US20080135248A1 - Method and apparatus for completing and fluid treating a wellbore - Google Patents
Method and apparatus for completing and fluid treating a wellbore Download PDFInfo
- Publication number
- US20080135248A1 US20080135248A1 US11/609,128 US60912806A US2008135248A1 US 20080135248 A1 US20080135248 A1 US 20080135248A1 US 60912806 A US60912806 A US 60912806A US 2008135248 A1 US2008135248 A1 US 2008135248A1
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- United States
- Prior art keywords
- casing
- sleeve
- bore
- wellbore
- fluid
- 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.)
- Abandoned
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- 238000000034 method Methods 0.000 title claims description 37
- 239000004568 cement Substances 0.000 claims abstract description 71
- 238000007789 sealing Methods 0.000 claims abstract description 63
- 230000015572 biosynthetic process Effects 0.000 claims description 77
- 238000005086 pumping Methods 0.000 claims description 13
- 239000002253 acid Substances 0.000 claims description 6
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 claims description 4
- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 claims description 4
- 239000003180 well treatment fluid Substances 0.000 claims description 4
- 230000003247 decreasing effect Effects 0.000 claims description 3
- 229910002092 carbon dioxide Inorganic materials 0.000 claims description 2
- 239000001569 carbon dioxide Substances 0.000 claims description 2
- 229910052757 nitrogen Inorganic materials 0.000 claims description 2
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- 239000002002 slurry Substances 0.000 description 35
- 238000004891 communication Methods 0.000 description 11
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- CWYNVVGOOAEACU-UHFFFAOYSA-N Fe2+ Chemical compound [Fe+2] CWYNVVGOOAEACU-UHFFFAOYSA-N 0.000 description 1
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Images
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
- E21B21/10—Valve arrangements in drilling-fluid circulation systems
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B34/00—Valve arrangements for boreholes or wells
- E21B34/06—Valve arrangements for boreholes or wells in wells
- E21B34/14—Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools
- E21B34/142—Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools unsupported or free-falling elements, e.g. balls, plugs, darts or pistons
Definitions
- a drilling fluid is pumped down a drill string and through a drill bit attached to the end of the drill string.
- the drilling fluid may also flow through a bottom hole assembly (“BHA”) located in the drill string above the bit.
- BHA bottom hole assembly
- the BHA may house any number of tools or sensors for performing operations while the drill string is in the wellbore.
- the drilling fluid is generally used for lubrication and cooling of drill bit cutting surfaces while drilling, transportation of “cuttings” (pieces of formation dislodged by the cutting action of the teeth on a drill bit) to the surface, controlling formation pressure to prevent blowouts, maintaining well stability, suspending solids in the well, minimizing fluid loss into and stabilizing the formation through which the well is being drilled, fracturing the formation in the vicinity of the well, and displacing the fluid within the well with another fluid.
- the wellbore remains filled with the drilling fluid.
- casing is often placed in the wellbore to facilitate the production of oil and gas from the formation.
- the casing is a string of pipes that extends down the wellbore, through which the oil and gas will eventually be extracted.
- a casing shoe is typically attached to the end of the casing string when the casing string is run into the wellbore.
- the casing shoe may be a “float” shoe, which has an open bottom with a check valve to prevent flow into the casing as the casing is run into the wellbore.
- the region between the casing and the wellbore itself is known as the casing annulus.
- the casing is usually “cemented” in the wellbore.
- Traditional cementing is done by pumping a cement slurry down the inside of the casing. As the slurry reaches the bottom of the casing, it flows out of the casing and into the casing annulus between the casing and the wellbore wall. As the cement slurry flows up the annulus, it displaces any fluid in the wellbore.
- devices called “wipers” are pumped through the inside of the casing after the cement. The wiper contacts the inside surface of the casing and pushes any remaining cement out of the casing.
- Wipers require a near uniform inside surface to be effective because the wipers must maintain contact with the inside surface of the casing to push the cement out.
- the cementing process is complete when cement slurry reaches the surface, and the annulus is completely filled with the slurry. When the cement hardens, it provides support and sealing between the casing and the wellbore wall. Once installed, the casing is perforated to permit inflow through the openings created by perforating and into the casing.
- Reverse cementing is a term of art used to describe a method where the cement slurry is pumped down the casing annulus instead of the inside casing. The cement slurry displaces any fluid as it is pumped down the annulus. The annulus fluid is forced down the annulus, into the casing, and then back up to the surface.
- the valve on the float shoe must be adjusted to allow flow into the casing and then sealed after the process is complete. Because of the changing requirements for the float shoe, the valve must be a complex device. Once slurry is pumped to the bottom of the casing, the reverse cementing process is complete.
- stimulation involves pumping stimulation fluids such as fracturing fluids, acid, cleaning chemicals, and/or proppant laden fluids into the formation to improve wellbore production.
- the stimulation fluids are pumped through the casing and then into the wellbore. If the casing is installed and more than one zone of interest of the formation is treated, tools must be run into the casing to isolate fluid flow at each zone.
- the well operator may choose to stimulate an uncased portion of a wellbore. To do so, the operator may run a liner extending from the surface into the uncased section of the wellbore with inflatable element packers to isolate the portions of the wellbore. Multiple packers allow the operator to isolate segments of the uncased portion of the wellbore so that each segment may be individually treated to concentrate and control fluid treatment along the wellbore.
- Such inflatable packers may be limited with respect to pressure capabilities as well as durability under high pressure conditions.
- the packers are run for a wellbore treatment, but must be moved after each treatment if it is desired to isolate other segments of the well for treatment. This process can be expensive and time consuming. Furthermore, it may require stimulation pumping equipment to be at the well site for long periods of time or for multiple visits. This method can be very time consuming and costly.
- the tubing string which conveys the treatment fluid, can include ports or openings for the fluid to pass into the wellbore. Where more concentrated fluid treatment is desired in one position along the wellbore, a small number of larger ports may be used. Where it is desired to distribute treatment fluids over a greater area, a perforated tubing string may be used having a plurality of spaced apart perforations through its wall. The perforations can be distributed along the length of the tube or only at selected segments. The open area of each perforation can be pre-selected to control the volume of fluid passing from the tube during use.
- Another method of treating a formation with or without an uncased wellbore involves running a non-casing fluid treatment tubing string with packers into the wellbore.
- the string includes at least one section of ports that are openable when desired to permit fluid flow into the wellbore.
- a sleeve or sleeves are located inside the tubing at each section of ports in the tubing and include ports that correspond with the ports in the tubing.
- the sleeves are initially axially offset from the tubing ports so that the tubing ports are closed to fluid flow.
- the sleeves include annular seats of differing diameters.
- At least one packer is set to isolate the annulus between the tubing string and the formation or casing around the section of ports.
- a ball is then pumped down and landed on the annular seat of the given sleeve. If more than one sleeve is used, the diameters of the annular seats are staged with decreasing diameters. Thus, a ball with a diameter for landing on the given sleeve will pass through the annular seats of any previous sleeves as is passes through the tubing. With the ball landed on the annular seat of the desired sleeve, fluid pressure is applied to form a seal preventing fluid flow past the sleeve.
- the fluid pressure also moves the sleeve axially, thus matching up the ports in the sleeve with the ports in the tubing and allowing fluid flow from the tubing to pass through the sleeve ports, through the tubing ports, and into the wellbore.
- This method is limited to using a non-casing tubing string with packers however.
- the method may not be used with a casing string cemented in place using traditional cementing.
- the annular seats on the sleeves prevent the ability of wipers to effectively clean the cement from the inside of the tubing string.
- a wellbore fluid treatment apparatus capable of being actuated by a sealing device, the apparatus comprising a casing including a bore and a casing port opened through the wall of the casing, a sleeve located within the casing bore and including a sleeve port opened through the wall of the sleeve, a baffle seat forming an inner flow area and configured to receive the sealing device, and the sleeve being moveable by the sealing device between a closed position preventing fluid flow from the bore through the casing port and an open position allowing fluid flow from the bore through the sleeve port and casing port, and a reverse cement shoe attached to the casing and including a valve allowing the casing to be cemented by displacing cement only on the outside of the casing.
- Also disclosed herein is a method of fluid treating a wellbore, the method comprising running a casing into the wellbore, the casing comprising a bore, a casing port opened through the wall of the casing, and a sleeve located in the casing bore, wherein the sleeve includes a sleeve port and is in a closed position preventing fluid flow from the bore through the casing port, cementing the casing in the wellbore by flowing cement from the surface down the casing annulus, with cement being displaced only on the outside of the casing, flowing a sealing device through the casing bore and into engagement with a baffle seat of the sleeve, moving the sleeve from closed position to an open position, the sleeve port allowing fluid flow from the bore through the casing port in the open position, and flowing well treatment fluids from the bore into the formation through the casing port.
- a well system including more than one string of casing, at least one string of casing including a wellbore fluid treatment apparatus capable of being actuated by a sealing device, the wellbore fluid treatment apparatus including a casing including a bore and a casing port opened through the wall of the casing, a sleeve located within the casing bore and including a sleeve port opened through the wall of the sleeve, a baffle seat forming an inner flow area and configured to receive the sealing device, the sleeve being moveable by the sealing device between a closed position preventing fluid flow from the bore through the casing port and an open position allowing fluid flow from the bore through the sleeve port and casing port, and a reverse cement shoe attached to the casing, the float shoe allowing the casing to be cemented by displacing cement only on the outside of the casing.
- Also disclosed herein is a method of producing fluid from a formation through a wellbore, the method including running a casing into the wellbore, the casing including a bore and a casing port opened through the wall of the casing, running a sleeve located in the casing bore into the wellbore with the casing, the sleeve including a sleeve port and being in a closed position preventing fluid flow from the bore through the casing port, cementing the casing in the wellbore, allowing fluids to flow into the casing bore through a reverse cement shoe with cement being displaced only on the outside of the casing, flowing a sealing device through the casing bore and into engagement with a baffle seat of the sleeve, moving the sleeve from closed position to an open position, the sleeve port allowing fluid flow from the bore through the casing port in the open position, flowing well treatment fluids from the bore into the formation through the casing port, and allowing fluids to flow from the formation through the
- a method of servicing a wellbore including running a ported casing into the wellbore, wherein one or more ports may be in a closed position, pumping cement from the surface down the casing annulus, isolating a portion of the casing prior to or after pumping the treatment fluid, and pumping a treatment fluid from the surface through the casing and out one or more ports into the formation.
- FIG. 1 is a schematic cross-section drawing of a well system including a wellbore fluid treatment apparatus
- FIG. 2A is a close-up cross section drawing illustrating an example of a reverse cement casing shoe in a flow-through position
- FIG. 2B is a close-up cross section drawing illustrating an example of a reverse cement casing shoe in a closed position
- FIG. 3 is a close-up cross-section drawing of a wellbore treatment system
- FIG. 4 is a close-up cross-section drawing of an individual wellbore isolation segment that is part of the wellbore treatment system
- FIG. 5 is a close-up cross-section drawing illustrating an alternative wellbore fluid treatment apparatus configuration
- FIG. 6 is a close-up cross-section drawing illustrating a wellbore fluid treatment at a first formation zone using an isolation sleeve and sealing device
- FIG. 7 is a close-up cross-section drawing illustrating a wellbore fluid treatment at a second formation zone using an isolation sleeve and a sealing device.
- any use of any form of the terms “connect”, “engage”, “couple”, “attach”, or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described.
- the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . ”. Reference to up or down will be made for purposes of description with “up”, “upper”, “upwardly” or “upstream” meaning toward the surface of the well and with “down”, “lower”, “downwardly” or “downstream” meaning toward the terminal end of the well, regardless of the well bore orientation.
- FIG. 1 a cross-sectional view of a wellbore 1 and casing 11 is shown.
- the wellbore 1 is drilled below the earth's surface 7 .
- a surface casing 2 is inserted a short distance below the surface 7 into the wellbore 1 .
- a blow out preventer 3 is attached to the top of the surface casing 2 which extends slightly above the surface 7 .
- a swage nipple 8 is attached to the top of the blow out preventer 3 or may be attached to the primary casing 11 .
- a return line 9 extends from the top of the swag nipple 8 , and a casing flow meter 6 monitors the flow rate in the return line 9 .
- a pump line 10 is attached to the surface casing 2 below the blow out preventer 3 to communicate fluid to the inside of the surface casing 2 .
- the pump line 10 has an annulus pressure meter 4 and an annulus flow meter 5 .
- the casing 11 is suspended in the wellbore 1 below the blow out preventer 3 .
- a pump 60 is used to pump cement slurry from a slurry mixing device 61 into the annulus 14 for cementing operations discussed below.
- the pump 60 could be any suitable pump, such as but not limited to, a low pressure pump or a centrifugal pump. It should be appreciated that the current description is not necessarily limited to the configuration showing in FIG. 1 , and that other well configurations are possible and other surface equipment configurations may be used as well.
- a reverse cement shoe 12 is attached to the lower end of the casing 11 .
- the shoe 12 includes a base 30 having an inner bore 37 formed by an inner surface 31 .
- the base 30 is held in place in the casing 11 using any suitable means, such as an interference fit or locking pins.
- Extending from the base 30 is a flow sleeve 32 with a central bore 42 and at least one offset bore 34 , with two offset bores 34 being shown.
- Each offset bore 34 includes an inlet 46 and is in fluid communication with the base inner bore 37 .
- the shoe 12 further includes a central valve member 36 . As shown in FIG.
- the central valve member 36 is initially held in place in the flow sleeve central bore 42 by the use of shear pins 44 . Also, a seal 40 on the outside of the central valve member 36 forms a seal with the inside of the flow sleeve 32 . As illustrated in FIG. 2A , as long as the flow sleeve offset bores 34 remain unobstructed, fluid may flow in through the offset bore inlets 46 and into the base inner bore 37 as shown by the flow direction arrows in FIG. 2A . The fluid may then continue up the bore 16 of the casing 11 .
- a wellbore fluid treatment apparatus 20 is shown. Included in the apparatus 20 is the reverse cement shoe 12 described above.
- the wellbore fluid treatment apparatus 20 also includes at least a portion of the casing 11 .
- the wellbore fluid treatment apparatus 20 also includes at least one casing port 21 opened through the wall of the casing 11 to the annulus 14 . As shown, there may be more than one casing port 21 . Additionally, the casing ports 21 may be grouped in sets and may be spaced apart axially along the casing 11 as shown with casing ports 21 a and 21 b.
- the wellbore fluid treatment apparatus also includes a pressure sleeve 17 located within the casing bore 16 .
- the pressure sleeve 17 includes at least one sleeve port 19 opened through the wall of the sleeve 17 .
- the sleeve 17 is shown in FIG. 3 as being in an open position where the sleeve ports 19 are axially aligned with the set of casing ports 21 a , thus allowing fluid flow from the casing bore 16 through the casing ports 21 a .
- the sleeve 17 includes seals that form a seal against the inside surface of the casing 11 on the outside of the casing ports 21 a .
- the sleeve 17 When initially run in, however, the sleeve 17 is in a closed position where the sleeve ports 19 are axially offset from the set of casing ports 21 a , thus preventing fluid flow from the casing bore 16 through the casing ports 21 a .
- the sleeve 17 further includes a reduced inner diameter that allows the pressure sleeve 17 to be moved from the closed position to the open position shown upon a sufficient pressure differential across the pressure sleeve 17 .
- the wellbore fluid treatment apparatus 20 also includes at least one sleeve 22 located within the casing bore 16 . As shown in FIG. 3 , the wellbore fluid treatment apparatus 20 only includes one sleeve 22 . However, the wellbore fluid treatment apparatus 20 may also include more than one sleeve 22 as described further below.
- the sleeve 22 includes at least one sleeve port 23 opened through the wall of the sleeve 22 .
- the sleeve 22 is shown in FIG. 3 as being in a closed position where the sleeve ports 23 are axially offset from a set of casing ports 21 b , thus preventing fluid flow from the casing bore 16 through the casing ports 21 b .
- the sleeve 22 includes seals that form a seal against the inside surface of the casing 11 on the outside of the casing ports 21 b .
- the sleeve 22 further includes a baffle seat 25 that forms an inner flow area 27 .
- the baffle seat 25 is configured to receive a sealing device 29 shown in FIG. 4 .
- the casing 11 is run into the wellbore 1 , and the casing-by-hole-annulus 14 may be isolated with common well blow out prevention equipment such as blow out preventer 3 .
- the wellbore 1 is prepared for cementing by circulating a conventional mud slurry in the conventional direction down through the inside of the casing 11 and up the annulus 14 until the annulus fluid is sufficiently clean.
- Pumping line 10 is connected at the surface 7 for flowing the fluid in the wellbore 1 .
- Return line 9 is installed to the top of the casing 11 and may flow to a return tank or pit (not shown).
- a flow meter 6 may be installed in the return line 9 to monitor the flow rate.
- circulation fluid rather than cement slurry
- the circulation fluid is reverse-circulated down the annulus 14 and up the inside diameter of the casing 11 .
- the annulus flow meter 5 and/or casing flow meter 6 are monitored to determine the fluid flow rate.
- the cement slurry from the slurry mixing device 61 is then pumped down the annulus 14 using the pump 60 .
- the cement slurry may be pumped at any suitable rate, for example, 1 bb/min to 15 bb/min.
- the word “pumping” broadly means to flow the slurry into the annulus 14 .
- Circulation fluid initially in the annulus 14 is displaced from the annulus 14 as it flows into the casing 11 through the reverse cement shoe 12 and up to the surface 7 . Thus, no cement is displaced inside the casing 11 during the cementing operation.
- At least one stopper 48 is inserted into the circulation fluid.
- suitable stoppers include plugs or balls made of composite, rubber, metal, or other suitable material.
- the stoppers 48 flow ahead of the cement slurry.
- the return flow from the casing 11 is monitored using the flow meter 9 .
- the stoppers 48 Once the stoppers 48 reach the reverse cement shoe 12 , they land and seal on the inlets 46 of the flow sleeve offset bores 34 . Once landed and sealed, the stoppers 48 prevent fluid from flowing into the reverse cement shoe 12 and the return flow rate will slow as indicated by the flow meter 6 .
- Additional fluid pressure on the reverse cement shoe 12 acts not only upon the stoppers 48 , but also upon the central valve member 36 .
- the valve member 36 shears the shearing pins 44 holding the central valve member 36 in place.
- the central valve member 36 then travels within the flow sleeve central bore 42 and into the base inner bore 37 .
- the central valve member 36 includes a base seal 38 that forms a seal between the central valve member 36 and the base seal surface 50 . Fluid pressure acting on the central valve member 36 pushes the central valve member 36 into the base 30 until an extension 52 on the central valve member 36 lands on the base inner surface 31 , preventing further travel of the central valve member 36 .
- the reverse circulation cementing process pumps the cement slurry directly down the annulus 14 , rather than pumping it up the annulus 14 from the reverse cement shoe 12 , no incremental work to lift the dense cement slurry in the casing-by-hole annulus 14 by high-pressure surface pumping equipment is needed.
- a pump 60 is used to transfer the cement slurry from a slurry mixing or holding device 61 to the well 1 .
- a low-pressure pump 60 such as a centrifugal pump, may be used for this purpose. Because low-pressure pumps and flow lines may be used, safety is inherently built into the system. It is not necessary to certify that the pumps and flow lines will operate safely at relatively higher pressures.
- a centrifugal pump 60 may be used to pump cement slurry from a slurry mixing device 61 into the primary annulus 14 .
- One or more 6 ⁇ 4 centrifugal pumps 60 (six inch suction x four inch discharge), which may operate between about 40 psi and about 80 psi, may be used to pump the cement slurry from the slurry mixing device 61 to the well 1 .
- Two or more centrifugal pumps 60 may be connected in series to produce a pump pressure of about 160 psi or more. This pressure may be required as the leading edge of the cement slurry is pumped into the annulus 14 . The pressure may then be reduced as more of the cement slurry enters the annulus 14 . Gravity acting on the relatively heavy cement slurry tends to pull the cement slurry down the annulus 14 so that less pump pressure is needed.
- wellbore fluid treatment may involve any type of fluid treatment to the formation 18 .
- the fluid treatment may be wellbore stimulation to increase the ability of the formation 18 to produce hydrocarbons by using stimulation fluids such as one or more of acid, gelled acid, gelled water, gelled oil, carbon dioxide, nitrogen, and any of these fluids containing proppants, such as for example, sand or bauxite.
- the casing 11 Before installation, the casing 11 is designed to include the one or more casing ports 21 at selected locations depending on the specific zones of interest of the formation 18 to be treated. For example, one or more segmented of ported casing may be placed at one or more intervals along the casing string.
- Treating or servicing fluids such as acid or a fracturing fluid, may be pumped through the casing ports 21 that break down the hardened cement in the casing annulus 14 . Only the cement adjacent to the casing ports 21 is broken down, however, allowing the well operator to specifically target areas of the formation 18 adjacent to the casing ports 21 .
- FIG. 3 there is one set of casing ports 21 a closed by the sleeve 17 .
- the area of the formation 18 adjacent the open casing ports 21 a will be treated.
- Fluid pressure inside the casing 11 above the sleeve 17 is increased to create a differential pressure across the sleeve 17 to move the sleeve 17 .
- Moving the sleeve 17 aligns the sleeve ports 19 with the casing ports 21 a , allowing fluid contact with the casing ports 21 a , initially sealed by cement.
- the wellbore treatment fluids are pumped down the casing bore 16 and through the uncovered casing ports 21 a .
- the wellbore treatment fluid breaks up the cement in the annulus 14 , establishing fluid communication between the casing bore 16 and the formation 18 adjacent the casing ports 21 a .
- the same or different wellbore treatment fluids may then be pumped into the formation 18 adjacent the casing ports 21 a , treating the formation 18 to enhance the production capabilities.
- a perforating device attached to the casing 11 may be used instead of the wellbore treatment fluids to break up the cement.
- a different location of the formation 18 may then be treated.
- a same or different wellbore treatment fluid may be needed for the new location in the formation 18 .
- a sealing device 29 is pumped down the casing bore 16 and into engagement with the baffle seat 25 of the sleeve 22 while the sleeve 22 is in the closed position. Once landed onto the baffle seat 25 , fluid pressure within the casing 11 causes the sealing device 29 to form a seal against the baffle seat 25 that prevents fluid flow through the inner flow area 27 .
- the sealing device 29 may be any suitable device that may be pumped into the casing 11 and landed on the baffle seat 25 to form a fluid tight seal.
- the sealing device may a ball or a plug and may be made of ferrous metal, composite, polymer, phenolic/foam, or any combination of these. Forming the seal with the sealing device 29 prevents fluid flow past the sleeve 22 and thus isolates the initially treated area of the formation 18 adjacent ports 21 a from any fluids in the casing 11 above the sleeve 22 .
- the sleeve 22 is initially in a closed position and held in place with sleeve shearing pins 28 .
- the sleeve 22 also includes guides 24 that travel within corresponding grooves 26 on the inside of the casing 11 .
- the grooves 26 contact and landing surface that limits the travel of the guides 24 and thus also limit the travel of the sleeve 22 .
- fluid communication must be established between the formation 18 and the casing bore 16 above the sealing device 29 .
- the sleeve 22 is moved from the initial closed position as shown in FIG. 3 to an open position as shown in FIG. 4 .
- the sleeve 22 is moved to the open position by increasing the fluid pressure above the sealing device 29 and creating a pressure differential across the sleeve baffle seat 25 such that the force acting on the sleeve 22 shears the sleeve shear pins 28 and moves the sleeve 22 relative to the casing 11 to substantially align the sleeve and casing ports.
- the sleeve ports 23 allow fluid flow from the casing bore 16 through the casing ports 21 .
- fluid is pumped through the casing ports 21 to deteriorate the cement in the annulus 14 and allow fluid to flow between the area of the formation 18 adjacent the casing ports 21 b and the casing bore 16 .
- wellbore treatment fluids may then be pumped into the casing bore 16 and into the formation 18 through the casing ports 21 b .
- the fluids treat the formation 18 and enhance the production capabilities of the formation 18 .
- fluid pressure within the casing 16 is lowered to less than the fluid pressure of fluids in the formation 18 . Fluids from the formation 18 are thus then allowed to enter the casing 11 through the casing ports 21 .
- the sealing device 29 is unseated from the baffle seat 25 and fluids from both above and below the sleeve 22 flow through the casing bore 16 to the surface 7 .
- the sealing device 29 is pumped by the formation fluids flowing in the casing bore 16 toward the surface 7 . If the sealing device 29 makes it to the surface, appropriate equipment at the surface, such as a sealing device catcher, may be used to retrieve the sealing device 29 from the fluid flow. Sometimes, however, the sealing device 29 is destroyed before reaching the surface 7 and no retrieval is necessary.
- FIG. 3 only shows two sets of casing ports 21 a and 21 b and one sleeve 22 , there may be as many sets of casing ports 21 and corresponding sleeves 22 as appropriate. There also need not be an initially open set of casing ports 21 a , but the casing ports 21 may all be associated with sleeves 22 (e.g., multiple sleeve/port assemblies may be placed at intervals along the casing).
- the wellbore fluid treatment apparatus 20 is not limited by the embodiment illustrated in FIGS. 3 and 4 .
- FIGS. 5 , 6 , and 7 show an alternate embodiment of the wellbore fluid treatment apparatus 20 .
- Like parts are given like reference numerals and the operation of the wellbore fluid treatment apparatus 20 is similar to the operation above with further explanation below.
- the wellbore fluid treatment apparatus 20 includes two sleeves 22 a and 22 b that correspond with the two sets of casing ports 21 a and 21 b .
- the casing ports 21 are spaced apart axially along the casing 11 as previously described and thus allow two different locations within the formation 18 to be treated with wellbore fluids.
- the operation of the wellbore fluid treatment apparatus 20 shown in FIGS. 5-7 differs in that the initial sealing device 29 a must flow past the baffle seat 25 of at least one sleeve 22 b before being seated on a subsequent sleeve 22 a . As shown in FIG.
- the initial sealing device 29 a must flow through the inner flow area 27 of the upper-most sleeve 22 b before landing on the lower-most sleeve baffle seat 25 .
- the baffle seat 25 of the upper sleeve 22 b has a larger inner flow area 27 than the inner flow area 27 of the lower and subsequent baffle seat 25 .
- the inner flow areas 27 of the sleeves 22 are different sizes and progressively decrease in size with each sleeve 22 .
- the casing 11 is installed with the sleeves 22 in the closed position such that none of the casing ports 21 are open.
- appropriate seals on the outside of the sleeves 22 seal the casing ports 21 from the casing bore 16 .
- the first zone of interest of the formation 18 is then ready to be treated.
- a first sealing device 29 a is inserted into the casing bore 16 and pumped downhole to the wellbore fluid treatment apparatus 20 .
- the sealing device 29 may be any suitable device that may be pumped into the casing 11 and landed on the baffle seat 25 to form a fluid tight seal.
- the sealing device 29 is a ball, but need not be limited to that configuration.
- the inner flow area 27 of the initial sleeve 22 b is large enough to allow the initial sealing device 29 a to pass through to the set sleeve 22 a .
- the inner flow area 27 of the lower baffle seat 25 is smaller such that the initial sealing device 29 a lands on the lower baffle seat 25 as previously described. Fluid pressure within the casing bore 16 is then increased to create a pressure differential across the lower sleeve baffle seat 25 such that the force acting on the sleeve 22 a shears the sleeve shear pins 28 and moves the sleeve 22 a relative to the casing 11 .
- the lower sleeve 22 a is thus moved from the initial closed position as shown in FIG. 5 to an open position as shown in FIG. 6 to establish fluid communication between the casing ports 21 a and the sleeve ports 23 a of the lower sleeve 22 .
- fluid is pumped in the casing bore 16 past the upper sleeve 22 and through the lower set of casing ports 21 to deteriorate the cement in the annulus 14 and allow fluid to flow between the formation 18 and the casing bore 16 .
- wellbore treatment fluids may then be pumped into the casing bore 16 , past the upper sleeve 22 b , and into the formation 18 through the casing ports 21 a to treat the formation 18 and enhance the production capabilities of the formation 18 .
- a different location of the formation 18 may then be treated.
- a different wellbore treatment fluid may be needed for the new location in the formation 18 .
- another sealing device 29 b is pumped down the casing bore 16 and into engagement with the baffle seat 25 of the upper sleeve 22 b while the sleeve 22 b is in the closed position. Because the inner flow area 27 of the upper sleeve 22 b being larger than the lower sleeve 22 a , the subsequent sealing device 29 is larger than the initial sealing device 29 a . Once landed on the baffle seat 25 of the upper sleeve 22 b , fluid pressure within the casing 11 causes the subsequent sealing device 29 b to form a seal against the baffle seat 25 that prevents fluid flow through the inner flow area 27 of the upper sleeve 22 b .
- the sealing device 29 may be any suitable device that may be pumped into the casing 11 and landed on the baffle seat 25 to form a fluid tight seal.
- the sealing device 29 b is a ball, but need not be limited to that configuration. Forming the seal with the sealing device 29 b prevents fluid flow past the upper sleeve 22 b and thus isolates the initially treated area of the formation 18 from any fluids in the casing 11 above the upper sleeve 22 b.
- the upper sleeve 22 b is initially in a closed position and held in place with sleeve shearing pins 28 . The upper sleeve 22 b is then moved from the initial closed position as shown in FIG. 6 to an open position as shown in FIG. 7 .
- the upper sleeve 22 b is moved to the open position by increasing the fluid pressure above the subsequent sealing device 29 b and creating a pressure differential across the sleeve baffle seat 25 such that the force acting on the sleeve 22 b shears the sleeve shear pins 28 and moves the upper sleeve 22 b relative to the casing 11 .
- the sleeve ports 23 b allow fluid flow from the casing bore 16 through the upper set of the casing ports 21 b .
- initially fluid is pumped through the casing ports 21 b to deteriorate the cement in the annulus 14 and allow fluid to flow between the area of the formation 18 adjacent the casing ports 21 and the casing bore 16 .
- wellbore treatment fluids may then be pumped into the casing bore 16 and into the formation 18 through the casing ports 21 to treat the formation 18 and enhance the production capabilities of the formation 18 .
- fluid pressure within the casing 16 is lowered to less than the fluid pressure of fluids in the formation 18 . Fluids from the formation 18 are thus then allowed to enter the casing 11 through all the casing ports 21 .
- the sealing devices 29 are unseated from the baffle seats 25 and fluids from both above and below the upper sleeve 22 flow through the casing bore 16 to the surface 7 .
- the sealing devices 29 are pumped by the formation fluids flowing in the casing bore 16 toward the surface 7 .
- sealing devices 29 make it to the surface, appropriate equipment at the surface, such as a sealing device catcher, may be used to retrieve the sealing devices 29 from the fluid flow. Sometimes, however, the sealing devices 29 are destroyed before reaching the surface 7 , and no retrieval is necessary.
- FIGS. 5-7 only show two sets of casing ports 21 and two sleeves 22 , there may be as many sets of casing ports 21 and corresponding sleeves 22 as appropriate. There may also be an initially open set of casing ports 21 a (e.g., not associated with a sleeve assembly) as shown in FIG. 3 .
- the wellbore fluid treatment apparatus 20 is not limited by the embodiment illustrated in FIGS. 5-7 .
Abstract
A wellbore fluid treatment apparatus capable of being actuated by a sealing device. The apparatus includes a casing including a bore and a casing port opened through the wall of the casing. The apparatus also includes a sleeve located within the casing bore. The sleeve includes a sleeve port opened through the wall of the sleeve and a baffle seat forming an inner flow area and configured to receive the sealing device. The sleeve is moveable by the sealing device between a closed position preventing fluid flow from the bore through the casing port and an open position allowing fluid flow from the bore through the sleeve port and casing port. The apparatus also includes a reverse cement shoe attached to the casing. The reverse cement shoe has a valve that allows the casing to be cemented by displacing cement only on the outside of the casing.
Description
- Not Applicable.
- Not Applicable.
- In general, when drilling a wellbore in the earth, a drilling fluid is pumped down a drill string and through a drill bit attached to the end of the drill string. The drilling fluid may also flow through a bottom hole assembly (“BHA”) located in the drill string above the bit. The BHA may house any number of tools or sensors for performing operations while the drill string is in the wellbore. The drilling fluid is generally used for lubrication and cooling of drill bit cutting surfaces while drilling, transportation of “cuttings” (pieces of formation dislodged by the cutting action of the teeth on a drill bit) to the surface, controlling formation pressure to prevent blowouts, maintaining well stability, suspending solids in the well, minimizing fluid loss into and stabilizing the formation through which the well is being drilled, fracturing the formation in the vicinity of the well, and displacing the fluid within the well with another fluid. When drilling is completed, the wellbore remains filled with the drilling fluid.
- After drilling, casing is often placed in the wellbore to facilitate the production of oil and gas from the formation. The casing is a string of pipes that extends down the wellbore, through which the oil and gas will eventually be extracted. A casing shoe is typically attached to the end of the casing string when the casing string is run into the wellbore. The casing shoe may be a “float” shoe, which has an open bottom with a check valve to prevent flow into the casing as the casing is run into the wellbore.
- The region between the casing and the wellbore itself is known as the casing annulus. To fill up the casing annulus and secure the casing in place, the casing is usually “cemented” in the wellbore. Traditional cementing is done by pumping a cement slurry down the inside of the casing. As the slurry reaches the bottom of the casing, it flows out of the casing and into the casing annulus between the casing and the wellbore wall. As the cement slurry flows up the annulus, it displaces any fluid in the wellbore. To ensure no cement remains inside the casing, devices called “wipers” are pumped through the inside of the casing after the cement. The wiper contacts the inside surface of the casing and pushes any remaining cement out of the casing. Wipers, however, require a near uniform inside surface to be effective because the wipers must maintain contact with the inside surface of the casing to push the cement out. The cementing process is complete when cement slurry reaches the surface, and the annulus is completely filled with the slurry. When the cement hardens, it provides support and sealing between the casing and the wellbore wall. Once installed, the casing is perforated to permit inflow through the openings created by perforating and into the casing.
- Another method for cementing a casing in a wellbore is called “reverse cementing.” Reverse cementing is a term of art used to describe a method where the cement slurry is pumped down the casing annulus instead of the inside casing. The cement slurry displaces any fluid as it is pumped down the annulus. The annulus fluid is forced down the annulus, into the casing, and then back up to the surface. When reverse cementing, the valve on the float shoe must be adjusted to allow flow into the casing and then sealed after the process is complete. Because of the changing requirements for the float shoe, the valve must be a complex device. Once slurry is pumped to the bottom of the casing, the reverse cementing process is complete.
- Before and even after casing is installed, the well may require wellbore treatment that is referred to as stimulation. Stimulation involves pumping stimulation fluids such as fracturing fluids, acid, cleaning chemicals, and/or proppant laden fluids into the formation to improve wellbore production. The stimulation fluids are pumped through the casing and then into the wellbore. If the casing is installed and more than one zone of interest of the formation is treated, tools must be run into the casing to isolate fluid flow at each zone.
- Instead of stimulating the formation after installing casing, the well operator may choose to stimulate an uncased portion of a wellbore. To do so, the operator may run a liner extending from the surface into the uncased section of the wellbore with inflatable element packers to isolate the portions of the wellbore. Multiple packers allow the operator to isolate segments of the uncased portion of the wellbore so that each segment may be individually treated to concentrate and control fluid treatment along the wellbore.
- Such inflatable packers may be limited with respect to pressure capabilities as well as durability under high pressure conditions. Generally, the packers are run for a wellbore treatment, but must be moved after each treatment if it is desired to isolate other segments of the well for treatment. This process can be expensive and time consuming. Furthermore, it may require stimulation pumping equipment to be at the well site for long periods of time or for multiple visits. This method can be very time consuming and costly.
- The tubing string, which conveys the treatment fluid, can include ports or openings for the fluid to pass into the wellbore. Where more concentrated fluid treatment is desired in one position along the wellbore, a small number of larger ports may be used. Where it is desired to distribute treatment fluids over a greater area, a perforated tubing string may be used having a plurality of spaced apart perforations through its wall. The perforations can be distributed along the length of the tube or only at selected segments. The open area of each perforation can be pre-selected to control the volume of fluid passing from the tube during use.
- In previous systems, it is necessary to run the tubing string into the bore hole with the ports or perforations already opened. This is especially true where a distributed application of treatment fluid is desired such that a plurality of ports or perforations must be open at the same time for passage therethrough of fluid.
- Another method of treating a formation with or without an uncased wellbore involves running a non-casing fluid treatment tubing string with packers into the wellbore. The string includes at least one section of ports that are openable when desired to permit fluid flow into the wellbore. A sleeve or sleeves are located inside the tubing at each section of ports in the tubing and include ports that correspond with the ports in the tubing. The sleeves are initially axially offset from the tubing ports so that the tubing ports are closed to fluid flow. The sleeves include annular seats of differing diameters. To open a given set of ports, at least one packer is set to isolate the annulus between the tubing string and the formation or casing around the section of ports. A ball is then pumped down and landed on the annular seat of the given sleeve. If more than one sleeve is used, the diameters of the annular seats are staged with decreasing diameters. Thus, a ball with a diameter for landing on the given sleeve will pass through the annular seats of any previous sleeves as is passes through the tubing. With the ball landed on the annular seat of the desired sleeve, fluid pressure is applied to form a seal preventing fluid flow past the sleeve. The fluid pressure also moves the sleeve axially, thus matching up the ports in the sleeve with the ports in the tubing and allowing fluid flow from the tubing to pass through the sleeve ports, through the tubing ports, and into the wellbore.
- This method, however, is limited to using a non-casing tubing string with packers however. The method may not be used with a casing string cemented in place using traditional cementing. As described above, the annular seats on the sleeves prevent the ability of wipers to effectively clean the cement from the inside of the tubing string.
- Disclosed herein is a wellbore fluid treatment apparatus capable of being actuated by a sealing device, the apparatus comprising a casing including a bore and a casing port opened through the wall of the casing, a sleeve located within the casing bore and including a sleeve port opened through the wall of the sleeve, a baffle seat forming an inner flow area and configured to receive the sealing device, and the sleeve being moveable by the sealing device between a closed position preventing fluid flow from the bore through the casing port and an open position allowing fluid flow from the bore through the sleeve port and casing port, and a reverse cement shoe attached to the casing and including a valve allowing the casing to be cemented by displacing cement only on the outside of the casing.
- Also disclosed herein is a method of fluid treating a wellbore, the method comprising running a casing into the wellbore, the casing comprising a bore, a casing port opened through the wall of the casing, and a sleeve located in the casing bore, wherein the sleeve includes a sleeve port and is in a closed position preventing fluid flow from the bore through the casing port, cementing the casing in the wellbore by flowing cement from the surface down the casing annulus, with cement being displaced only on the outside of the casing, flowing a sealing device through the casing bore and into engagement with a baffle seat of the sleeve, moving the sleeve from closed position to an open position, the sleeve port allowing fluid flow from the bore through the casing port in the open position, and flowing well treatment fluids from the bore into the formation through the casing port.
- Also disclosed herein is a well system including more than one string of casing, at least one string of casing including a wellbore fluid treatment apparatus capable of being actuated by a sealing device, the wellbore fluid treatment apparatus including a casing including a bore and a casing port opened through the wall of the casing, a sleeve located within the casing bore and including a sleeve port opened through the wall of the sleeve, a baffle seat forming an inner flow area and configured to receive the sealing device, the sleeve being moveable by the sealing device between a closed position preventing fluid flow from the bore through the casing port and an open position allowing fluid flow from the bore through the sleeve port and casing port, and a reverse cement shoe attached to the casing, the float shoe allowing the casing to be cemented by displacing cement only on the outside of the casing.
- Also disclosed herein is a method of producing fluid from a formation through a wellbore, the method including running a casing into the wellbore, the casing including a bore and a casing port opened through the wall of the casing, running a sleeve located in the casing bore into the wellbore with the casing, the sleeve including a sleeve port and being in a closed position preventing fluid flow from the bore through the casing port, cementing the casing in the wellbore, allowing fluids to flow into the casing bore through a reverse cement shoe with cement being displaced only on the outside of the casing, flowing a sealing device through the casing bore and into engagement with a baffle seat of the sleeve, moving the sleeve from closed position to an open position, the sleeve port allowing fluid flow from the bore through the casing port in the open position, flowing well treatment fluids from the bore into the formation through the casing port, and allowing fluids to flow from the formation through the casing ports and into the casing bore.
- Further disclosed herein is a method of servicing a wellbore, including running a ported casing into the wellbore, wherein one or more ports may be in a closed position, pumping cement from the surface down the casing annulus, isolating a portion of the casing prior to or after pumping the treatment fluid, and pumping a treatment fluid from the surface through the casing and out one or more ports into the formation.
- For a more detailed description of the embodiments, reference will now be made to the following accompanying drawings:
-
FIG. 1 is a schematic cross-section drawing of a well system including a wellbore fluid treatment apparatus; -
FIG. 2A is a close-up cross section drawing illustrating an example of a reverse cement casing shoe in a flow-through position; -
FIG. 2B is a close-up cross section drawing illustrating an example of a reverse cement casing shoe in a closed position; -
FIG. 3 is a close-up cross-section drawing of a wellbore treatment system; -
FIG. 4 is a close-up cross-section drawing of an individual wellbore isolation segment that is part of the wellbore treatment system; -
FIG. 5 is a close-up cross-section drawing illustrating an alternative wellbore fluid treatment apparatus configuration; -
FIG. 6 is a close-up cross-section drawing illustrating a wellbore fluid treatment at a first formation zone using an isolation sleeve and sealing device; and -
FIG. 7 is a close-up cross-section drawing illustrating a wellbore fluid treatment at a second formation zone using an isolation sleeve and a sealing device. - In the drawings and description that follows, like parts are marked throughout the specification and drawings with the same reference numerals, respectively. The drawing figures are not necessarily to scale. Certain features of the invention may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness. The present invention is susceptible to embodiments of different forms. Specific embodiments are described in detail and are shown in the drawings, with the understanding that the present disclosure is to be considered an exemplification of the principles of the invention, and is not intended to limit the invention to that illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed below may be employed separately or in any suitable combination to produce desired results. Unless otherwise specified, any use of any form of the terms “connect”, “engage”, “couple”, “attach”, or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described. In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . ”. Reference to up or down will be made for purposes of description with “up”, “upper”, “upwardly” or “upstream” meaning toward the surface of the well and with “down”, “lower”, “downwardly” or “downstream” meaning toward the terminal end of the well, regardless of the well bore orientation. The various characteristics mentioned above, as well as other features and characteristics described in more detail below, will be readily apparent to those skilled in the art upon reading the following detailed description of the embodiments, and by referring to the accompanying drawings.
- Referring to
FIG. 1 , a cross-sectional view of awellbore 1 andcasing 11 is shown. Thewellbore 1 is drilled below the earth's surface 7. Asurface casing 2 is inserted a short distance below the surface 7 into thewellbore 1. A blow outpreventer 3 is attached to the top of thesurface casing 2 which extends slightly above the surface 7. Aswage nipple 8 is attached to the top of the blow outpreventer 3 or may be attached to theprimary casing 11. Areturn line 9 extends from the top of theswag nipple 8, and acasing flow meter 6 monitors the flow rate in thereturn line 9. Apump line 10 is attached to thesurface casing 2 below the blow outpreventer 3 to communicate fluid to the inside of thesurface casing 2. Thepump line 10 has anannulus pressure meter 4 and anannulus flow meter 5. Thecasing 11 is suspended in thewellbore 1 below the blow outpreventer 3. Apump 60 is used to pump cement slurry from aslurry mixing device 61 into theannulus 14 for cementing operations discussed below. Thepump 60 could be any suitable pump, such as but not limited to, a low pressure pump or a centrifugal pump. It should be appreciated that the current description is not necessarily limited to the configuration showing inFIG. 1 , and that other well configurations are possible and other surface equipment configurations may be used as well. - Referring to
FIGS. 1 , 2A, and 2B, areverse cement shoe 12 is attached to the lower end of thecasing 11. Theshoe 12 includes a base 30 having aninner bore 37 formed by aninner surface 31. Thebase 30 is held in place in thecasing 11 using any suitable means, such as an interference fit or locking pins. Extending from thebase 30 is aflow sleeve 32 with acentral bore 42 and at least one offset bore 34, with two offsetbores 34 being shown. Each offset bore 34 includes aninlet 46 and is in fluid communication with the baseinner bore 37. Theshoe 12 further includes acentral valve member 36. As shown inFIG. 2A , thecentral valve member 36 is initially held in place in the flow sleeve central bore 42 by the use of shear pins 44. Also, aseal 40 on the outside of thecentral valve member 36 forms a seal with the inside of theflow sleeve 32. As illustrated inFIG. 2A , as long as the flow sleeve offset bores 34 remain unobstructed, fluid may flow in through the offset boreinlets 46 and into the base inner bore 37 as shown by the flow direction arrows inFIG. 2A . The fluid may then continue up thebore 16 of thecasing 11. - Referring to
FIGS. 1 and 3 , a wellborefluid treatment apparatus 20 is shown. Included in theapparatus 20 is thereverse cement shoe 12 described above. The wellborefluid treatment apparatus 20 also includes at least a portion of thecasing 11. The wellborefluid treatment apparatus 20 also includes at least one casing port 21 opened through the wall of thecasing 11 to theannulus 14. As shown, there may be more than one casing port 21. Additionally, the casing ports 21 may be grouped in sets and may be spaced apart axially along thecasing 11 as shown withcasing ports - The wellbore fluid treatment apparatus also includes a
pressure sleeve 17 located within the casing bore 16. As shown inFIG. 3 , thepressure sleeve 17 includes at least onesleeve port 19 opened through the wall of thesleeve 17. Thesleeve 17 is shown inFIG. 3 as being in an open position where thesleeve ports 19 are axially aligned with the set ofcasing ports 21 a, thus allowing fluid flow from the casing bore 16 through thecasing ports 21 a. Although not shown, thesleeve 17 includes seals that form a seal against the inside surface of thecasing 11 on the outside of thecasing ports 21 a. When initially run in, however, thesleeve 17 is in a closed position where thesleeve ports 19 are axially offset from the set ofcasing ports 21 a, thus preventing fluid flow from the casing bore 16 through thecasing ports 21 a. Thesleeve 17 further includes a reduced inner diameter that allows thepressure sleeve 17 to be moved from the closed position to the open position shown upon a sufficient pressure differential across thepressure sleeve 17. - The wellbore
fluid treatment apparatus 20 also includes at least onesleeve 22 located within the casing bore 16. As shown inFIG. 3 , the wellborefluid treatment apparatus 20 only includes onesleeve 22. However, the wellborefluid treatment apparatus 20 may also include more than onesleeve 22 as described further below. Thesleeve 22 includes at least onesleeve port 23 opened through the wall of thesleeve 22. Thesleeve 22 is shown inFIG. 3 as being in a closed position where thesleeve ports 23 are axially offset from a set ofcasing ports 21 b, thus preventing fluid flow from the casing bore 16 through thecasing ports 21 b. Although not shown, thesleeve 22 includes seals that form a seal against the inside surface of thecasing 11 on the outside of thecasing ports 21 b. As shown, although there is asleeve 22 initially preventing fluid flow through a set ofcasing ports 21 b, there are also a set ofcasing ports 21 a that do not have acorresponding sleeve 22 to prevent fluid flow. Thesleeve 22 further includes abaffle seat 25 that forms aninner flow area 27. As will be discussed in more detail below, thebaffle seat 25 is configured to receive a sealing device 29 shown inFIG. 4 . - Referring to
FIGS. 1 , 2A, and 2B, thecasing 11 is run into thewellbore 1, and the casing-by-hole-annulus 14 may be isolated with common well blow out prevention equipment such as blow outpreventer 3. Thewellbore 1 is prepared for cementing by circulating a conventional mud slurry in the conventional direction down through the inside of thecasing 11 and up theannulus 14 until the annulus fluid is sufficiently clean. Pumpingline 10 is connected at the surface 7 for flowing the fluid in thewellbore 1.Return line 9 is installed to the top of thecasing 11 and may flow to a return tank or pit (not shown). Aflow meter 6 may be installed in thereturn line 9 to monitor the flow rate. - After the
annulus 14 is sufficiently cleaned, circulation fluid, rather than cement slurry, is pumped down theannulus 14. The circulation fluid is reverse-circulated down theannulus 14 and up the inside diameter of thecasing 11. Theannulus flow meter 5 and/orcasing flow meter 6 are monitored to determine the fluid flow rate. - Once the circulation fluid is sufficiently in place, the cement slurry from the
slurry mixing device 61 is then pumped down theannulus 14 using thepump 60. The cement slurry may be pumped at any suitable rate, for example, 1 bb/min to 15 bb/min. As used in this description, the word “pumping” broadly means to flow the slurry into theannulus 14. Circulation fluid initially in theannulus 14 is displaced from theannulus 14 as it flows into thecasing 11 through thereverse cement shoe 12 and up to the surface 7. Thus, no cement is displaced inside thecasing 11 during the cementing operation. - Just before the cement slurry is pumped into the
annulus 14, at least onestopper 48 is inserted into the circulation fluid. Examples of suitable stoppers include plugs or balls made of composite, rubber, metal, or other suitable material. As the cement slurry flows down theannulus 14, thestoppers 48 flow ahead of the cement slurry. The return flow from thecasing 11 is monitored using theflow meter 9. Once thestoppers 48 reach thereverse cement shoe 12, they land and seal on theinlets 46 of the flow sleeve offset bores 34. Once landed and sealed, thestoppers 48 prevent fluid from flowing into thereverse cement shoe 12 and the return flow rate will slow as indicated by theflow meter 6. Additional fluid pressure on thereverse cement shoe 12 acts not only upon thestoppers 48, but also upon thecentral valve member 36. Once a sufficient pressure differential across thecentral valve member 36 is reached, thevalve member 36 shears the shearing pins 44 holding thecentral valve member 36 in place. Thecentral valve member 36 then travels within the flow sleeve central bore 42 and into the baseinner bore 37. Thecentral valve member 36 includes abase seal 38 that forms a seal between thecentral valve member 36 and thebase seal surface 50. Fluid pressure acting on thecentral valve member 36 pushes thecentral valve member 36 into the base 30 until an extension 52 on thecentral valve member 36 lands on the baseinner surface 31, preventing further travel of thecentral valve member 36. Forming a seal to prevent flow through thereverse cement shoe 12 with thecentral valve member 36 prevents the flow of cement slurry into thecasing 11 should thestoppers 48 unseat from theinlets 46 once the cement slurry is pumped in place but before the cement sets. Once thecentral valve member 36 is landed on thebase 30, thecasing 11 is landed in a casing hanger or wellhead and the cement job is complete. - Because the reverse circulation cementing process pumps the cement slurry directly down the
annulus 14, rather than pumping it up theannulus 14 from thereverse cement shoe 12, no incremental work to lift the dense cement slurry in the casing-by-hole annulus 14 by high-pressure surface pumping equipment is needed. With this process, only apump 60 is used to transfer the cement slurry from a slurry mixing or holdingdevice 61 to thewell 1. A low-pressure pump 60, such as a centrifugal pump, may be used for this purpose. Because low-pressure pumps and flow lines may be used, safety is inherently built into the system. It is not necessary to certify that the pumps and flow lines will operate safely at relatively higher pressures. - As shown in
FIG. 1 , acentrifugal pump 60 may be used to pump cement slurry from aslurry mixing device 61 into theprimary annulus 14. One or more 6×4 centrifugal pumps 60 (six inch suction x four inch discharge), which may operate between about 40 psi and about 80 psi, may be used to pump the cement slurry from theslurry mixing device 61 to thewell 1. Two or morecentrifugal pumps 60 may be connected in series to produce a pump pressure of about 160 psi or more. This pressure may be required as the leading edge of the cement slurry is pumped into theannulus 14. The pressure may then be reduced as more of the cement slurry enters theannulus 14. Gravity acting on the relatively heavy cement slurry tends to pull the cement slurry down theannulus 14 so that less pump pressure is needed. - It should be appreciated that other configurations of a
reverse cement shoe 12 than discussed above may be used. All configurations, however, will allow thecasing 11 to be cemented in place without flowing the cement slurry through theinner bore 16 of thecasing 11, but instead by displacing cement slurry on the outside of thecasing 11 in theannulus 14. - Referring to
FIGS. 3 and 4 , once thecasing 11 is installed, the wellbore fluid treatment operations may be performed. It should be appreciated that wellbore fluid treatment may involve any type of fluid treatment to theformation 18. For example, the fluid treatment may be wellbore stimulation to increase the ability of theformation 18 to produce hydrocarbons by using stimulation fluids such as one or more of acid, gelled acid, gelled water, gelled oil, carbon dioxide, nitrogen, and any of these fluids containing proppants, such as for example, sand or bauxite. - Before installation, the
casing 11 is designed to include the one or more casing ports 21 at selected locations depending on the specific zones of interest of theformation 18 to be treated. For example, one or more segmented of ported casing may be placed at one or more intervals along the casing string. To treat theformation 18, fluid communication between thecasing 11 and theformation 18 must be established. Treating or servicing fluids, such as acid or a fracturing fluid, may be pumped through the casing ports 21 that break down the hardened cement in thecasing annulus 14. Only the cement adjacent to the casing ports 21 is broken down, however, allowing the well operator to specifically target areas of theformation 18 adjacent to the casing ports 21. - As shown in
FIG. 3 , there is one set ofcasing ports 21 a closed by thesleeve 17. For the initial wellbore fluid treatment, the area of theformation 18 adjacent theopen casing ports 21 a will be treated. Fluid pressure inside thecasing 11 above thesleeve 17 is increased to create a differential pressure across thesleeve 17 to move thesleeve 17. Moving thesleeve 17 aligns thesleeve ports 19 with thecasing ports 21 a, allowing fluid contact with thecasing ports 21 a, initially sealed by cement. To treat theformation 18, the wellbore treatment fluids are pumped down the casing bore 16 and through the uncoveredcasing ports 21 a. The wellbore treatment fluid breaks up the cement in theannulus 14, establishing fluid communication between the casing bore 16 and theformation 18 adjacent thecasing ports 21 a. The same or different wellbore treatment fluids may then be pumped into theformation 18 adjacent thecasing ports 21 a, treating theformation 18 to enhance the production capabilities. Alternatively, to establish fluid communication with theformation 18 through thecasing ports 21 a, a perforating device attached to thecasing 11 may be used instead of the wellbore treatment fluids to break up the cement. - Once wellbore treatment at the initial location is complete, a different location of the
formation 18 may then be treated. A same or different wellbore treatment fluid may be needed for the new location in theformation 18. Additionally, it may not be desirable to perform any additional treatment procedures on the initial location of theformation 18. Thus, it may be desirable to isolate the initial location of theformation 18 already treated from wellbore treatment fluids in the casing bore 16 before treating the new location. - To isolate the first portion of treated formation
adjacent ports 21 a, a sealing device 29 is pumped down the casing bore 16 and into engagement with thebaffle seat 25 of thesleeve 22 while thesleeve 22 is in the closed position. Once landed onto thebaffle seat 25, fluid pressure within thecasing 11 causes the sealing device 29 to form a seal against thebaffle seat 25 that prevents fluid flow through theinner flow area 27. The sealing device 29 may be any suitable device that may be pumped into thecasing 11 and landed on thebaffle seat 25 to form a fluid tight seal. For example, the sealing device may a ball or a plug and may be made of ferrous metal, composite, polymer, phenolic/foam, or any combination of these. Forming the seal with the sealing device 29 prevents fluid flow past thesleeve 22 and thus isolates the initially treated area of theformation 18adjacent ports 21 a from any fluids in thecasing 11 above thesleeve 22. - Once the initially treated area of the
formation 18 is isolated, wellbore treatment procedures may perform at the new location without affecting the initially treated location. As shown inFIG. 3 , thesleeve 22 is initially in a closed position and held in place with sleeve shearing pins 28. Thesleeve 22 also includesguides 24 that travel within correspondinggrooves 26 on the inside of thecasing 11. Thegrooves 26 contact and landing surface that limits the travel of theguides 24 and thus also limit the travel of thesleeve 22. To treat theformation 18 adjacent thecasing ports 21 b covered by thesleeve 22, fluid communication must be established between theformation 18 and the casing bore 16 above the sealing device 29. To establish fluid communication, thesleeve 22 is moved from the initial closed position as shown inFIG. 3 to an open position as shown inFIG. 4 . Thesleeve 22 is moved to the open position by increasing the fluid pressure above the sealing device 29 and creating a pressure differential across thesleeve baffle seat 25 such that the force acting on thesleeve 22 shears the sleeve shear pins 28 and moves thesleeve 22 relative to thecasing 11 to substantially align the sleeve and casing ports. Once in the open position, thesleeve ports 23 allow fluid flow from the casing bore 16 through the casing ports 21. Again, initially fluid is pumped through the casing ports 21 to deteriorate the cement in theannulus 14 and allow fluid to flow between the area of theformation 18 adjacent thecasing ports 21 b and the casing bore 16. With fluid communication established, wellbore treatment fluids may then be pumped into the casing bore 16 and into theformation 18 through thecasing ports 21 b. The fluids treat theformation 18 and enhance the production capabilities of theformation 18. - When wellbore treatment operations are complete, fluid pressure within the
casing 16 is lowered to less than the fluid pressure of fluids in theformation 18. Fluids from theformation 18 are thus then allowed to enter thecasing 11 through the casing ports 21. When the fluid pressure is high enough from the flow of formation fluids in the casing bore 16, the sealing device 29 is unseated from thebaffle seat 25 and fluids from both above and below thesleeve 22 flow through the casing bore 16 to the surface 7. The sealing device 29 is pumped by the formation fluids flowing in the casing bore 16 toward the surface 7. If the sealing device 29 makes it to the surface, appropriate equipment at the surface, such as a sealing device catcher, may be used to retrieve the sealing device 29 from the fluid flow. Sometimes, however, the sealing device 29 is destroyed before reaching the surface 7 and no retrieval is necessary. - It should be appreciated that more than two zones of interest of the
formation 18 may be treated. AlthoughFIG. 3 only shows two sets ofcasing ports sleeve 22, there may be as many sets of casing ports 21 andcorresponding sleeves 22 as appropriate. There also need not be an initially open set ofcasing ports 21 a, but the casing ports 21 may all be associated with sleeves 22 (e.g., multiple sleeve/port assemblies may be placed at intervals along the casing). Thus, the wellborefluid treatment apparatus 20 is not limited by the embodiment illustrated inFIGS. 3 and 4 . - For example,
FIGS. 5 , 6, and 7 show an alternate embodiment of the wellborefluid treatment apparatus 20. Like parts are given like reference numerals and the operation of the wellborefluid treatment apparatus 20 is similar to the operation above with further explanation below. - As shown in
FIGS. 5 , 6, and 7, instead of onesleeve 22, the wellborefluid treatment apparatus 20 includes twosleeves casing ports casing 11 as previously described and thus allow two different locations within theformation 18 to be treated with wellbore fluids. The operation of the wellborefluid treatment apparatus 20 shown inFIGS. 5-7 differs in that theinitial sealing device 29 a must flow past thebaffle seat 25 of at least onesleeve 22 b before being seated on asubsequent sleeve 22 a. As shown inFIG. 5 , theinitial sealing device 29 a must flow through theinner flow area 27 of theupper-most sleeve 22 b before landing on the lower-mostsleeve baffle seat 25. To allow theinitial sealing device 29 a to pass theupper sleeve 22 b, thebaffle seat 25 of theupper sleeve 22 b has a largerinner flow area 27 than theinner flow area 27 of the lower andsubsequent baffle seat 25. Thus, theinner flow areas 27 of thesleeves 22 are different sizes and progressively decrease in size with eachsleeve 22. - As shown in
FIG. 5 , thecasing 11 is installed with thesleeves 22 in the closed position such that none of the casing ports 21 are open. As previously described, appropriate seals on the outside of thesleeves 22 seal the casing ports 21 from the casing bore 16. The first zone of interest of theformation 18 is then ready to be treated. - To flow wellbore treatment fluid into the first zone of the
formation 18, afirst sealing device 29 a is inserted into the casing bore 16 and pumped downhole to the wellborefluid treatment apparatus 20. Again, the sealing device 29 may be any suitable device that may be pumped into thecasing 11 and landed on thebaffle seat 25 to form a fluid tight seal. As shown inFIGS. 6 and 7 , the sealing device 29 is a ball, but need not be limited to that configuration. As shown inFIG. 6 , theinner flow area 27 of theinitial sleeve 22 b is large enough to allow theinitial sealing device 29 a to pass through to theset sleeve 22 a. Theinner flow area 27 of thelower baffle seat 25, however, is smaller such that theinitial sealing device 29 a lands on thelower baffle seat 25 as previously described. Fluid pressure within the casing bore 16 is then increased to create a pressure differential across the lowersleeve baffle seat 25 such that the force acting on thesleeve 22 a shears the sleeve shear pins 28 and moves thesleeve 22 a relative to thecasing 11. Thelower sleeve 22 a is thus moved from the initial closed position as shown inFIG. 5 to an open position as shown inFIG. 6 to establish fluid communication between thecasing ports 21 a and thesleeve ports 23 a of thelower sleeve 22. Once in the open position, fluid is pumped in the casing bore 16 past theupper sleeve 22 and through the lower set of casing ports 21 to deteriorate the cement in theannulus 14 and allow fluid to flow between theformation 18 and the casing bore 16. With fluid communication established, wellbore treatment fluids may then be pumped into the casing bore 16, past theupper sleeve 22 b, and into theformation 18 through thecasing ports 21 a to treat theformation 18 and enhance the production capabilities of theformation 18. - Once wellbore treatment at the initial location is complete, a different location of the
formation 18 may then be treated. A different wellbore treatment fluid may be needed for the new location in theformation 18. Additionally, it may not be desirable to perform any additional treatment procedures on the initial location of theformation 18. Thus, it may be desirable to isolate the initial location of theformation 18 already treated from wellbore treatment fluids in the casing bore 16 before treating the new location. - To isolate the already treated formation, another sealing
device 29 b is pumped down the casing bore 16 and into engagement with thebaffle seat 25 of theupper sleeve 22 b while thesleeve 22 b is in the closed position. Because theinner flow area 27 of theupper sleeve 22 b being larger than thelower sleeve 22 a, the subsequent sealing device 29 is larger than theinitial sealing device 29 a. Once landed on thebaffle seat 25 of theupper sleeve 22 b, fluid pressure within thecasing 11 causes thesubsequent sealing device 29 b to form a seal against thebaffle seat 25 that prevents fluid flow through theinner flow area 27 of theupper sleeve 22 b. Again, the sealing device 29 may be any suitable device that may be pumped into thecasing 11 and landed on thebaffle seat 25 to form a fluid tight seal. As shown inFIGS. 6 and 7 , the sealingdevice 29 b is a ball, but need not be limited to that configuration. Forming the seal with the sealingdevice 29 b prevents fluid flow past theupper sleeve 22 b and thus isolates the initially treated area of theformation 18 from any fluids in thecasing 11 above theupper sleeve 22 b. - Once the initially treated area of the
formation 18 is isolated, wellbore treatment procedures may be performed without affecting the initially treated location. To treat theformation 18 adjacent thecasing ports 21 b covered by theupper sleeve 22 b, fluid communication must be established between theformation 18 and the casing bore 16 above thesubsequent sealing device 29 b. As shown inFIG. 6 , theupper sleeve 22 b is initially in a closed position and held in place with sleeve shearing pins 28. Theupper sleeve 22 b is then moved from the initial closed position as shown inFIG. 6 to an open position as shown inFIG. 7 . Theupper sleeve 22 b is moved to the open position by increasing the fluid pressure above thesubsequent sealing device 29 b and creating a pressure differential across thesleeve baffle seat 25 such that the force acting on thesleeve 22 b shears the sleeve shear pins 28 and moves theupper sleeve 22 b relative to thecasing 11. Once in the open position, thesleeve ports 23 b allow fluid flow from the casing bore 16 through the upper set of thecasing ports 21 b. Again, initially fluid is pumped through thecasing ports 21 b to deteriorate the cement in theannulus 14 and allow fluid to flow between the area of theformation 18 adjacent the casing ports 21 and the casing bore 16. With fluid communication established, wellbore treatment fluids may then be pumped into the casing bore 16 and into theformation 18 through the casing ports 21 to treat theformation 18 and enhance the production capabilities of theformation 18. - When the decision is made that wellbore treatment operations are complete, fluid pressure within the
casing 16 is lowered to less than the fluid pressure of fluids in theformation 18. Fluids from theformation 18 are thus then allowed to enter thecasing 11 through all the casing ports 21. When the fluid pressure is high enough from the flow of formation fluids in the casing bore 16, the sealing devices 29 are unseated from the baffle seats 25 and fluids from both above and below theupper sleeve 22 flow through the casing bore 16 to the surface 7. The sealing devices 29 are pumped by the formation fluids flowing in the casing bore 16 toward the surface 7. If the sealing devices 29 make it to the surface, appropriate equipment at the surface, such as a sealing device catcher, may be used to retrieve the sealing devices 29 from the fluid flow. Sometimes, however, the sealing devices 29 are destroyed before reaching the surface 7, and no retrieval is necessary. - It should be appreciated that more than two zones of interest of the
formation 18 may be treated. AlthoughFIGS. 5-7 only show two sets of casing ports 21 and twosleeves 22, there may be as many sets of casing ports 21 andcorresponding sleeves 22 as appropriate. There may also be an initially open set ofcasing ports 21 a (e.g., not associated with a sleeve assembly) as shown inFIG. 3 . Thus, the wellborefluid treatment apparatus 20 is not limited by the embodiment illustrated inFIGS. 5-7 . - While specific embodiments have been shown and described, modifications can be made by one skilled in the art without departing from the spirit or teaching of this invention. The embodiments as described are exemplary only and are not limiting. Many variations and modifications are possible and are within the scope of the invention. Accordingly, the scope of protection is not limited to the embodiments described, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims.
Claims (22)
1. A wellbore fluid treatment apparatus capable of being actuated by a sealing device, the apparatus comprising:
a casing including a bore and a casing port opened through the wall of the casing;
a sleeve located within the casing bore and including:
a sleeve port opened through the wall of the sleeve;
a baffle seat forming an inner flow area and configured to receive the sealing device; and
the sleeve being moveable by the sealing device between a closed position preventing fluid flow from the bore through the casing port and an open position allowing fluid flow from the bore through the sleeve port and casing port; and
a reverse cement shoe attached to the casing and including a valve allowing the casing to be cemented by displacing cement only on the outside of the casing.
2. The apparatus of claim 1 , further comprising:
more than one casing port; and
wherein the sleeve includes sleeve ports corresponding with the casing ports.
3. The apparatus of claim 1 , further comprising:
more than one casing port spaced apart axially along the casing;
more than one sleeve corresponding to spaced apart casing ports, each sleeve baffle seat being configured to receive a different size sealing device; and
the size of baffle seat inner flow areas progressively decreasing such that a sealing device may flow through at least one sleeve before reaching a subsequent sleeve.
4. The apparatus of claim 1 , wherein the sleeve is axially slideable between the closed and open positions.
5. The apparatus of claim 1 , wherein the sleeve is moveable from the closed position to the open position upon a pressure differential across the baffle seat.
6. The apparatus of claim 1 , wherein the baffle seat is configured to form a fluid tight seal with the sealing device, preventing fluid flow past the baffle seat.
7. The apparatus of claim 1 , wherein wellbore treatment fluid may flow from the bore into the formation with the sleeve in the open position.
8. The apparatus of claim 7 , wherein the wellbore treatment fluid is a fracturing fluid, an acidized fluid, or any combination of the two.
9. A method of fluid treating a wellbore, the method comprising:
running a casing into the wellbore, the casing comprising a bore, a casing port opened through the wall of the casing, and a sleeve located in the casing bore, wherein the sleeve includes a sleeve port and is in a closed position preventing fluid flow from the bore through the casing port;
cementing the casing in the wellbore by flowing cement from the surface down the casing annulus, with cement being displaced only on the outside of the casing;
flowing a sealing device through the casing bore and into engagement with a baffle seat of the sleeve;
moving the sleeve from closed position to an open position, the sleeve port allowing fluid flow from the bore through the casing port in the open position; and
flowing well treatment fluids from the bore into the formation through the casing port.
10. The method of claim 9 , wherein cementing the casing in the wellbore further comprises allowing fluids to flow into the casing bore through a reverse cement shoe.
11. The method of claim 9 , further comprising preventing fluid flow through an inner flow area of the baffle seat by forming a fluid tight seal with the sealing device.
12. The method of claim 9 , wherein the casing further includes:
a set of casing ports; and
wherein the sleeve includes sleeve ports corresponding to the casing ports.
13. The method of claim 9 , further including:
the casing including more than one casing port spaced apart axially along the casing;
wherein running a casing into the wellbore includes running in more than one sleeve corresponding to each casing port, each sleeve baffle seat inner flow area being a different size and progressively decreasing with each sleeve; and
flowing the sealing device through at least one sleeve before engaging a subsequent sleeve.
14. The method of claim 13 , further including flowing more than one sealing device in the casing bore, each sealing device engaging a different sleeve.
15. The method of claim 14 , further including:
moving each sleeve from the closed position to the open position by creating a pressure differential across the sleeve baffle seats, the sleeve ports allowing fluid flow from the bore through the casing port in the open position; and
flowing well treatment fluids from the bore into the formation through the casing ports.
16. The method of claim 9 , moving the sleeve further including axially sliding the sleeve between the closed and open positions.
17. The method of claim 9 , further including creating a pressure differential across the baffle seat to move the sleeve from the closed position to the open position.
18. The method of claim 9 , wherein flowing wellbore treatment fluid includes flowing wellbore treatment fluid selected from at least one of the group consisting of acid, gelled acid, gelled water, gelled oil, carbon dioxide, nitrogen, and any of these fluids containing proppants.
19. The method of claim 9 , further including flowing the sealing device back to the surface.
20. The method of claim 9 , further including allowing fluids to flow from the formation through the casing ports and into the casing bore.
21. A method of servicing a wellbore, including:
running a ported casing into the wellbore, wherein one or more ports may be in a closed position;
pumping cement from the surface down the casing annulus;
isolating a portion of the casing prior to or after pumping the treatment fluid; and
pumping a treatment fluid from the surface through the casing and out one or more ports into the formation.
22. The method of claim 21 , further including opening one or more ports.
Priority Applications (2)
Application Number | Priority Date | Filing Date | Title |
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US11/609,128 US20080135248A1 (en) | 2006-12-11 | 2006-12-11 | Method and apparatus for completing and fluid treating a wellbore |
PCT/GB2007/004628 WO2008071912A1 (en) | 2006-12-11 | 2007-12-04 | Method and apparatus for completing and fluid treating a wellbore |
Applications Claiming Priority (1)
Application Number | Priority Date | Filing Date | Title |
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US11/609,128 US20080135248A1 (en) | 2006-12-11 | 2006-12-11 | Method and apparatus for completing and fluid treating a wellbore |
Publications (1)
Publication Number | Publication Date |
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US20080135248A1 true US20080135248A1 (en) | 2008-06-12 |
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Application Number | Title | Priority Date | Filing Date |
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US11/609,128 Abandoned US20080135248A1 (en) | 2006-12-11 | 2006-12-11 | Method and apparatus for completing and fluid treating a wellbore |
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US (1) | US20080135248A1 (en) |
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