.

[0078] Assuming an operating temperature of about 40° C. and the data shown in FIG. 7, the expected compressibility of silicone was determined to be about 0.0106% per bar of pressure to achieve a desired stroke of about 50 cm.

[0079] Based upon wellbore conditions, such as in a demanding 1000 m total vertical depth (TVD) well, generated pressures and expected displacements were calculated for both the static (input) and pressurized (discharge) positions as shown in Table B.

[0080]

TABLE B
Static condition (inlet position)
Rod compresses	5.717352	cc of fluid/cm
		of movement
Compressibility	0.010645	%/bar
Static pressure in coil	98.1	bar
Load on liquid spring	11174	N
Pressure in spring chamber	19.54429	N/mm{circumflex over ( )}2 (Mpa)
Pressure in spring chamber	195.4429	bar
Volume of spring chamber	13.5	liters
Volume of spring chamber	13500	cc
Compressed liquid (dV)	280.8661	cc
Rod movement	49.1252	cm
Pressurized position (discharge position)
Additional pressure	100	bar
Additional load	11391	N
Added pressure in chamber	19.92282	N/mm{circumflex over ( )}2 (Mpa)
Added pressure in chamber	199.2282	bar
Total pressure in chamber	394.6711	bar
Volume of spring chamber	13.5	liters
Volume of spring chamber	13500	cc
Compressed liquid (dV)	567.172	cc
Additional Movement	50.07666	cm
Totals
Coiled tubing pressure	100	bar at surface
CT pressure at depth	198.1	bar at depth
Total force on rod	22565	N
Total pressure in spring	394.6711	bar
Total Movement	99.20186	cm
Length of liquid spring cylinder	5.262734	m

[0081] As determined from Table B, a spring rod 53 length of approximately 1 m is required to achieve a 50 cm stroke. To minimize buckling force, the diameter of spring rod 53 used to compress the fluid F in the pressurized sealed spring chamber 50 was selected to have an OD of 27 mm (1 1/16″) for a spring chamber 50 having a volume of 13.5 l. Further, it was determined that the spring rod 53 would therefore have a maximum unsupported length of 1.2 m at 70% allowable force as demonstrated on FIG. 8 which was created using the following calculations:

[0082] Johnson's Equation for Short Column Buckling (Local Buckling):
Flb=Sy*As*(1−(L/R/G)^2/(2*(SRc)^2))

[0083] and

[0084] Euler's Equation for Long Column Buckling (Major Axis Buckling):
Feb=(3.14)^2*E*I/(L)^2
Where: As=steel cross sectional area

[0085] Sy=yield stress of steel

[0086] I=moment of inertia

[0087] RG=radius of gyration

[0088] SR=slenderness ratio for a given length

[0089] SRc=critical slenderness ratio

[0090] L=unsupported length

[0091] At maximum compression, approximately 1 m of the spring rod 53 is freely extending into the fluid FC in the spring chamber 50, the freely extending portion of the spring rod 53 being supported thereabouts by the fluid FC which exerts an equal pressure around the spring rod 53 decreasing any tendency for buckling.

[0092] In one embodiment, a fill port was formed in a bottom wall of the spring chamber 50 to permit filling with compressible fluid FC after assembly of the pump. Further, a bleed screw was included to permit removal of all air present in the chamber 50.

[0093] In one embodiment, a standard API pump barrel 11 having an OD of 69.9 mm (2.75″) and an ID of 57.15 mm (2.25″) was used for the spring chamber 50 cylinder. The cylinder was made of AISI C1040 Carbon Steel and behaved essentially as a pressure vessel containing a pressurized fluid. Fatigue calculations using thick-walled cylinder assumptions and Von Mises stress analysis were performed to determine the factor of safety the cylinder provided under maximum loading at 1000 m TVD. The resulting fatigue factor of safety for a fluctuating pressure from 200 barg (2900 psi) to 400 barg (5800 psi) was 1.86.

[0094] The chamber seal 54, utilized to seal about the spring rod 53 extending through the port 52 in the spring chamber 50, was required to provide a reliable seal at approximately 400 barg (5800 psi) psi. Using silicone as the compressible fluid F of choice in this embodiment, the chemical properties of the chamber seal 54 were constrained only in that the material for the seal 54 could not be a like material, in this case silicone. In an embodiment of the invention, a nitrile t-seal having nylon backups and a wiper to protect the seal 54 from produced fluids within the wellbore was selected.