Source: https://patents.justia.com/patent/8122948
Timestamp: 2019-06-16 03:17:14
Document Index: 162824955

Matched Legal Cases: ['Application No. 10185612', 'Application No. 01980737', 'art 1', 'art 2', 'Application No. 2', 'Application No. 10185612', 'Application No. 10161116', 'Application No. 10161117', 'Application No. 10161120', 'Application No. 10167181', 'Application No. 10167182', 'Application No. 10167183', 'Application No. 10167184', 'Application No. 10185612', 'Application No. 20015431', 'Application No. 10185795', 'Application No. 01980737', 'Application No. 10013192', 'Application No. 2004289864', 'Application No. 2004289864', 'Application No. 2', 'Application No. 05717806', 'Application No. 05717806', 'Application No. 07864486', 'Application No. 10167181', 'Application No. 10167183', 'Application No. 10167182', 'Application No. 10167184', 'Application No. 07842464', 'Application No. 10185795', 'Application No. 10013192', 'Application No. 06024001', 'Application No. 20032037', 'Application No. 200903221', 'Application No. 2', 'Application No. 05781685', 'Application No. 01980737', 'Application No. 10185612']

US Patent for Apparatus and method for recovering fluids from a well and/or injecting fluids into a well Patent (Patent # 8,122,948 issued February 28, 2012) - Justia Patents Search
Justia Patents Treatment Of Produced FluidsUS Patent for Apparatus and method for recovering fluids from a well and/or injecting fluids into a well Patent (Patent # 8,122,948)
Apr 27, 2010 - Cameron Systems (Ireland) Limited
Latest Cameron Systems (Ireland) Limited Patents:
Well Testing and Production Apparatus and Method
Embodiments of the invention will now be described by way of example only and with reference to the accompanying drawings in which: —
Referring to FIG. 3a, a further embodiment of a cap 40a has a large diameter conduit 42a extending through the open PSV 15 and terminating in the production bore 1 having seal stack 43a below the branch 10, and a further seal stack 43b sealing the bore of the conduit 42a to the inside of the production bore 1 above the branch 10, leaving an annulus between the conduit 42a and bore 1. Seals 43a and 43b are disposed on an area of the conduit 42a with reduced diameter in the region of the branch 10. Seals 43a and 43b are also disposed on either side of the crossover port 20 communicating via channel 21c to the crossover port 21 of the annulus bore 2.
Injection fluids enter the branch 10 from where they pass into the annulus between the conduit 42a and the production bore 1. Fluid flow in the axial direction is limited by the seals 43a, 43b and the fluids leave the annulus via the crossover port 20 into the crossover channel 21c. The crossover channel 21c leads to the annulus bore 2 and from there the fluids pass through the outlet 62 to the pump or chemical treatment apparatus. The treated or pressurised fluids are returned from the pump or treatment apparatus to inlet 61 in the production bore 1. The fluids travel down the bore of the conduit 42a and from there, directly into the well bore.
Cap service valve (CSV) 60 is normally open, annulus swab valve 32 is normally held open, annulus master valve 25 and annulus wing valve 29 are normally closed, and crossover valve 30 is normally open. A crossover valve 65 is provided between the conduit bore 42a and the annular bore 2 in order to bypass the pump or treatment apparatus if desired. Normally the crossover valve 65 is maintained closed.
FIG. 3b shows a simplified version of a similar embodiment, in which the conduit 42a is replaced by a production bore straddle 70 having seals 73a and 73b having the same position and function as seals 43a and 43b described with reference to the FIG. 3a embodiment. In the FIG. 3b embodiment, production fluids enter via the branch 10, pass through the open valve PWV 12 into the annulus between the straddle 70 and the production bore 1, through the channel 21c and crossover port 20, through the outlet 62a to be treated or pressurised etc, and the fluids are then returned via the inlet 61a, through the straddle 70, through the open LPMV18 and UPMV 17 to the production bore 1.
The FIG. 4a embodiment has a different design of cap 40c with a wide bore conduit 42c extending down the production bore 1 as previously described. The conduit 42c substantially fills the production bore 1, and at its distal end seals the production bore at 83 just above the crossover port 20, and below the branch 10. The PSV 15 is, as before, maintained open by the conduit 42c, and perforations 84 at the lower end of the conduit are provided in the vicinity of the branch 10. Crossover valve 65b is provided between the production bore 1 and annulus bore 2 in order to bypass the chemical treatment or pump as required.
The FIG. 4a embodiment works in a similar way to the previous embodiments. This embodiment therefore provides a fluid diverter for use with a wellhead tree comprising a thin walled conduit connected to a tree cap, with one seal stack element, which is plugged at the bottom, sealing in the production bore above the hydraulic master valve and crossover outlet (where the crossover outlet is below the horizontal plane of the flowline outlet), diverting flow through the branch to the annular space between the perforated end of the conduit and the existing tree bore, through perforations 84, through the bore of the conduit 42, to the tree cap, to a treatment or booster apparatus, with the return flow routed through the annulus bore (or annulus flow path in concentric trees) and crossover outlet, to the production bore 1 and the well bore.
Referring now to FIG. 4b, a modified embodiment dispenses with the conduit 42c of the FIG. 4a embodiment, and simply provides a seal 83a above the XOV port 20 and below the branch 10. This embodiment works in the same way as the previous embodiments.
FIG. 5 shows a subsea tree 101 having a production bore 123 for the recovery of production fluids from the well. The tree 101 has a cap body 103 that has a central bore 103b, and which is attached to the tree 101 so that the bore 103b of the cap body 103 is aligned with the production bore 123 of the tree. Flow of production fluids through the production bore 123 is controlled by the tree master valve 112, which is normally open, and the tree swab valve 114, which is normally closed during the production phase of the well, so as to divert fluids flowing through the production bore 123 and the tree master valve 112, through the production wing valve 113 in the production branch, and to a production line for recovery as is conventional in the art.
In the embodiment of the invention shown in FIG. 5, the bore 103b of the cap body 103 contains a turbine or turbine motor 108 mounted on a shaft that is journalled on bearings 122. The shaft extends continuously through the lower part of the cap body bore 103b and into the production bore 123 at which point, a turbine pump, centrifugal pump or, as shown here a turbine pump 107 is mounted on the same shaft. The turbine pump 107 is housed within a conduit 102.
The turbine motor 108 is configured with inter-collating vanes 108v and 103v on the shaft and side walls of the bore 103b respectively, so that passage of fluid past the vanes in the direction of the arrows 126a and 126b turns the shaft of the turbine motor 108, and thereby turns the vanes of the turbine pump 107, to which it is directly connected.
The upper end of the conduit 102 is sealed in a similar fashion to the inner surface of the cap body bore 103b, at a lower end thereof, but the conduit 102 has apertures 102a allowing fluid communication between the interior of the conduit 102, and the annulus 124, 125 formed between the conduit 102 and the bore of the tree.
The turbine motor 108 is driven by fluid propelled by a hydraulic power pack H which typically flows in the direction of arrows 126a and 126b so that fluid forced down the bore 103b of the cap turns the vanes 108v of the turbine motor 108 relative to the vanes 103v of the bore, thereby turning the shaft and the turbine pump 107. These actions draw fluid from the production bore 123 up through the inside of the conduit 102 and expels the fluid through the apertures 102a, into the annulus 124, 125 of the production bore. Since the conduit 102 is sealed to the bore above the apertures 102a, and below the production wing branch at the lower end of the conduit 102, the fluid flowing into the annulus 124 is diverted through the annulus 125 and into the production wing through the production wing valve 113 and can be recovered by normal means.
Another benefit of the present embodiment is that the direction of flow of the hydraulic power pack H can be reversed from the configuration shown in FIG. 5, and in such case the fluid flow would be in the reverse direction from that shown by the arrows in FIG. 5, which would allow the re-injection of fluid from the production wing valve 113, through the annulus 125, 124 aperture 102a, conduit 102 and into the production bore 123, all powered by means of the pump 107 and motor 108 operating in reverse. This can allow water injection or injection of other chemicals or substances into all kinds of wells.
FIG. 8 shows a further modified embodiment using a hollow turbine shaft 102s that draws fluid from the production bore 123 through the inside of conduit 102 and into the inlet of a combined motor and pump unit 105, 107. The motor/pump unit has a hollow shaft design, where the pump rotor 107r is arranged concentrically inside the motor rotor 105r, both of which are arranged inside a motor stator 105s. The pump rotor 107r and the motor rotor 105r rotate as a single piece on bearings 122 around the static hollow shaft 102s thereby drawing fluid from the inside of the shaft 102 through the upper apertures 102u, and down through the annulus 124 between the shaft 102s and the bore 103b of the cap 103. The lower portion of the shaft 102s is apertured at 1021, and the outer surface of the conduit 102 is sealed within the bore of the shaft 102s above the lower aperture 1021, so that fluid pumped from the annulus 124 and entering the apertures 1021, continues flowing through the annulus 125 between the conduit 102 and the shaft 102s into the production bore 123, and finally through the production wing valve 113 for export as normal.
Referring now to FIG. 9a, this embodiment employs a motor 106 in the form of a disc rotor that is preferably electrically powered, but could be hydraulic or could derive power from any other suitable source, connected to a centrifugal disc-shaped pump 107 that draws fluid from the production bore 123 through the inner bore of the conduit 102 and uses centrifugal impellers to expel the fluid radially outwards into collecting conduits 124, and thence into an annulus 125 formed between the conduit 102 and the production bore 123 in which it is sealed. As previously described in earlier embodiments, the fluid propelled down the annulus 125 cannot pass the seal at the lower end of the conduit 102 below the production wing branch, and exits through the production wing valve 113.
FIG. 9b shows the same pump configured to operate in reverse, to draw fluids through the production wing valve 113, into the conduit 125, across the pump 107, through the re-routed conduit 124′ and conduit 102, and into the production bore 123.
Referring now to FIGS. 10 and 11, this embodiment illustrates a piston 115 that is sealed within the bore 103b of the cap 103, and connected via a rod to a further lower piston assembly 116 within the bore of the conduit 102. The conduit 102 is again sealed within the bore 103b and the production bore 123. The lower end of the piston assembly 116 has a check valve 119.
The piston 115 is moved up from the lower position shown in FIG. 10a by pumping fluid into the aperture 126a through the wall of the bore 103b by means of a hydraulic power pack in the direction shown by the arrows in FIG. 10a. The piston annulus is sealed below the aperture 126a, and so a build-up of pressure below the piston pushes it upward towards the aperture 126b, from which fluid is drawn by the hydraulic power pack. As the piston 115 travels upward, a hydraulic signal 130 is generated that controls the valve 117, to maintain the direction of the fluid flow shown in FIG. 10a. When the piston 115 reaches its uppermost stroke, another signal 131 is generated that switches the valve 117 and reverses direction of fluid from the hydraulic power pack, so that it enters through upper aperture 126b, and is exhausted through lower aperture 126a, as shown in FIG. 11a. Any other similar switching system could be used, and fluid lines are not essential to the invention.
As the piston is moving up as shown in FIG. 10a, production fluids in the production bore 123 are drawn into the bore 102b of the conduit 102, thereby filling the bore 102b of the conduit underneath the piston. When the piston reaches the upper extent of its travel, and begins to move downwards, the check valve 119 opens when the pressure moving the piston downwards exceeds the reservoir pressure in the production bore 123, so that the production fluids 123 in the bore 102b of the conduit 102 flow through the check valve 119, and into the annulus 124 between the conduit 102 and the piston shaft. Once the piston reaches the lower extent of its stroke, and the pressure between the annulus 124 and the production bore 123 equalises, the check valve 119 in the lower piston assembly 116 closes, trapping the fluid in the annulus 124 above the lower piston assembly 116. At that point, the valve 117 switches, causing the piston 115 to rise again and pull the lower piston assembly 116 with it. This lifts the column of fluid in the annulus 124 above the lower piston assembly 116, and once sufficient pressure is generated in the fluid in the annulus 124 above lower piston assembly 116, the check valves 120 at the upper end of the annulus open, thereby allowing the well fluid in the annulus to flow through the check valves 120 into the annulus 125, and thereby exhausting through wing valve 113 branch conduit. When the piston reaches its highest point, the upper hydraulic signal 131 is triggered, changing the direction of valve 117, and causing the pistons 115 and 116 to move down their respective cylinders. As the piston 116 moves down once more, the check valve 119 opens to allow well fluid to fill the displaced volume above the moving lower piston assembly 116, and the cycle repeats.
By reversing and/or re-arranging the orientations of the check valves 119 and 120, the direction of flow in this embodiment can also be reversed, as shown in FIG. 10d.
Referring now to FIGS. 12 and 13, a further embodiment has a similar piston arrangement as the embodiment shown in FIGS. 10 and 11, but the piston assembly 115, 116 is housed within a cylinder formed entirely by the bore 103b of the cap 103. As before, drive fluid is pumped by the hydraulic power pack into the chamber below the upper piston 115, causing it to rise as shown in FIG. 12a, and the signal line 130 keeps the valve 117 in the correct position as the piston 115 is rising. This draws well fluid through the conduit 102 and check valve 119 into the chamber formed in the cap bore 103b. When the piston has reached its full stroke, the signal line 131 is triggered to switch the valve 117 to the position shown in FIG. 13a, so that drive fluid is pumped in the other direction and the piston 115 is pushed down. This drives piston 116 down the bore 103b expelling well fluid through the check valves 120 (valve 119 is closed), into annulus 124, 125 and through the production wing valve 113. In this embodiment the check valve 119 is located in the conduit 102, but could be immediately above it. By reversing the orientation of the check valves as in previous embodiments the flow of the fluid can be reversed.
A further embodiment is shown in FIGS. 14 and 15, which works in a similar fashion but has a short diverter assembly 102 sealed to the production bore and straddling the production wing branch. The lower piston 116 strokes in the production bore 123 above the diverter assembly 102. As before, the drive fluid raises the piston 115 in a first phase shown in FIG. 14, drawing well fluid through the check valve 119, through the diverter assembly 102 and into the upper portion of the production bore 123. When the valve 117 switches to the configuration shown in FIG. 15, the pistons 115, 116 are driven down, thereby expelling the well fluids trapped in the bore 123u, through the check valve 120 (valve 119 is closed) and the production wing valve 113.
FIG. 16 shows a further embodiment, which employs a rotating crank 110 with an eccentrically attached arm 110a instead of a fluid drive mechanism to move the piston 116. The crank 110 is pulling the piston upward when in the position shown in FIG. 16a, and pushing it downward when in the position shown in 16b. This draws fluid into the upper part of the production bore 123u as previously described. The straddle 102 and check valve arrangements as described in the previous embodiment.
Conduit 542 does not necessarily form an extension of axial passage 508. Alternative embodiments could include a conduit which is a separate component to housing 504; this conduit could be sealed to the upper end of axial passage 508 above outlet 544, in a similar way as conduit 542 is sealed at seal 532. Embodiments of the invention can be retrofitted to many different existing designs of manifold, by simply matching the positions and shapes of the hydraulic control channels 3 in the cap, and providing flow diverting channels or connected to the cap which are matched in position (and preferably size) to the production, annulus and other bores in the tree or other manifold.
The production bore 602 and the annulus bore 603 extend down into the well from the tree 601, where they are connected to a tubing system 800a, shown in FIG. 24.
The tubing system 800a is adapted to allow the simultaneous injection of a first fluid into an injection zone 805 and production of a second fluid from a production zone 804. The tubing system 800a comprises an inner tubing 810 which is located inside an outer tubing 812. The production bore 602 is the inner bore of the inner tubing 810. The inner tubing 810 has perforations 814 in the region of the production zone 804. The outer tubing has perforations 816 in the region of the injection zone 805. A cylindrical plug 801 is provided in the annulus bore 603 which lies between the outer tubing 812 and the inner tubing 810. The plug 801 separates the part of the annulus bore 803 in the region of the injection zone 805 from the rest of the annulus bore 803.
FIG. 25 shows an alternative form of tubing system 800b including an inner tubing 820, an outer tubing 822 and an annular seal 821, for use in situations where a production zone 824 is located above an injection zone 825. The inner tubing 820 has perforations 836 in the region of the production zone 824 and the outer tubing 822 has perforations 834 in the region of the injection zone 825.
The tubing system 800a, 800b could be any system that allows both production and injection; the system is not limited to the examples given above. Optionally, the tubing system could comprise two conduits which are side by side, instead of one inside the other, one of the conduits providing the production bore and the second providing the annulus bore.
FIG. 35 shows an embodiment of the invention especially adapted for injecting gas into the produced fluids. A wellhead cap 40e is attached to the top of a horizontal tree 400. The wellhead cap 40e has plugs 408, 409; an inner axial passage 402; and an inner lateral passage 404, connecting the inner axial passage 402 with an inlet 406. One end of a coil tubing insert 410 is attached to the inner axial passage 402. Annular sealing plug 412 is provided to seal the annulus between the top end of coil tubing insert 410 and inner axial passage 402. Coil tubing insert 410 of 2 inch (5 cm) diameter extends downwards from annular sealing plug 412 into the production bore 1 of horizontal Christmas tree 400.
In use, inlet 406 is connected to a gas injection line 414. Gas is pumped from gas injection line 414 into Christmas tree cap 40e, and is diverted by plug 408 down into coil tubing insert 410; the gas mixes with the production fluids in the well. The gas reduces the density of the produced fluids, giving them “lift”. The mixture of oil well fluids and gas then travels up production bore 1, in the annulus between production bore 1 and coil tubing insert 410. This mixture is prevented from travelling into cap 40e by plug 408; instead it is diverted into branch 10 for recovery therefrom.
In use, as in the FIG. 35 embodiment, gas is injected through inlet 406 into Christmas tree cap 40e and is diverted by plug 408 and annular sealing plug 412 into coil tubing insert 410. The gas travels down the coil tubing insert 410, which extends into the depths of the well. The gas combines with the well fluids at the bottom of the wellbore, giving the fluids “lift” and making them easier to pump. The booster pump between the outlet 44 and the inlet 46 draws the “gassed” produced fluids up the annulus between the wall of production bore 1 and coil tubing insert 410. When the fluids reach conduit 42, they are diverted by seals 43 into the annulus between conduit 42 and coil tubing insert 410. The fluids are then diverted by annular sealing plug 412 through outlet 44, through the booster pump, and are returned through inlet 46. At this point, the fluids pass into the annulus created between the production bore/tree cap inner axial passage and conduit 42, in the volume bounded by seals 416 and 43. As the fluids cannot pass seals 416, 43, they are diverted out of the Christmas tree through valve 12 and branch 10 for recovery.
1. A christmas tree of an oil or gas well, comprising:
2. The christmas tree of claim 1 wherein the diverter bore is located in the lateral branch.
3. The christmas tree of claim 1 wherein the diverter bore is located in the choke body.
4. The christmas tree of claim 3 wherein the diverter is a choke insert received by the diverter bore in the choke body, the choke insert having a port communicating with the internal passage.
5. The christmas tree of claim 1 further including a processing apparatus in fluid communication with the diverter.
6. The christmas tree of claim 5 wherein the processing apparatus is selected from the group consisting of at least one of a pump, process fluid turbine, gas injection apparatus, steam injection apparatus, chemical injection apparatus, materials injection apparatus, gas separation apparatus, water separation apparatus, sand/debris separation apparatus, hydrocarbon separation apparatus, fluid measurement apparatus, temperature measurement apparatus, flow rate measurement apparatus, constitution measurement apparatus, consistency measurement apparatus, chemical treatment apparatus, pressure boosting apparatus, and water electrolysis apparatus.
7. A diverter assembly for a tree of an oil or gas well, comprising:
8. The diverter assembly of claim 7 further including a choke body disposed on the lateral branch, the choke body having a choke bore communicating with the second branch bore and export line to form a part of the second flowpath.
9. The flow diverter assembly of claim 7 wherein the processing apparatus is selected from the group consisting of at least one of a pump, process fluid turbine, gas injection apparatus, steam injection apparatus, chemical injection apparatus, materials injection apparatus, gas separation apparatus, water separation apparatus, sand/debris separation apparatus, hydrocarbon separation apparatus, fluid measurement apparatus, temperature measurement apparatus, flow rate measurement apparatus, constitution measurement apparatus, consistency measurement apparatus, chemical treatment apparatus, pressure boosting apparatus, and water electrolysis apparatus.
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Patent number: 8122948
Patent Publication Number: 20100206576
Inventors: Ian Donald (Moneymusk), John Reid (Bairuddery Invergowrie)
Application Number: 12/768,337
Current U.S. Class: Treatment Of Produced Fluids (166/75.12); With Means For Inserting Fluid Into Well (166/90.1); With Flow Restrictions (e.g., Chokes Or Beans) (166/91.1); Wellhead (166/368)