CONFIGURING A VELOCITY STRING IN A PRODUCTION TUBING OF A WET GAS PRODUCTION WELL

Abstract

A velocity string for increasing fluid velocity in a production tubing (1) of a wet natural gas production well is configured downhole by:—inserting components (5) for configuring an annular liner (4) into the production tubing (1); and—clustering the components together in an annular space (9) adjacent to an inner surface of the production tubing (1) to configure the annular liner (4) in a cost effective manner without requiring killing the well with a high density liquid, expensive hoisting and/or other workover equipment and materials required to install conventional corrosion resistant steel velocity strings.

Description

FIELD OF THE INVENTION

In one aspect, the invention relates to a method for configuring a velocity string downhole in a production tubing of a wet gas production well. In another aspect, the invention relates to a method for producing wet natural gas employing a wet gas production well.

BACKGROUND OF THE INVENTION

It is known to enhance the fluid velocity in a production tubing of a wet gas production well to inhibit downward flux of condensed water and/or other condensable components by inserting a velocity string in the production tubing, which reduces the cross-sectional flow area thereof and thereby increases the wet gas velocity and inhibits downward flux of condensed water and/or other condensable components in the production tubing.

The cost of installing a conventional corrosion resistant steel velocity string in an onshore well may be between 300,000 and 900,000 US dollars. For offshore it is much higher, due to the higher service cost.

There is a need for a more cost effective and efficient method for installing a velocity string in a production tubing of a wet gas production well with a minimal period of interruption of gas production operations and optionally not requiring elongate corrosion resistant steel velocity string tubulars and/or a large work over rig with a complex snubbing and/or coiled tubing insertion unit.

SUMMARY OF THE INVENTION

In accordance with one aspect of the invention, there is provided a method for downhole configuring a velocity string to increase fluid velocity in a production tubing of a wet natural gas production well, the method comprising:

• • inserting components for configuring an annular liner into the production tubing;
  • clustering the components together in an annular space within the production tubing to configure the annular liner.

In accordance with another aspect of the invention, there is provided a method for producing wet natural gas comprising downhole configuring a velocity string to increase fluid velocity in a production tubing of a wet natural gas production well, the method comprising:

• • inserting components for configuring an annular liner into the production tubing;
  • clustering the components together in an annular space within the production tubing to configure the annular liner; and
  • producing wet natural gas through the interior of the velocity string formed by the annular liner.

These and other features, embodiments and advantages of the method according to the invention are described in the accompanying claims, abstract and the following detailed description of non-limiting embodiments depicted in the accompanying drawings, in which description reference numerals are used which refer to corresponding reference numerals that are depicted in the drawings.

Similar reference numerals in different figures denote the same or similar objects. Objects and other features depicted in the figures and/or described in this specification, abstract and/or claims may be combined in different ways by a person skilled in the art.

BRIEF DESCRIPTION OF THE DRAWINGS

FIGS. 1A-F show a first sequence of steps illustrating a first embodiment, which uses a (solid) casting string;

FIGS. 2A-F show a second sequence of steps illustrating a second embodiment, which uses an expandable casting string;

FIGS. 3A-E show a third sequence of steps illustrating a third embodiment, which uses a casting string in the form of a casting tubular;

FIGS. 4A-E show a fourth sequence of steps illustrating a fourth embodiment, which uses a casting tubular in a different manner as in FIGS. 3A-E;

FIGS. 5A-E show a fifth sequence of steps illustrating a fifth embodiment, wherein a slug line is used as casting string;

FIGS. 6A-E show a sixth sequence of steps illustrating a sixth embodiment wherein a slug line is used as casting string;

FIGS. 7A-F show a seventh sequence of steps illustrating a seventh embodiment wherein a vertical slug line is used as casting string;

FIGS. 8A-F show an eighth sequence of steps illustrating an eighth embodiment, wherein a spray head is used to build the annular liner layer by layer;

FIGS. 9A-F show a ninth sequence of steps illustrating a ninth embodiment, wherein flexible hoses are used to build the annular liner layer by layer; and

FIGS. 10A-F show a tenth sequence of steps illustrating a tenth embodiment, wherein ring-shaped liner sections are stacked.

DETAILED DESCRIPTION OF THE DEPICTED EMBODIMENTS

It is presently proposed to insert components for configuring an annular liner into the production tubing, which are clustered together filling up an annular space within the production tubing to configure the annular liner. Wet natural gas may subsequently be produced through the interior of the velocity string formed by the annular liner.

It is envisaged that, prior to inserting the components for configuring the annular liner into the production tubing, wet natural gas would have been produced through the interior of the production tubing. The proposed method may be employed as an alternative to installing elongate corrosion resistant steel velocity string tubulars, such as would have been done in wells when the upward fluid velocity through the production tubing would have dropped below a certain lower threshold and backflow of water and other condensable components would become problematic.

In the context of the present disclosure, clustering may involve packing the components together within the bounds of the production tubing thereby filling up the annular space within the production tubing. The annular liner may thus comprise, preferably consist of, a full solid layer which clads the inside surface of the production tubing over its entire circumference. Suitably, a majority of the inside surface of the production tubing is in physical contact with the annular liner. The production tubing provides the mechanical support to the annular liner so that the annular liner itself does not have to be self-supporting.

Suitably, the components are injected in a substantially liquid form into the well and are solidified and/or bonded together in the annular space to configure the annular liner.

The liquid components may be inserted by pumping the liquid components into the annular space, whereby the annular liner is formed by inducing the liquid components to harden in the annular space within the production tubing.

Suitably, insertion of the liquid components may be facilitated by inserting a casting string provided near a lower end thereof with a solid or annular bottom plug that slideably engages an inner surface of the production tubing through a stuffing box at a wellhead of the well. The stuffing box may comprise a lubricator.

The casting string may be a solid rod or tubular which is removed from the well before the step of producing wet natural gas through the interior of the annular liner.

The liquid components may comprise a cement slurry or a fluid resin which hardens downhole to an annular synthetic liner and the components and any associated casting and/or other annular liner assembling equipment are inserted via a pressure resistant lock, lubricator and/or stuffing box in the wellhead and the well is not killed by a high density liquid when the annular liner is configured, thereby significantly reducing downtime of wet gas production operations.

In various embodiments, a liquid filler material is pumped through an injection port in the wellhead, below the stuffing box and above the bottom plug, thereby pushing the bottom plug down into the well until it has reached a target depth.

In other embodiments, the liquid filler material is inserted in the annular space via a fluid injection string, which is lowered into the production tubing.

FIGS. 1A-F show a first embodiment of the method of in-situ casting a velocity string in accordance with the invention.

FIG. 1A shows the production tubing 1 of a wet natural gas production well through which wet gas comprising methane (CH₄), water (H₂O), and possibly condensates (C₂-C₆) and/other condensable components flow to surface as illustrated by arrow 2, but in which due to a gradual temperature and pressure decrease water and/or other condensable components flow back to the bottom of the well as illustrated by arrow 3.

This backflow of water and other condensable components inhibits and may even fully choke the gas production and may require pumping the water from the well during a temporary well shut down.

A velocity string consisting of a steel pipe (not shown) may be suspended within the production tubing 1, to enhance the upward velocity of the wet natural gas and inhibit backflow of water and/or other condensable components. However, illustrated below are preferred alternatives.

FIGS. 1B-1F show a cost efficient alternative wherein as illustrated in FIG. 1F a velocity string formed by an annular liner 4 is cast in situ, which enhances the wet gas velocity 2 such that backflow of water and/or other condensable components is inhibited.

FIG. 1B shows that the annular liner 4 is formed by pumping a cement slurry 4A or another hardenable initially liquid substance into via an injection port 5 in the wellhead 6 into the production tubing 1, along with a solid casting string 7, which may be made of poly-ethylene or another stretchable plastic material.

A bottom plug 8 is connected to the lower end of the casting string 6 and the wellhead 6 comprises a stuffing box 10 that sealingly surrounds the casting string 7, thereby forming a annular space 9 between the casting string 7 and production tubing 1, which is sealed at the bottom by the bottom plug 8 and at the top by the stuffing box 10. Stuffing box 10 schematically comprises seals 10a and 10b.

Subsequently cement slurry 4A is injected via the injection port 5 into the annular space 9 as illustrated by arrows 11 thereby pushing the bottom plug down as illustrated by arrow 12, which then pulls the casting string 6 down into the production tubing 1 as illustrated by arrow 13.

FIG. 1C shows that injection of the cement slurry 4A is continued until the bottom plug 8 has reached the target depth near the bottom of the production tubing 1 and just above the production interval (not shown) where during production wet natural gas flows into the wellbore via a permeable tubular sand screen.

FIG. 1D shows that after the cement slurry 4A has hardened into an annular liner 4 the casting string 7 may be pulled out of the production tubing 1 as illustrated by arrow 14. Due to the tension the casting string 7 elongates and its diameter may decrease, leading to it being freed up from the solidified annular liner 4.

FIG. 1E shows that the lower end of casting string 7 is also released from the bottom plug 8 and the entire casting string 7 is pulled out of the solidified liner 4 via the stuffing box 10.

FIG. 1F shows that after removal of the casting string 7 the stuffing box 10 may be removed from the wellhead 6 and the well is brought back in production whereby the upward velocity of the wet natural gas is increased (relative to the situation as shown in FIG. 1A) due to the presence of the annular liner 4, so that downward reflux of condensed water and/or other condensable components is inhibited.

FIGS. 2A-2F illustrate an alternative method of inserting an annular liner. In the alternative method:

• • the casting string is an expandable casting tubular;
  • during the pump down procedure the casting tubular is collapsed by the pressure of the liquid filler material that is pumped into the surrounding annular space; and
  • after the bottom plug has reached the target depth fluid is pumped into the interior of the casting tubular, thereby radially expanding the tubular and pushing excess liquid filler slurry out of the annular space via the injection port.

FIG. 2A shows again the starting situation of the unlined tubing 1 in which the gas velocity becomes too low to lift water and other condensable components to surface.

FIG. 2B shows that the annular liner 4 may be formed by pumping a cement slurry 4A or another hardenable initially liquid substance into via the injection port 5 in the wellhead 26 into the production tubing 1, along with a hollow casting string 27, which is in a collapsed state during insertion through the stuffing box 10 in the wellhead 6.

A bottom plug 8 is connected to the lower end of the casting string 27 and the wellhead 6 comprises a stuffing box 10 that sealingly surrounds the collapsed casting string 7, thereby forming an annular space 29 between the casting string 27 and the production tubing 1, which is sealed at the bottom by the bottom plug 8 and at the top by the stuffing box 10.

Subsequently cement slurry 4A may be injected via the injection port 5 into the annular space 29 as illustrated by arrows 11 thereby pushing the bottom plug down as illustrated by arrow 12, which may then pull the casting string 6 down into the production tubing 1 as illustrated by arrow 13.

FIG. 2C shows that injection of the cement slurry 4A may be continued until the bottom plug 8 has reached the target depth near the bottom of the production tubing 1 and just above the production interval (not shown) where during production wet natural gas flows into the wellbore via a permeable tubular sandscreen.

FIG. 2D shows that, after the bottom plug 8 has reached the target depth, a working fluid 26, such as water, brine and/or compressed air, may be injected into the interior of the casting string 27 thereby radially expanding the casting string 27 until the entire casting tubular 27 is expanded to an enlarged and preferably uniform outer diameter D as illustrated in FIG. 2E. The expanding casting tubular 27 reduces the volume of the surrounding annular space 29 and pushes any excess cement slurry out of the annular space 29 vie the cement injection port 5. The expanding casting tubular 27 is held at pressure during cement hardening to generate a cement liner 4 with a uniform inner diameter and without any voids or other irregularities.

FIGS. 2D and 2E shows how the production tubing 1 with annular liner 4 and expanded casting tubular 27 may be prepared for re-initiating wet gas production at elevated velocity after removal of the stuffing box 10 and closed bottom end 27A of the expanded casting tubular 27.

In another embodiments:

• • the liquid components are inserted by injecting them as an annular gel body around a substantially cylindrical core formed by a degradable gel which is injected into the wellhead simultaneously with and at substantially the same downward velocity as the annular gel body, and
  • after the annular space is substantially filled with the annular gel body the annular gel body is allowed to harden and the cylindrical core is allowed to degrade.

FIGS. 3A-3E show such an embodiment of the method according to the invention, wherein a gelled cement slurry 34A is pumped through the injection port 5 into the annulus 39 surrounding a substantially unexpandable casting tubular 37. A degradable bottom plug 32 is provided in a lower end of the casting tubular 37. A degradable gelling core fluid 38 may be pumped into the casting tubular 37 at substantially the same downward velocity as the gelled cement slurry 34A to assist in pushing the degradable bottom plug 32 down into the production tubing 1.

The degradable gelled core fluid 38 and the degradable bottom plug 32 may be designed to deteriorate over time or may be otherwise removed after the gelled cement slurry in the annular space has hardened to a solid annular liner 4 as illustrated in FIG. 3C. For instance, the degradable bottom plug 32 and/or the degradable gelled core fluid 38 may dissolve over time.

FIG. 3D shows that one way of getting the remaining degraded core fluid 38 out of the well is to use sodium balls 35 to create bubbles and let the degraded core fluid be lifted to the surface.

FIG. 3E shows that alternatively, the degraded core fluid 38 could be lifted from the well by means of a coiled tubing 33 or other type of pipe. Alternatively a wireline with a bailing device (not shown) could be used to remove the degraded core fluid from the well and prepare the well for resumption of wet gas production at elevated speed through the hardened annular liner 4 that functions as a velocity string.

FIGS. 4A-4E show another embodiment wherein the annular liner 4 is cast in-situ within the production tubing 1 to generate the pumped velocity string. In this example, the liquid filler material comprises a chemical composition that hardens upon mixing with a hardening agent. After the bottom plug has reached the target depth, the casting tubular is pulled out of the well whilst the interior of the bottom section thereof is closed and the hardening agent is injected via the upper part of the casting tubular and a hardening agent injection opening in the wall of the casting tubular above the closed bottom section. Thereby a hardened synthetic liner is generated. The casting string for this embodiment is preferably a casting tubular with a bottom section which may have a larger outer diameter than an upper part of the casting tubular to facilitate compacting the filler material in the annular space.

FIG. 4A shows again the original condition of the production tubing 1 in which water and/or other condensable components may trickle down (3) through the production tubing 1.

FIG. 4B shows that a hardenable fluid 44A, such as an epoxy resin or other chemical composition is pumped via the injection port 5 into the annular space 41 between the production tubing 1 and a casting tubular 47. The casting tubular 47 may be a coiled tubing. A bottom section 47A is provided with the bottom plug 8 which may be similar as in other embodiments. The casting tubular 47 may have an enlarged bottom section 47A, to which bottom plug 8 is connected. A ball catcher 50 may be provided in the casting tubular 47. The ball catcher 50 may seal off (or be operatively connected to seals that seal off) agent injection ports 52 provided in the casting tubular 47.

FIG. 4C shows that once the bottom plug 8 has reached a target depth a ball 49 is pumped into the ball catcher 50, whereupon the agent injection ports 52 are opened. A hardening agent 54 may then be pumped into the annular space 41 via casting tubular 47 (as illustrated by arrows 51) and the injection ports 52. The injection ports may be circumferentially spaced around the casting tubular 47.

FIG. 4D shows how hardening agent 54 may be continuously pumped via the injection ports 52 into the surrounding annulus as illustrated by arrows 53 while pulling the casting tubular 47 out of the production tubing 1 as illustrated by arrow 55. The hardening agent 54 can thereby be thoroughly mixed with the hardenable fluid 44A to form a hardened annular liner 44 that performs as velocity string as illustrated in FIG. 4E.

The bottom section of the casting string may be provided with a coating to prevent sticking to the annular liner being produced.

In yet another group of embodiments, a fluid injection string, which is lowered into the production tubing, is employed to insert the liquid filler material into the annular space within the production tubing. An advantage of this group of embodiment is that the wellhead can be bypassed whereby contact between the liquid filler material and the wellhead can be fully avoided. Moreover, the liquid filler material does not need to be occupying the annular space all the way up to the wellhead but it can be provided only in a certain depth interval below the wellhead. The annular liner can then suitably be constructed only in sections of the production tubing that are free from subsurface well equipment such as safety valves. The casting string may fulfil the function of such injection string.

The casting string, or other type of injection string, may suitably take the form of a slug line which is lowered through the production tubing. The slug line may subsequently be retrieved from the production tubing, while pumping slugs of said components down the slug line to a frusto-conical injection head at a lower end of the slug line. The components may be mixed at an entrance of the frusto-conical injection head, and mixed components may be discharged from the frusto-conical injection head against the inner surface of the production tubing, whereby allowing the mixed components to cure to generate a cured solidified annular liner against the inner surface of the production tubing.

FIGS. 5A-F, 6A-F, and 7A-F show embodiments wherein a slug line comprising a frusto-conical injection head is employed. The slug line is provided with a mixer tool in or above the frustro-conical injection head. Three examples are illustrated. Suitably, the slug line may be made of coiled tubing.

FIG. 5A shows the original situation of a production tubing 1 of a wet gas production well in which the upward velocity 2 is too low to inhibit downward reflux 3 of condensed water and/or other condensates.

FIG. 5B shows how a frusto-conical injection head 80 attached to a filled slug line 81 may be lowered into the production tubing 1. Slugs of two different gels 82 and 83 are pumped down the slug line 81 to the injection head 80.

FIG. 5C shows how the slugs of two gels 82 and 83 may be mixed at the entrance of the injection head 80 by pumping them through a piece of pipe split in two parallel channels 84 and 85 with different flow resistances, slowing the flow more down in the narrowest channel 85 with higher flow resistance than in the widest channel 84. The two gels 82 and 83 are thereby mixed in the annular space 86 surrounding the injection head to generate a cured solidified annular liner 87 against the inner surface of the production tubing 1 below the injection head 80. FIGS. 5C and 5D show how the injection head 80 may be pulled upwards as illustrated by arrows 88 by pulling the slug line 81 through a stuffing box assembly 10 at the wellhead 6 while the gel slugs 82 and 83 are pumped down, creating the solidified annular liner 87 against the inner surface of the production tubing 1.

FIG. 5E shows how the injection head 80 and stuffing box assembly 10 may be removed from the wellhead 6 after the solidified annular liner 87 has been placed.

FIG. 5F shows how wet gas production with an elevated production velocity 2 is resumed in the production tubing 1 of which the inner wall is covered by the cured annular liner 87.

FIG. 6A again shows the original situation of a production tubing 1 of a wet gas production well in which the upward velocity 2 is too low to inhibit downward reflux 3 of condensed water and/or other condensates.

FIG. 6B shows how a frusto-conical injection head 90 attached to a filled slug line 91 may be lowered into the production tubing 1. Slugs of two different gels 92 and 93 are pumped down the slug line 91 to the injection head 90.

FIG. 6C shows how the slugs of two gels 92 and 93 may be mixed at the entrance of the injection head 90 by pumping them through a piece of pipe split in two parallel channels 94 and 95 with different flow resistances, slowing the flow more down in the narrowest and longer channel 95 with higher flow resistance than in the widest channel 94. The two gels 92 and 93 are thereby mixed in the annular space 96 surrounding the injection head to generate a cured solidified annular liner 97 against the inner surface of the production tubing 1 below the injection head 90. FIGS. 6C and 6D show how the injection head 90 may be pulled upwards as illustrated by arrows 98 by pulling the slug line 91 through a stuffing box assembly 10 at the wellhead 6, while the gel slugs 92 and 93 are pumped down, creating the solidified annular liner 97 against the inner surface of the production tubing 1.

FIG. 6E shows how the injection head 90 and stuffing box assembly 10 may be removed from the wellhead 6 after the solidified annular liner 97 has been placed.

FIG. 6F shows how wet gas production with an elevated production velocity 2 is resumed in the production tubing 1 of which the inner wall is covered by the cured annular liner 97.

FIG. 7A again shows the original situation of a production tubing 1 of a wet gas production well in which the upward velocity 2 is too low to inhibit downward reflux 3 of condensed water and/or other condensates.

FIG. 7B shows how a frusto-conical injection head 100 attached to a filled slug line 101 may be lowered into the production tubing 1. As shown, vertical slugs of two different components 102 and 103 are pumped down the slug line 101 to the injection head 100. The slug line may be compartmentalized to prohibit contact between the vertical slugs of different components. For instance, the slug line 101 may comprise concentrically arranged conduits. Alternatively, the slug line 101 may have multiple tubes bundled within one slug line 101. All conduits and tubes may consist of coiled tubing. Compartmentalization may not be necessary in case the components are pumped down in gelled form.

FIG. 7C shows how the slugs of two components 102 and 103 may be mixed at the entrance of the injection head 100 by pumping them through a suitable mixer tool. A static mixer 105 may be employed, such as for instance a helical static mixer available from StamixCo or an X-grid static mixer. The two components 102 and 103 are thereby mixed in the annular space 106 surrounding the injection head to generate a cured solidified annular liner 107 against the inner surface of the production tubing 1 below the injection head 100. FIGS. 7C and 7D show how the injection head 100 may be pulled upwards as illustrated by arrows 108 by pulling the slug line 101 through a stuffing box assembly 10 at the wellhead 6, while the component slugs 102 and 103 are pumped down, creating the solidified annular liner 107 against the inner surface of the production tubing 1.

FIG. 7E shows how the injection head 100 and stuffing box assembly 10 may be removed from the wellhead 6 after the solidified annular liner 107 has been placed.

FIG. 7F shows how wet gas production with an elevated production velocity 2 is resumed in the production tubing 1 of which the inner wall is covered by the cured annular liner 107.

In any of these examples, the frusto-conical injection head may be provided with a bypass line (not shown) to establish fluid communication between the annular space above the injection head (between the slug line and the production tubing) and the interior space surrounded by the annular liner below the injection head. Herewith pressure differential below and above the injection head can be equalized when the slug line is inserted into or retracted from the production tubing. Furthermore, a coating may be provided on the injection head to prevent sticking with the annular liner.

As can be seen in FIGS. 5A-F, 6A-F, and 7A-F, while the cured annular liner may necessarily extend all the way up to the wellhead (similar to the other embodiments), it is also conceived that the cured annular liner does not necessarily extend all the way up to the wellhead. Suitably, the cured annular liner is only formed below installed well equipment, such as a subsurface safety valve.

The liquid components may also be inserted by a longitudinally movable, and optionally rotatable, spray head that sprays and clads the liquid components against the inner surface of the production tubing to configure the annular liner. FIGS. 8A-E show an example wherein from the wellhead 6 a spray head 60 is lowered to the target depth D.

FIG. 8B shows that once at the target depth D, a hardenable liquid 63, for example a liquid or gelled cement slurry or a hardenable epoxy resin composition, may be sprayed onto the inner surface of the production tubing 1 wall whilst the spray head 60 is pulled upwards as illustrated by arrow 61 and optionally also rotated as illustrated by arrow 62 to provide an annular cladding 64 with uniform thickness against the inner surface of the production tubing 1.

FIGS. 8C and 8D show that after the hardenable liquid has cured, the spray head 60 can be lowered again to the target depth D as illustrated by arrow 65 whereupon the spray head 60 may be pulled up again as illustrated by arrow 61 and an additional annular layer 66 is applied within the existing annular layer 64. The way the velocity string is built up layer by layer. This spraying process may be repeated as many times as necessary to obtain the desired internal flow diameter of the velocity string.

FIG. 8E shows that when the appropriate thickness of the annular layer 64,66 has been reached, the well is opened up again for production of wet gas at an elevated velocity.

FIGS. 9A-E illustrate various steps of a ninth embodiment, in which an initially collapsed flexible hose 56A, suitably impregnated with resin, is at a surface end 56D thereof connected to the wellhead 6, The flexible hose 56A is gradually inverted, as illustrated by reference sign 56B, and thereby cladded to the inner surface of the production tubing 1 as illustrated by reference sign 56C.

FIG. 9A illustrates that this may be done by pressurizing the inside of the hose 56A-D by pumping working fluid into the hose 56A-D via fluid inlet ports 6A in the wellhead as illustrated by arrows 57.

FIG. 9B shows how a major part of the hose 56B has been cladded to the inner surface of the production tubing 1 after lowering the hose to a target depth D within the production tubing 1. This may be accompanied by paying out a hose hoisting cable 58, connected to a lower end of the hose.

FIG. 9C shows that the resin in the hose 56B may be cured, for example by heat and/or a UV light source and/or a slowly releasing hardening agent that may be released by the inversion process.

FIG. 9D shows that the inverted lower end 56B of the hose 56 may be cut off at the target depth D, for instance using a cutting tool 55, to open up the interior. The cut off lower end may be removed from the interior of the production tubing 1, for instance by pulling up the hose hoisting cable 58. The result is illustrated in FIG. 9E. The surface end 56D may be cut off at S.

FIG. 9E illustrates that the hose inversion process may be repeated with other impregnated hoses 59A-D as many times as needed for to reduce the width of the flow path within the cladded production tubing 1 to the desired size. This is another example of how the annular liner may be built up layer by layer.

Optionally, the components comprise ring shaped liner sections with substantially cylindrical inner surfaces that are clustered together by stacking the sections on top of each other within the annular space to configure the annular liner. In an example illustrated in FIGS. 10A-10F, ring-shaped liner sections 70A-I are lowered through the wellhead 6 into the production tubing 1 and stacked on top of each other to configure the annular liner. The liner sections may be introduced into the production tubing via a pressure resistant lock (not shown).

FIG. 10A shows that initially a landing sleeve 71 with a conic inner surface or any other desired type of landing device may be inserted at the target depth D.

FIG. 10B shows that subsequently an annular bottom section 72, which may for example be made of plastic or another resilient material, with a conic outer surface 73 is lowered through the wellhead 6 into the production tubing 1.

FIG. 10C shows that the ring shaped bottom section 72 has landed within the landing sleeve 71.

FIG. 10D shows how a first ring-shaped liner section 70A may be lowered through the wellhead 6 into the production tubing.

FIG. 10E shows how the first ring-shaped liner section 70A may be stacked on top of the ring shaped bottom section 72 and a second ring-shaped liner section 70B may be lowered through the wellhead 6 into the production tubing 1.

FIG. 10F shows that the procedure of stacking subsequent ring shaped liner sections 70A-I on top of each other until the thus created annular liner has reached the wellhead 6 or a certain specified depth below the wellhead 6 within the production tubing.

It is observed that the ring shaped liner sections 70A-I may be inserted in a folded and collapsed configuration through the wellhead 6 and expanded to an annular shape downhole within the production tubing 1.

It will be understood that the downhole annular liner configuration method and/or any annular liners configured in accordance with the present invention are well adapted to create velocity strings that can be inserted into the production tubing in an efficient and cost effective manner without requiring complex and expensive hoisting and other workover equipment and without requiring expensive elongate stainless steel or other corrosion resistant velocity string tubulars. Furthermore, most of the embodiments described herein can be implemented in a pressurized well, without the need to kill the well. This is a big advantage.

After having produced wet natural gas through the interior of the velocity string formed by the annular liner for a period of time, the flow area available within the annular liner may be further reduced if deemed necessary by inserting and clustering additional components and configuring an additional annular liner within the annular liner. This may, for instance, be done when, after further depleting the gas reservoir, the flow velocity has again declined.

The particular embodiments disclosed above are illustrative only, as the present invention may be modified, combined and/or practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein.

Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below.

It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined and/or modified and all such variations are considered within the scope of the present invention as defined in the accompanying claims.

While any methods, systems and/or products embodying the invention are described in terms of “comprising,” “containing,” or “including” various described features and/or steps, they can also “consist essentially of” or “consist of” the various described features and steps.

All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values.

Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee.

Moreover, the indefinite articles “a” or “an”, as used in the claims, are defined herein to mean one or more than one of the element that it introduces.

If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be cited herein by reference, the definitions that are consistent with this specification should be adopted.

Claims

1. A method for producing wet natural gas comprising downhole configuring a velocity string to increase fluid velocity in a production tubing of a wet natural gas production well, the method comprising:

inserting components for configuring an annular liner into the production tubing;

clustering the components together in an annular space within the production tubing to configure the annular liner; and

producing wet natural gas through the interior of the velocity string formed by the annular liner.

2. The method of claim 1, wherein the components are injected in a substantially liquid form into the well and are solidified and/or bonded together in the annular space to configure the annular liner.

3. The method of claim 2, wherein the liquid components are inserted by pumping the liquid components into the annular space and the annular liner is formed by inducing the liquid components to harden in the annular space within the production tubing.

4. The method of claim 2, wherein lowering a slug line through the production tubing and subsequently retrieving the slug line from the production tubing while pumping slugs of said components down the slug line to a frusto-conical injection head at a lower end of the slug line, wherein the components are mixed at an entrance of the frusto-conical injection head, and discharging mixed components against the inner surface of the production tubing, whereby allowing the mixed components to cure to generate a cured solidified annular liner against the inner surface of the production tubing.

5. The method of claim 4, wherein the components are gels.

6. The method of claim 3, wherein:

the liquid components are inserted by injecting them as an annular gel body around a substantially cylindrical core formed by a degradable gel which is injected into the wellhead simultaneously with and at substantially the same downward velocity as the annular gel body, and

after the annular space is substantially filled with the annular gel body the annular gel body is allowed to harden and the cylindrical core is allowed to degrade.

7. The method of claim 3, wherein the liquid components are inserted by:

inserting a casting string through a stuffing box at a wellhead of the well, which casting string is provided near a lower end thereof with one of the group consisting of a solid bottom plug and an annular bottom plug, which bottom plug slideably engages an inner surface of the production tubing; and

pumping the liquid filler material through an injection port in the wellhead below the stuffing box and above the bottom plug, thereby pushing the bottom plug down into the well until it has reached a target depth.

8. The method of claim 7, wherein the casting string comprises one of the group consisting of a solid rod and a tubular, which is removed from the well before the step of producing wet natural gas through the interior of the annular liner.

9. The method of claim 7, wherein:

the casting string is an expandable casting tubular;

during the pump down procedure the casting tubular is collapsed by the pressure of the liquid filler material that is pumped into the surrounding annular space; and

after the bottom plug has reached the target depth fluid is pumped into the interior of the casting tubular, thereby radially expanding the tubular and pushing excess liquid filler slurry out of the annular space via the injection port.

10. The method of claim 7, wherein:

the casting string is a casting tubular with a bottom section having a larger outer diameter than an upper part of the casting tubular;

the liquid filler material comprises a chemical composition that hardens upon mixing with a hardening agent;

after the bottom plug has reached the target depth the casting tubular is pulled out of the well, whilst the interior of the bottom section thereof is closed and the hardening agent is injected via the upper part of the casting tubular and a hardening agent injection opening in the wall of the casting tubular above the closed bottom section, thereby generating a hardened synthetic liner.

11. The method of claim 7, wherein:

the casting string is one of the group consisting of a rod and a tubular, made of poly-ethylene or another plastic material that stretches and obtains a reduced diameter when a tension force is exerted to the casting string; and

the casting string is released from the bottom plug and pulled out of the well after hardening of the annular liner.

12. The method of claim 2, wherein the liquid components are inserted by a longitudinally movable, and optionally rotatable, spray head that sprays and clads the liquid components against the inner surface of the production tubing to configure the annular liner.

13. The method of claim 2, wherein the liquid components comprise a cement slurry, which is induced to harden to an annular cement liner.

14. The method of claim 2, wherein the liquid components comprise a fluid resin which hardens downhole to an annular synthetic liner.

15. The method of claim 14, wherein the liquid components comprise a hardenable resin composition and a hardening agent that are separately injected into the well and mixed and cured downhole.

16. The method of claim 1, wherein the components comprise ring shaped liner sections with substantially cylindrical inner surfaces that are clustered together by stacking the sections on top of each other within the annular space to configure the annular liner.

17. The method of claim 1, wherein the components and any associated casting and/or other annular liner assembling equipment are inserted via at least one of the group consisting of a pressure resistant lock, a lubricator, and a stuffing box in the wellhead, and wherein the well is not killed by a high density liquid when the annular liner is configured.

18. The method of claim 1, wherein producing wet natural gas through the interior of the production tubing prior to inserting the components for configuring the annular liner into the production tubing.

19. The method of claim 1, wherein, after having produced wet natural gas through the interior of the velocity string formed by the annular liner for a period of time, inserting and clustering additional components for configuring an additional annular liner within the annular liner.

20. A method of downhole configuring a velocity string to increase fluid velocity in a production tubing of a wet natural gas production well, the method comprising:

inserting components for configuring an annular liner into the production tubing;

clustering the components together in an annular space within the production tubing to configure the annular liner.