Abstract:
The pump and pump system of the present invention is designed to remove liquids, gas, sand and coal fines from gas and/or oil well bores. There is a need in the oil and gas industry to develop a more efficient operating pump that is capable of operating in wells that do not have enough bottom hole pressure to lift liquids to the surface causing the well to log off with fluids and if not economic, potentially be plugged prematurely. Additionally, this design will allow the producer the ability to conduct well bore maintenance such as acid flushes for perforation cleaning and scale batch treating for continued scale treatment.

Description:
RELATED APPLICATIONS 
   This application claims the benefit of prior filed copending U.S. Provisional Application No. 60/327,803 filed Oct. 9, 2001, and is a 371 of PCT/US02/32462 filed Oct. 9, 2002. 

   FIELD OF INVENTION 
   The present invention relates generally to a pump system for removing natural hydrocarbons or other fluids from a cased hole, i.e. a well bore. More particularly, the present invention relates to a novel downhole, gas-driven pump particularly suitable for removing fluids from gas-producing wells. 
   BACKGROUND OF THE INVENTION 
   Increasing production demands and the need to extend the economic life of oil and gas wells have long posed a variety of problems. For example, as natural gas is produced, from a reservoir, the pressure within the reservoir decreases over time and some fluids that are entrained in the gas stream with higher pressures, break out due to lower reservoir pressures, and build up within the well bore. In time, the bottom hole pressure will decrease to such an extent that the pressure will be insufficient to lift the accumulated fluids to the surface. In turn, the hydrostatic pressure of the accumulated fluids causes the natural gas produced from the “pay zone” to become substantially reduced or maybe even completely static, reducing or preventing the gases/fluids from flowing into the perforated cased hole and causing the well bore to log off and possibly plugged prematurely for economic reasons. 
   The oil and gas industry has used various methods to lift fluids from well bores. The most common method is the use of a pump jack (reciprocating pump), but pump jack systems have given rise to additional problems. Pump jack systems require a large mass of steel to be installed on the surface and comprise several moving parts, including counter balance weights, which pose a significant risk of serious injury to operators. Additionally, this type of artificial lift system causes wear to well tubing due to pumping rods that are constantly moving up and down inside the tubing. Consequently, pump jack systems have significant service costs, which negatively impact the economic viability of a well. 
   Another known system for lifting well fluids is a plunger lift system. The plunger lift system requires bottom hole pressure assistance to raise a piston, which lifts liquids to the surface. Like the pump jack system, the plunger lift system includes numerous supporting equipment elements that must be maintained and replaced regularly to operate effectively, adding significant costs to the production of hydrocarbons from the well and eventually becoming ineffective due to lower reservoir pressures than are required to lift the piston to the surface to evacuate the built up liquids. 
   Thus, there is a need for a safer, longer lived, and more cost effective pump system that effectively removes liquids from well bores that do not have sufficient bottom hole pressure to lift the liquids to the surface. 
   SUMMARY OF THE INVENTION 
   It has now been found that that above-referenced needs can be met by a downhole pump system that powered by gas, preferably the gases produced from the subject well or wells. Specifically, the pump system includes a pump housing having an engine end and a pump end. Disposed within the engine end of the pump housing is an “engine” having impeller or turbine-type blades fixably connected to a shaft disposed within said housing. Upon supplying pressurized gas to the engine-end blades being the shaft rotates. A “pump” is disposed within the pump end of the housing, the pump comprising blades (preferably impeller-type) fixably connected to the same shaft. Upon the rotation of the shaft the pump-end blades lift the well fluids from the well. 
   In a preferred embodiment of the invention, the gas that drives the pump is provided through a tubing string attached adjacent the engine end of the pump housing and that tubing string is disposed within a larger diameter production tubing string. In this configuration well fluids are produced through the annulus formed between the production tubing string and the smaller diameter tubing string holding the pump. 
   In another preferred embodiment of the invention, the pump housing has an outer diameter of at least 3.25 inches. 
   In yet another embodiment of the invention, a method of producing fluids from a well is provided whereby a gas (preferably the gas from the subject well or wells) is supplied to a pump disposed in a well, the pump including (1) an engine portion that is powered by said pressurized gas and effectuates a rotation of a vertical shaft disposed within said pump and (2) a pump portion that lifts fluids from said well by blades disposed within said pump portion affixed to said rotating shaft. In a preferred embodiment of this method a compressor is used to control the pressure of the gas and a separator disposed upstream from the compressor to separate liquids from the gas. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
     For a more complete understanding of the present invention and for further advantages thereof, reference is now made to the following description, taken in conjunction with the accompanying drawings, in which: 
       FIG. 1  is cross section view of the down-hole pump of the pump system in a preferred embodiment of the invention. 
       FIG. 2  is a schematic view of the down-hole pump and system of a preferred embodiment of the invention. 
       FIG. 3  is schematic view of the down-hole pump and system of an alternative embodiment of the invention. 
       FIG. 4  is a schematic view of the down-hole pump of another alternative embodiment of the invention. 
       FIG. 5  is a schematic view of the down-hole pump of another alternative embodiment of the invention. 
   

   DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
   The present invention is a novel pump and pump system for use in the removal of liquids from wells, especially, but not limited to, wells that have insufficient bottom hole pressure to lift the well liquids out of the well bore and to the surface. Referring to  FIGS. 1 and 2 , a first preferred embodiment of the present invention shall be described.  FIG. 1  and  FIG. 2  illustrate a section of a typical hydrocarbon well completion, which includes a casing string  100  with perforations  102  adjacent the hydrocarbon- producing formation and a production tubing string  104  with perforations  106 . The production tubing  104  is installed with a down hole standing valve or check valve  120  in the cased hole or well bore. Preferably, the check valve/standing valve  120  is threaded onto the bottom of the production tubing  104 , just above a perforated tubing sub  122 . This configuration allows for the pump  10  and 1″ tubing  110  to be removed without exposing the formation to any produced fluids and/or material that are captured inside of the annulus  108  between the production tubing  104  and the 1″ tubing  110 . In the event that a need was presented requiring the release of this fluid, the bottom of the standing valve (ball and seat)  120  could be knocked off and a “Slickline” tool could be used to remove the standing valve. Additionally, the operator would have the option of removing the liquids out of the tubing by means of forced air or any other type of pressure through the annulus that would make the tubing void of any fluids or material prior to removing the standing valve  120 . 
   The pump of the present invention, generally  10 , is disposed within the production tubing string  104  at a depth adjacent perforations  102  in casing  100 . Production tubing string  104  and casing  100  are conduits whose use, construction and implementation are well known in the oil and gas production field. Pump  10  includes an engine end  12  and a pump end  14 , both encased in barrel  16 . The pump, as shown in the embodiment of  FIGS. 1 and 2 , is designed to fit within the well&#39;s production tubing and its size is determined by a number of factors, down hole temperatures, such as production tubing size, casing size and the amount of liquids and/or particulates (e.g., sand and coal fines) to be removed. 
   In a preferred embodiment on the invention shown in  FIG. 1  and  FIG. 2 , pump  10  is attached at the end of a 1-inch diameter (outer diameter) tubing string  110 . Preferably, the pump is threaded onto the bottom of the 1-inch tubing and inserted into the production tubing  104 , setting the pump into a standard API seating nipple  130  and hanging the top of the 1-inch diameter tubing  110  in a set of tubing slips that are part of the wellhead on the surface. As shown, tubing string  110  and pump  10  are disposed within the production tubing string  104 , which is disposed within casing  100 . For the purposes of this invention, pump  10  need not be disposed entirely within production tubing string and may extend below the lower end of the production tubing string in the embodiment shown. 
   Although shown as one inch tubing, the tubing string  110  that supports pump  10  is not limited to one inch tubing and is preferably sized to meet the particular needs of the well. For example, tubing string  110  may comprise larger diameter tubing if large amounts of liquid are produced and must be lifted from the well. In sizing the tubing string  110 , there are several factors to be taken into consideration, including the required feeding pressure/gas volume required to operate the engine end of the pump, the tensile strength of the tubing that the operator desires in the wellbore, the size of the production tubing, the size of the well casing, and the amount of fluids that are calculated to be removed from the wellbore. 
   Alternatively, instead of attachment to the end of a 1-inch tubing string disposed within a production tubing string, pump  10  can be attached (threaded attachment) to the end of the production tubing string  104  or the tubing string nearest the face rock (see  FIG. 3 ). In this alternative embodiment, a seal assembly would be disposed at the top of pump  10  into which a tubing string or pipe can be inserted to supply appropriate gas pressure to the engine end of the pump. 
   Referring to  FIG. 1  and  FIG. 2 , the pump  10  and pump system shall be described. The components of pump  10  are encased in a cylindrical steel housing (pump barrel)  16  much like conventional, well-known rod pumps. The pump and its components can be constructed of any suitable material, such as stainless steel, which will enable it to be utilized in harsh or corrosive conditions. External seating cups  132  are disposed on the pump barrel, to isolate the engine end gas from the produced hydrocarbons, when utilized in the smaller diameter tubing. The seating cups  132  rest upon a seating nipple  130  installed in the production tubing  104 . 
   As stated previously, the pump includes an engine end  12  and a pump end  14  disposed within the housing  16  ( FIG. 1 ). The engine end and the pump end may be separated by a permanent packed bearing, maintenance free needle or metal to metal type bearing  40  (preferably high temperature) and are operably connected by a common rod or shaft  42  that extends into the engine and pump ends of the pump  10 . Additionally, both ends of the pump preferably include stabilizer permanent packed or maintenance free bearings  44  and  46  (preferably high temperature) with ports  45  and  47  for fluid and/or gas entry. This arrangement allows the pump to operate in a vertical or any angle, including all the way to a horizontal position without a loss of efficiency or unnecessary pump wear. Attached to the shaft  42  in the engine end  12  of the pump are blades  50  that are pitched to move fluids (especially gas) away from the ported bearing  44  in the engine end. Although blades  50  are shown as impeller blades, in a preferred embodiment blades  50  are not impeller-type blades, but instead is a turbine type blade design such as that disclosed in U.S. Pat. No. 4,931,026 (see reference numeral  14 ), which is hereby incorporated by reference. 
   Still referring to  FIGS. 1 and 2 , exhaust ports  60  are provided in the engine end of the pump above bearing  40  to allow the driving gas to exhaust from the engine end of the pump. These exhaust ports are provided with a ball check valve  62  that opens under pressure from the driving fluids and closes to prevent fluid from entering the engine end through the exhaust ports when the pump is idle (See  FIG. 3 , reference numerals  60 ,  62 ,  64  and  66  for ball check valve configuration). Attached to the shaft in the pump end  14  of the pump are blades  52  (axial impeller blades) that are pitched to move fluids upward toward exhaust ports  64  in the pump end  14 . Exhaust ports  64  are provided with a ball check valve  66  that opens when fluids are being lifted by the moving blades  52  in the pump end and closes to prevent fluid from entering the pump end through the exhaust ports  64  when the pump is idle. As shown ( FIGS. 1-3 ), the axial turbine/turbines in the engine end are driven by pressurized (gas) to create the correct amount of torque and/or revolutions per minute (RPM) of the shaft to create substantially reduced pressures at the pump inlet ports via the axial impellers in the pump end. 
   In a preferred embodiment of the invention, pump  10  would be driven by the natural gas produced from the well. Generally, natural gas from the producing formation and/or formations will flow up the production tubing or the annulus  109  between the production tubing and the casing  100  to a separator  200  at the surface, which then feeds a surface compressor  210 . Preferably, the surface compressor/compressors  210  would be designed to have sufficient engine horsepower (HP), engine and gas water cooling, and compressor design, to exceed the highest pressure required to move the static column of fluid that will exist if the pump were to become idle. Additionally, the compressor preferably would be versatile enough to adapt to a wide range of inlet and discharge pressures without rod loading the compressor or having the engine die due to not enough HP. This versatility would allow the operator to adjust the discharge pressure or gas volume that feeds the pump engine. This would further allow the operator to adjust the surface pressure feeding the compressor  210  from the surface separator  200 , thereby allowing the operator to achieve optimum well bore protection and gas/oil flow. 
   In the arrangement shown (see  FIG. 2 ), the pressure relieved off of the producing formation can be controlled utilizing the inlet control valve  202  on the surface separator which may prevent damage to producing sands/shale&#39;s. At the discharge line of the compressor  210  a pipe “tee”  212  would be installed with a line  214  being laid back to the well bore to connect to the 1″ diameter (or larger) tubing (the “drive line”) to which the pump  10  is connected and a second line  216  extends from the tee joint to a sales line. At this stage, any chemicals required to produce the well such as paraffin, methanol for hydrates prevention, and corrosion can be injected into the 1″ tubing  110 , and swept down to the engine end  12  of the pump  10 . A standard type of continuous injection chemical pump (e.g., natural gas or electric), and either a threaded or welded ½″ collar installed on the pipe for the injection point are suitable for this purpose. This will allow the chemicals to have contact with produced fluids to perform their functions while providing maximum protection for the producing horizon/horizons from coming in contact with these chemicals. 
   Continuing with the description of the preferred process/method of operation, a portion of the pressurized gas from the compressor  210  is discharged through the tee joint  212  into the 1 inch drive line  110 , with the remainder of the pressurized gas being discharged into the sales line  216  to continue on to sales. The amount of gas needed to be directed to drive the pump  10  is adjustable by operation of an adjustable valve  218 . For example, the adjustment of the amount of gas can be achieved utilizing a manual choke that can be locked at different settings or with a motor valve that can be operated either with a pneumatic pressure controller alone or utilizing remote communications technology. The amount of gas needed to operate the pump  10  will be dependent upon the pitch of the blades, length of the “axial turbine” in the pump barrel, and the pressure required to lift the annular fluids, as well as other factors. 
   As illustrated in  FIGS. 1 and 2  (gas path indicated by arrows), the drive gas discharged into the tubing string  110  enters the pump through the ported bearing  44  at the engine end  12 . The pressurized gas entering the engine end then acts upon the blades  50  causing the blades and shaft  42  to rotate. Then, the pressured driving gas (fluid) is exhausted from the engine through the exhaust ports  60  located just above the isolation bearing  40  and into the annulus  108  between the one-inch tubing string and the production tubing. With the common shaft rotating, the blades  52  in the pump end  14  rotate as well, causing a vacuum (or suction) effect which draws fluid from the well through the ported bearing  46  at the pump end. The well fluids drawn into the pump end  14  are then forced toward and through the exhaust ports  64  located just below the isolation bearing  40  and into the annular space  108  between the 1-inch tubing  110  and the production tubing  104 . The well fluids then combine with the driving fluids in this annular space and flow toward the surface and to the separator  200 . The mixture of the produced liquids and the natural gas utilized for power, will create a lighter gravity fluid in the annular space  108  between the production tubing and the 1-inch tubing allowing for less force (pressure) to be required to lift both to the surface for separation.  FIG. 2  illustrates the flow of gas (arrows indicating flow) in a preferred embodiment of the pump system. 
   As is evident from the description above, the preferred process is repetitive, thus keeping the well bore clear of produced liquids and sand while allowing less back pressure on the face rock. By producing up the casing annulus without the back pressure or friction losses generally created by free liquids, the face rock or producing horizon will yield additional amounts of gas and/or oil. This will extend the life of the well, thus enabling the operator to recover potential incremental reserves that may be otherwise uneconomic to produce utilizing existing conventional artificial lift methods. 
   Further, although the ball check valves used at the exhaust ports in both the engine and pump ends of the pump have the primary purpose of preventing/reducing back flow of fluids into the pump, they also provide a secondary benefit of allowing pressure testing of the production tubing from the surface to check for any mechanical failures. This may be done utilizing a pump truck that fills the annulus between the 1-inch and the production tubing with a neutral fluid, usually produced or salt water, and then pressures up to a calculated pressure. Significant pressure leak-off may indicate that a mechanical failure of the 1-inch tubing has occurred. This can be determined by an increase in pressure in the 1-inch tubing as the annulus pressure depletes. The ball checks prevent the test fluids (and any debris or other foreign material) from entering the pump. Should the 1 inch tubing not show a mechanical failure then the operator can evaluate if a rig is required to remove or unseat the pump and again apply pressure to the production tubing to see if leak off occurs. This would determine if the mechanical failure is in the production tubing. The check valve  120  installed at the bottom of the production tubing  104  would allow for this test procedure. 
   Additional benefits can be derived from the system described herein. For example, the system described above provides a means to increase liquid removal from produced gasses. Simultaneously acting with the process above will be an effective method of liquid removal from the compressor discharge gas prior to sales or custody transfer of the gas. This will occur due to the reduction of gas pressure utilized for driving the pump engine to the existing sales line pressure. The hot gas from the discharge of the compressor that is not utilized for operation of the pump will cool when it is controlled or experiences a pressure drop caused by the separator inlet controller. This will cause some of the entrained water and/or oil condensate to separate out of the sales gas stream and be recovered, utilizing the surface equipment on location. Thus, in the preferred embodiment of the invention, the primary (three-phase) separator  200  would remove all free liquids that are initially removed from the wellbore prior to feeding the pressure to the inlet of the compressor  210 . Then all produced liquids and any excess gas that is not utilized in the process of operating the pump and will be controlled or choked back down to the sales-line pressure utilizing an inlet control valve  222  installed on a second (two-phase) separator  230  that removes produced liquids and liquids that have fallen out of the gas stream due to pressure drop, allowing less saturated “cleaner” gas to continue on to the sale line  216  at line pressure and temperature. 
   Referring to  FIG. 3 , there is shown an alternative embodiment of the pump and pump system of the present invention. The same reference numerals used above and shown in  FIGS. 1 and 2  are used in  FIG. 3  for like components and processes.  FIG. 3  depicts an alternative configuration where the pump  10  is attached directly to the production string  104  rather than a one-inch tubing string. As shown, in this alternative embodiment, the pump is not set in a seating nipple. Further, in this embodiment, it is preferred that production tubing  104  is held in place with a packer  300 . In this embodiment, the process and system functions are the same as those described above; however, the pump  10  lifts fluids through the annulus  109  between the production tubing  104  and casing  100 . These fluids are lifted and then processed at the surface as described in connection with  FIGS. 1 and 2 . 
   In another alternative embodiment of the pump system, a central compressor with a distribution piping system (holding a set pressure) can be used. This alternative configuration would give the same effect as having a wellhead compressor and is akin to a gas lift system where the power natural gas would be delivered to the well from one central site to cover several wells (e.g., 100-200 wells). In this alternative embodiment, the gas flow would be the same as that shown in  FIG. 2  and described above in connection with  FIGS. 1 and 2 , with the exception that only one surface separator would be needed. 
   Reference is made to  FIG. 4  for another alternative embodiment of the present invention. The same reference numerals used above and shown in  FIGS. 1-3  are used in  FIG. 4  for like components and processes. Accordingly, the above descriptions made in conjunction with  FIGS. 1-3  apply with respect to the alternative embodiment depicted in  FIG. 4  and will not be repeated. Like  FIGS. 1 and 2 ,  FIG. 4  depicts a configuration designed to produce well fluids between the annulus  108  formed between tubing string  110  and the larger diameter production tubing string  104 .  FIG. 4  illustrates a section of a hydrocarbon well completion, which includes a casing string  100  with perforations  102  adjacent the hydrocarbon-producing formation and a production tubing string  104  with perforations  106 . The production tubing is installed in the cased hole or well bore. In the embodiment of  FIG. 4 , check valve/standing valve  120  is a removable standing valve or vertical check valve that is installed into the seating nipple or “O-Ring” assembly  130  of the tubing string  104 . The seating nipple  130  is located at the bottom of the production string or one (1) joint of pipe up from the bottom such that it is disposed below. This configuration allows for the pump  10  and 1″ tubing  110  to be removed without exposing the formation to any produced fluids and/or material that are captured inside of the annulus  108  between the production tubing  104  and the 1″ tubing  110 . In the event that a need was presented requiring the release of this fluid, the standing valve  120  would be removed utilizing a “Slickline” tool. Additionally, the operator would have the option of removing the liquids out of the tubing by means of forced air or any other type of pressure forced down the annulus that would make the tubing void of any fluids or material prior to removing the standing valve  120 . 
   Still referring to  FIG. 4 , turbine blades or turbine means  50  are schematically depicted in the engine portion of the pump  10 . For a more detailed description and depiction of suitable pump engine turbine means reference is made to U.S. Pat. No. 4,931,026 (see generally reference numeral  14 ), which has been incorporated by reference. Because of the high rotational speed created by the turbine configuration (e.g. 20,000-30,000 rpm), it is preferred that a vertical stabilizer bearing  140  be used as shown. 
   Reference is made to  FIG. 5  for another alternative embodiment of the present invention. The same reference numerals used above and shown in  FIGS. 1-4  are used in  FIG. 5  for like components and processes. Accordingly, the above descriptions made in conjunction with  FIGS. 1-4  (including the design of pump  10 ) apply with respect to the alternative embodiment depicted in  FIG. 5  and will not be repeated. As shown in  FIG. 5 , a larger diameter pump  10  is threaded onto a larger tubing string  110  (e.g., 2⅜ inch OD tubing) than that depicted in  FIGS. 1 and 4  (1 inch tubing). In this alternative configuration, the pump  10  is located above the perforations  102  formed in larger diameter casing  100 , such as a liner top. In a preferred aspect of this embodiment of the invention, pump  10  is housed within a housing or barrel  16  having an outer diameter of at least 3.25 inches. As shown in  FIG. 5 , pump  10  is disposed within a section of 3.25 inch (OD) tubing which is threaded to a 2⅜ inch tubing section  110  above the pump  10 . As shown, pump  10  is fixed within a 4½ inch production tubing section  104  by a seating nipple or a seating cup  132  which holds the pump in place and isolates the engine end  12  from the pump end  14  of the pump. The 3.25 inch tubing section  104  is threaded below pump  10  to 2⅜ inch tubing (tail pipe)  114 . In a preferred aspect of this embodiment of the invention, a packer is set below the pump instead of a down hole standing valve. Further, as shown in  FIG. 5 , preferably a string of “tail pipe”  114  or several joints of tubing extend below the pump  10 , with the tail pipe set or landed at the optimum place in the perforations. In a most preferred configuration, the tail pipe is smaller in diameter (e.g. 1½ inch) than the tubing string  110  feeding the engine of pump (e.g., 2⅜ inch). This preferred configuration would increase velocity of fluids entering the tail pipe and would produce increased torque pressures for setting and releasing the packer. Further, this configuration will allow more gas volume and less friction loss to the engine end, and increase velocities in the smaller diameter tubing installed inside the larger casing. 
   The various embodiments of this invention have been described herein to enable one skilled in the art to practice and use the invention. Its is understood that one skilled in the art will have the knowledge and experience to select suitable components and materials to implement the invention. For example, those skilled in the art will understand that components such as bearings, seals and valves referenced herein will be selected to effectively withstand and operate in the harsh pressure and temperature environments encountered in an oilk or gas well. 
   Although the present invention has been described with respect to preferred embodiments, various changes, substitutions and modifications of this invention may be suggested to one skilled in the art, and it is intended that the present invention encompass such changes, substitutions and modifications.