Liquefied Gas-Driven Gas-Lift System

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

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

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.

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

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.

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.

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.

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

In the drawings:

FIG. 1 shows an illustrative liquefied gas-driven gas-lift system.

FIG. 2A shows an illustrative gas-lift intake phase.

FIG. 2B shows an illustrative gas-lift injection phase.

FIG. 3 is a function-block diagram of an illustrative artificial lift system.

FIG. 4 is a flow diagram of an illustrative artificial lift method.

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

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

FIG. 1 shows a borehole extending downward from the Earth'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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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).

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

Claims

1. An artificial lift method that comprises:

deriving compressed natural gas (CNG) from liquid natural gas (LNG); and

injecting the CNG into a well, wherein the CNG enters a lift conduit as a lift gas that aids in conveying fluid from the well.

2. The method of claim 1, wherein said deriving includes raising a temperature of LNG trapped in a restricted volume.

3. The method of claim 1, further comprising:

transporting liquid natural gas (LNG) to a site of the well.

4. The method of claim 1,

wherein the well includes an inner production tubular defining an inner conduit,

wherein the well further includes an outer production tubular defining an annular conduit between the inner and outer production tubulars,

wherein the outer production tubular is terminated by a check valve that permits fluid to enter the outer production tubular.

5. The method of claim 4, wherein said inner conduit serves as the lift conduit, and wherein said injecting is performed via the annular conduit.

6. The method of claim 4, wherein said annular conduit serves as the lift conduit, and wherein said injecting is performed via the inner conduit.

7. The method of claim 4, further comprising:

pausing said injecting operation to enable fluid to accumulate in the outer production tubular.

8. The method of claim 7, wherein said pausing is contingent upon detecting a change in injection pressure or flow rate.

9. The method of claim 7, wherein said pausing is contingent upon detecting a flow rate or pressure condition at an upper end of the lift conduit.

10. The method of claim 7, further comprising:

repeating said injecting and pausing operations to provide intermittent lift.

11. The method of claim 10, further comprising:

adapting one or more parameters of the injecting or pausing operations to optimize a performance measure.

12. The method of claim 11, wherein 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.

13. An artificial lift system that comprises:

an evaporator that converts liquid natural gas (LNG) into compressed natural gas (CNG); and

a controller that injects the CNG into a well, wherein the CNG enters a lift conduit as a lift gas to aid in conveying fluid from the well.

14. The system of claim 13, further comprising a transport trailer coupled to provide LNG to the evaporator.

15. The system of claim 13, wherein the well includes:

an inner production tubular that defines an inner conduit;

an outer production tubular that defines an annular conduit between the inner and outer production tubulars; and

a check valve that terminates the outer production tubular and that permits fluid to enter the outer production tubular.

16. The system of claim 15, wherein said inner conduit serves as the lift conduit, and wherein the controller injects the CNG via the annular conduit.

17. The system of claim 15, wherein the controller periodically pauses the injection of CNG to enable fluid to accumulate in the outer production tubular.

18. The system of claim 17, wherein the controller adapts timing parameters of the injection and pausing operations to optimize a ratio of produced fluid to injected CNG.

19. A virtual pipeline method for providing artificial lift, the method comprising:

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 liquid natural gas (LNG) as needed for supplying gas lift in the well.

20. The method of claim 20, further comprising:

replacing an emptied trailer at the site with a non-empty trailer of LNG; and

returning the emptied trailer to the offsite facility for filling.