WO2005100744A1 - Appareil et procede pour assecher les puits de gaz a gradient basse pression - Google Patents

Appareil et procede pour assecher les puits de gaz a gradient basse pression Download PDF

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Publication number
WO2005100744A1
WO2005100744A1 PCT/US2005/010725 US2005010725W WO2005100744A1 WO 2005100744 A1 WO2005100744 A1 WO 2005100744A1 US 2005010725 W US2005010725 W US 2005010725W WO 2005100744 A1 WO2005100744 A1 WO 2005100744A1
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WO
WIPO (PCT)
Prior art keywords
tubing string
coiled tubing
assembly
jet pump
wellbore
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Ceased
Application number
PCT/US2005/010725
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English (en)
Inventor
John Gordon Misselbrook
T. Roland Jackson
Alexander Raphael Crabtree
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
BJ Services Co USA
Original Assignee
BJ Services Co USA
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by BJ Services Co USA filed Critical BJ Services Co USA
Priority to CA002562085A priority Critical patent/CA2562085A1/fr
Publication of WO2005100744A1 publication Critical patent/WO2005100744A1/fr
Anticipated expiration legal-status Critical
Ceased legal-status Critical Current

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
    • E21B43/121—Lifting well fluids
    • E21B43/13—Lifting well fluids specially adapted to dewatering of wells of gas producing reservoirs, e.g. methane producing coal beds
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
    • E21B17/20—Flexible or articulated drilling pipes, e.g. flexible or articulated rods, pipes or cables
    • E21B17/203—Flexible or articulated drilling pipes, e.g. flexible or articulated rods, pipes or cables with plural fluid passages
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B19/00—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables
    • E21B19/22—Handling reeled pipe or rod units, e.g. flexible drilling pipes

Definitions

  • cementing of the casing string usually includes lowering the casing to a desired depth and displacing a desired volume of cement down the inner diameter of the casing. Cement is displaced downward into the casing until it exits the bottom of the casing and moves up into the annular space between the outer diameter of the casing and the wellbore. The cement cures to firmly anchor the casing to the walls of the wellbore and seal off the well.
  • both the casing and concrete are perforated at a predetermined downhole location.
  • the oil or natural gas moves from the formation into the well casing via the perforations due to the difference in pressure between the formation and the well casing interior.
  • This pressure differential carries the oil or natural gas to the surface where it is collected.
  • many such wells produce small amounts of liquid along with the gas. Initially, when the pressure differential is significant, the liquid is carried to the surface with the natural gas.
  • the well production tubulars are sized to maintain a practical flow velocity to keep the well unloaded during much of its producing life.
  • the formation pressure decreases, it becomes increasingly difficult for the gas velocity to carry the associated liquid to the surface. Accordingly, the well begins to load up with liquid, which has a negative impact on natural gas production.
  • One method involves intermittent production and unloading cycles (e.g., plunger lift), while another employs reduced sized tubulars (e.g., velocity strings) to increase gas velocity to a level sufficient to carry the liquid out of the well.
  • Another method uses a capillary string to inject foamer into the well, which can improve the transport of liquid. While all are somewhat beneficial, each of these methods generally results in a lower gas production rate than if the well was allowed to produce gas without having to also carry the liquid.
  • Many gas wells are originally fitted, or re-completed, with relatively small production tubing in an attempt to maintain velocities sufficient to unload produced liquids.
  • jet pumps for removing large amounts of liquid from wellbores.
  • jet pumps generally include a power fluid line operably coupled to the entrance of the jet pump, and a return line coupled to receive fluids from a discharge end of the pump. As the pressurized power fluid is forced, by a pump at the surface, down through the jet pump, the power fluid draws in and intermixes with the produced fluid.
  • Down-hole jet pumps are advantageous because they have no moving parts, which increase their reliability over the more conventional mechanical pumps.
  • Many jet pump installations incorporate removable sub-assemblies that enable the sub- assembly to be removed remotely from the jet pump body while leaving the jet pump body intact in the well.
  • Such jet pump sub-assemblies also called “carriers,” can be installed for operation by pumping the "carrier” down the tubing, and may also be removed by reversing the flow of the power fluid.
  • the "removable" jet pump may be adjusted and/or replaced without requiring that the tubing be pulled from the well.
  • Concentric coiled tubing or coiled-in-coiled tubing is also known in the prior art.
  • Concentric coiled tubing strings provide two channels for fluid communication downhole, typically with one channel, such as the inner channel, used to pump fluid (liquid, gas, or multiphase fluid) downhole with a second channel, such as the annular channel formed between the concentric strings, used to return fluid to the surface.
  • One channel such as the inner channel
  • a second channel such as the annular channel formed between the concentric strings
  • Both concentric coiled tubing channels could be used to pump up or down. While both of these concepts are known in the prior art, the two have not been combined, reduced significantly in size, and employed to remove small amounts of extraneous liquid from a deep, undersized natural gas well. The rising price of natural gas has made such a system viable. Accordingly, the following invention demonstrates such.
  • This invention relates to a method of removing extraneous fluid from a subterranean petroleum reservoir. More particularly, this invention relates to a method of removing water from a natural gas well using a miniaturized jet pump assembly attached to an undersized concentric coiled tubing string.
  • a miniaturized jet pump assembly is attached to a concentric coiled tubing string at the surface and is run in the well as one unit. The jet pump assembly is typically placed below the formation perforations, in an area adjacent the extraneous water. Once correctly positioned, a power fluid is pumped down the concentric coiled tubing and used to activate the functional portion of the jet pump assembly.
  • the jet pump assembly When activated, the jet pump assembly creates an area of low pressure that draws the extraneous water into the assembly. This extraneous water is intermixed with the power fluid and returned to the surface via the concentric coiled tubing, where it can be collected or reused. More often than not, the functional portion of the jet pump assembly wears out with extensive use. Rather than remove the entire concentric coiled string and assembly from the well to replace the worn-out components, the functional portion can be removed from the jet pump assembly by "reversing" the power fluid flow within the concentric coiled tubing. Once the worn portion of the jet pump assembly has been replaced, the new components are pumped downhole to their appropriate location.
  • the dimensions of the jet pump apparatus and concentric coiled tubing string are an important part of the present invention.
  • Many wells have relatively small production tubing at that portion of the wellbore that is producing the natural gas. Accordingly, the introduction of concentric coiled tubing into the production tubing further limits the area in which natural gas can flow to the surface. Therefore, it is desirable to utilize the smallest tubing possible. Small tubing necessarily requires a small jet pump to allow passage of the "carrier" sub-assembly through the inner coiled tubing string.
  • the present invention requires the concentric coiled tubing string to be small enough to fit inside undersized production tubing (typically with an outer diameter as small as 2-3/8" and 2-7/8"), and the attached jet pump apparatus to be effectively miniaturized.
  • Another embodiment of the present invention is directed to an assembly and method for removing produced water essentially identical to the embodiment described above, except that a jointed tubing string is used for the outer tubing string instead of the previously referenced coiled tubing string.
  • the outer jointed tubing string may be comprised of a corrosion-resistant material.
  • This method includes running an outer coiled tubing string into a wellbore, cutting the outer tubing string and hanging it off in a "Christmas tree,” running an inner coiled tubing string (with the jet pump assembly attached) through the outer tubing string, cutting the inner tubing string, landing the jet pump assembly in a specially designed seating assembly (attached to the bottom of the previously run outer coiled tubing string), and finally hanging off the inner string in the Christmas tree on the surface.
  • This method is particularly well suited for offshore use where lifting a spool of concentric coiled tubing is not feasible. To ensure oil and/or natural gas cannot flow freely to the surface when a wellbore is open to the atmosphere, certain jurisdictions require one or more mechanical flow barriers to be maintained in the wellbore.
  • the permutation of a check valve, a blow out plug, an extended seal bore, a nipple profile, and a seating assembly attached to the outer coiled tubing string, together with the use of a dummy carrier set in the jet pump assembly and attached to the inner concentric coiled tubing string, provides a means of installing a concentric coiled tubing jet pump dewatering system in a natural gas well while maintaining one or more mechanical barriers during the process.
  • Another embodiment of the present invention is directed to a method of removing the jet pump assembly and concentric coiled tubing string from the wellbore.
  • This method includes replacing a working carrier in the jet pump assembly with a dummy carrier, removing the inner coiled tubing string from within the outer coiled tubing string, placing a wireline plug in the lower end of the outer coiled tubing, pressure testing the wireline plug, and thereafter removing the outer coiled tubing string from the well.
  • a working carrier in the jet pump assembly with a dummy carrier
  • removing the inner coiled tubing string from within the outer coiled tubing string placing a wireline plug in the lower end of the outer coiled tubing, pressure testing the wireline plug, and thereafter removing the outer coiled tubing string from the well.
  • FIG. 1 shows a longitudinal cross section of a jet pump assembly of the present invention.
  • FIG. 2 shows an alternative view of a longitudinal cross section of a jet pump assembly of the present invention.
  • FIG. 3 illustrates surface equipment used in a method according to one embodiment of the invention wherein the concentric coiled tubing string is assembled in the well bore.
  • the outer coiled tubing string is illustrated being run into the existing production tubing in the well.
  • FIG. 4 illustrates the bottom hole assembly attached to the bottom of the outer coiled tubing string according to the method of one embodiment of the present invention.
  • FIG. 5 illustrates the outer coiled tubing string having been cut according to the method of one embodiment of the present invention.
  • FIG. 6 illustrates the installation of the slip bowl on the outer coiled tubing string according to the method of one embodiment of the present invention.
  • FIG. 7 illustrates the landing of the slip bowl on the outer coiled tubing string according to the method of one embodiment of the present invention.
  • FIG. 8 illustrates the outer coiled tubing string landed in the Christmas tree spool according to the method of one embodiment of the present invention.
  • FIG. 9 illustrates the jet pump assembly attached to the inner coiled tubing string according to the method of one embodiment of the present invention.
  • FIG. 10 illustrates the installation of the slip bowl on the inner coiled tubing string according to the method of one embodiment of the present invention.
  • FIG. 11 illustrates the location of the jet pump assembly during the step of removing the blow out plug from the bottom sub of the seating assembly according to the method of one embodiment of the present invention.
  • FIG. 12 illustrates the lowering of the inner coiled tubing string according to the method of one embodiment of the present invention.
  • FIG. 13 illustrates the passing of the stinger on the jet pump assembly through the flapper valve and landing of the jet pump assembly in the seating assembly according to the method of one embodiment of the present invention.
  • FIG. 14 illustrates a plug set in the nipple profile of the jet pump assembly according to the method of one embodiment of the present invention.
  • FIGS. 1 and 2 illustrate a jet pump apparatus (1) in accordance with the present invention.
  • the jet pump apparatus (1) is comprised of an outer tubular member, referred to herein as the "shroud" (2).
  • the shroud (2) is attached to an outer coiled tubing string (not shown) by any suitable means, but preferably by welding. Welding the shroud (2) to the outer coiled tubing string allows for a smooth connection profile between the coiled tubing and the shroud (2), thereby simplifying the surface installation and preventing any hang-ups when running the jet pump apparatus (1) into the wellbore.
  • the outer tubing string (not shown) is a jointed tubing string.
  • the shroud (2) may be threaded onto the lower end of the jointed tubing string.
  • Contained within the shroud (2) is an inner tubular member referred to as the pump housing (3).
  • the pump housing (3) is attached to the inner coiled tubing string (not shown) by any suitable means, but preferably by means of a threaded connection.
  • a first annulus (4) is formed between the inner surface of the shroud (2) and the outer surface of the pump housing (3). The first annulus (4) is in fluid communication with both the wellbore and any surface equipment.
  • the carrier (5) Contained within the pump housing (3) is the functional portion of the jet pump apparatus (1) referred to, in total, as the carrier (5).
  • a second annulus (6) is formed between the inner surface of the pump housing (3) and the outer surface of the carrier (5). As with the first annulus (4), the second annulus (6) is in fluid communication with both the wellbore and any surface equipment.
  • the carrier (5) Moving from the top of the carrier (5) downward, the carrier (5) essentially comprises a jet nozzle (7), a throat (8), and the uppermost portion of a diffuser (9a). Near the jet nozzle portion (7) of the carrier (5) is located a series of first sealing members (10), which in this embodiment take the form of three O-rings.
  • first sealing members (10) create a seal between the outer surface of the carrier (5) and the inner surface of the pump housing (3).
  • a second series of sealing members (17) which in this embodiment take the form of two O-rings. These second sealing members (17) create a seal between the outer surface of the carrier (5) and the lowermost portion of the diffuser (9b).
  • the check valve (11) can be any suitable one-way-type valve, but is preferably a ball valve. The check valve (11) only allows fluid to enter the jet pump apparatus (1), rather than exit.
  • the check valve (11) is located inside the pump housing (3).
  • a third series of sealing members (12) which in this embodiment again take the form of three O-rings. These sealing members (12) create a seal between the outer surface of the pump housing (3) and the inner surface of the shroud (2).
  • a boot sub (13) At the very bottom of the jet pump apparatus (1) is located a boot sub (13).
  • the boot sub (13) is essentially attached to both the shroud (2) and the pump housing (3) - the attachment preferably consisting of one threaded connection and two shoulders.
  • the dual shoulders help to maintain the positional integrity of the shroud (2) and the pump housing (3) as the inner concentric coiled tubing string attempts to expand and shift due to pressure and temperature changes.
  • the boot sub contains a bore (14) in the lower portion thereof, which provides fluid communication between the wellbore and the inner components of the jet pump apparatus (1).
  • the embodiment of the jet pump apparatus (1) disclosed in FIGS. 1 and 2 is attached to concentric coiled tubing (not shown) at the surface as described above. Because the jet pump apparatus (1) is made up entirely at the surface, it can be tested and checked prior to placing the apparatus downhole. Once tested, the jet pump apparatus (1) and concentric coiled tubing string are run into the wellbore together.
  • the complete apparatus is run in such that the jet pump apparatus (1) is placed below the perforations, at or near the location of extraneous water.
  • the jet pump apparatus (1) is placed below the perforations, at or near the location of extraneous water.
  • one embodiment of the present invention includes utilizing a corrosion-resistant material for the outer coiled tubing string (not shown). Typically, a corrosion resistant alloy (CRA) is used.
  • CRA corrosion resistant alloy
  • Nitronic 30 stainless steel has proved to be corrosion resistant under simulated downhole conditions, although any suitable CRA can be used.
  • the CRA material can extend the entire length of the outer coiled tubing string, or it may be included only in those portions of the coiled tubing that will be adjacent to the perforations (as a cost savings measure). If the CRA material is only included in a section of the outer coiled tubing string, it may be connected to the standard section by any suitable means, including welding or threaded connections.
  • a jointed tubing string (not shown) is used for the outer tubing string instead of the previously mentioned coiled tubing string.
  • the outer jointed tubing string is made of the corrosion-resistant material referenced above.
  • the CRA material can extend the entire length of the outer jointed tubing string, or it may be included only in those portions of the jointed tubing string that will be adjacent to the perforations in the wellbore (as a cost savings measure).
  • Nitronic 30 stainless steel has proved to be corrosion resistant when used with a jointed tubing string, although any other suitable CRA can be used. If the CRA material is only included in a section of the outer jointed tubing string, it may be connected to the standard section by any suitable means, including welding or threaded connections.
  • the power fluid can be any suitable substance, although produced water is preferred for cost savings.
  • the power fluid is pumped into the pump housing (3) and eventually reaches the carrier (5). Once the power fluid reaches the carrier (5), it is initially forced through the jet nozzle (7). The power fluid exists the jet nozzle (7) at a high rate of speed and travels downward into the throat (8). From there, the power fluid moves into the uppermost portion of the diffuser (9a) and subsequently into the lowermost portion of the diffuser (9b). The power fluid is then forced out of the lowermost portion of the diffuser (9b) via the diffuser opening (15). At this point, the power fluid is forced into the first annulus (4) between the inner surface of the shroud (2) and the outer surface of the pump housing (3).
  • the power fluid is then returned to the surface via the first annulus (4) to be re-circulated or collected.
  • fluid communication is provided between the pump housing (3) and the wellbore via the bore (14) of the boot sub (13). Accordingly, any extraneous fluid (e.g., water) that is present in the wellbore near the boot sub (13) will be sucked into the jet pump apparatus (1) due to the area of low pressure created by the power fluid stream.
  • the extraneous water is sucked into the bore (14) of the boot sub (13) and past the oneway check valve (11) located at the top of the bore (14).
  • the extraneous water then moves up the second annulus (6) until it reaches a port (16) near the jet nozzle (7) of the carrier (5).
  • the flow of the power fluid through the jet nozzle (7) creates an area of low pressure in the immediate vicinity. Accordingly, the extraneous water is sucked through the port (16) where it intermixes with the power fluid. Thereafter, the extraneous water and power fluid move through the carrier (5) and back to the surface as described previously.
  • the jet pump apparatus (1) of the present invention requires a relatively low amount of operational horsepower in comparison with prior art jet pump systems.
  • the removal of 20 barrels of produced water a day from an 8,000 ft. well only requires an output of approximately 1.2 horsepower from an operating jet pump assembly (1).
  • the present invention is designed to remove only a relatively small amount of produced water from the wellbore, the surface equipment (not shown) operating the jet pump apparatus can be relatively small (e.g. 10 horsepower) and can function economically even though the jet pump may be operating inefficiently (e.g., at approximately 20% efficiency or less). Accordingly, the jet pump assembly (1) of the present invention is financially viable. In a typical oilfield application, certain portions of the jet pump apparatus (1) wear out or corrode with extensive use. This wear usually occurs with regard to the carrier (5) and its subcomponents.
  • the present invention allows for the removal of the worn parts without removing the entire apparatus from the wellbore.
  • power fluid is "reverse circulated" down the first annulus (4) formed between the inner surface of the shroud (2) and the outer surface of the pump housing (3).
  • the power fluid is prevented from exiting the jet pump apparatus (1) by the one-way check valve (11), which only allows fluid to flow into the tool, rather than out. Pressure builds up against the carrier (5) to the point where the entire assembly, including the first and second sealing members (10 and 17) are removed from the jet pump apparatus (1) and forced towards the surface.
  • a tool trap (not shown) or similar device is then employed to retrieve the carrier (5). Once the worn carrier (5) is removed, a new carrier (5) is pumped back downhole through the inner coiled tubing (not shown) until it reaches the appropriate location in the jet pump apparatus (1). If, for any reason, it is impossible to generate enough pressure to force the worn carrier
  • a back up system is included on the jet pump apparatus (1).
  • a fishing neck (18) is included on the top of the carrier (5). If the carrier (5) cannot be removed by reverse circulation, a wire-line fishing tool can be lowered into the inner coiled tubing, stabbed into the fishing neck (18), and utilized to remove the carrier mechanically.
  • the one-way check valve (11) can be omitted from the design of the jet pump apparatus (1). Without the one-way check valve (11) in place, the power fluid will drain out of the bottom of the jet pump apparatus (1) and into the wellbore when the surface pump is switched off.
  • the present invention requires the concentric coiled tubing string to be extremely small, and the attached jet pump apparatus (1) to be effectively miniaturized.
  • the concentric coiled tubing may be assembled using 2", 1 %", or even 1 V" coiled tubing for the outer string and 1" or 7/8" coiled tubing for the inner string.
  • the jet pump apparatus (1) may be approximately 1 %" in diameter with a "carrier” in the approximate range of 5/8" to 3/4" depending on the inner string size. Intermediate sizes of coiled tubing can be manufactured to further optimize performance if demand warrants it.
  • another embodiment of the present invention includes a method of running an outer coiled tubing string into a wellbore, cutting the outer tubing string and hanging it off in the "Christmas tree,” running an inner coiled tubing string (with the jet pump assembly attached) through the outer tubing string, cutting the inner tubing string, landing the jet pump assembly in a specially designed seating assembly (attached to the bottom of the previously run outer coiled tubing string), and finally hanging off the inner string in the Christmas tree on the surface.
  • FIG. 3 illustrates some of the surface equipment used to assemble the concentric coiled tubing string and lower it into the wellbore.
  • a new spool piece (30) is installed between a master valve (35) and the remainder of the Christmas tree (34).
  • a coiled tubing blow out preventer (“BOP") stack (40) is installed on top of the master valve (35).
  • the BOP stack (40) includes a plurality of hydraulically actuated rams such as shear rams, slip rams, and/or tubing or pipe rams.
  • a hydraulically actuated work window (45) is attached between the BOP stack (40) and a lubricator (50).
  • a stuffing box (55) is located above the lubricator and beneath an injector head (60).
  • a bottom hole assembly (“BHA") (75) is assembled and attached to the bottom of the outer coiled tubing (25), preferably by a threaded connection.
  • the BHA as shown in FIG. 4, comprises a seating assembly (80), a valve body (85), and a bottom sub (90).
  • the seating assembly (80) further comprises a landing shoulder (81), an extended seal bore (82), and a nipple profile (83).
  • the valve body (85) is connected to the lower end of the seating assembly (80) by any suitable means such as a threaded connection.
  • the valve body (85) houses a spring-biased flapper (87), which, in the closed position, will prevent the flow of well bore fluids up through the valve and into the outer coiled tubing.
  • a spring-biased flapper 87
  • dual flapper valves (not shown) can be utilized.
  • the bottom sub (90) is preferably threaded to the lowermost end of the valve body (85) and includes a profile (92) for receiving a removable blow out plug (95), which can be pre- installed in the bottom sub. While a variety of well-known blow out plugs may be used with this invention, the blow out plug disclosed in FIG. 4 includes a plurality of "dogs" that extend radially into the aforementioned profile (92).
  • the blow out plug may be pressure tested while still on the surface.
  • the string is fed through the surface equipment by the injector head (60) and into existing natural gas production tubing (70), as illustrated in FIG 3.
  • the outer coiled tubing string (25) is lowered through the production tubing (70) until it reaches the desired depth in the wellbore.
  • the flapper valve (87) and blow out plug (95) serve as dual mechanical barriers to fluid flow when the outer coiled tubing (25) is being run into the well. Once the outer coiled tubing string (25) has been lowered to the desired depth, it is landed in the spool (30).
  • slip rams (41) in the BOP stack to grip the outer coiled tubing (25) and closing tubing rams (42) to seal the annulus around the tubing (25), as illustrated in FIG. 5.
  • the work window (45) is then opened and the outer coiled tubing (25) is cut by any suitable means such as a mechanical pipe cutter.
  • a hang-off bushing or "slip bowl” (100) may be attached to the top of the severed tubing (25) by any suitable means.
  • the slip bowl (100) is bolted to the outer coiled tubing string (25) and includes one or more seals (105).
  • the slip bowl (100) includes a profile (106) for receiving and connecting to an "overshot" (110).
  • the overshot (110) is attached to the end of the severed outer coiled tubing (25A), as shown in FIG. 6.
  • the severed coiled tubing (25 A) is then lowered until the overshot (110) latches onto the profile of the slip bowl (100).
  • the overshot (110) can support the weight of the suspended outer coiled tubing string (25) and the BHA (75).
  • tubing rams (42) and slip rams (41) are opened and the outer coiled tubing (25) is lowered until the bowl (100) lands on the lowermost shoulder in the bore of the spool (30), as shown in FIG. 7. Once landed, the spool (30) supports the weight of the outer tubing string (25).
  • FIG. 8 illustrates the outer tubing string (25) landed in the spool (30).
  • the severed coiled tubing (25A) is then removed from the surface equipment. Once the outer coiled tubing string (25) has been landed and the severed tubing (25 A) has been removed, the master valve (35) is closed and the BOP stack (40) is changed out in preparation for running the inner string (125) of the concentric coiled tubing string.
  • a jet pump assembly (135), a standing or check valve (140), a landing shoulder (145), a seal assembly (150), and a stinger (155).
  • a dummy carrier (not shown) may be installed in the jet pump assembly as an additional mechanical barrier.
  • the BHA (130) can be connected together by any suitable means such as by threaded connections between the components.
  • the BHA (130) is threaded to the bottom of the inner coiled tubing (125) after the inner coiled tubing (125) has been aligned with and lowered into the surface equipment.
  • the inner coiled tubing is lowered into the outer coiled tubing (25) by the injector head (60).
  • the injector head (60) can be adapted to handle the smaller diameter inner coiled tubing (125).
  • the inner coiled tubing (125) may be lowered into the outer coiled tubing (25) until the inner BHA (130) reaches the outer BHA (75).
  • the inner coiled tubing (125) may be cut in the same manner as the outer coiled string (25). Specifically, the slip rams (41) and tubing rams (42) are closed about the inner tubing string (125).
  • a slip bowl (175) is connected to the top end of the suspended inner coiled tubing string (125), as shown in FIG. 10.
  • the slip bowl (175) includes an outer diameter that will allow the bowl to land on the upper shoulder of the spool (30) and has a suitable seal assembly, such as plurality of o-ring seals, that will seal against the upper seal bore of the spool (30).
  • An overshot (180) is attached to the lower end of the severed tubing (125A). The overshot (180) is lowered over and latched to the upwardly extending profile on the slip bowl (175).
  • the slip rams (41) and tubing rams (42) are then opened.
  • the inner string (125) may then be slowly lowered until the blow out plug (95) is tagged to verify the location of the BHA (130).
  • the inner string is picked up a short distance to verify that the seal assembly (150) is not engaged in the seal bore (82), as shown in FIG. 11.
  • the lower BHA (130) is in the position shown in FIG. 11, the position of the slip bowl (175) relative to the spool (30) is illustrated in FIG. 12.
  • Pressure may then be applied via a jet pump circulating port (32) to the annulus (151) between the inner coiled tubing (125) and the outer coiled tubing (25).
  • the pressure opens the flapper (87) and is applied against the blow out plug (95).
  • the pressure is increased until the plug (95) is expelled from the bottom sub (90).
  • the release of the plug (95) from the bottom sub will be indicated by a sudden reduction in surface pressure.
  • the inner tubing string (125) is lowered and landed in the spool (30).
  • a stinger (155) will pass through the flapper (87), holding the flapper in the open position, and will extend past the bottom sub (90) as shown in FIG 13.
  • seal assembly (150) will encounter the seal bore (82) prior to the opening of the flapper (87), thereby providing another downhole barrier.
  • a shoulder (145) on the inner string BHA (130) will land on the landing shoulder (81) to give a positive indication that the seal assembly (150) and the stinger (155) are properly located within the outer BHA (75).
  • Shoulders (145) and (81) may also be used to properly space out the inner tubing string (125) prior to cutting the inner coiled tubing and installing the slip bowl (175), as is well understood in the art. After the inner string (125) has been landed, the severed coiled tubing (125 A) is removed from the surface equipment.
  • the master valve (35) is closed and the BOP (40), work window (45), lubricator (50), stuffing box (55), and injector head (60) are nippled down and removed. If a dummy carrier has been installed in the jet pump assembly, a working carrier may be pumped down and installed after the dummy carrier has been reverse circulated out of the well.
  • the jet pump assembly is activated by fluid flow pumped down the inner coiled tubing (125), water will be sucked into the stinger (155) and on to the jet pump assembly where it will be pumped out of the hole.
  • a strainer serves as the stinger (155) and prevents large debris from plugging the jet pump assembly.
  • the strainer may be a sucker rod strainer, a wire wrapped screen, a perforated/slotted pipe, or any other suitable means that has been effectively miniaturized to fit through the outer coiled tubing string (25).
  • a working carrier may be reverse circulated out of the jet pump assembly and a dummy carrier (not shown) circulated down and installed.
  • a dummy carrier may be installed via wireline in the jet pump assembly. The dummy carrier will serve as a mechanical barrier for the inner string (125) as it is removed from the well.
  • the wireline plug (175) may be tested with pressure to make sure it is holding. Once the wireline plug (175) is set and tested, the outer string (25) may then be removed from the well. While preferred embodiments of the apparatus and methods have been discussed for purposes of this disclosure, numerous changes in the construction, installation, and function of the jet pump apparatus and concentric coiled tubing string may be made by those skilled in the art. All such changes are encompassed within the scope and spirit of the following claims.

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  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Mining & Mineral Resources (AREA)
  • Fluid Mechanics (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Mechanical Engineering (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • Chemical & Material Sciences (AREA)
  • General Chemical & Material Sciences (AREA)
  • Jet Pumps And Other Pumps (AREA)

Abstract

L'invention concerne un appareil et un procédé pour éliminer des eaux parasitaires d'un puits de gaz naturel, au moyen d'un ensemble de pompage à jet miniaturisé et d'un train de tiges à tube de production concentrique. L'ensemble de pompage à jet miniaturisé est fixé sur le train de tiges à la surface, puis il est descendu dans le puits sous forme d'une seule unité. En variante, le train de tiges peut être assemblé dans le puits. Une fois au fond, l'ensemble de pompage à jet est activé pour éliminer les eaux parasitaires du puits, tout en facilitant la production de gaz naturel. Si la partie fonctionnelle de l'ensemble de pompage à jet se corrode ou périt, ladite partie peut être désinstallée et remplacée sans retirer l'ensemble de pompage à jet et le train de tige à tube de production concentrique du puits.
PCT/US2005/010725 2004-04-05 2005-03-30 Appareil et procede pour assecher les puits de gaz a gradient basse pression Ceased WO2005100744A1 (fr)

Priority Applications (1)

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CA002562085A CA2562085A1 (fr) 2004-04-05 2005-03-30 Appareil et procede pour assecher les puits de gaz a gradient basse pression

Applications Claiming Priority (4)

Application Number Priority Date Filing Date Title
US55964704P 2004-04-05 2004-04-05
US60/559,647 2004-04-05
US58930204P 2004-07-20 2004-07-20
US60/589,302 2004-07-20

Publications (1)

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WO2005100744A1 true WO2005100744A1 (fr) 2005-10-27

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US (2) US20050274527A1 (fr)
CA (1) CA2562085A1 (fr)
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CN110537001A (zh) * 2017-04-17 2019-12-03 通用电气(Ge)贝克休斯有限责任公司 具有井下流动致动泵的双壁连续油管

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CN110537001A (zh) * 2017-04-17 2019-12-03 通用电气(Ge)贝克休斯有限责任公司 具有井下流动致动泵的双壁连续油管
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US20050274527A1 (en) 2005-12-15
CA2562085A1 (fr) 2005-10-27

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