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CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0001]    The present application claims priority to U.S. Provisional Application No. 61/030,809, filed Feb. 22, 2008. 
     
    
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
       [0002]    None 
       FIELD OF THE INVENTION 
       [0003]    This invention relates to pumping fluids from the bottom of a wellhole. 
       BACKGROUND OF THE INVENTION 
       [0004]    In natural gas wells, it is common for fluids such as water to be produced that if allowed to remain in the wellhole, will choke the production of natural gas. Pumping such fluids to the surface increases the gas productivity of such wells and increases the profits of the well owners. However, most gas wells are not straight or vertical. Many have deviations and it is common to drill substantial deviations to increase well contact with the productive zone. Another reason for directional drilling is to reduce the environmental impact of oil and gas production by drilling from existing well or drilling sites with the aim of reaching out underground to new hydrocarbon bearing zones to get access to additional reserves with a minimal footprint. Such deviated wells make pumping with a pump driven by a reciprocating rod or rotating shaft unattractive as the casing is likely to be worn and breached over time. Moreover, the frictional losses increase the horsepower requirements and increases costs of production. 
         [0005]    Another challenge with pumping wells is the cost of repairing or replacing a pump. With reciprocating rod pumps, electrically driven pumps and hydraulically driven pumps, the problems with friction and deviated wells may be avoided, but even these types of pumps suffer problems and must be removed and replaced. Typically, when a problem occurs with a well, a workover rig is required to pull the pump back to the surface. It is not uncommon for a workover rig to take four days to pull a pump and then insert the repaired or replacement pump back into location. This does not take into account the availability of a workover rig. As such, the well may be offline for a week or more and seriously cut into the profitability of the gas well. 
       SUMMARY OF THE INVENTION 
       [0006]    The present invention provides an arrangement for An apparatus for producing fluids in a wellbore wherein gas is produced through one annular space and fluids are produced through a separate space; wherein the apparatus comprises casing in the wellbore and production tubing within the casing. A hydraulically driven downhole pump is located within the production tubing and attached to the distal end of a multi-channel coiled tubing string that extends to the surface of the borehole. A hydraulic power unit disposed at the surface and connected to the multi-channel coiled tubing string is arranged to provide high pressure hydraulic fluid into a first channel within the multi-channel coiled tubing string and receive hydraulic fluid through a second channel within the multi-channel coiled tubing string and together define a closed loop hydraulic fluid system where hydraulic fluid is not mixed with production fluids. With this arrangement a fluid production space is defined within the production tubing and outside the multi-channel coiled tubing driven by the hydraulically driven downhole pump and further whereby a gas production space is defined outside of the production tubing and within the casing. 
         [0007]    A process for co-producing hydrocarbon gas and produced fluids separately from a wellbore wherein the process comprises providing casing in the wellbore and inserting production tubing within the casing. A hydraulically driven downhole pump is attached to the distal end of a multi-channel coiled tubing string and then inserted into the production tubing within the wellbore. The process further includes providing high pressure hydraulic fluid from a hydraulic power unit to the distal end of the multi-channel coiled tubing string so that high pressure hydraulic fluid is delivered by the hydraulic power unit and to the downhole hydraulically driven pump and returns to the hydraulic power unit through a second channel in the multi-channel coiled tubing string thereby pumping produced fluid in the wellbore up through the annular space within the production tubing but outside the multi-channel coiled tubing string while hydrocarbon gas is produced in the annular space within the casing but outside the production string. 
         [0008]    In a further preferred arrangement of the invention, the process includes assembling the multi-channel coiled tubing as a concentric coiled tubing string with fittings to seal the bottom and top ends for pumping hydraulic fluid in a closed loop while also providing simpler processes for pulling and replacing the pump in the event of pump failure and other downhole issues. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0009]    The invention, together with further advantages thereof, may best be understood by reference to the following description taken in conjunction with the accompanying drawings in which: 
           [0010]      FIG. 1  is a fragmentary view of the coiled tubing string connected to a hydraulic pump illustrating the gas production annular space, the liquid production annular space and the closed hydraulic system for driving the hydraulic pump; 
           [0011]      FIG. 2  is a somewhat schematic perspective view of a production skid at the surface adjacent a hydrocarbon producing well; 
           [0012]      FIG. 3  is a cross section of a first embodiment of a coiled tubing string for use with the present invention; 
           [0013]      FIG. 4  is a cross section of a second embodiment of a coiled tubing string that is suitable for use with the present invention; 
           [0014]      FIG. 5  is a perspective view of the pump adaptor; 
           [0015]      FIG. 6  is a perspective view of the return fitting; 
           [0016]      FIG. 7  is a perspective view of the stinger; 
           [0017]      FIG. 8  is an elevation view of the top end coiled tubing fixture; and 
           [0018]      FIG. 9  is a schematic top view of an alternative embodiment of a production skid at the surface adjacent a hydrocarbon producing well. 
       
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
       [0019]    This invention relates to producing water and other fluids in a gas well where the fluids must be produced to avoid restricting the production of hydrocarbon gas. As best seen in  FIG. 1 , the invention is generally indicated by the numeral  10 . The invention  10  is positioned within a well that has been drilled or bored into the ground and in which a string of casing  12  has been inserted. It is conventional for the casing to extend below the surface S down through the ground into a production zone  14 . The production zone  14  is where the gas and fluids permeate toward the casing  12  and enters the production well  15  at the base of the casing  12 . Fractures (not indicated) are created in the casing  12  in the proximity of the production zone  14  so that, according to conventional procedures, the gas permeates from the production zone  14  and into the production well  15 . 
         [0020]    Within the casing  12  is positioned a production tubing  18  through which any fluids may be produced to the surface. The gas in the production well  15  is produced through the annular space between the outside of the production tubing  18  and the inside of casing  15  as indicated by arrows  19 . The gas is directed through a valve  21  and piping  22  to a production meter and a gathering system and perhaps other post production treatments before it is conveyed to market. 
         [0021]    Near the base of the production tubing  18  is a hydraulically driven downhole pump  30 . Various hydraulic pump styles will be useful with the present invention, however, it is preferred to use a hydraulic diaphragm pump also called a hydraulic diaphragm insert pump or HDI pump. The preferred HDI pump is available from SmithLift, a division of Smith Industries, Inc. The hydraulically driven downhole pump  30  is arranged at the base of the production tubing  18  so as to draw water and other produced fluids that settle in the production well  15  up into the production tubing  18  through a nipple  24  at the base of the production tubing  18  and up through standing valve  25 . As is conventional, once the fluids pass through the nipple  24  and standing valve  25  into production tubing  18 , the fluids are not permitted to drain back into the production well  15 . In the event that the hydraulically driven downhole pump  30  is pulled out of the production tubing  18 , water is allowed to fill the space it occupied and the standing valve  25  maintains the fluid level within the production tubing  18 . Having fluid in the production tubing provides head pressure to maintain well control. In operation, the hydraulically driven downhole pump  30  pushes the fluids up through the production tubing  18  to the surface as indicated by arrows  31  until the fluids are collected through valve  33  and piping  34 . It is not uncommon for the fluids to include valuable hydrocarbon fluids so their collection may be quite profitable. While any water may require treatment to separate valuable fluids and may be disposed of by re-injection or other environmentally acceptable disposal means, there is another potential problem if the hydrocarbon fluids include amounts of paraffins. At lower temperatures, the paraffins may form waxy deposits in the production tubing  18  that may restrict or plug the annular space and impede the removal of the fluids from the gas production zone  14 . 
         [0022]    Within the production tubing  18  is a multi-channel coiled tubing string  50 . In the preferred embodiment and referring to  FIG. 3 , the multi-channel coiled tubing string  50  includes a concentric coiled tubing string  51  having a smaller diameter inserted within a larger diameter coiled tubing string  52 . With this concentric coiled tubing string, axial channel  54  is defined which is separate from annular channel  55 . For comparison, referring to  FIG. 4  is a second embodiment of a coiled tubing string  150  having side by side channels defined by the outer wall  151  and a continuous web section  152  that separates a first channel  154  from a second channel  155 . Other structural arrangements for coiled tubing having multiple channels would also be useful with the present invention. With multiple channels, the third and subsequent channel may be used for pump or other well control or may be adapted to carry the produced liquids to the surface through an additional channel 
         [0023]    Turning back to  FIG. 1 , the hydraulically driven downhole pump  30  is connected to the base or distal end of coiled tubing string  50  so as to be inserted into position by a coiled tubing unit as the coiled tubing string  50  is inserted into the production tubing  18  of the wellbore. A coiled tubing unit is generally smaller, less expensive and is operated with fewer people than a workover rig. With no joints to assemble or disassemble, coiled tubing may be quickly inserted into a borehole, withdrawn and re-inserted. With the hydraulically driven downhole pump  30  attached to the bottom or distal end of the coiled tubing string  50 , the pump is also quickly and easily installed, retrieved and replaced as compared to the same job being performed by a workover rig that uses thirty foot segments of pipe or rod connected by threaded joints at each end. 
         [0024]    In operation, the hydraulically driven downhole pump  30  is driven by a hydraulic drive unit generally indicated by the numeral  60  at the surface. Hydraulic drive unit  60  includes a hydraulic power unit  62  sometimes called a hydraulic pump but to avoid confusion with pump  30  the term “hydraulic power unit” is employed. The hydraulic power unit  62  is of conventional design that draws hydraulic fluid from reservoir  64  and delivers high pressure hydraulic fluid through tubing  66 . Referring to  FIG. 2 , hydraulic power unit  62  may be driven by an internal combustion engine  72  or other suitable drive unit such as an electric motor. In the field, it is conventional to use whatever power source is available and cost effective. Mounting equipment for use in the field on a skid unit such as skid unit  74  is well known. As such, the internal combustion engine  72  is shown mounted on a skid unit  74  along with hydraulic power unit  62 . 
         [0025]    Referring back to  FIG. 1 , the hydraulic fluid is directed into the first axial channel  54  to provide high pressure fluid to the hydraulically driven downhole pump  30  at the distal end of the coiled tubing string  50 . The high pressure hydraulic fluid is preferably provided continuously at a relative constant pressure as compared to a push/pull stroke from the surface. The high pressure hydraulic fluid may run over vanes to cause rotational motion of the pump  30  and therefore pumping of the fluid or, as preferred, the high pressure hydraulic fluid is directed through valves in the hydraulic pump that causes positive displacement of the fluids in the annular space inside the production tubing  18  and outside the coiled tubing string  50 . 
         [0026]    As is known in the pumping arts, a positive displacement pump will cycle from drawing fluid into a chamber through one or more one-way valves in one stroke and then push the fluid out of the chamber through a reverse stroke through one or more one-way valves that lead to the desired space for the fluid. The preferred embodiment of the present invention seeks to take advantage of known systems utilizing valving in the pump that allows the pump to extend through a full stroke and then actuated by the completion of the stroke and begin to use the source of high pressure to reverse the stroke and cycle back and forth pushing fluids to the surface. Considering the depth of some wells, having the valving to reverse the stroke at the surface with the hydraulic power is not preferred as delays from sensing the end of the stroke and over pressure situations are likely to occur. Pump reliability is an issue with pumps in wells and while the present invention is intended to help minimize the cost of deploying and replacing pumps, anything to improve the reliability of pumps improves the bottom line for the well owner. 
         [0027]    So in preferred operation, the high pressure hydraulic fluid is directed down the axial channel  54  of the concentric coiled tubing  50  and follows the path shown by arrow  56 . The high pressure hydraulic fluid is then used by the hydraulically driven downhole pump  30  to drive fluids up the annular space outside the coiled tubing  50  and inside the production tubing  18  to follow the path indicated by the arrows  31 . At the same time, the hydraulic fluid used by the hydraulically driven downhole pump  30  flows back to the surface in an annular channel  55  along a path indicated by arrows  57  and back to reservoir  64  through tubing  65 . With the fluids withdrawn from the production well  15 , the gas production flows up the annulus outside of the production tubing  18  and within the casing  12  along a path indicated by arrows  19 . It should be noted that the hydraulic fluid is not permitted to mix with the production fluids and that there are at least four distinct and separate flow channels created within the casing  12  by the production tubing  18  and the multi-channel coiled tubing  50 . One flow channel is downward and three are upward. 
         [0028]    In another aspect of the present invention, as more particularly shown in  FIG. 2 , the internal combustion engine  72  may be used to drive other systems at the well. As shown, gas compressor  82  is shown being driven by belt  75  along with hydraulic power unit  62 . Sharing the power source for different systems reduces costs and improves the bottom line for marginal wells. In addition, since multiple wells are being drilled from existing or common drill sites, it is another aspect of the invention to operate hydraulic pumps for several wells based on a common internal combustion engine  72 . In such an arrangement, the internal combustion engine may be run continuously and the various demands of different wells and compressing the produced gas from one or more wells while the control systems may operate the various hydraulic pumps on an intermittent basis. 
         [0029]    In the preferred embodiment, the hydraulic fluid directed down the axial channel  54  and back up the annular channel  55  of the coiled tubing sting  50  comprises a water based biodegradable hydraulic fluid that will cause little if any hazard if there is a spill or leak. It certainly will be recognized by those skilled in the art that any hydraulic fluid can be used to operate the pump. 
         [0030]    In the most preferred embodiment, concentric coiled tubing string  50  comprises two coiled tubing strings. The first is a ¾″ coiled tubing string (power-string) placed inside of a 1½″ coiled tubing string (return-string). The high pressure hydraulic fluid is pumped from the surface down the ¾″ coiled tubing string. The return fluid is directed up the annular channel  55  outside of the ¾″ inner coiled tubing string  51  and the inside of the 1½″ outer coiled tubing string  52 . The concentric coiled tubing strings are sealed on bottom with a stinger and receiver seal-assembly combination as are known. The concentric coiled tubing strings are sealed at the surface with a combination of fittings as are also known by those using coiled tubing. The concentric coiled tubing, seal assembly and associated fittings ensure that the hydraulic fluid is contained within the closed-loop throughout the pumping process. 
         [0031]    Concentric coiled tubing is not new. However, it is not generally available from coiled tubing manufacturers or vendors. The inventors have developed a new and inventive procedure to insert a smaller diameter coiled tubing string into a larger coiled tubing string and, if necessary, to easily remove it. The process begins onsite at the well with production tubing  18  already installed within the casing  12 . Referring to  FIGS. 5 and 6 , return fitting  71  is attached to the bottom end of the outer coiled tubing string  52  while the outer coiled tubing string is still wound on the coiled tubing unit. Preferably, the end  72  is welded to the bottom end of the outer coiled tubing string  52 . Pump adaptor  81  is connected by screw threads  84  into screw threads  74  of return fitting  71 . Upper receiver end  85  of pump adaptor  81  extends up inside returning fitting  71  so that the outer surface of the upper receiver end  85  forms an annular space within the inner surface  73  of return fitting  71 . The connection between the return fitting  71  and the pump adaptor  81  is preferably sealed by suitable o-rings  87 . A cap (not shown) is attached over screw threads  88  and sealed by o-ring  89  and the entire length of the coiled tubing string  52  is filled with a suitable well control fluid. 
         [0032]    The outer coiled tubing string  52  is then run into the production tubing  18  until the cap comes into contact with the standing valve  25 . The outer coiled tubing string  52  is then cut to length and the coiled tubing unit associated with the larger diameter outer coiled tubing string  52  is moved away from the well. The smaller diameter inner coiled tubing string  51 , still wound on a coiled tubing unit spool, is provided with stinger  91  attached to the bottom end thereof. Preferably, the top end  92  of stinger  91  is welded onto the end of the smaller diameter inner coiled tubing string and the coiled tubing unit is arranged to then insert the smaller diameter inner coiled tubing string  51  into the outer coiled tubing string disposed within the production tubing  18 . Tapered end  93  of stinger  91  eventually stings into the open end of the pump adaptor  81  and seal against the interior of the upper end thereof with o-rings  94 . At the top end of the coiled tubing strings, a top end coiled tubing fixture  111  shown in  FIG. 8  is attached to the outer coiled tubing string  52 . The top end coiled tubing fixture  111  comprises two components that are connected by screw threads. The first component  112  comprises a first end  113  for insertion into the outer coiled tubing string  52 . The first end  113  includes a longitudinal outer surface groove  114  to align with any welding seam in the coiled tubing. The first component  112  is intended to have a tight fit with the outer coiled tubing string and may be hammered to fully seat the collar  115  to the end of the outer coiled tubing string  52 . Once in place, the first component  112  of the fixture is welded to the outer coiled tubing string  52  so as to seal the two together. The second component  121  attaches to the first component  112  by screwing the threads  122  into the threads  116  of the first component and the free end is configured with radial grooves  124  and o-rings  125  for having a tail section (not shown) of coiled tubing crimped thereon for pulling the concentric coiled tubing out of the well on wound onto coiled tubing unit spool. With this arrangement, each time the coiled tubing and pump are pulled and re-installed, the length of the two coiled tubing strings are preserved. 
         [0033]    The first coiled tubing unit is then moved into position over the well to connect to the upper end of the second component  121  of top end coiled tubing fixture  111  to withdraw both coiled tubing strings  51  and  52 . In another aspect of the present invention, it is not uncommon for scale and other surface debris to become loosened from the inner surface of both strings of coiled tubing. As such, the debris may pose a risk to the long term operation of the hydraulic pump and it is preferred that such debris is removed from the systems. In respect of this concern, once the two strings of coiled tubing are installed into the well and then pulled in preparation for installing the hydraulic pump, the bottom end of the two strings are opened by the removal of the cap that was attached to the end of the pump adaptor at threads  88 . Cleaning fluid may be pumped through the coiled tubing while wound on the coiled tubing unit and filtered and recycled until the operator is satisfied that any loosened particles have been washed out of the system. With this simple step, it is anticipated that operational availability of the pump has been extended. 
         [0034]    The hydraulically driven downhole pump  30  is then attached to the screw threads  88  so that the hydraulic fluid inlet of the pump is connected to fitting  101  and the hydraulic fluid outlet flow passes through the pump adaptor  81  and into the annular channel  55  through holes  82 . Holes (not shown) are positioned at the bottom of the pump adaptor  81  between the screw threads  88  and fitting  101  which are in fluid communication with holes  81  so that low pressure hydraulic fluid then passes up through the annular channel  55 . Once the hydraulically driven downhole pump  30  is attached to the end of the concentric coiled tubing strings  51  and  52 , and the string is inserted into the production tubing so that the hydraulically driven downhole pump  30  engages with standing seal  25 , the coiled tubing strings  51  and  52  may also be cut to length and provided with fittings for connection to tubing  65  and  66 . 
         [0035]    As noted above, a particular advantage of the present invention is that a single coiled tubing unit may quickly pull the multi-channel coiled tubing string out of the well with the pump attached. However, if the pump or coiled tubing string is stuck or gets stuck while being pulled, a new problem emerges. When it is clear that the coiled tubing will break under the tension of the unit against the “stuck” pump, the coiled tubing can be withdrawn by an inventive technique to minimize the hassle and time involved with recovering the pump and getting the well back into service. If the tubing is cut off at the surface and a workover rig is called in to withdraw the production tubing, additional coiled tubing will have to be cut as each joint of production tubing is broken apart. With a production tubing string being many thousands of feet, significant additional time could be wasted cutting the coiled tubing or worse yet, cutting two strings concentrically disposed. In the inventive process, the inner coiled tubing string  51  is withdrawn by un-stinging the stinger  91  from pump adaptor  81 . Then a wireline free point tool may be inserted into the outer tubing. The wireline free point tool is able to measure minute stretching in the tubing and by sequentially pulling and releasing the tubing can determine “free point” or the lowest point at which the tubing is “not stuck”. Weatherford International Ltd is a well known oil field services company that provides such free point tools and services. The free point tool is removed and a chemical or explosive cutting tool is run down into the outer coiled tubing string to a point just above free point to cut the outer coiled tubing string  52  so that the coiled tubing unit can pull the free portion of the coiled tubing string out of the production tubing. Then the workover rig can then pull the production tubing  18  and only deal with the length of stuck coiled tubing attached to the pump  30 . Once the pump is recovered, the production tubing  18  and pump  30  along with the multi-channel coiled tubing may be re-installed in the well to return it to productive service. 
         [0036]    In another aspect of the present invention, wells that produce a lot of gas and fluid generally remain fairly warm as the fluids entering the wellbore retain the heat energy of the formation. However, in circumstances where small amounts of gas and fluids are produced, cool nights may allow water to freeze inside the well bore and for paraffinic hydrocarbons to congeal as wax. In one embodiment of the invention, such problems can be addressed by an arrangement shown in  FIG. 9 . A skid unit  274 , which is similar to skid unit  74  in  FIG. 2 , is illustrated with an internal combustion engine  272  to drive the hydraulic power unit  262  and a gas compressor  282  by belts  275 A and  275 B, respectively. The internal combustion engine, as is conventional, is cooled by a fluid jacket in which coolant is pumped through and into a radiator  276 . However, in the present invention, the coolant is first directed to a liquid/liquid heat exchanger  267  via conduit  277  where some of the engine heat is transferred to the hydraulic fluid used to drive the hydraulically driven downhole pump  30  at the base of the well. Coolant exits heat exchanger  267  via conduit  278  and enters radiator  276  and eventually returns to the engine  272 . In  FIG. 9 , the hydraulic fluid is driven by hydraulic power unit  262  through conduit  266  to liquid/liquid heat exchanger  267 . In the heat exchanger  267 , heat is transferred from the engine coolant to the hydraulic fluid and the heated hydraulic fluid is then carried to the well via conduit  269 . The warm hydraulic fluid then transfers some of its heat to the well to prevent or at least reduce the likelihood of ice forming downhole and prevent wax buildup by keeping any paraffins in the liquid above their cloud point temperature. The temperature of the hydraulic fluid may be maintained to be sufficiently above ambient air temperature with little operating cost and will maintain the wellbore and pipes therein well above freezing and above the cloud point of any paraffin in a gas well. It should be understood that it is preferred for the heat exchanger  267  to heat the hydraulic fluid prior to entering the well so that the hydraulic is warmest as it enters the well and is coolest when entering the hydraulic power unit  262 . 
         [0037]    Finally, the scope of protection for this invention is not limited by the description set out above, but is only limited by the claims which follow. That scope of the invention is intended to include all equivalents of the subject matter of the claims. Each and every claim is incorporated into the specification as an embodiment of the present invention. Thus, the claims are part of the description and are a further description and are in addition to the preferred embodiments of the present invention. The discussion of any reference is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application.

Summary:
This invention relates to a coiled tubing installed and operated hydraulically driven downhole pump for hydrocarbon wells and especially hydrocarbon gas wells that are prone to produce fluids that choke gas production. The hydraulically driven downhole pump is driven by a closed loop surface positioned hydraulic power system. Should the hydraulically driven downhole pump become inoperative, it may be quickly retrieved and immediately replaced using a coiled tubing unit as compared to a workover rig. A coiled tubing unit is able to pull the coiled tubing string and re-install the string quite rapidly because the coiled tubing does not have joints that need to be disassembled or reconnected. The manpower needs and costs for replacement are considerably less and lost production of the well is substantially reduced.