System and method for preventing solids build-up in gas well

Abstract

A system for preventing build-up of solids in a gas well enables a production string annulus to remain free of destructive build-up of suspended solids while reducing methane emissions. The system includes a hollow rod string located within a production string in a well to define a production string annulus, the hollow rod string having a top end and a bottom end; a prime mover attached to the top end of the hollow rod string; a fluid distribution assembly attached to the bottom end of the hollow rod string; and a pump attached to the bottom end of the fluid dispensing assembly. The prime mover provides power to move the hollow rod string that moves the fluid dispensing assembly, and moves a driven element of the pump for pumping fluid annually upward along the production string. Fluid introduced into the top end of the hollow rod string flows down through the hollow rod string to a fluid distribution assembly where it is injected into a well sump and / or production string annulus.

Description

Technical Field

[0001] This invention generally relates to preventing the accumulation of particulate matter inside and around pumps in gas wells. In particular, but not exclusively, this invention includes a system and method for preventing solid accumulation in coalbed methane (CSG) wells equipped with screw pumps (PCPs) for removing water from the bottom of the well. Background Technology

[0002] Downhole pumps, including screw pumps (PCPs), are widely used in coalbed methane wells to transport water from the bottom of the well near the coal seam to the surface using a tubing string as a conduit. The conduit is typically located within a larger casing, forming an annulus, which is not connected to the interior of the conduit. This allows gas to flow upwards along the annulus at low pressure, while water is pumped upwards along the conduit at higher pressure.

[0003] The pump is typically operated by the rotational motion of a high-grade steel rotor within a rubber stator located at the distal end of a conduit in the lower sump of the well. The rotor is driven by a (sucking) rod string located within the conduit. The sucking rod string connects the pump rotor to a drive head located at the surface wellhead. The sucking rod string creates an annular space within the production tubing.

[0004] The geology of CSG reservoirs and surrounding formations is typically fragile and water-flooded. When gas is produced from coal seams, water and particulate matter often accompany the produced gas. Some of these particles flow down into the well sump with the water and then up through the PCP to the surface, while others accumulate at the bottom of the production string and still others accumulate in the sump at the bottom of the well.

[0005] Depending on the nature of the reservoir, the accumulation of particles can sometimes render a PCP inoperable in less than a year, and usually within three years of operation.

[0006] When particles accumulate in the annulus of the tube column, the loss of power to drive the PCP will cause these particles, which are normally suspended in the water column above the PCP rotor, to fall to the bottom of the annulus and cause the PCP rotor to become stuck due to the heavy sludge column around the ejector rod and on top of the rotor.

[0007] Particles may also accumulate in the sump and may include material that has slid down from the inner walls of the casing string above and / or below the coal seam. Particles may fill the sump to the bottom of the PCP, potentially clogging the PCP inlet and rendering it inoperable.

[0008] Operating a PCP in a dry (waterless) state or in the presence of excessive gas can also lead to premature pump failure. Therefore, considerable effort is usually required to monitor the water level and keep the PCP adequately lubricated.

[0009] If the PCP (Potentially Activated Propellant) system fails, well workover is usually required to resolve the issue. This is an expensive process and can further lead to gas production losses during the planning and execution of well workovers; well workovers are typically accompanied by the release of large amounts of methane gas into the atmosphere.

[0010] Furthermore, current practices typically require continuous operation of the PCP (Potentially Plug Propellant) to prevent particle accumulation in the lower annulus of the production tubing. This particle accumulation is often exacerbated in wells with low flow rates, and in wells where PCP regulation capacity does not allow for continuous operation and well workovers are required to replace the PCP or adapt to alternative manual lifting methods. Of course, continuous operation also increases the risk of power failure and raises overall operating and maintenance costs.

[0011] Alternatively, some PCP operators have implemented automated "pump stop" feedback control systems to reduce overall costs and downtime. These systems typically schedule PCP cycles based on desired bottomhole pressure. Pumping is usually performed at a rate that maintains minimum bottomhole pressure and prevents the well from drying out, as measured, for example, by downhole pressure gauges or acoustic devices. Other measured parameters, such as pump temperature and torque load on the sucker rod string, can also be used as inputs. However, ultimately, such control systems often prove ineffective because maintaining the accuracy of the input data is difficult.

[0012] Furthermore, CSG wells that have undergone workover typically experience reduced production capacity after the workover, thus lowering the overall gas production of the gas field. The high workover costs and lower production value also lead to a premature arrival of the economic tipping point, which can further reduce the ultimate recovery rate of the gas field's natural gas resources.

[0013] Therefore, there is a need for improved systems and methods to prevent the accumulation of solids in gas wells, in order to reduce the frequency of well workovers, improve the overall performance of wells, and reduce methane emissions into the atmosphere.

[0014] Purpose of the invention The purpose of this invention is to overcome and / or mitigate one or more disadvantages of the prior art, or to provide users with a useful or commercially viable option. Summary of the Invention

[0015] In one, though not necessarily the only or most extensive, aspect of the invention provides a system for preventing solid buildup in gas wells, the system comprising: A hollow rod string located within the production string in the well to define the annulus of the production string, the hollow rod string having a top end and a bottom end; A prime mover attached to the top of a hollow rod; A fluid distribution assembly attached to the bottom end of a hollow rod; The pump is attached to the bottom of the fluid distribution assembly, and The fluid outlet is connected to the bottom of the pump; In use: The prime mover provides power to the moving hollow rod column, which moves the fluid distribution assembly and the driven element of the pump for pumping fluid upward along the annulus of the production tubing. The fluid introduced into the top of the hollow rod flows downward through the hollow rod to the fluid distribution assembly, determining the operating position of the fluid distribution assembly; and The operating position of the fluid distribution assembly can be selected between a first operating position that guides fluid through a fluid outlet and a second operating position that guides fluid into the annulus of the production column.

[0016] Preferably, the prime mover provides power for the rotational motion of the hollow rod, the fluid distribution assembly, and the driven element of the pump.

[0017] Preferably, the fluid dispensing assembly includes a plug for opening and closing a limiting port connected to an internal spring, wherein the differential pressure between the top and bottom surfaces of the plug can overcome the tension of the internal spring and move the plug between operating positions.

[0018] Preferably, the fluid distribution assembly has one or more ports that direct the injected fluid into the production tubing annulus or downward into the sump, or simultaneously into the production tubing and the sump.

[0019] Preferably, the fluid injection head at the top of the hollow rod is capable of injecting gas or water, or both, into the hollow rod.

[0020] Preferably, the fluid injection head includes a port connected to a leak detection system.

[0021] Preferably, the well is a coalbed methane (CSG) well.

[0022] Preferably, in the first operating position, low-speed gas flows from the fluid outlet to the sump, enabling the calculation of the water level in the production casing annulus.

[0023] Preferably, in the first operating position, high-speed fluid flows out from the fluid outlet to wash away particles in the sump below the pump, so that the particles are carried by the water in the sump through the pump and into the annulus of the production tubing.

[0024] Preferably, gas or water, or both, can be injected into the top of the hollow rod column to assist in the rinsing of particles in the collection pit or to flush the collection pit.

[0025] Preferably, in the second operating position, gas or water, or both, can be injected into the production column annulus to flush the production column annulus.

[0026] Preferably, the pump is a screw pump (PCP), and the driven element is a rotor located within the stator.

[0027] Preferably, the rotor includes a hollow channel that allows fluid to flow from the fluid distribution assembly to the fluid outlet.

[0028] Preferably, the fluid outlet is a fluid nozzle.

[0029] Preferably, the hollow rod is a vacuum rod.

[0030] According to another aspect, the present invention provides a method for operating the above-described system, the method comprising: A first fluid differential pressure is applied to the fluid distribution assembly to control the operating position of the fluid distribution assembly and define a first operating mode of the fluid distribution assembly; A second fluid differential pressure is applied to the fluid distribution assembly to control its operating position and define alternative operating modes; and The fluid distribution component cycles between a first operating mode and an alternative operating mode.

[0031] Preferably, the alternative operating mode is selected from various available operating modes.

[0032] Preferably, applying a first fluid differential pressure to the top of the fluid distribution assembly selects a first operating position for the fluid distribution assembly and enables at least one of the following operating modes: • Mode A1 – Sump pressure monitoring (using low-pressure gas); •Mode A2 – Sump flushing (using high-pressure gas); • Mode A3 – Sump flushing (using water and high-pressure gas); and • Mode A4 – Sump flushing (using water only); • Mode A5 – In Modes B1, B2, or B3, after the water in the production column annulus is removed, sump flushing and production column flushing are performed simultaneously (using gas and water).

[0033] Preferably, a second fluid differential pressure is applied to the top of the fluid distribution assembly to select a second operating position of the fluid distribution assembly, and at least one of the following operating modes is enabled: •Mode B1 – Production tubing flushing (water only); • Mode B2 – Production string flushing (using high-pressure gas and water); and • Mode B3 – Production string flushing (using high-pressure gas only).

[0034] Preferably, operating mode B2 or B3 is performed before operating modes A2, A3, A4 or A5 to reduce the load on the pump.

[0035] According to another aspect, the present invention provides a system for preventing solid accumulation in gas wells, the system comprising: A hollow rod string located within the production string in the well to define the annulus of the production string, the hollow rod string having a top end and a bottom end; A prime mover attached to the top of a hollow rod; A fluid distribution assembly attached to the bottom end of the hollow rod; and The pump is attached to the bottom of the fluid distribution assembly. In use: The prime mover powers the moving hollow rod column, which in turn moves the fluid distribution assembly and the driven element of the pump, for pumping fluid upwards along the annulus of the production tubing; and The fluid introduced into the top of the hollow rod flows down through the hollow rod to the fluid distribution assembly, where it is injected into the annulus of the production column.

[0036] Preferably, the fluid distribution assembly includes multiple check valves to prevent fluid from flowing upward from the sump to the hollow rod column, and to allow the fluid to flow downward through the hollow rod column, through the fluid distribution assembly, and into the annulus of the production tubing.

[0037] Preferably, the fluid introduced into the top of the hollow rod is a gas.

[0038] Preferably, the gas introduced into the top of the hollow rod is pulsed.

[0039] Preferably, the fluid dispensing assembly includes: The outer wall of the central cavity is defined; Fluid connection between the central cavity and the outlet of the hollow rod column; At least one check valve in the outer wall; and An axial check valve located in the central cavity; Specifically, under the first differential pressure on the axial check valve in the central cavity, the check valve in the outer wall is biased closed, and the axial check valve is biased open, allowing fluid to flow from the central cavity through the axial check valve, then through the bottom of the fluid distribution assembly, and then through the pump; and Under a second differential pressure greater than the first differential pressure, the axial check valve closes, and the check valve in the outer wall opens, allowing fluid to flow from the central cavity through the check valve in the outer wall and into the annulus of the production tubing.

[0040] Preferably, under a third pressure between the first and second pressures, the check valves in the outer wall and the axial check valve are both biased open, allowing fluid to flow from the central cavity into the annulus of the production tubing via a pump. Attached Figure Description

[0041] To aid in understanding the present invention and to enable those skilled in the art to practice it, preferred embodiments of the invention are described below by way of example only with reference to the accompanying drawings, in which: Figure 1 This is a cross-sectional view of the underground portion of a system for preventing solid accumulation in coalbed methane (CSG) wells according to some embodiments of the present invention. Figure 2 This is according to some embodiments of the present invention. Figure 1 A cross-sectional view of the above-ground portion of the system; Figure 3 These are schematic diagrams illustrating some embodiments of the present invention. Figure 1 The cross-section of the system's fluid distribution assembly (FDA) in the first operating position A; Figure 4 These are schematic diagrams illustrating some embodiments of the present invention. Figure 1 The cross-section of the system's fluid distribution assembly (FDA) in the second operating position B; Figure 5 This is according to some embodiments of the present invention. Figure 1 The lower cross-sectional view of the system when operating in mode A1; Figure 6 This is according to some embodiments of the present invention. Figure 1 A cross-sectional view of the lower part of the system when operating in mode A2; Figure 7 This is according to some embodiments of the present invention. Figure 1 The lower cross-sectional view of the system when operating in mode B1; Figure 8 This is according to some embodiments of the present invention. Figure 1 A cross-sectional view of the lower part of the system when operating in mode B3; Figure 9 and Figure 10 These are schematic diagrams of embodiments of some defined basic systems according to the present invention, showing cross-sections of an alternative FDA during normal and flushing operation states; Figure 11 and Figure 12 These are schematic diagrams of embodiments of some defined intermediate systems according to the present invention, showing an alternative FDA cross-section during normal and flushing operation states; Figure 13 This is a cross-sectional perspective view of a fluid injection head including leak detection system elements according to some embodiments of the present invention. Detailed Implementation

[0042] This invention relates to an improved system and method for preventing solid buildup in gas wells. The elements of the invention are shown in simplified outline form in the accompanying drawings, which illustrate only those specific details necessary for understanding embodiments of the invention, so as not to obscure the content of this disclosure with excessive details that would be obvious to those skilled in the art based on this specification.

[0043] In this patent specification, adjectives such as first and second, left and right, above and below, top and bottom, upper and lower, rising and falling, upward and downward are used only to distinguish one element or method step from another, and do not necessarily require the specific relative position or order described by the adjective. Words such as "comprising" or "including" are not used to define an exclusive set of elements or method steps. Rather, these words define only the minimum set of elements or method steps contained in a particular embodiment of the invention.

[0044] According to one aspect, the present invention provides a system for preventing solid accumulation in gas wells, the system comprising: A hollow rod string located within the production string in the well to define the annulus of the production string, the hollow rod string having a top end and a bottom end; A prime mover attached to the top of a hollow rod; A fluid distribution assembly attached to the bottom end of a hollow rod; The pump is attached to the bottom of the fluid distribution assembly, and The fluid outlet is connected to the bottom of the pump; In use: The prime mover provides power to the moving hollow rod column, which moves the fluid distribution assembly and the driven element of the pump for pumping fluid upward along the annulus of the production tubing. The fluid introduced into the top of the hollow rod flows downward through the hollow rod to the fluid distribution assembly, determining the operating position of the fluid distribution assembly; and The operating position of the fluid distribution assembly can be selected between a first operating position that guides fluid through a fluid outlet and a second operating position that guides fluid into the annulus of the production column.

[0045] Some embodiments of the invention offer advantages including enabling the production string annulus to remain free from the destructive buildup of suspended solids in the water, which allows the pump to be stopped and started without concern about the pump getting stuck or the well becoming clogged.

[0046] In addition, some implementations allow the injected process fluid to be switched between injecting fluid into the well sump and injecting fluid into the annulus of the production tubing.

[0047] In addition, some implementations allow particulate aggregates in the sump to be removed by adding fluid to the annulus of the production column and to be washed away by the particles conveyed through the PCP.

[0048] In addition, some implementations allow liquid to be injected into a sump to ensure that the pump does not operate dry and damage the stator.

[0049] In addition, some implementations ensure that the area in the sump around the pump inlet remains free of particle accumulation.

[0050] In addition, some implementations enable the measurement of the bottom pressure in the sump and the calculation of the water height in the annulus above the pump to ensure that the pump does not operate in a dry state.

[0051] In addition, some implementations enable the combined action of water and gas through fluid nozzles to provide a high-speed fluid flow that can agitate the highly viscous slurry in the sump.

[0052] In addition, some implementations enable the combined action of water and gas entering the production string annulus to provide a highly turbulent fluid flow for flushing the production string annulus.

[0053] In addition, some implementations enable the combination of water and gas to minimize the total gas volume required to remove accumulated particles from the sump and flush the annulus of the production tubing.

[0054] In addition, some implementations enable the combination of water and gas to reduce the water flow required to remove accumulated particles from the sump and flush the annulus of the production tubing.

[0055] In addition, some implementations include optional components to prevent production fluid that may leak through the fluid distribution assembly from flowing into the hollow rod column.

[0056] In addition, some implementation methods reduce the frequency of well workovers, thereby reducing methane emissions during the workover process.

[0057] Those skilled in the art will understand that not all of the above advantages must be included in all embodiments of the present invention.

[0058] Figure 1This is a cross-sectional view of the underground portion of a system 100 for preventing solid accumulation in a coalbed methane (CSG) well 105 according to some embodiments of the present invention. System 100 includes a hollow sucker rod string (HSRS) 110 extending downward from the ground surface 115 within a production string (PTS) 120, which itself is within a production casing string (PCS) 132. The outer wall of the HSRS 110 and the inner wall of the PTS 120 define a production string annulus (PTA) 165. Well 105 extends through a coal seam 125, and, although not shown to scale in the figure, well 105 extends into a sump 130. Typically, the depth of the sump 130 may extend 20 meters or more below the coal seam. The production casing annulus 133, defined by the outer wall of PTS 120 and the inner wall of production casing string 132, allows produced gas from coal seam 125 to flow to surface facilities.

[0059] The bottom end of HSRS 110 connects to the top end of fluid distribution assembly (FDA) 135. The bottom end of FDA 135 then connects to short-connect hollow ejector joint (HSRJ) 140, which connects to the top end of hollow rotor 145 of screw pump (PCP) 150. Rotor 145 is located within rubber stator 155 of PCP 150. The distal end of rotor 145 connects to fluid nozzle 160 extending downward into sump 130 of well 105.

[0060] As is typical when a CSG well is online, well 105 produces gas and water. The gas and water separate in the production casing annulus 133 adjacent to the coal seam 125. The water falls downward into the sump 130, while the gas flows upward through the production casing annulus 133 to the surface production facility. PCP 150 pumps water from the sump around the outside of FDA 135 and pumps it upward along the production string annulus (PTA) 165 to the surface production facility.

[0061] Figure 2 This is a cross-sectional view of the above-ground portion of system 100 according to some embodiments of the present invention. In operation, a prime mover in the form of a PCP drive head 200 powers the rotational motion of the SRS 110. It will be readily understood by those skilled in the art that various commercially available electric motors are available for powering the SRS 110, and such motors are known in the art. The rotational motion of the SRS 110, in turn, powers the rotational motion of the FDA 135, which in turn powers the rotational motion of the short-connected HSRJ 140, which in turn powers the rotational motion of the rotor 145 of the PCP 150.

[0062] System 100 uses high-pressure and low-pressure air and water sources, both of which are connected to a fluid injection head 205 located on top of SRS 110. Details regarding these fluid sources are not provided because they are well-known to those skilled in the art, based on this specification. Fluid injection head 205 is capable of injecting water or gas, or both, into the top of SRS 110 and downwards into FDA 135 at varying pressures and flow rates as needed.

[0063] also, Figure 2 The diagram shows produced water 210 discharged from PTA 120 and produced gas 215 discharged from production casing annulus (PCA) 133.

[0064] The operating position of the FDA135 is controlled by controlling the pressure of water or gas, or both, passing through the axial check valve within the FDA135.

[0065] PCP 150 can be operated in a manner similar to various screw pumps known in the prior art. However, rotor 145 is hollow so that water or gas flowing through HSRS 110 via FDA 135, or both, can be discharged through one or more directional restricted orifices at the distal end of nozzle 160. This flow provides a high-speed fluid flow capable of agitating highly viscous slurry in sump 130.

[0066] Depending on the selected operating mode, FDA 135 can direct injected fluid to the rotor 145 of PCP 150, or to the production column annulus 165, or both simultaneously. The discharge point of FDA 135 depends on the pressure at the top of FDA 135, which is generated by the fluid head and / or fluid flow through FDA 135 and the fluid head in the production column annulus 165.

[0067] The configuration of FDA 135 relative to the pump 150 discharge port allows the fluid flow discharged by PCP 150 to continuously flow into the production string annulus 165 during the operation of well 105. In this specification, various check valve mechanisms are interchangeably referred to as valves, shuttle valves, or plugs.

[0068] Figure 3 This is a schematic diagram showing a cross-section of FDA 135 in its default operating position A.

[0069] Figure 4 This is a schematic diagram showing the cross-section of FDA 135 in the high differential pressure head operating position B.

[0070] FDA 135 includes an FDA body 2 having a thread 2b at its top end that can be screwed into the lower end of HSRS110; and a thread 2c at the lower end of the FDA body 2 that can be screwed into the top end of HSRJ 140.

[0071] FDA 135 also includes a shuttle valve 4 capable of vertical movement relative to the FDA body 2, wherein when the shuttle valve 4 is moved upward to the operating position A, shuttle valve ports 4b and 4c are opened (e.g., Figure 3 (as shown), thus allowing fluid to flow out from the bottom of FDA 135.

[0072] Furthermore, at position A, port 2z allows fluid to flow into the production string annulus 165, where the fluid experiences a higher pressure in HSRS 110 than in the production string annulus 165.

[0073] Shuttle valve 4 is biased by spring 5a to the shuttle valve upward operating position A. If the differential pressure between the top and bottom of shuttle valve 4 exceeds a given threshold, shuttle valve 4 moves downward to operating position B. Other components according to FDA 135 include O-ring carrier 3, flow-limiting orifice core 6, centering washer 5b, and ports 2a and upper port 2z, each including a check valve core. Multiple retaining clips (3f, 4d, and 5c) hold the individual components in place while allowing vertical movement of the shuttle valve assembly when spring 5a is compressed. Multiple sets of seals, including O-rings and seals 3d, 3e, 4e, and 4f, are provided to prevent fluid leakage.

[0074] The internally machined shoulder 2d on the FDA body 2 provides a positioning surface for the shuttle valve 4 in position B. Internal circumferential grooves 2e, 2f, and 2g are cut into the FDA body 2 to provide a receiving portion for retaining the clamp.

[0075] Similarly, an O-ring carrier sleeve 3, positioned by shoulder 2d, is fitted with a pair of O-rings 3d around its outer circumference to provide a seal between the upper and lower sections of the shuttle valve 4. The sleeve 3 has multiple inner bores 3a radially positioned around its center, with upper port 3b and lower port 3c connecting the inner bores 3a to the hollow interior of the shuttle valve 4. A pressure balancing port 3f is drilled through the outer circumference of the sleeve 3 between the inner bores 3b and 3c. A balancing port 4a is also drilled through the upper body of the shuttle valve 4 to prevent pressure differentials across the shuttle valve sections.

[0076] A longitudinal center top hole is machined into the shuttle valve 4, the depth of which is below the midpoint of the shuttle valve 4. A longitudinal center bottom hole is also machined into the shuttle valve 4, the height of which leaves a solid barrier between the top hole and the bottom hole. When the shuttle valve 4 is in position A, a first radial port 4b connects the center top hole to port 3b; when the shuttle valve 4 is in position A, a second radial port 4c connects the center bottom hole to port 3c.

[0077] The shuttle valve 4 is equipped with an upper seal 4e and a lower seal 4f. When the shuttle valve 4 is in position A, the upper seal 4e blocks fluid flow between the HSRS 110 and the production string annulus 165. At this time, fluid from the HSRS 110 can flow into port 4b, through sleeve 3, out through port 4c, and finally out of the bottom of FDA 135.

[0078] The upper port 2z in the body 2 of FDA 135 is now closed by the pressure head of the fluid in PTA 165.

[0079] When shuttle valve 4 is in position B, shuttle valve ports 4b and 4c are no longer aligned with ports 3b and 3c of sleeve 3, thereby closing the flow path between the upper and lower sections of the shuttle valve; thus, the pressure in the upper section of FDA 135 is allowed to increase to a value exceeding the pressure in the production string annulus 165, and fluid is allowed to flow between HSRS 110 and the production string annulus 165, while the set of lower seals 4f prevents fluid from flowing out of the bottom end of FDA 135 through port 4b.

[0080] The flow-limiting orifice element 6 is connected to the top of the central top hole of the shuttle valve 4 and provides a throttling point for the fluid flowing through FDA 135 when the shuttle valve 4 is in position A. At high fluid flow rates, orifice 6a generates a differential pressure sufficient to compress spring 5a and move the shuttle valve 4 to operating position B. Once in position B, the pressure in HSRS 110 rises to equal the pressure head in the production string annulus 165, thereby holding the shuttle valve in position B.

[0081] The centering washer 5b is sized to guide the lower section of the shuttle valve 4 to prevent the shuttle valve 4 from “tilting” and potentially getting stuck when moving longitudinally in FDA 135, and to provide a reaction surface for the spring 5a.

[0082] Those skilled in the art will understand that the various components of FDA 135 can be made of a variety of materials, including stainless steel, various polymers and metal alloys.

[0083] To ensure that the production string annulus 165 remains free from destructive accumulation of suspended solids and that particulate buildup in the sump 130 can be removed and flushed out, various operating modes of FDA 135 can be run cyclically and / or sequentially according to sump flushing and well cleaning procedures. These procedures define different intervals between operating modes based on the characteristics of the well, as needed. For example, a high-particle-generation well may require a procedure performed twice daily, while a low-particle-generation well may require a procedure performed once weekly.

[0084] When FDA 135 is in Position A, the following operating modes are available: • Mode A1 – Sump pressure monitoring (using gas); • Mode A2 – Sump flushing and PTA injection (using gas); •Mode A3 – Sump flushing (using water and gas); • Mode A4 – Sump flushing (water only); and • Mode A5 – In Modes B1, B2, or B3, after the water in the production column annulus is removed, sump flushing and production column flushing are performed simultaneously (using gas and water).

[0085] Modes A1-A5 all involve directing fluid from the bottom of HSRS 110 to FDA 135 and through nozzle 160 into sump 130. Each mode A1-A5 is defined by the pressure, height, flow rate, and type of fluid (water or gas, or both) injected into the top of HSRS 110 via fluid injection head 205. As described below, mode A1 is the default operating mode, while modes A2-A5 can be used intermittently to remove particles accumulated in sump 130 and / or to flush sump 130 with water.

[0086] When FDA 135 is in Position B, the following operating modes are available: •Mode B1 – Production tubing flushing (water only); •Mode B2 – Production tubing flushing (using high-pressure gas and water); • Mode B3 – Production string flushing (using high-pressure gas only).

[0087] Modes B1-B3 all introduce fluid from HSRS 110 into the production column annulus 165 through ports 2a and 2z of FDA 135. Each mode B1-B3 is also defined by the pressure, flow rate, and type of fluid (water or gas or both) injected into the top of HSRS 110 through fluid injection head 205.

[0088] Figure 5This is a lower cross-sectional view of the system 100 according to some embodiments of the invention, operating in mode A1. Gas is injected at a low flow rate through the fluid injection head 205, such low flow rate that it does not create a perceptible back pressure at the flow-limiting orifice 6a through the shuttle valve 4, which is therefore held in the upper position A. This allows for surface pressure measurement at the top of the internal cavity 112 of the HSRS 110, which substantially reflects the pressure at the tip of the nozzle 160 in the sump 130. The injected gas is delivered to the bottom of the FDA 135, then exits the nozzle 160, and rises as a bubble 500 into the production sleeve annulus 133.

[0089] The difference between the surface pressure measurement at the top of HSRS 110 and the casing head at the surface of the production casing annulus 133 is equal to the pressure exerted by the water column above nozzle 160. Since the difference in gas head between HSRS 110 and PCA 133 is negligible, this allows for accurate measurement of the water height in the production casing annulus 133. In high-flow-rate wells, common engineering equations can be used to calculate the flow losses of the gas generated upwards along the production casing annulus 133 to obtain the accurate water height above PCP 150. This figure is used to determine the PCP start-up water level 170 and the PCP stop-down water level 175 (see...). Figure 1 ( ), to turn PCP 150 on and off, and to prevent PCP 150 from operating in a dry state.

[0090] PCP 150 can operate in or out of Mode A1; when operating, water discharged from PCP 150 flows into the production line annulus 165, surrounds FDA 135, and continues upward along the production line annulus 165 to the ground facility. PCP inlet 605 is defined by sleeve 610, which extends below the bottom end of the production line (PTS) 120.

[0091] Figure 6 This is a lower cross-sectional view of the system 100 according to some embodiments of the invention, operating in mode A2. As the PCP 150 operates, gas is injected at the fluid injection head 205 and flows along the same flow path as in mode A1. High-speed gas exiting from nozzle 160 siphons particles from the water in the sump 130 below the PCP 150, allowing the particles to be carried by the water to the PCP inlet 605 and then into the production string annulus 165. As indicated by arrow 600, water in the production sleeve annulus 133 flows downward through the annulus 133, then through the PCP inlet 605, and upward along the small annulus defined between the sleeve 610 and the nozzle 160 to reach the PCP 150.

[0092] Nozzle 160 directs most of the injected gas to the inner wall of well 105, where it rises through water into the production casing annulus 133, where it merges with produced gas from coal seam 125 above sump 130 and flows toward the surface facility. Casing 610 also helps prevent excess injected gas from entering PCP inlet 605. During sump 130 flushing in Mode A2, the upper port 2z in FDA body 2 allows some gas to vent from FDA 135 into the production string annulus 165. It should be understood, based on this specification, that the size of the upper port 2z can be adjusted to provide an effective ratio of gas flowing through the upper port 2z to gas flowing through nozzle 160. Gas flowing through the upper port 2z helps reduce the contents of the production string annulus 165 and thus reduces the discharge load / pressure at the PCP 150 outlet. As is known in the art, the presence of excess gas can damage the screw pump. Reducing the discharge load / pressure at the outlet of PCP 150 helps to ensure that the load on PCP 150 is reduced and that PCP 150 is not damaged by the presence of gas flowing through PCP 150 in mode A2.

[0093] When the PCP run time has elapsed, the gas injection into PCP 150 and the fluid injection head 205 is shut off, allowing produced water to refill the production casing annulus 133 below coal seam 125. Following the gas flow termination, the gas pressure in HSRS 110 immediately and rapidly decays, allowing for a rapid recalculation of the water height above PCP 150 before recovery mode A1. At this point, the water level above the top of PCP 150 can be used to update the PCP run time calculation.

[0094] When the water level is determined to rise to the PCP start-up level of 170, mode A2 is resumed. The mode A2 / mode A1 cycle is repeated as needed, or according to the characteristics of the well.

[0095] In mode A3, PCP 150 is always operational. Gas and water are simultaneously injected into fluid injection head 205, mixed together before flowing into HSRS 110, and follow the same flow path as in modes A1 and A2. Water and gas are injected into fluid injection head 205 at a calculated rate less than the throttling rate of water / gas flowing through ports 6a and 4b of FDA 135. This allows water to flow freely through FDA 135 and into sump 130 without accumulating a fluid head within HSRS 110 that would compress spring 5a and cause shuttle valve 4 to move to position B.

[0096] High-speed gas flowing from nozzle 160 and water wash away particles from the water in the sump 130 below PCP 150, allowing the particles to be carried by the water to the PCP inlet 605 of PCP 150 and then into the annulus 165 of the production column. The system 100 is designed to provide sufficient water injection to continuously operate PCP 150 in mode A3.

[0097] At the end of mode A3, mode A2 is activated for a short period to purge water from HSRS 110. When mode A2 is deactivated, mode A1 is activated, allowing precise pressure measurement at the end of nozzle 160 in sump 130 and determining the water level above the top of PCP 150. The water level above the top of PCP 150 can then be used to fine-tune the running time calculation for mode A3.

[0098] Mode A4 can be started while Mode A1 is running, which prevents HSRS 110 from being in a vacuum state when water injection begins in Mode A4. Mode A4 can be used to flush the sump 160 with clean water and allows PCP 150 to pump water from the sump into the production string annulus 165, for example, at a rate of up to 1000 barrels of water per day (bwpd), thereby effectively flushing the production string annulus 165.

[0099] During operation, water is injected into the fluid inlet head 205 at a calculated rate less than the throttling rate of water flowing through ports 6a and 4b of FDA 135. This allows water to flow freely through FDA 135 and into the sump without accumulating a water pressure head within HSRS 110, which would compress spring 5a and cause shuttle valve 4 to move to position B. System 100 is designed to provide sufficient water injection to continuously operate PCP 150 in mode A3.

[0100] At the end of mode A4, mode A2 is activated for a short period to purge water from HSRS 110. When mode A2 is deactivated, mode A1 is activated, allowing precise pressure measurement at the end of nozzle 160 in sump 130 and determining the water level above the top of PCP 150. The water level above the top of PCP 150 can then be used to fine-tune the running time calculation for mode A3.

[0101] Figure 7This is a lower cross-sectional view of system 100 according to some embodiments of the invention, operating in mode B1. With FDA 135 in position B and PCP 150 closed, mode B1 can be used to flush the production line annulus 165 with clean water at a flow rate of up to 2000 barrels per day (bwpd), resulting in a very short flushing time, for example, less than four minutes. Mode B1 can be started from mode A1, which prevents HSRS 110 from being in a vacuum state when water injection begins in mode B4. As shown, clean water flows down HSRS 110 to FDA 135, as indicated by arrow 700, and then flows up along the production line annulus 165. With PCP 150 closed, water (as indicated by crosshair 750) remains in the sump 130 and the production line annulus 133.

[0102] In mode B1, when HSRS 110 is filled with water, the resulting fluid column applies a pressure head, for example, exceeding 2000 kPag, to the top of shuttle valve 4, causing spring 5a to compress and FDA 135 to move to position B. Multiple ports 2a and 2z connected to the production string annulus 165 are opened, and multiple ports 4b and 4c are isolated. This allows water to flow down through HSRS 110 and through FDA 135 to the production string annulus 165, thereby flushing accumulated particulate matter to the ground facility.

[0103] Mode B2 operates similarly to Mode B1, but high-pressure gas is added to the water injected at the fluid injection head 205. Mode B2 can be started from Mode A1, where FDA 135 is in position A and PCP 150 is closed. Injecting water and gas simultaneously at a rate exceeding the throttling flow value at port 6a moves shuttle valve 4 to position B.

[0104] Mode B2 can be used to flush the production string annulus 165 with water and gas. When water and gas are mixed, high-speed turbulent conditions can be generated in the production string annulus 165. For example, at a water injection rate of up to 500 bwpd (55 liters / min) and a gas injection rate of 10 kg / min, effective flushing of accumulated particulate matter from the production string annulus 165 to the ground facility helps result in very short flushing times, such as less than two minutes.

[0105] Each of modes B1 and B2 is able to limit the total power demand of system 100 because the water pump supplying water to fluid injection head 205 located on the ground only needs to operate at high load when PCP150 is offline and gas is extracted from the high-pressure storage device.

[0106] After sufficient water has been circulated to flush the production string annulus 150, either mode B1 or mode B2 is terminated, and mode A2 is activated for a short period to transfer water from HSRS 110 into the production string annulus 165 until shuttle valve 4 returns to position A, as the total pressure head on shuttle valve 4 decreases. Mode A2 is then terminated, and mode A1 is reactivated, allowing for precise pressure measurement at the tip of nozzle 160 and determination of the water level in the PCA.

[0107] Figure 8 This is a lower cross-sectional view of the system 100 according to some embodiments of the present invention when operating in mode B3. Mode B3 involves injecting high-pressure gas only at the fluid injection head 205, with PCP 150 open or closed. As indicated by arrow 800, with PCP 150 open, the gas flows downward through HSRS 110, through ports 2a and 2z of FDA 135, and then upwards to the production column annulus 165 after mixing with water leaving PCP 150. Mode B3 can be initiated from mode A1 when FDA 135 is in position A. Injecting gas at a rate exceeding the throttling flow rate value at port 6a creates a downward force on the top of the upper shuttle valve body 4a, thereby moving the shuttle valve 4 to position B.

[0108] Mode B3 can be used to flush the production column annulus 165 with gas, thereby creating turbulent, high-speed conditions within the production column annulus 165. For example, at a gas injection rate of 30 kg / min, a flushing time as short as one minute can flush accumulated particulate matter from the production column annulus 165 to the ground facility.

[0109] The design of system 100 enables the production string annulus 165 to be flushed clean in modes B1, B2 or B3 while the water level in the production casing annulus 133 rises from the PCP stop level 175 to the PCP start level 170, with PCP 150 closed.

[0110] In mode B3, after sufficient gas has been circulated to drain the production string annulus 165, such as after one or more drainages, the gas flow into the fluid injection head 205 is stopped. As gas continues to flow from the production string annulus 165 to the ground facility, the pressure in HSRS 110 decreases until shuttle valve 4 returns to position A. At this point, mode A1 can be reactivated to allow for precise pressure measurement at the end of nozzle 160 and determination of the water level in the production sleeve annulus 133.

[0111] As described above, the hydraulic head that significantly reduces the contents of the production string annulus 165 can reduce the discharge load / pressure at the PCP 150 outlet and helps ensure that the PCP 150 is only under light load and is not damaged by the gas passing through the PCP 150, while the full rotor torque of the PCP 150 can be used to transport solids. Therefore, the operating procedure for a particular system 100 may include running system 100 in mode B2 or B3 for a short period of time before starting mode A2, A3, or A4 to reduce the load on the PCP 150 when flushing the sump 130 with gas or a gas / liquid mixture.

[0112] Those skilled in the art will understand that, according to alternative embodiments of the present invention, FDA 135 can be replaced by one of a variety of alternative fluid distribution assemblies having various alternative internal ports and fluid response elements. Furthermore, those skilled in the art will understand that alternative embodiments of the present invention can be applied to various types of pumps, including pumps powered by the reciprocating motion of a hollow rod rather than rotational motion.

[0113] For example, according to an alternative implementation, the orifice 6a can be smaller, so that the flow rate into the sump 130 is minimized, thereby providing only the flow rate of the bubble tube passing through FDA 135 and entering the sump 130.

[0114] Furthermore, according to an alternative basic system embodiment of the invention, where sump 130 does not require flushing, a conventional water level determination mechanism can be used in the well, and the FDA 135 can be replaced with a simplified fluid distribution assembly in the form of a solid or fixed plug having a port (similar to port 2a or 2z) leading from HSRS 110 to the production string annulus 165. This provides a flow path for the gas or liquid injected into HSRS 110 to enhance the removal and generation of liquid / solid only above PCP 150 in the production string annulus 165. In such an embodiment, rotor 145 does not need to be hollow, and nozzle 160 can be eliminated or replaced by a simple fluid outlet.

[0115] Figure 9 and Figure 10 These are schematic diagrams of embodiments of some defined basic systems according to the present invention, showing a cross-section of the alternative fluid dispensing assembly (FDA) 900 during normal and flushing operation states.

[0116] In an embodiment of the basic system of the present invention, FDA 135 is replaced by FDA 900, while the other components of system 100 remain as described above. In the basic system, FDA 900 is essentially an on / off device that prevents fluid backflow into HSRS 110 (in Figure 9 and Figure 10(Not shown in the image). A push-button check valve 905 is used to prevent leakage from PTA 165 into the central chamber 910 of FDA 900, thereby preventing fluid from entering HSRS 110. Furthermore, with FDA 900, no fluid flows from the bottom of FDA 900 into PCP 150 or sump 130.

[0117] In the normal operation of the basic system, such as Figure 9 As shown, the push-button check valve 905, which is spring-biased and opens only when the pressure is above a predetermined level, closes when HSRS 110 is filled with low-pressure gas. Well 105 continues to produce gas normally, and PCP 150 operates under its normal control functions.

[0118] The pressure in PTA 165 at an FDA 900 depth is a function of well depth. For example, due to the water head in PTA 165 plus the pipe head pressure, a 600-meter deep well at an FDA 900 depth might have a pressure of approximately 60 barg. Flushing PTA 165 with gas can be performed in two steps: 1) Use a surface gas source to inflate the HSRS 110 to a pressure equal to the calculated bottom hole pressure at the FDA 900 depth; and 2) Flush PTA 165 with gas, for example, from an above-ground storage cylinder, at a controlled flow rate through HSRS 110. Figure 10 As shown, the gas then flows from HSRS 110 into the central chamber 910 of FDA 900 and (as indicated by the arrow) into PTA 165 through the open push-button check valve 905.

[0119] The gas flowing into HSRS 110 can be pulsed, so that each pulse will lift a section of water up along PTA 165 to the ground. As the gas expands up along PTA 165, a noticeable increase in head pressure (THP) occurs.

[0120] Figure 11 and 12 These are schematic diagrams of embodiments of some defined intermediate systems according to the present invention, showing a cross-section of an alternative fluid distribution assembly (FDA) 1100 located within production tubing 120 during normal and flushing operation.

[0121] In an embodiment of the intermediate system of the present invention, FDA 135 is replaced by FDA 1100, while the other components of system 100 remain as described above. In the intermediate system, FDA 1100 either a) introduces gas into well sump 130 to measure bottom hole pressure (BHP), or b) introduces gas and / or water into PTA 165 during flushing of PTA 165 while axial flow check valve 1110 is closed to prevent fluid from flowing into well sump 130, or c) introduces fluid into both sump 130 and PTA 165 simultaneously.

[0122] During the normal operation of the intermediate system, such as Figure 11 As shown, the push-button check valve 1105 of FDA 1100 is closed, and HSRS 110 contains gas at a pressure equal to the pressure at the bottom of PCP 150; this pressure can be nominally equal to the pressure at the top of PCA 133 plus the water head in PCA 133 above the bottom of PCP 150. This normal operating pressure in the central chamber 1115 of FDA 1100 is lower than the pressure required to overcome the spring bias in 1) push-button check valve 1105 and 2) axial flow check valve 1110, therefore valve 1105 remains closed and axial flow check valve 1110 remains open.

[0123] Well 105 then proceeds with normal gas production, and PCP 150 operates under its conventional control functions. The axial check valve 1110 of FDA 1100 opens and is held in place by spring tension, allowing gas to flow from HSRS 110 (in...). Figure 11 (Not shown) flows through FDA 1100 at a nominal rate (e.g., 2-3 kg / h), thereby providing a means of measuring the BHP at the end of PCP 150 (read at the gas injection line upstream of fluid injection head 205); when compared with the casing head pressure (CHP) measurement, an accurate measurement of the water level in PCA 133 above the bottom of PCP 150 can be calculated.

[0124] like Figure 12 As shown, when using the intermediate system, the following procedure can be used to flush PTA 165: 1) Using a surface gas source, inflate the HSRS 110 to a pressure equal to the calculated bottom hole pressure at the FDA 1100 depth; and 2) PTA 165 is flushed through HSRS 110 using, for example, gas from an above-ground storage cylinder and water injected by an above-ground high-pressure pump at a controlled flow rate. The gas is then discharged from HSRS 110 (in... Figure 12(Not shown) Flows into FDA 1100, through the open push-button check valve 1105, and into PTA 165. The higher pressure in the central chamber 1115 keeps the axial check valve 1110 closed, and fluid does not flow through the bottom of FDA 1100 to PCP 150.

[0125] exist Figure 12 During the flushing process shown, THP, CHP, and HSRS pressures can be monitored, and the water level in the PTA 165 can be continuously calculated.

[0126] The gas pulse / water injection sequence can be repeated multiple times until the intermediate system flushing procedure is terminated. This termination may occur when one of the following two things happens: i) the pressure in the above-ground gas cylinder decays to the minimum cylinder operating pressure; or ii) the calculated water level in PTA 165 is essentially zero. The flushing procedure may be terminated after the gas injection pulse to prevent water from accumulating in HSRS 110.

[0127] According to another embodiment, the spring tensions in the push-button check valve 1105 and the axial flow check valve 1110 can be balanced so that both the push-button check valve 1105 and the axial flow check valve 1110 can operate simultaneously in the open position at a specified pressure in the central chamber 1115. After PTA 165 has been cleaned or unloaded, this allows fluid to flow through FDA 1100 and into PTA 165, while simultaneously flowing downwards into the sump 130.

[0128] The benefits of injecting water during rinsing include: • Improve turbulence in PTA 165.

[0129] • Dilute the particle-laden water in PTA 165, including any water introduced by PCP 150 during rinsing.

[0130] • The cleaning performance of PTA 165 is enhanced compared to flushing procedures that use only gas.

[0131] Figure 13 This is a cross-sectional perspective view of a fluid injection head 205 including leak detection system elements according to some embodiments of the present invention.

[0132] A common problem with PCP pumps is methane leakage at the rotating shaft seal. According to some embodiments, the fluid injection head 205 can detect leaks based on pressure measurements in a line (not shown) connected to the auxiliary port 220. The fluid injection head 205 also includes a set of main seals 225, a set of auxiliary seals 230, and a centering device 235 (which may be solid or a bearing to stabilize the seals). The line connected to the auxiliary port 220 is routed back to a low-pressure area at the ground facility to trap any leaked gas.

[0133] In addition, an automatic valve (normally closed) located in the pipeline connected to the auxiliary port 220 supports the identification of any leaks passing through the main seal 225 and determines the extent of the leak by periodically cyclically manipulating the valve in the pipeline.

[0134] In another embodiment, an additional port (not shown, but similar to port 220) is added between the seals in the set of main seals 225 to provide an early warning of seal failure.

[0135] In addition, according to some implementations, an optional additional check valve assembly can be connected to the top of FDA 135, 900, or 1100 to prevent production fluid that may leak upward through FDA 135, 900, or 1100 (when no fluid is injected into HSRS110) from flowing into HSRS 110.

[0136] Since the risk of particle concentration in PTA 165 is greatly reduced after the above flushing using the intermediate system, PCP 150 can be cyclically turned on and off, while greatly reducing the risk of PCP 150 getting stuck or well blockage.

[0137] Those skilled in the art will understand that embodiments of the present invention can be implemented in various types of hydrocarbon gas-producing wells, and not just in wells with the specific features shown in the accompanying drawings.

[0138] The above description of various embodiments of the present invention is provided to illustrate the invention to those skilled in the art. This description is not exhaustive and is not intended to limit the invention to the single embodiment disclosed. Many alternatives and variations of the invention will be apparent to those skilled in the art of the above teachings. Therefore, while some alternative embodiments have been specifically discussed, other embodiments will be obvious or readily developed by those skilled in the art. Accordingly, this specification is intended to cover all alternatives, modifications, and variations of the invention discussed herein, as well as other embodiments falling within the spirit and scope of the above invention.

Claims

1. A system for preventing solid accumulation in a gas well, the system comprising: A hollow rod column located within a production string in a well to define the annulus of the production string, the hollow rod column having a top end and a bottom end; A prime mover attached to the top of the hollow rod; A fluid distribution assembly attached to the bottom end of the hollow rod; A pump attached to the bottom of the fluid distribution assembly, and The fluid outlet is connected to the bottom end of the pump; In use: The prime mover provides power to move the hollow rod column, which moves the fluid distribution assembly and the driven element of the pump for pumping fluid upward along the annulus of the production tubing. The fluid introduced into the top of the hollow rod flows downward through the hollow rod to the fluid distribution assembly, thus determining the operating position of the fluid distribution assembly; and The operating position of the fluid distribution assembly can be selected between a first operating position that guides fluid at least through the fluid outlet and a second operating position that guides fluid into the annulus of the production column.

2. The system according to claim 1, wherein the prime mover provides power for the rotational motion of the hollow rod, the fluid distribution assembly, and the driven element of the pump.

3. The system of claim 1, wherein the fluid dispensing assembly includes a plug for opening and closing a limiting port connected to an internal spring, wherein the differential pressure between the top and bottom surfaces of the plug is capable of overcoming the tension of the internal spring and moving the plug between operating positions.

4. The system of claim 1, wherein the fluid distribution component has one or more ports that direct injected fluid into a production line or downward into a sump, or simultaneously into the production line and the sump.

5. The system of claim 1, wherein the fluid injection head at the top of the hollow rod is capable of injecting gas or water, or both, into the hollow rod.

6. The system of claim 5, wherein the fluid injection head includes a port connected to a leak detection system.

7. The system of claim 1, wherein the well is a coalbed methane (CSG) well.

8. The system according to claim 1, wherein, In the first operating position, low-speed gas flows from the fluid outlet to the sump, enabling accurate calculation of the water level in the production casing annulus.

9. The system according to claim 1, wherein, In the first operating position, high-speed fluid flows out from the fluid outlet to wash away particles in the sump below the pump, so that the particles are carried by the water in the sump through the pump and into the annulus of the production column.

10. The system of claim 9, wherein gas or water, or both, can be injected into the top of the hollow rod to assist in the sifting of particles in the collection pit or to flush the collection pit.

11. The system according to claim 1, wherein, In the second operating position, gas or water, or both, can be injected into the production column annulus to flush the production column annulus.

12. The system of claim 1, wherein the pump is a screw pump (PCP) and the driven element is a rotor located within the stator.

13. The system of claim 12, wherein the rotor includes a hollow channel that allows fluid to flow from the fluid distribution assembly to the fluid outlet.

14. The system of claim 1, wherein the fluid outlet is a fluid nozzle.

15. The system according to claim 1, wherein the hollow rod is a vacuum rod.

16. A method of operating the system according to claim 1, comprising: A first fluid differential pressure is applied to the fluid distribution assembly to control the operating position of the fluid distribution assembly and define a first operating mode of the fluid distribution assembly; A second fluid differential pressure is applied to the fluid distribution assembly to control the operating position of the fluid distribution assembly and to define alternative operating modes of the fluid distribution assembly; and The fluid distribution assembly cycles between a first operating mode and an alternative operating mode.

17. The method of claim 16, wherein the alternative operating mode is selected from a variety of available operating modes.

18. The method of claim 16, wherein a first fluid differential pressure is applied to the top of the fluid dispensing assembly to select a first operating position of the fluid dispensing assembly, and at least one of the following operating modes is enabled: • Mode A1 – Sump pressure monitoring (using gas); • Mode A2 – Sump flushing (using gas); •Mode A3 – Sump flushing (using water and gas); • Mode A4 – Sump flushing (water only); and • Mode A5 – In Modes B1, B2, or B3, after the water in the annulus of the production column has been removed (using gas and water).

19. The method of claim 18, wherein a second fluid pressure is applied to the top of the fluid dispensing assembly to select a second operating position of the fluid dispensing assembly, and at least one of the following operating modes is enabled: •Mode B1 – Production tubing flushing (water only); • Mode B2 – Production string flushing (using high-pressure gas and water); and • Mode B3 – Production string flushing (using high-pressure gas only).

20. The method of claim 19, wherein operating mode B2 or B3 is performed before operating mode A2, A3, A4 or A5 to reduce the load on the pump.

21. A system for preventing solid accumulation in a gas well, the system comprising: A hollow rod column located within a production string in a well to define the annulus of the production string, the hollow rod column having a top end and a bottom end; A prime mover attached to the top of the hollow rod; A fluid distribution assembly attached to the bottom end of the hollow rod; and A pump attached to the bottom of the fluid distribution assembly; In use: The prime mover provides power to move the hollow rod column, which moves the fluid distribution assembly and the driven element of the pump for pumping fluid upward along the annulus of the production tubing. and The fluid introduced into the top of the hollow rod flows down through the hollow rod to the fluid distribution assembly, where it is injected into the annulus of the production column.

22. The system of claim 21, wherein the fluid distribution assembly includes a plurality of check valves to prevent fluid from flowing upward from the sump to the hollow rod column, and to allow fluid to flow downward through the hollow rod column, through the fluid distribution assembly, and into the annulus of the production column.

23. The system of claim 21, wherein the fluid introduced into the top of the hollow rod is a gas.

24. The system of claim 23, wherein the gas introduced into the top of the hollow rod is pulsed.

25. The system of claim 1, wherein the fluid distribution component comprises: The outer wall of the central cavity is defined; The central cavity is fluidly connected to the outlet of the hollow rod column; At least one check valve in the outer wall; and An axial check valve located in the central cavity; Under a first differential pressure on the axial check valve in the central cavity, the check valve in the outer wall is biased closed, and the axial check valve is biased open, allowing fluid to flow from the central cavity through the axial check valve, then through the bottom of the fluid distribution assembly, and through the pump; and Under a second differential pressure greater than the first differential pressure, the axial check valve closes and the check valve in the outer wall opens, allowing fluid to flow from the central cavity through the check valve in the outer wall and into the annulus of the production tubing.

26. The system according to claim 25, wherein, Under a third pressure between the first and second pressures, the check valve in the outer wall and the axial check valve are both biased open, allowing fluid to flow from the central cavity into the annulus of the production tubing via the pump.

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