US20100263873A1 - Method and apparatus for use in selectively fracing a well - Google Patents
Method and apparatus for use in selectively fracing a well Download PDFInfo
- Publication number
- US20100263873A1 US20100263873A1 US12/579,358 US57935809A US2010263873A1 US 20100263873 A1 US20100263873 A1 US 20100263873A1 US 57935809 A US57935809 A US 57935809A US 2010263873 A1 US2010263873 A1 US 2010263873A1
- Authority
- US
- United States
- Prior art keywords
- tubular body
- pressure
- fluid
- external sealing
- sealing sleeve
- 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
Links
- 238000000034 method Methods 0.000 title claims description 15
- 238000007789 sealing Methods 0.000 claims abstract description 106
- 239000012530 fluid Substances 0.000 claims abstract description 102
- 230000015572 biosynthetic process Effects 0.000 claims abstract description 13
- 230000007246 mechanism Effects 0.000 claims abstract description 13
- 238000004519 manufacturing process Methods 0.000 claims description 22
- 238000002955 isolation Methods 0.000 claims description 21
- 238000004891 communication Methods 0.000 claims description 6
- 238000003825 pressing Methods 0.000 claims description 5
- 238000005086 pumping Methods 0.000 claims description 5
- 238000009826 distribution Methods 0.000 claims description 3
- 208000006670 Multiple fractures Diseases 0.000 description 2
- 238000012986 modification Methods 0.000 description 2
- 230000004048 modification Effects 0.000 description 2
- 239000004215 Carbon black (E152) Substances 0.000 description 1
- 239000003082 abrasive agent Substances 0.000 description 1
- 230000006978 adaptation Effects 0.000 description 1
- 230000000712 assembly Effects 0.000 description 1
- 238000000429 assembly Methods 0.000 description 1
- 238000010276 construction Methods 0.000 description 1
- 230000009977 dual effect Effects 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 229930195733 hydrocarbon Natural products 0.000 description 1
- 150000002430 hydrocarbons Chemical class 0.000 description 1
- 238000009434 installation Methods 0.000 description 1
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
- E21B34/00—Valve arrangements for boreholes or wells
- E21B34/16—Control means therefor being outside the borehole
-
- 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
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/10—Sealing or packing boreholes or wells in the borehole
- E21B33/12—Packers; Plugs
- E21B33/126—Packers; Plugs with fluid-pressure-operated elastic cup or skirt
-
- 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
- E21B34/08—Valve arrangements for boreholes or wells in wells responsive to flow or pressure of the fluid obtained
-
- 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
- E21B2200/00—Special features related to earth drilling for obtaining oil, gas or water
- E21B2200/06—Sleeve valves
Definitions
- U.S. Pat. No. 7,267,172 entitled “Cemented Open Hole Selective Fracing System” teaches selectively opening holes in production tubing of a hydrocarbon producing well by using sliding valves which can be selectively opened by a shifting tool.
- U.S. Pat. No. 7,096,954 entitled “Method and Apparatus for Placement of Multiple Fractures in Open Hole Wells” teaches using a plurality of burst disk assemblies, each having an independent burst pressure. The present method provides an alternative method of selectively opening holes in production tubing.
- the apparatus comprises a tubular body having an exterior surface, and an interior surface that defines an interior bore.
- An annular flow area that has at least one fluid flow port extends radially through the tubular body from the interior surface to the exterior surface to permit fluids from the interior bore to pass through the at least one fluid flow port into a surrounding earth formation.
- An external sealing sleeve is detachably secured to the exterior surface of the tubular body to selectively cover the annular flow area and close the at least one fluid flow port.
- There is a pressure actuated sleeve shifting mechanism with increasing pressure tending to cause axial movement of the external sealing sleeve. Axial movement is resisted until a pre-selected pressure threshold is reached to permit movement of the external sealing sleeve to open the at least one fluid flow port.
- a method for use in selectively fracing a well comprising the following steps: (a) providing a plurality of apparatus as described above; (b) deploying the apparatuses along a production tubing string in a well with packers being positioned between the apparatuses to isolate production areas, the pre-selected pressure threshold for each production area increasing from a toe of the well toward a heel of the well; (c) pumping fluids down the production tubing at pressures just sufficient to selectively shift the external sealing sleeve of the apparatus having a lowest shifting pressure to an open position without shifting the external sealing sleeve of others of the apparatus having higher shifting pressures; (d) continuing to pump fluids down the production tubing to pump fluids into the earth formation through the apparatus that has had its external sealing sleeve moved to the open position; (e) pumping balls down the production tubing until the balls seat on and close the at least one fluid flow port on the apparatus that has had its external sealing sleeve moved to the open position; (f) using
- the isolation tool for selectively applying pressure to an outer tubular body.
- the isolation tool comprises a tubular body carrying a first sealing element and a second sealing element.
- the tubular body has a fluid inlet and a fluid outlet.
- the tubular body is movable within the outer tubular body.
- a pressure cavity is defined by an outer surface of the tubular body, an inner surface of the outer tubular body, and the first and second sealing elements.
- the fluid outlet of the tubular body is in fluid communication with the pressure cavity.
- the first sealing element and the second sealing element permit fluid flow into the pressure cavity and sealing against fluid flow out of the pressure cavity.
- FIG. 1 is a side elevation view in section of an apparatus for selectively fracing a well.
- FIG. 2 is an end elevation view in section of a sealing sleeve of the apparatus depicted in FIG. 1 .
- FIG. 3 is a detailed side elevation view of the sealing cavity of the fluid cavity of FIG. 1 .
- FIG. 4 is a side elevation view in section of the sealing sleeve in the open position.
- FIG. 5 is a side elevation view in section of the flow ports plugged with balls.
- FIG. 6 is a side elevation view of the apparatus depicted in FIG. 1 installed in a tubing string and inserted into a well.
- FIG. 7 is a side elevation view in section of an alternative tubular body.
- FIG. 8 is a side elevation view in partial section of an isolation tool.
- FIG. 9 is a side elevation view in partial section of the isolation tool adjacent to the apparatus depicted in FIG. 1 .
- FIG. 10 is a side elevation view in section of an alternative apparatus.
- FIG. 1 through 4 An apparatus for use in selectively fracing a well generally identified by reference numeral 10 , will now be described with reference to FIG. 1 through 4 . The use and operation of the apparatus will then be discussed with reference to FIG. 1 through 6 , 8 and 9 . An alternative tubular body will be described with reference to FIGS. 7 and 10 .
- apparatus 10 includes a tubular body 12 that has an exterior surface 14 and an interior bore 16 defined by an interior surface 17 .
- An annular flow area 18 has one or more fluid flow ports 20 extending radially through tubular body 12 from interior surface 17 to exterior surface 14 .
- three flow ports 20 are included and in FIG. 2 , the sealing sleeve 24 is designed to cover three. It will be understood that the number may be varied during construction of apparatus 10 , according to the preferences of the user or manufacturer.
- Fluid flow ports 20 permit fluids from interior bore 16 to pass through fluid flow ports 20 into a surrounding earth formation.
- an external sealing sleeve 24 is detachably secured to exterior surface 14 of tubular body 12 to selectively cover annular flow area 18 and close fluid flow ports 20 .
- External sleeve 24 has a first end 26 with a first internal diameter that engages a first sealing area 28 on exterior surface 14 of tubular body 12 on a first side 30 of annular flow area 18 .
- External sleeve has a second end 32 with a second internal diameter that engages a second sealing area 34 on exterior surface 14 of tubular body 12 on a second side 36 of annular flow area 18 .
- first sealing area 28 and second sealing area 34 have first and second seal grooves 38 and 40 in which are positioned first and second O-ring seals 42 and 44 , respectively.
- a locking engagement is preferably provided between external sealing sleeve 24 and exterior surface 14 of tubular body 12 to lock external sealing sleeve 24 in the open position as shown in FIG. 4 .
- several resilient fingers 52 may be carried by external sealing sleeve 24 . Resilient fingers 52 would then engage an engagement profile 54 on exterior surface 14 of tubular body 12 to maintain external sealing sleeve 24 in the open position.
- external sealing sleeve 24 is detachably secured to exterior surface 14 of tubular body 12 by shear pins 46 in shear pin apertures 47 .
- Exterior surface 14 of tubular body 12 has a circumferential shear pin groove 48 to accommodate shear pins 46 .
- Shear pins 46 are designed to shear and permit external sealing sleeve 24 to move as pressure builds within annular flow area 18 and reaches a predetermined pressure threshold.
- the number of shear pins 46 is adjustable, which permits a user to select a pre-selected pressure threshold at which the external sealing sleeve 24 is able to move by using a greater number or fewer number of shear pins 46 .
- External sealing sleeve 24 is moved by applying pressure to a pressure actuated sleeve shifting mechanism.
- a pressure actuated sleeve shifting mechanism For example, as shown in FIG. 3 , external sealing sleeve 24 is shifted by applying pressure within a fluid cavity 50 that is formed between external sealing sleeve 24 and exterior surface 14 of tubular body 12 . Fluid cavity 50 is asymmetrical to provide an asymmetrical pressure distribution, so that increasing pressure within fluid cavity 50 tends to cause axial movement of external sealing sleeve 24 .
- external sealing sleeve 24 may also be shifted by applying pressure to an inclined plane 51 located at the end of fluid flow port 20 .
- sleeve 24 may be biased to the shifted, open position, and a pressure increase may release a catch that allows sleeve 24 to shift.
- apparatuses 10 are deployed along a production tubing string 53 with packers 55 , such as hydraulically set dual element open hole packers.
- packers 55 such as hydraulically set dual element open hole packers.
- the type of packer used will be selected based on the conditions and preferences of the user.
- apparatuses 10 may be hard coated with carbide seats to improve durability.
- each apparatus 10 is prepared by positioning external sealing sleeve 24 over annular flow area 18 such that flow ports 20 are blocked. External sealing sleeve 24 is then locked into the closed position by inserting a certain number of shear pins 46 that engage shear pin groove 48 .
- the number of shear pins 46 sets the pressure at which external sealing sleeve 24 will move, such that, by increasing the number of shear pins 46 , the pre-determined pressure also increases.
- packers 55 are positioned between apparatuses 10 to isolate the desired production areas.
- Tubing string 53 is then inserted into the casing 56 of a wellbore 58 , in this case, a horizontal wellbore, such that each apparatus 10 is aligned with the portion of the formation to be fraced.
- tubing string 53 Once tubing string 53 is positioned with packers 55 set, fluids are pumped down tubing string 53 at pressures just sufficient to selectively shift external sealing sleeve 24 of apparatus 10 having the lowest pre-determined shifting pressure to an open position as shown in FIG. 3 , such that fingers 52 engage profile 54 , without shifting other external sealing sleeves 24 that have higher shifting pressures. Fluids are continued to be pumped down production tubing 53 to pump fluids into the earth formation through apparatus 10 that has had its external sealing sleeve 24 moved to the open position to treat the formation. Once treated, balls 60 are then pumped down tubing 53 until balls 60 seat on, and close fluid flow ports 20 on the open apparatus 10 as shown in FIG. 5 . Fluid pressure is maintained to keep balls 60 seated on fluid flow ports 20 .
- Fluid pressure is then increased until the next pre-determined pressure threshold is met to move the desired external sealing sleeve 24 to the open position.
- These steps are repeated to selectively open the desired external sealing sleeves 24 in the desired order, generally by starting toward the toe 62 and working toward the heel 64 if the well is a horizontal wellbore, or from the end of the wellbore and working backward.
- an isolation tool 70 may be used to apply pressure to a specific portion of tubing string 53 shown in FIG. 6 .
- Isolation tool 70 may be a cup frac tool, which is used to selectively frac a portion of a formation.
- Isolation tool 70 has an input 72 in fluid communication with an output or fluid flow ports 74 , with sealing elements 76 positioned on either side of fluid flow ports 74 .
- Input 72 is connected to another tubing string (not shown) that extends to the surface, such that fluid pressure may be applied by pumping fluid through the tubing string and out outputs 74 , as shown by arrows 78 .
- Isolation tool 70 is inserted into tubing string 53 until fluid flow ports 20 of a selected apparatus 10 are positioned between sealing elements 76 . Referring to FIG. 9 , sealing elements 76 engage interior surface 17 such that the fluid pressure is applied to the selected fluid flow ports 20 . Once the fluid pressure causes external sealing sleeve 24 to shift as described above, pressure is continued to be applied to frac the portion of the formation corresponding to those ports 20 .
- isolation tool 70 is repositioned at the next set of fluid flow ports, and the process is repeated. This also leaves a full bore access as the internal components used to shift sleeve 24 are removed.
- an isolation tool 70 is used to apply pressure to a specific portion of outer tubular member, or tubing string 53 . It will be understood that this particular tool may be used for other tools aside from a sealing sleeve 24 .
- the isolated pressure may be used to open various types of pressure-actuated openings, such as rupture discs, removable plugs, shifting sleeves, etc. as are known in the art.
- isolation tool 70 has sealing elements 76 that are in constant contact with the inner surface of an outer tubular body, such as tubing string 53 , during installation.
- isolation tool 70 has an equalization valve 86 that is open when tool 70 is being run in, and closes when pressure is applied within the pressure cavity 88 that is defined by sealing elements 76 , the outer surface of tubular member 12 , and As sealing elements 76 are cup-shaped, they permit fluid to flow past in one direction, but create a seal when a force is applied in the other directions. Thus, as tool 70 is being run in, fluid flows past the lower sealing element 76 and through equalization valve 86 .
- Equalization valve 86 is preferably adjustable such that the pressure at which it closes is adjustable. Once positioned, fluid pressure is applied between sealing elements 76 and as pressure builds within pressure cavity 88 , sealing elements 76 are sealed against the inner surface of outer tubular body 53 . Preferably, sealing elements 76 are biased into sealing contact with tubular body 53 , otherwise the pressurized fluid may flow around elements 76 and out of pressure cavity 88 .
- FIG. 7 shows a slightly modified tubular body 12 .
- tubular body 12 has been lengthened. This has the effect of locking external sealing sleeve 24 (not shown) further from flow ports 20 .
- profile 54 is a groove. This allows tubular body 12 to have a thicker sidewall past profile 54 .
- tubular body has a slightly angled surface 66 between seal groove 40 and shear pin groove 48 . While not shown, external sealing sleeve 24 will also have a corresponding angled surface 66 .
- FIG. 10 shows another modification, where, instead of finger 52 engaging shoulder 54 , a ratcheting system is provided, where a profiled element 80 engages a profiled surface 82 on tubular body 12 .
- the top surface of element 80 is sloped and engages a sloped surface within external sealing sleeve 24 , such that any reverse movement is discouraged by the engagement between element 80 and surface 82 , which increases due to the sloped surfaced as any reverse force increases.
- element 80 is enclosed within a resilient portion of sleeve 24 , such as a split ring-type design, such that sleeve 24 is able to flex, but still applies pressure to element 80 .
- an inner sleeve 84 that can be shifted back to close off ports 20 if desired.
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
CA2,641,778 | 2008-10-14 | ||
CA2641778A CA2641778A1 (fr) | 2008-10-14 | 2008-10-14 | Procede et appareil de fracturation selective d'un puits |
Publications (1)
Publication Number | Publication Date |
---|---|
US20100263873A1 true US20100263873A1 (en) | 2010-10-21 |
Family
ID=42110374
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US12/579,358 Abandoned US20100263873A1 (en) | 2008-10-14 | 2009-10-14 | Method and apparatus for use in selectively fracing a well |
Country Status (2)
Country | Link |
---|---|
US (1) | US20100263873A1 (fr) |
CA (2) | CA2641778A1 (fr) |
Cited By (16)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20110174491A1 (en) * | 2009-07-27 | 2011-07-21 | John Edward Ravensbergen | Bottom hole assembly with ported completion and methods of fracturing therewith |
WO2012081986A1 (fr) * | 2010-12-15 | 2012-06-21 | Statoil Petroleum As | Surveillance de l'érosion d'une soupape autonome |
WO2012174663A1 (fr) * | 2011-06-21 | 2012-12-27 | Packers Plus Energy Services Inc. | Dispositif de positionnement d'orifice de fracturation et outil d'isolation |
US20130161015A1 (en) * | 2010-08-24 | 2013-06-27 | Stonecreek Technologies Inc. | Apparatus and method for fracturing a well |
US8672036B2 (en) | 2011-07-11 | 2014-03-18 | Resource Well Completion Technologies Inc. | Wellbore circulation tool and method |
US8695716B2 (en) | 2009-07-27 | 2014-04-15 | Baker Hughes Incorporated | Multi-zone fracturing completion |
US8727010B2 (en) | 2009-04-27 | 2014-05-20 | Logan Completion Systems Inc. | Selective fracturing tool |
US8931565B2 (en) | 2010-09-22 | 2015-01-13 | Packers Plus Energy Services Inc. | Delayed opening wellbore tubular port closure |
US8944167B2 (en) | 2009-07-27 | 2015-02-03 | Baker Hughes Incorporated | Multi-zone fracturing completion |
US8955603B2 (en) | 2010-12-27 | 2015-02-17 | Baker Hughes Incorporated | System and method for positioning a bottom hole assembly in a horizontal well |
US9140097B2 (en) | 2010-01-04 | 2015-09-22 | Packers Plus Energy Services Inc. | Wellbore treatment apparatus and method |
US9366109B2 (en) | 2010-11-19 | 2016-06-14 | Packers Plus Energy Services Inc. | Kobe sub, wellbore tubing string apparatus and method |
CN106499360A (zh) * | 2016-12-27 | 2017-03-15 | 中煤科工集团重庆研究院有限公司 | 煤矿井下水力压裂钻孔封孔装置 |
EP3068970A4 (fr) * | 2013-11-13 | 2017-07-19 | Hydrawell Inc. | Appareil et système de découpe et de retrait en un seul déplacement |
US9797221B2 (en) | 2010-09-23 | 2017-10-24 | Packers Plus Energy Services Inc. | Apparatus and method for fluid treatment of a well |
US20220259942A1 (en) * | 2021-02-18 | 2022-08-18 | Baker Hughes Oilfield Operations Llc | Circulation sleeve and method |
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- 2009-10-14 CA CA2682621A patent/CA2682621A1/fr not_active Abandoned
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