US20100000727A1 - Apparatus and method for inflow control - Google Patents
Apparatus and method for inflow control Download PDFInfo
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- US20100000727A1 US20100000727A1 US12/166,257 US16625708A US2010000727A1 US 20100000727 A1 US20100000727 A1 US 20100000727A1 US 16625708 A US16625708 A US 16625708A US 2010000727 A1 US2010000727 A1 US 2010000727A1
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- 238000005553 drilling Methods 0.000 description 7
- 206010017076 Fracture Diseases 0.000 description 6
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- 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
-
- 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
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/02—Subsoil filtering
- E21B43/08—Screens or liners
-
- 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
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/11—Perforators; Permeators
- E21B43/114—Perforators using direct fluid action on the wall to be perforated, e.g. abrasive jets
-
- 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
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/14—Obtaining from a multiple-zone well
-
- 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
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/25—Methods for stimulating production
- E21B43/26—Methods for stimulating production by forming crevices or fractures
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- Geology (AREA)
- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Mining & Mineral Resources (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- Physics & Mathematics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Physical Or Chemical Processes And Apparatus (AREA)
- Massaging Devices (AREA)
- External Artificial Organs (AREA)
- Water Treatment By Sorption (AREA)
Abstract
A wellbore servicing apparatus comprising an inflow control assembly having an inflow flowbore and a stimulation assembly having a stimulation flowbore is disclosed. A method of servicing a wellbore comprising placing a stimulation assembly in the wellbore and placing at least one inflow control assembly in the wellbore, the at least one inflow control assembly comprising a selectively adjustable inflow sleeve, is also disclosed. A method of servicing a wellbore comprising opening a plurality of jetting nozzles in a production string located in a wellbore adjacent a formation, jetting a treatment fluid through the nozzles and perforating and/or fracturing the formation, at least partially closing the plurality of jetting nozzles, opening a plurality of inflow ports to allow fluid to flow from the formation into the production string, and filtering the fluid prior to the fluid entering the inflow ports is disclosed.
Description
- Not applicable.
- Not applicable.
- Not applicable.
- Hydrocarbon-producing wells often are stimulated by hydraulic fracturing operations, wherein a fracturing fluid may be introduced into a portion of a subterranean formation penetrated by a wellbore at a hydraulic pressure sufficient to create or enhance at least one fracture therein. Stimulating or treating the wellbore in such ways increases hydrocarbon production from the well. The fracturing equipment may be included in a completion assembly used in the overall production process.
- In some wells, it may be desirable to individually and selectively create multiple fractures along a wellbore at a distance apart from each other, creating multiple “pay zones.” The multiple fractures should have adequate conductivity, so that the greatest possible quantity of hydrocarbons in an oil and gas reservoir can be drained/produced into the wellbore. When stimulating a formation from a wellbore, or completing the wellbore, especially those wellbores that are highly deviated or horizontal, it may be advantageous to create multiple pay zones with a series of actuatable sleeve assemblies disposed in a downhole tubular. The actuatable sleeve assemblies are also referred to as sleeves or casing windows.
- A stimulation sleeve may include a section of tubing having holes or apertures pre-formed in the tubing, and a sliding sleeve movable relative to the tubing section. The sliding sleeve also includes apertures alignable with the apertures in the tubing section. Upon actuation of the stimulation sleeve, such as by ball drop or other obturating member interference, the sliding sleeve moves and the sliding sleeve apertures are aligned with the tubing section apertures. This exposes the reservoir to the interior of the tubing string, and vice versa. The flow path created between the reservoir and the tubing string through the stimulation sleeve can be used for fracturing or production operations. The apertures in the tubing section may include jet forming nozzles to provide a fluid jet into the formation, causing tunnels and fractures therein.
- Using multiple stimulation sleeves to create multiple formation zones may allow full wellbore access and increase hydrocarbon production; however, such operation may suffer from a variety of challenges depending on wellbore conditions such as an imbalanced inflow throughout a formation zone, production of water and gas, etc. Enhancement in methods and apparatuses to overcome these challenges can further improve hydrocarbon production. Thus, there is an ongoing need to develop new methods and apparatuses to enhance hydrocarbon production.
- The present invention, in at least one embodiment among others, relates to a wellbore servicing apparatus comprising at least one inflow control assembly having an inflow flowbore and at least one stimulation assembly having a stimulation flowbore, the stimulation flowbore being in fluid communication with the inflow flowbore.
- The present invention, in at least one embodiment among others, further relates to a method of servicing a wellbore comprising placing at least one stimulation assembly in the wellbore, the at least one stimulation assembly comprising a selectively adjustable stimulation sleeve and a stimulation flowbore, and placing at least one inflow control assembly in the wellbore, the at least one inflow control assembly comprising a selectively adjustable inflow sleeve and an inflow flowbore.
- The present invention, in at least one embodiment among others, further relates to a method of servicing a wellbore, comprising opening a plurality of jetting nozzles in a production string located in a wellbore adjacent a formation, jetting a treatment fluid through the nozzles and perforating and/or fracturing the formation, at least partially closing the plurality of jetting nozzles, opening a plurality of inflow ports to allow fluid to flow from the formation into the production string, and filtering the fluid prior to the fluid entering the inflow ports.
- For a more complete understanding of the present disclosure and the advantages thereof, reference is now made to the following brief description, taken in connection with the accompanying drawings and detailed description:
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FIG. 1 is a schematic, partial cross-sectional view of a wellbore completion apparatus in an operating environment; -
FIG. 2 is a cross-sectional view of an inflow control assembly of the wellbore completion apparatus ofFIG. 1 ; -
FIG. 3 is a cross-sectional view of a stimulation assembly of the wellbore completion apparatus ofFIG. 1 ; -
FIG. 4 is a cross-sectional view of an alternative embodiment of an inflow control assembly; -
FIG. 5 is an alternative embodiment of a wellbore completion apparatus; -
FIG. 6 is another alternative embodiment of a wellbore completion apparatus; and -
FIG. 7 is a further alternative embodiment of a wellbore completion apparatus. - In the drawings and description that follow, like parts are typically 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 infra 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”, “upward” or “upstream” meaning toward the surface of the wellbore and with “down”, “lower”, “downward” or “downstream” meaning toward the terminal end of the well, regardless of the wellbore orientation. The term “zone” or “pay zone” as used herein refers to separate parts of the wellbore designated for treatment or production and may refer to an entire hydrocarbon formation or separate portions of a single formation such as horizontally and/or vertically spaced portions of the same formation. The term “seat” as used herein may be referred to as a ball seat, but it is understood that seat may also refer to any type of catching or stopping device for an obturating member or other member sent through a work string fluid passage that comes to rest against a restriction in the passage. 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 with the aid of this disclosure upon reading the following detailed description of the embodiments, and by referring to the accompanying drawings.
- Several wellbore servicing apparatus embodiments are disclosed herein. Each wellbore servicing apparatus may comprise multiple wellbore completion apparatuses disposed in a work string. Each wellbore completion apparatus comprises at least one stimulation assembly and at least one inflow control assembly, thereby allowing selective zone treatment (e.g., perforation and/or fracturing) and production, respectively. Optimization of hydrocarbon production and minimization of unwanted fluid production (such as water and gas) in completion operations may be achieved using a wellbore completion apparatus having at least one selective inflow control assembly and at least one selective stimulation assembly in each formation zone. Each inflow control assembly can be independently selectively actuated to control and/or restrict inflow at different formation zones at different times. Each stimulation assembly can also be independently selectively actuated to expose different formation zones to stimulation (e.g., flow of a treatment fluid, e.g., fracturing fluid, from an inner fluid passage of the work string) at different times. As discussed infra in greater detail, the different assemblies of a wellbore completion apparatus may be configured in the formation zone in any suitable combination.
- Referring to
FIG. 1 , an embodiment of awellbore servicing apparatus 100 is shown in an exemplary operating environment. While thewellbore servicing apparatus 100 is shown and described with specificity, various other wellbore servicing apparatus embodiments consistent with the teachings herein are described infra. As depicted, the operating environment comprises adrilling rig 106 that is positioned on the earth'ssurface 104 and extends over and around awellbore 114 that penetrates asubterranean formation 102 for the purpose of recovering hydrocarbons. Thewellbore 114 may be drilled into thesubterranean formation 102 using any suitable drilling technique. Thewellbore 114 may extend substantially vertically away from the earth'ssurface 104 over a verticalwellbore portion 116, or may deviate at any angle from the earth'ssurface 104 over a deviated or horizontalwellbore portion 118. In alternative operating environments, all or portions of thewellbore 114 may be vertical, deviated, horizontal, and/or curved. - At least a portion of the
vertical wellbore portion 116 is lined with acasing 120 that is secured into position against theformation 102 in a conventionalmanner using cement 122. In alternative operating environments, thehorizontal wellbore portion 118 may be cased and cemented and/or portions of thewellbore 114 may be uncased. In an alternative embodiment, the horizontal wellbore portion may remain uncemented, but further integrate the use of Swellpackers™ (commercially available from Halliburton Energy Services, Inc.) that are deployed to develop at least partially sealed compartments in the horizontal sections. Thedrilling rig 106 comprises aderrick 108 with arig floor 110 through which a tubing orwork string 112 extends downward from thedrilling rig 106 into thewellbore 114. Thework string 112 delivers thewellbore servicing apparatus 100 to a predetermined depth within thewellbore 114 to perform an operation such as perforating a casing and/or formation, expanding a fluid path therethrough, fracturing theformation 102, producing hydrocarbons from theformation 102, or other completion operation. Thedrilling rig 106 may be conventional and may comprise a motor driven winch and other associated equipment for extending thework string 112 into thewellbore 114 to position thewellbore servicing apparatus 100 at the desired depth. - While the exemplary operating environment depicted in
FIG. 1 refers to astationary drilling rig 106 for lowering and setting thewellbore servicing apparatus 100 within a land-basedwellbore 114, one of ordinary skill in the art will readily appreciate that mobile workover rigs, wellbore servicing units (such as coiled tubing units), and the like may be used to lower thewellbore servicing apparatus 100 into thewellbore 114. It should be understood that thewellbore servicing apparatus 100 may alternatively be used in other operational environments, such as within an offshore wellbore operational environment. - The
wellbore servicing apparatus 100 comprises an upper end having a liner hanger 124 (such as a Halliburton VersaFlex® liner hanger), alower end 128, and atubing section 126 extending therebetween. Thelower end 128 has afloat shoe 130 and afloat collar 132 of a type known in the art connected therein, and tubing conveyeddevices 134 connected therein. Thetubing section 126 further comprises a plurality of packers 152 (such as Halliburton Swellpacker™ Isolation Systems) that function to isolate formation zones, thereby creatingformation zones tubing section 126. For example, the Swellpacker™ Isolation System is adapted to swell when exposed to hydrocarbons, water, gas, or combinations thereof. In alternative embodiments, any suitable packers may be used such as inflatable packers, squeeze packers, production packers, or combinations thereof. - The
horizontal wellbore portion 118 and thetubing section 126 define anannulus 138 therebetween. Thetubing section 126 comprises aninterior wall 140 that defines a flow passage 142 therethrough. Aninner string 144 is disposed intubing section 126 and theinner string 144 extends therethrough so that an inner stringlower end 146 extends into and is received by apolished bore receptacle 136. Theinner string 144 may be used to carrycement 122 if the completion operation requirescement 122. Alternatively,cement 122 may not be utilized and thetubing section 126 may not comprise theinner string 144 so that the flow passage 142 is the main flowbore through thewellbore servicing apparatus 100. - By way of a non-limiting example, six
wellbore completion apparatuses 190 are connected in-line with each other and housed in thetubing section 126. A singlewellbore completion apparatus 190 is placed in each of theformation zones packers 152 as described infra. Eachwellbore completion apparatus 190 comprises aninflow control assembly 148 placed adjacent astimulation assembly 150. Thus, theinflow control assemblies 148 are disposed alternatingly along the length of thetubing section 126 with thestimulation assemblies 150. In other words, astimulation assembly 150 is disposed adjacent aninflow control assembly 148 that is disposed adjacent anotherstimulation assembly 150 that is disposed adjacent anotherinflow control assembly 148, etc. - In an embodiment, the
stimulation assemblies 150 are ball drop activated. In alternative embodiments, the stimulation assemblies may be mechanical shift activated, hydraulically activated, electrically activated, or combinations thereof to allow or prevent access to a formation zone (e.g., to open and/or close a window or sliding sleeve). In an alternative embodiment of a stimulation assembly, any of the mechanical shift activated, hydraulically activated, and electrically activated systems may be triggered or otherwise controlled using a pressure pulse system, such as the HalSonics™ system that is commercially available from Halliburton Energy Services, Inc. Examples ofsuitable stimulation assemblies 150 include, without limitation, Delta Stim® Sleeves which are also available from Halliburton Energy Services, Inc. - In an embodiment, activation of the
inflow control assembly 148 is accomplished by ball drop. However, alternative embodiments of inflow control assemblies may include, without limitation, mechanical shift actuation, hydraulic actuation, electrical actuation, etc., to allow or prevent access to a formation zone (e.g., to open and/or close a window or sliding sleeve). An example of mechanical actuation includes a mechanical shift activation similar to the mechanical actuation of the mechanical shift activated Delta Stim® Sleeves. An example of hydraulic actuation includes a ball drop activation similar to the one on the ball drop activated Delta Stim® Sleeves. Further, in an alternative embodiment of an inflow control assembly, any of the mechanical shift activated, hydraulically activated, and electrically activated systems may be triggered or otherwise controlled using a pressure pulse system, such as the HalSonics™ system that is commercially available from Halliburton Energy Services, Inc. Generally, the inflow control assemblies differ from the stimulation assemblies in that the inflow control assemblies have additional structures that can restrict inflow of unwanted fluid such as gas and water and/or particles, which will be described infra. - Referring now to
FIG. 2 , awellbore completion apparatus 190 comprisingpackers 152 on each end is shown. Thewellbore completion apparatus 190 comprises thestimulation assembly 150 placed adjacent and above theinflow control assembly 148. Theinflow control assembly 148 comprises aninflow housing 154 with aninflow sleeve 156 detachably connected therein. Theinflow housing 154 comprises a plurality ofinflow housing ports 178 defined therein. Theinflow sleeve 156 has an inflow sleevelower end 158. Theinflow sleeve 156 further comprises a central inflow flowbore 157 that allows fluid communication between theinflow control assembly 148 and the flow passage 142 (shown inFIG. 1 ). After being detached from theinflow housing 154, theinflow sleeve 156 is slidable or movable in theinflow housing 154 as explained infra. Theinflow housing 154 has an inflow housingupper end 160 and an inflow housinglower end 162, both of which are configured to be directly connected to or threaded into tubing section 126 (or toother stimulation assemblies 150 and/or inflow control assemblies 148) such that theinflow housing 154 makes up a part of thetubing section 126 shown inFIG. 1 . Still referring toFIG. 2 , theinflow sleeve 156 is initially connected to theinflow housing 154 with aninflow snap ring 164 that extends into aninflow groove 166 defined on an inflow housinginner surface 168 of theinflow housing 154. In addition, inflow shear pins (not shown) extend through theinflow housing 154 and into theinflow sleeve 156 to detachably connect theinflow sleeve 156 to theinflow housing 154. Inflow guide pins 170 are threaded or otherwise attached to theinflow sleeve 156 and are received in inflow axial grooves or inflowaxial slots 172 of theinflow housing 154. The inflow guide pins 170 are slidable in the inflowaxial slots 172 thereby preventing relative rotation between theinflow sleeve 156 and theinflow housing 154. Theinflow sleeve 156 has a plurality ofinflow sleeve ports 174 therethrough. An inflowannular gap 175 formed by a recess of the interior wall of theinflow housing 154 serves to provide a fluid path between theinflow sleeve ports 174 and theinflow housing ports 178 when theinflow sleeve ports 174 are at least partially radially aligned with the inflowannular gap 175. Theinflow control assembly 148 further comprises ascreen 176, one or morepressure altering devices 180, and aport cover 182. - The
screen 176, disposed about a portion of the inflow housing 154 (e.g., adjacent inflow housing ports 178), is used to filter debris and may be constructed of wire wraps. However, in alternative embodiments, the screen may be made from any type of filter material such as mesh, sintered materials, etc. Thepressure altering devices 180 are nozzles positioned adjacent to (e.g., screwed into) and/or within theinflow housing ports 178. Thepressure altering devices 180 can restrict inward fluid flow through theinflow housing ports 178 during production of hydrocarbons thereby creating a pressure differential between theinflow flowbore 157 and theformation zones pressure altering device 180 can also delay early breakthrough of unwanted fluid (e.g., water, gas, etc.). In other alternative embodiments, the pressure altering devices may be tubes, pipes, or a combination of nozzles, wrapped tubing, tubes, baffles, channels, pipes, and/or any other structure suitable for altering pressure. Theport cover 182 covers theinflow housing ports 178 andpressure altering devices 180, thus protecting theinflow housing ports 178 andpressure altering devices 180 from being clogged. Thescreen 176 may be disposed within or adjacent to a flow path created by theport cover 182 such that any fluid flow through thepressure altering devices 180 and/orinflow housing ports 178 must first pass through and be filtered by thescreen 176. - Still referring to
FIG. 2 , theinflow sleeve ports 174 are radially misaligned (or longitudinally offset along the central lengthwise axis of the inflow control assembly 148) from the inflowannular gap 175 such that theinflow control assembly 148 is in a closed position where there is no access to theformation zones inflow flowbore 157 and the formation zones. Theinflow sleeve 156 has aninflow seat ring 184 operably associated therewith and is connected therein at or near the inflow sleevelower end 158. Theinflow seat ring 184 has an inflow seat ringcentral opening 186 defining a seat ring diameter therethrough. Theinflow seat ring 184 also has aninflow seat surface 188 for engaging an obturating member that may be dropped through thework string 112. - To move the
inflow sleeve 156 from the closed position to an open position, an obturating member, such as a closing ball (not shown), may be dropped through thework string 112 so that it engages theinflow seat surface 188 on theinflow seat ring 184. Although the obturating member is typically a ball, other types of obturating members may be used such as plugs and darts that engage theinflow seat surface 188 and prevent flow therethrough. With closing ball in placed on theinflow seat ring 184 and blocking flow, pressure is increased to overcome the holding force applied by theinflow snap ring 164 and the shear pins (not shown), thereby moving theinflow sleeve 156 to an open position where a fluid path exists between theinflow sleeve ports 174 and theinflow housing ports 178 via the inflowannular gap 175 to allow passage of fluids between theinflow flowbore 157 and theformation zones - Referring now to
FIG. 3 , thewellbore completion apparatus 190 is again shown, but with thestimulation assembly 150 shown in greater detail. Thestimulation assembly 150 has components similar to theinflow control assembly 148 inFIG. 2 as described infra. - The
stimulation assembly 150 comprises astimulation housing 202 with a stimulation housingupper end 208 and a stimulation housinglower end 210, both of which are configured to be directly connected or threaded into tubing section 126 (or toother stimulation assemblies 150 and/or inflow control assemblies 148) in a manner similar to theinflow control assembly 148 inFIG. 2 . Thestimulation housing 202 has astimulation sleeve 204 detachably connected therein with a stimulation sleevelower end 206. Thestimulation housing 202 has a plurality ofstimulation housing ports 224 defined therein. Thestimulation sleeve 204 has a central stimulation flowbore 205 that allows fluid communication between thestimulation assembly 150 and the flow passage 142 (shown inFIG. 1 ). - Similar to the
inflow control assembly 148 inFIG. 2 , thestimulation sleeve 204 is initially connected to thestimulation housing 202 with astimulation snap ring 212 that extends into astimulation groove 214 defined on a stimulation housinginner surface 216 of thestimulation housing 202. In addition, stimulation shear pins (not shown) extend through thestimulation housing 202 and into thestimulation sleeve 204 to detachably connect thestimulation sleeve 204 to thestimulation housing 202. Stimulation guide pins 218 are threaded or otherwise attached to thestimulation sleeve 204 and are received in stimulation axial grooves or stimulationaxial slots 220 of thestimulation housing 202. The stimulation guide pins 218 are slidable in the stimulationaxial slots 220 thereby preventing relative rotation between thestimulation sleeve 204 and thestimulation housing 202. Thestimulation sleeve 204 has a plurality ofstimulation sleeve ports 222 therethrough. A stimulationannular gap 223 formed by a recess of the interior wall of thestimulation housing 202 serves to provide a fluid path between thestimulation sleeve ports 222 and thestimulation housing ports 224 when thestimulation sleeve ports 222 are at least partially radially aligned with the stimulationannular gap 223. In alternative embodiments of a stimulation assembly, the housing ports may be fitted with a fluid jet forming nozzle suitable for perforating and/or fracturing a formation zone as described infra. - The
stimulation sleeve ports 222 are radially aligned with the stimulationannular gap 223 such that thestimulation assembly 150 is in an open position where there is access to theformation zones annular gap 223. Thestimulation sleeve 204 has astimulation seat ring 226 operably associated therewith and is connected therein at or near the stimulation sleevelower end 206. Thestimulation seat ring 226 has a stimulation seat ringcentral opening 228 defining a seat ring diameter therethrough. Thestimulation seat ring 226 also has astimulation seat surface 230 for engaging an obturating member 232 (shown as a ball) that is dropped through the stimulation flowbore 205 to actuate (e.g., open) thestimulation sleeve 204 by aligning thestimulation sleeve ports 222 and thestimulation housing ports 224. - In operation, a plurality of
wellbore completion apparatuses 190 may be used in servicing thewellbore 114, for example, in a wellbore completion service. Generally, servicing awellbore 114 is carried out starting from a formation zone in the furthest or lowermost end of the surface (i.e., toe) and sequentially backwards toward the closest or uppermost end of the surface (i.e., heel). The wellbore servicing begins by disposing aliner hanger 124 comprising afloat shoe 130, afloat collar 132, and atubing section 126 comprising a plurality ofwellbore completion apparatuses 190 separated from each other by a plurality ofpackers 152. Thefloat shoe 130 andfloat collar 132 are disposed near the toe. Thewellbore completion apparatuses 190 are positioned adjacent a plurality offormation zones wellbore completion apparatus 190 is placed adjacent each formation zone. The orientation of thewellbore completion apparatuses 190 may be horizontal, deviated, vertical, or angled, and can be selected based on the wellbore conditions. As previously explained, eachwellbore completion apparatus 190 comprises at least oneinflow control assembly 148 and at least onestimulation assembly 150. Next, a hydrocarbon fluid is disposed through thefloat shoe 130 to activate or swell thepackers 152. If desired, cementing of thewellbore 114 is performed usingcement 122. At this point, both thestimulation assemblies 150 and theinflow control assemblies 148 are closed, where theinflow sleeve ports 174 are radially misaligned from the inflowannular gaps 175 of theinflow assemblies 148, and thestimulation sleeve ports 222 are radially misaligned from the stimulationannular gaps 223 of thestimulation assemblies 150. - Once the
packers 152 are activated or swelled, the first formation zone 12 (typically the lowermost zone near the toe) is exposed by aligning (i.e., opening) thestimulation sleeve ports 222 with the stimulationannular gap 223 of thefirst stimulation assembly 150 that is associated with thefirst formation zone 12. The aligning is carried out by dropping a first obturating member 232 (e.g., ball). In alternative embodiments, the aligning may be carried out by hydraulically applying pressure, or by mechanically or electrically shifting thestimulation sleeve 204 to move thestimulation sleeve ports 222. The aligning is carried out untilstimulation sleeve ports 222 are completely aligned with the stimulationannular gap 223 to a fully opened position. In alternative embodiments, the aligning may be carried out until thestimulation sleeve ports 222 are partially aligned with the stimulationannular gap 223 to a partially opened position. - A wellbore servicing fluid (such as a fracturing fluid) may be pumped down the
wellbore 114 at sufficient pressure to perforate and/or fracture thefirst formation zone 12. The wellbore servicing fluid may be pumped through thestimulation housing ports 224 at a velocity sufficient to form perforation tunnels and/or fractures within thefirst formation zone 12. A sufficient volume of fracturing fluid may be pumped through the open ports to expand and/or propagate the fractures into the formation. - Next, the
second formation zone 10 may be exposed by any suitable method described infra, for example, by dropping another obturating member or mechanically shifting thestimulation sleeve 204 to align thestimulation sleeve ports 222 with the stimulationannular gap 223 of thestimulation assembly 150 associated with thesecond formation zone 10. The wellbore servicing fluid is again pumped down thewellbore 114 at sufficient pressure to form perforation tunnels and/or fracture thesecond formation zone 10. The procedure is repeated selectively and/or sequentially to service any selected and/or allformation zones inflow sleeve ports 174 of theinflow control assemblies 148 are at least partially misaligned (and preferably fully misaligned) from the inflowannular gaps 175 and at least partially (and preferably fully) closed to reduce the fluid path between the inflow flowbores 157 and theformation zones inflow control assemblies 148 may be completely closed, eliminating a fluid flow path between theflowbores 157 and formation zones. If obturating members are used, they can be returned to the earth'ssurface 104, for example, by flowing back with a hydraulic fluid or retrieval with a fishing tool, or the obturating members may be otherwise removed for example by drilling out. - Once the selected formation zones are perforated and/or fractured, production fluid (e.g., hydrocarbons) can now flow through flow paths in the formation, through the
stimulation housing ports 224 and thestimulation sleeve ports 222 of thestimulation assemblies 150, and into thestimulation flowbore 205 provided that such flow paths remain at least partially open. Alternatively, these flow paths may be partially or completely closed and the production of fluid from the formation controlled as follows. - Since sometimes the pressure of the
various formation zones inflow control assemblies 148 are used to alter the pressure of fluid flowing into theinflow flowbores 157. To accomplish this, thestimulation assemblies 150 are next at least partially closed by moving (i.e., misaligning) thestimulation sleeve ports 222 away from the stimulationannular gaps 223. Thestimulation sleeves 204 can be moved using any suitable tools or methods known in the art with the aid of this disclosure, for example, using a fishing tool on a wireline. - Next, to allow flow of fluid from the
formation zones inflow flowbore 157 with altered pressure, theinflow control assemblies 148 are at least partially (and preferably fully) opened. Similarly, the opening may be carried out by moving theinflow sleeves 156 by mechanically, hydraulically, or electrically shifting theinflow sleeves 156 untilinflow ports 174 are at least partially aligned (i.e., partially opened) or are fully aligned (i.e., opened) with the inflowannular gaps 175. Production fluid is filtered through thescreen 176 on theinflow control assemblies 148, and proceeds to flow through at least one pressure altering device 180 (e.g., nozzles, wrapped tubing, tubes, baffles, channels, pipes, and/or any other structure suitable for altering pressure), thereby altering (in this embodiment, lowering) the pressure of the flow of production fluids from the formation into theinflow flowbore 157. In other words, passing the wellbore servicing fluid through apressure altering device 180 of theinflow control assembly 148 creates a pressure differential between thewellbore 114 and theinflow flowbore 157. - The number of zones, the order in which the inflow control assemblies and the stimulation assemblies are used (e.g., partially and/or fully opened and/or closed), the wellbore completion apparatuses, the stimulation assemblies, the inflow control assemblies, etc. shown herein may be used in any suitable combination and the configurations shown herein are not intended to be limiting and are shown only for exemplary purposes. Any desired number of formation zones may be treated or produced in any order.
- Referring now to
FIG. 4 , an alternative embodiment of aninflow control assembly 300 is shown. Theinflow control assembly 300 has a casing window configuration that operates to enable selective access to a formation zone. An associated (but not shown) alternative embodiment of a stimulation assembly may comprise a casing window configuration similar to theinflow control assembly 300, but the associated stimulation assembly would not comprise any pressure altering components and optionally noport cover 312. - The
inflow control assembly 300 comprises an inflow cylindricalouter casing 302 that receives an inflowmovable sleeve member 304. Theinflow control assembly 300 also has a central inflow flowbore 305 that allow fluid communication between theinflow control assembly 300 and a flow passage of an associated work string. The inflow cylindricalouter casing 302 comprises one or more inflowouter casing apertures 306 to allow access for a fluid from the interior of the inflow cylindricalouter casing 302 into a formation zone 308. The inflowouter casing apertures 306 are coupled to ascreen 316, aport cover 312, and pressure altering devices (e.g.,pressure altering nozzles 310 and/or pressure altering pipes or tubes 314). The functions of thescreen 316, theport cover 312, and the pressure altering devices (e.g.,pressure altering nozzles 310 and/or pressure altering pipes or tubes 314) have been described supra. Thepressure altering nozzles 310 are inserted into the inflowouter casing apertures 306 while the pressure altering pipes ortubes 314 are placed adjacent thescreen 316 and inside theport cover 312. In alternative embodiments, pressure altering nozzles may be placed adjacent the outer casing apertures of the inflow control assembly, similar to the placement of thepressure altering device 180 ofFIG. 2 . Thepressure altering nozzles 310 are isolated from the inflow annulus 318 (formed between the inflow cylindricalouter casing 302 and the inflow movable sleeve member 304) by inflow coupling seals or inflowfluid flow barriers 320 to the inflow cylindricalouter casing 302. An inflowannular gap 307 formed by a recess in the outer wall of the inflowmovable sleeve member 304 serves to provide a fluid path between the inflow movablesleeve member apertures 322 and the inflowouter casing apertures 306 when the inflowouter casing apertures 306 are at least partially radially aligned with the inflowannular gap 307. - The inflow movable
sleeve member apertures 322 can be selectively aligned with the inflow asannular gap 307 to allow passage of fluid from the formation zone 308 into theinflow flowbore 305 through thescreen 316, the pressure altering pipes ortubes 314, inflowouter casing apertures 306 havingpressure altering nozzles 310, and the inflow movablesleeve member apertures 322 via the inflowannular gap 307. The inflowmovable sleeve member 304 can be shifted axially, rotatably, or by a combination thereof (to open and/or close) thereby selectively controlling flow of a fluid from the formation zone 308 into theinflow flowbore 305. The inflowmovable sleeve member 304 may be shifted via any suitable mechanism such as mechanical shift actuation, hydraulic actuation, electric actuation, etc. - The wellbore completion apparatus comprising at least one inflow control assembly and at least one stimulation assembly may be used in a variety of combinations. The number of inflow control assemblies and the stimulation assemblies in each wellbore completion apparatus can be selected based on the conditions of the wellbore and/or any other suitable determining factor. For example, in a single wellbore completion apparatus, the number of inflow control assemblies may be 2, 3, 4, 5, or more, and the number of stimulation assemblies may be 2, 3, 4, 5, or more.
-
FIG. 5 is an exemplary combination of an inflow control assembly and a stimulation assembly in awellbore completion apparatus 502. Thewellbore completion apparatus 502 comprises aninflow control assembly 506 adjacent and above astimulation assembly 508 withpackers wellbore completion apparatus 502. -
FIG. 6 shows awellbore completion apparatus 512 that comprises aninflow control assembly 516 adjacent and above astimulation assembly 518 that is adjacent and above anotherinflow control assembly 520 withpackers wellbore completion apparatus 512. -
FIG. 7 shows awellbore completion apparatus 524 that comprises astimulation assembly 528 adjacent and above aninflow control assembly 530 that is adjacent and above anotherstimulation assembly 532 that is adjacent and above anotherinflow control assembly 534 withpackers wellbore completion apparatus 524. - While embodiments of the disclosure have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of the disclosure. The embodiments described herein are exemplary only, and are not intended to be limiting. Many variations and modifications of the disclosure disclosed herein are possible and are within the scope of the disclosure. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations (e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater than 0.10 includes 0.11, 0.12, 0.13, etc.). For example, whenever a numerical range with a lower limit, RL, and an upper limit, RU, is disclosed, any number falling within the range is specifically disclosed. In particular, the following numbers within the range are specifically disclosed: R=RL+k*(RU−RL), wherein k is a variable ranging from 1 percent to 100 percent with a 1 percent increment, i.e., k is 1 percent, 2 percent, 3 percent, 4 percent, 5 percent, . . . 50 percent, 51 percent, 52 percent . . . , 95 percent, 96 percent, 97 percent, 98 percent, 99 percent, or 100 percent. Moreover, any numerical range defined by two R numbers as defined in the above is also specifically disclosed. Use of the term “optionally” with respect to any element of a claim is intended to mean that the subject element is required, or alternatively, is not required. Both alternatives are intended to be within the scope of the claim. Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, etc.
- Accordingly, the scope of protection is not limited by the description set out above but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated into the specification as an embodiment of the present disclosure. Thus, the claims are a further description and are an addition to the embodiments of the present disclosure. The discussion of a reference in the Description of Related Art is not an admission that it is prior art to the present disclosure, especially any reference that may have a publication date after the priority date of this application. The disclosures of all patents, patent applications, and publications cited herein are hereby incorporated by reference, to the extent that they provide exemplary, procedural, or other details supplementary to those set forth herein.
Claims (26)
1. A wellbore servicing apparatus, comprising:
at least one inflow control assembly having an inflow flowbore; and
at least one stimulation assembly having a stimulation flowbore, the stimulation flowbore being in fluid communication with the inflow flowbore.
2. The wellbore servicing apparatus according to claim 1 , the at least one inflow control assembly comprises:
an inflow housing having at least one inflow housing port; and
an inflow sleeve having at least one inflow sleeve port, the inflow sleeve being movable with respect to the inflow housing to selectively provide a fluid flow path between the at least one inflow housing port and the at least one inflow sleeve port.
3. The wellbore servicing apparatus according to claim 2 , the at least one inflow control assembly further comprises:
at least one pressure altering device.
4. The wellbore servicing apparatus according to claim 3 , wherein the at least one pressure altering device is selected from the group consisting of nozzles, wrapped tubing, tubes, baffles, channels, pipes, and any combination thereof.
5. The wellbore servicing apparatus according to claim 3 , the at least one inflow control assembly further comprises:
a port cover at least partially covering the at least one inflow housing port.
6. The wellbore servicing apparatus according to claim 3 , the at least one inflow control assembly further comprising:
a screen operably associated with the at least one pressure altering device.
7. The wellbore servicing apparatus according to claim 6 , wherein the screen is constructed of one of the group comprising wire wraps, mesh, sintered material, and any combination thereof.
8. The wellbore servicing apparatus according to claim 6 , the at least one inflow control assembly further comprising:
a port cover at least partially covering the at least one inflow housing port.
9. The wellbore servicing apparatus according to claim 3 , wherein the inflow sleeve is moved by one of the group consisting of ball drop actuation, mechanical shifting actuation, mechanical actuation, hydraulic actuation, electrical actuation, and any combination thereof.
10. The wellbore servicing apparatus according to claim 1 , the stimulation assembly further comprising:
a stimulation housing having at least one stimulation housing port; and
a stimulation sleeve having at least one stimulation sleeve port, the stimulation sleeve being movable with respect to the stimulation housing to selectively provide a fluid flow path between the at least one stimulation housing port and the at least one stimulation sleeve port.
11. The wellbore servicing apparatus according to claim 1 , further comprising:
a plurality of packers operably associated with the at least one inflow control assembly and the at least one stimulation assembly so that the at least one inflow control assembly and the at least one stimulation assembly are isolated within a formation zone.
12. The wellbore servicing apparatus according to claim 11 , wherein the packers are selected from the group consisting of swellable packers, inflatable packers, squeeze packers, production packers, and any combination thereof.
13. A method of servicing a wellbore, comprising:
placing at least one stimulation assembly in the wellbore, the at least one stimulation assembly comprising a selectively adjustable stimulation sleeve and a stimulation flowbore;
placing at least one inflow control assembly in the wellbore, the at least one inflow control assembly comprising a selectively adjustable inflow sleeve and an inflow flowbore.
14. The method according to claim 13 , further comprising:
transferring a wellbore servicing fluid from the stimulation flowbore to the wellbore while the at least one stimulation sleeve is at least partially open and provides a fluid path between the stimulation flowbore and the wellbore and while the at least one inflow sleeve is at least partially closed to at least partially reduce a fluid path between the inflow flowbore and the wellbore.
15. The method according to claim 14 , wherein the inflow sleeve is fully closed to eliminate a fluid path between the inflow flowbore and the wellbore during transferring of the wellbore servicing fluid from the stimulation flowbore to the wellbore.
16. The method according to claim 14 , wherein the stimulation sleeve is fully open to maximize a fluid path between the stimulation flowbore and the wellbore during transferring of the wellbore servicing fluid from the stimulation flowbore to the wellbore.
17. The method according to claim 14 , further comprising:
after the wellbore servicing fluid has been transferred from the stimulation flowbore to the wellbore, at least partially closing the stimulation sleeve to reduce the fluid path between the stimulation flowbore and the wellbore and at least partially opening the inflow sleeve to increase the fluid path between the inflow flowbore and the wellbore.
18. The method according to claim 14 , wherein the wellbore servicing fluid is a fracturing fluid.
19. The method according to claim 14 , further comprising:
passing the wellbore servicing fluid through a pressure altering device of the inflow control assembly, thereby creating a pressure differential between the wellbore and the inflow flowbore.
20. The method according to claim 19 , wherein the at least one stimulation assembly and the at least one inflow control assembly are isolated within a portion of the wellbore associated with a formation zone so that transferring the wellbore servicing fluid from the stimulation flowbore to the wellbore occurs within the formation zone and so that the pressure differential between the wellbore and the inflow flowbore is associated with the formation zone.
21. The method according to claim 13 , further comprising:
selectively adjusting the stimulation sleeve to change a fluid path between the stimulation flowbore and the wellbore, thereby adjusting a flow of treatment fluid flow from the stimulation flowbore into the wellbore.
22. The method according to claim 13 , further comprising:
selectively adjusting the stimulation sleeve to change a fluid path between the stimulation flowbore and the wellbore, thereby adjusting a flow of hydrocarbon fluid into the stimulation flowbore from the wellbore.
23. The method according to claim 13 , further comprising:
selectively adjusting the inflow sleeve to change a fluid path between the inflow flowbore and the wellbore, thereby adjusting a pressure differential between the wellbore and the inflow flowbore.
24. A method of servicing a wellbore, comprising:
opening a plurality of jetting nozzles in a production string located in a wellbore adjacent a formation;
jetting a treatment fluid through the nozzles and perforating and/or fracturing the formation;
at least partially closing the plurality of jetting nozzles;
opening a plurality of inflow ports to allow fluid to flow from the formation into the production string; and
filtering the fluid prior to the fluid entering the inflow ports.
25. The method of claim 24 further comprising decreasing the fluid pressure when flowing the fluid from the formation into the production string.
26. The method of claim 24 further comprising isolating the jetting nozzles and the inflow ports from upper and lower portions of the wellbore prior to their opening.
Priority Applications (2)
Application Number | Priority Date | Filing Date | Title |
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US12/166,257 US20100000727A1 (en) | 2008-07-01 | 2008-07-01 | Apparatus and method for inflow control |
PCT/GB2009/001505 WO2010001087A2 (en) | 2008-07-01 | 2009-06-12 | Apparatus and method for inflow control |
Applications Claiming Priority (1)
Application Number | Priority Date | Filing Date | Title |
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US12/166,257 US20100000727A1 (en) | 2008-07-01 | 2008-07-01 | Apparatus and method for inflow control |
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