Abstract:
One illustrative artificial lift method includes deriving compressed natural gas (CNG) from liquefied natural gas (LNG) and injecting the CNG into the well as a lift gas that aids in conveying fluid from the well. An illustrative system embodiment includes an evaporator and a controller. The evaporator converts LNG into CNG, which the controller injects into a well to enter a lift conduit as a lift gas to aid in conveying fluid from the well. Further disclosed herein is the use of a virtual pipeline to supply LNG for such artificial lift systems and methods. It includes: liquefying natural gas to fill a transport trailer at an offsite facility; transporting the trailer to a site of a well; and coupling the trailer to surface equipment to supply LNG as needed for supplying gas lift in the well. Once emptied, the trailer may be returned to the offsite facility for refilling.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0001]    The present application claims priority to Provisional U.S. Pat. App. No. 62/176,068, titled “Compressed and Liquefied Gas Driven Production System” and filed Feb. 9, 2015 by inventor Humberto Leniek, and relates to U.S. patent application Ser. No. ______ (Atty Dkt CTLIF-001A), titled “Liquefied Gas-Driven Production System”, by inventor Humberto Leniek, which has been filed concurrently herewith. Each of these references is hereby incorporated by reference in their entirety. 
     
    
     BACKGROUND 
       [0002]    Hydrocarbon reservoirs are generally formed by traps in the geologic structure where the less buoyant ground water is displaced by rising hydrocarbons. When these reservoirs are first accessed, the fluid in the rock pores generally enters the well with sufficient pressure to carry the fluids to the surface. However, depending on the rate at which fluids are produced, this pressure generally falls over time, reducing the natural “lift” in the well and making the well unable to continue producing at an adequate rate on its own. (The natural lift can also be inhibited by the accumulation of dense fluids that create a large hydrostatic pressure in the wellbore.) To address these issues, oil producers have developed “artificial lift”, a term that covers a wide variety of techniques for conveying fluid to the surface. 
         [0003]    For the most part, these techniques require a source of power, e.g., fuel or electricity, to drive a motor on the surface or downhole. The raw hydrocarbons produced by the well itself are generally unsuitable for use as fuel, presenting a challenge for supplying artificial lift to remotely-located wells. 
       SUMMARY 
       [0004]    Accordingly, there is disclosed herein an illustrative embodiment of an artificial lift method that includes deriving compressed natural gas (CNG) from liquefied natural gas (LNG) and injecting the CNG into the well as a lift gas that aids in conveying fluid from the well. 
         [0005]    Also disclosed herein is an illustrative embodiment of an artificial lift system that includes an evaporator and a controller. The evaporator converts liquefied natural gas (LNG) into compressed natural gas (CNG). The controller injects the CNG into a well where the CNG enters a lift conduit and acts as a lift gas to aid in conveying fluid from the well. 
         [0006]    Further disclosed herein is an illustrative embodiment of an artificial lift method employing a virtual pipeline. The virtual pipeline method includes: liquefying natural gas to fill a transport trailer at an offsite facility; transporting the trailer to a site of a well; and coupling the trailer to surface equipment to enable the surface equipment to obtain liquefied natural gas (LNG) as needed for supplying gas lift in the well. 
         [0007]    Each of the disclosed embodiments may further include one or more of the following additional features in any combination: (1) the deriving includes raising a temperature of LNG trapped in a restricted volume. (2) the LNG is transported to the well site by trailer from an offsite facility. (3) the well includes an inner production tubular defining an inner conduit. (4) the well includes an outer production tubular defining an annular conduit between the inner production tubular and the outer production tubular. (5) the outer production tubular is terminated by a check valve that permits fluid to enter the outer production tubular. (6) the inner conduit serves as the lift conduit, and the injecting is performed via the annular conduit. (7) the annular conduit serves as the lift conduit, and the injecting is performed via the inner conduit. (8) the injecting operation is paused to enable fluid to accumulate in the outer production tubular. (9) the pausing is contingent upon detecting a change in injection pressure or flow rate. (10) the pausing is contingent upon detecting a predetermined flow rate or pressure condition at an upper end of the lift conduit. (11) the injecting and pausing operations are repeated to provide intermittent lift. (12) one or more parameters of the injecting and/or pausing operations are adapted to optimize a performance measure. (13) the performance measure accounts for at least one of the following: fluid production rate; usage rate of natural gas; and a ratio of produced fluid to injected CNG. (14) a transport trailer is coupled to provide LNG to the evaporator. (15) once emptied, the trailer is replaced with a non-empty trailer of LNG. (16) the emptied trailer is returned to the offsite facility for refilling with LNG. 
     
    
     
       BRIEF DESCRIPTION OF DRAWINGS 
         [0008]    In the drawings: 
           [0009]      FIG. 1  shows an illustrative liquefied gas-driven gas-lift system. 
           [0010]      FIG. 2A  shows an illustrative gas-lift intake phase. 
           [0011]      FIG. 2B  shows an illustrative gas-lift injection phase. 
           [0012]      FIG. 3  is a function-block diagram of an illustrative artificial lift system. 
           [0013]      FIG. 4  is a flow diagram of an illustrative artificial lift method. 
       
    
    
       [0014]    It should be understood, however, that the specific embodiments given in the drawings and detailed description do not limit the disclosure. On the contrary, they provide the foundation for one of ordinary skill to discern the alternative forms, equivalents, and modifications that are encompassed together with one or more of the given embodiments in the scope of the appended claims. 
       Nomenclature 
       [0015]    In the following description, the term “fluid” is employed for liquids, gases, and mixtures thereof, whether or not they may be laden with solid particulates. The term “tubular” is employed as a generic term for piping of every sort that might be found in an oil, gas, or water well, including coiled (steel) tubing, continuous (composite) tubing, and strings of threaded tubing with regular or premium threads. The term tubular applies to small and large diameter tubing whether employed as drill pipe, casing, production tubing, or service strings. “Conduit” is employed as a generic term for any of the various tubular-defined fluid flow passages including the central bore of a tubular or the annular space around an inner tubular that is perhaps defined with the help of an outer tubular. 
       DETAILED DESCRIPTION 
       [0016]      FIG. 1  shows a borehole extending downward from the Earth&#39;s surface  100  and lined with a casing tubular  102 . Though the well is shown as a straight vertical hole, it may in practice deviate from the vertical and extend for quite some distance in a horizontal direction, in some cases following a tortuous trajectory. At one or more positions along its length, the casing tubular  102  may be perforated to enable formation fluid  104  to enter and accumulate in the interior, forming one or more fluid layers  106 ,  108 . The height at which the fluid layers stabilize is determined by the pressure of fluid in the formation pores and the densities of the fluids. 
         [0017]    An outer production tubular  110  extends from the surface  100  to reach the pool of accumulated fluids, preferably extending below the lowermost casing perforation. The outer production tubular  110  is terminated by a check valve  112 . (The operation of the check valve  112  is discussed in greater detail below.) An inner production tubular  114  is lowered into the outer production tubular  110  until the end is positioned near the check valve  112  (e.g., within 15 meters and more preferably positioned one to three meters from the check valve). The end of the inner production tubular  114  extends below the surface of the accumulated fluids  106 ,  108 , and more preferably extends below the lowermost perforation in the casing. 
         [0018]    The annular conduit between the outer production tubular  110  and the inner production tubular  114  is coupled via a pressure line  116  to a surface unit  118 . The surface unit  118  employs the pressure line  116  as an injection line to inject compressed natural gas (CNG) into the well via the annular conduit, which in this embodiment acts as the injection conduit. The central conduit (i.e., the bore of inner production tubular  114 ) is coupled to a production line  120 . The central conduit acts as a lift conduit to raise fluid from the well and deposit that fluid (via production line  120 ) in a storage tank  122 . 
         [0019]    Storage tank  122  holds the produced fluids until they can be transported to an offsite facility. In addition, tank  122  may serve as a gas separation unit, with gas moving through a recovery line  124  to surface unit  118  for potential compression and recycling. A safety valve  126  prevents the storage tank  122  from becoming over-pressured. 
         [0020]    A supply line  128  couples the surface unit  118  to a source of liquefied natural gas (LNG), such as a cryogenic transport trailer  130  or an on-site LNG storage tank. LNG is natural gas (predominately methane, with small amounts of ethane, propane, butane, and heavier alkanes) that has been cooled below about −162° C. It is normally stored below about 4 psi as a boiling cryogen, meaning that heat leakage through the insulation gets consumed and dissipated by the phase change of some of the liquid to gaseous phase. Once the LNG in one trailer has been mostly consumed, that trailer may be supplemented or replaced with a full trailer. An offsite facility liquefies the natural gas and refills the empty trailers for transport back to the well site. 
         [0021]      FIG. 1  further shows an access line  136  for accessing the annular conduit between the outer production tubular  110  and casing  102 . It may be used for controlling pressure in this region and/or for circulating treatment fluids to service the well. 
         [0022]      FIGS. 2A and 2B  show a detail view of the outer and inner production tubulars  110 ,  114 , termini as well as the check valve  112  that terminates the outer tubular  110 . The check valve  112  takes the form of a ball-and-seat valve. During the intake phase shown in  FIG. 2A , the pressures on either side of the check valve  112  are balanced, enabling the formation fluid  104  to raise the ball  140  and flow inside the lower end of the inner and outer tubulars. During the injection phase shown in  FIG. 2B , the surface unit  118  injects CNG via the annular conduit. The increase in pressure forces the ball  140  onto its seat, preventing the fluid from escaping. Instead, the fluid is forced into the central conduit and lifted by the gas pressure to the surface and into the storage tank. Once the bulk of the fluid has been cleared from the central conduit, the pressure drops rapidly and the gas injection ceases until a sufficient amount of fluid has accumulated for the process to be repeated. 
         [0023]    In this embodiment, it is contemplated that the gas injection is performed quickly, at high pressure, to lift the accumulated formation fluid as one or more large slugs (“slug flow”) in the lift conduit. The surface unit  118  may optionally introduce an interphase liquid via the pressure line into the injection conduit. The interphase liquid forms a layer on top of the accumulated formation fluid  104  to resist intrusion of the gas into the fluid and thereby assist in the formation and maintenance of slug flow during the injection phase. Oil may serve as an effective interphase liquid for lifting accumulated water from a gas well. 
         [0024]    Though the central conduit is shown as the lift conduit and the annular conduit is shown as the injection conduit, the flow path can be reversed such that the central conduit operates as the injection conduit and the annular conduit serves as the lift conduit. In either case, the alternate intake and injection phases enable the accumulated formation fluids to enter the production tubulars and be lifted from the well. 
         [0025]    It is desirable to minimize the production tubular diameters to minimize the volume of gas needed during the injection phase, yet the volume of fluid that accumulates during the intake phase is also dependent on the diameter of the outer tubular, at least at the terminal end of the outer tubular. To accommodate these competing considerations, the lower end of the outer tubular may be given a larger diameter to permit the accumulation of a greater fluid volume, while the diameter along the remaining length of the tubulars is minimized, subject to the provision that gas and liquids experience only nominal flow resistance. 
         [0026]    In certain contemplated alternative embodiments, the check valve  112  is not permanently affixed to the outer production tubular, but rather is configured as a retrievable check valve that can be set in place using a wireline or service tubular. The check valve may even be affixed to the inner production tubular, so long as an annular seal is provided between the inner and outer production tubulars and ports are provided in the inner tubular to establish fluid communication between the central and annular conduits. 
         [0027]    Also contemplated is the use of a seating nipple or packer to seal the annular space between the outer production tubing and the casing and anchor the outer production tubing in place. 
         [0028]    The functional modules of the surface unit  118  correspond to blocks  304 ,  306 ,  308 ,  310 , and  312  of  FIG. 3 . An offsite condenser  302  accepts natural gas from a pipeline or other source and liquefies it to form LNG, which is loaded on a cryogenic transport trailer  130 . A truck driver hauls the LNG-filled trailer to the well site and couples it to the surface unit  118 . An evaporator  304  converts the LNG to compressed natural gas (CNG), e.g., by warming the LNG in a confined volume. 
         [0029]    A CNG storage module  306  stores the CNG at ambient temperature with a pressure in the range of 2900 to 3600 psi. Depending on the production characteristics of the well, the volume of the CNG storage module may range from relatively small (i.e., enough to pressurize the hydraulic line for a limited number of cycles) to relatively large (i.e., enough to fill one or more LNG transport trailers). 
         [0030]    A controller module  308  includes electronics for opening and closing valves, for acquiring measurements of fluid flow rates and pressures, and further includes a processor executing software or firmware that coordinates the operation of the valves to control the various modules. Among the operations facilitated by the controller module  308  is the periodic injection of CNG as a lift gas to raise fluid from the well into the fluid storage tank  122 . The injected gas is exhausted via the lift conduit and passes into the storage tank  122 , where it may be captured and directed to an optional compressor  312  for recycling into the form of CNG. Alternatively, or in addition, such gas may be combusted by a generator or may be otherwise converted into electricity to satisfy the power requirements of the various modules of surface unit  118 . 
         [0031]      FIG. 3  further shows an optional oil module  310 , which may supply an interphase liquid to reduce gas intrusion into the lifted fluid during slug flow through the lift conduit. 
         [0032]      FIG. 4  is a flow diagram of an illustrative artificial lift method embodiment. It begins in block  402  with liquefying natural gas at an offsite facility to fill a cryogenic transport trailer with LNG. In block  404 , the LNG is transported to the well site and coupled to the surface unit to supply LNG as needed for injecting lift gas into the well. 
         [0033]    In block  406 , the system evaporates the LNG to obtain CNG. If such evaporation is performed in a confined volume, the LNG is converted directly to CNG without requiring a compressor. Alternatively, some of the gas may be combusted to power a compressor that converts the evaporated LNG into CNG. 
         [0034]    Blocks  408 - 414  form a cycle that is repeatedly performed by controller module  308 . In block  408 , the controller  308  opens an injection valve, permitting CNG to enter the injection conduit and force accumulated fluid up the lift conduit and into the storage tank. The injection phase is terminated when the bulk of the fluid gets displaced from the lift conduit. This event is detectable in a number of ways. For example, the liquid flow rate in the production line drops. The resistance to gas flow drops rapidly, reducing the pressure in the production line as well as the pressure downstream from the injection valve. The differential pressure between the inlet of the injection conduit and the outlet of the lift conduit drops rapidly, and there is a rapid increase in the gas flow rate through the system. Thus the controller  308  may employ one or more pressure sensors, gas flow sensors, and/or liquid flow sensors to detect this condition and terminate the injection phase. 
         [0035]    In block  410 , the exhausted natural gas is captured and re-compressed for reuse. Some of the gas may be combusted to supply power to for the various system components. Less desirably, the exhausted gas may be vented. In block  412 , the controller optionally analyzes a measure of performance, which may account for the volume of produced fluid, the volume of injected gas, production rate, and any other suitable optimization variables, to adapt parameters for the next cycle. Illustrative parameters include: intake phase length, injection pressure, injection rate, injection profile (i.e., time dependence of the injection pressure and/or rate), interphase liquid volume, and interphase liquid timing. For example, increasing the length of the intake phase permits a greater volume of fluid to accumulate with diminishing returns as the length increases, thereby impairing the production rate when the intake phase grows too lengthy. 
         [0036]    In block  414 , the controller  308  pauses for the intake phase, providing time for formation fluid to accumulate and enter the production tubulars. Once sufficient time has elapsed, the controller returns to block  408  to initiate the next injection phase. 
         [0037]    The illustrative embodiments disclosed above may prove advantageous in that they minimize the number of moving components. Downhole, the sole moving component is the check valve. At the surface, the sole moving components are the valves and the optional compressor. Thus the reliability of these illustrative embodiments is expected to be very high and suitable for use in very remote areas. 
         [0038]    Nevertheless, in less remote areas, the illustrated embodiments can be augmented with an on-site condenser for producing LNG. In certain alternative embodiments, a single on-site condenser or a single cryogenic LNG trailer may be used to supply the surface units  118  of multiple wells in a localized region. Still other embodiments may employ an off-site compressor to fill CNG transport trailers, and may transport those trailers to the well site to be used as a CNG source and optional CNG storage without need of an evaporator. 
         [0039]    Moreover, the use of gas-lift obviates any requirement for a pump rod or other reciprocating string downhole, enabling the illustrative embodiments to be used in highly-deviated, extended reach wells having high tortuosity or other factors that would render traditional artificial lift systems unusable. 
         [0040]    Though the check valves in the illustrative downhole pump assembly are ball-and-seat valves, other check valve configurations are known and may be used. Suitable alternatives include flapper valves, reed valves, and sliding sleeve valves. 
         [0041]    Numerous other variations and modifications will become apparent to those skilled in the art once the above disclosure is fully appreciated. For example, certain contemplated embodiments replace the periodic high-pressure gas injection with a continuous stream of gas at a pressure and rate designed to introduce a stream of bubbles into the lift conduit and thereby reduce the effective fluid density in that column enough to make the formation pressure sufficient for ensuring continuous flow of production fluid to the surface. In these contemplated embodiments, the downhole check valve becomes optional and may be omitted. The ensuing claims are intended to cover such variations where applicable.