Not applicable.
Not applicable.
Not applicable.
Hydrocarbon-producing wells often are stimulated by hydraulic fracturing operations, wherein a servicing fluid such as a fracturing fluid or a perforating 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. Such a subterranean formation stimulation treatment may increase hydrocarbon production from the well.
Additionally, in some wellbores, 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 produced from the wellbore. Some pay zones may extend a substantial distance along the length of a wellbore. In order to adequately induce the formation of fractures within such zones, it may be advantageous to introduce a stimulation fluid via multiple stimulation assemblies positioned within a wellbore adjacent to multiple zones. To accomplish this, it is necessary to configure multiple stimulation assemblies for the communication of fluid via those stimulation assemblies.
An activatable stimulation tool may be employed to allow selective access to one or more zones along a wellbore. However, it is not always apparent when or if a particular one, of sometimes several, of such activatable stimulation tools has, in fact, been activated, thereby allowing access to a particular zone of a formation. As such, where it is unknown whether or not a particular downhole tool has been activated, it cannot be determined if fluids thereafter communicated into a wellbore, for example in the performance of a servicing operation, will reach the formation zone as intended.
As such, there exists a need for a downhole tool, particularly, an activatable stimulation tool, capable of indicating to an operator that it, in particular, has been activated and will function as intended, as well as methods of utilizing the same in the performance of a wellbore servicing operation.
Disclosed herein is a wellbore servicing apparatus comprising a housing defining an axial flowbore and comprising one or more ports providing a route of fluid communication between the axial flowbore and an exterior of the housing, a sliding sleeve disposed within the housing and comprising a seat and an orifice, the sliding sleeve being movable from a first position in which the ports are obstructed by the sliding sleeve to a second position in which the ports are unobstructed by the sliding sleeve, and the seat being configured to engage and retain an obturating member, and a fluid delay system comprising a fluid chamber containing a fluid, wherein the fluid delay system is operable to allow the sliding sleeve to transition from the first position to the second position at a delayed rate.
Also disclosed herein is a wellbore servicing method comprising positioning a casing string within a wellbore, the casing string having incorporated therein a wellbore servicing apparatus, the wellbore servicing apparatus comprising a housing defining an axial flowbore and comprising one or more ports providing a route of fluid communication between the axial flowbore and an exterior of the housing, a sliding sleeve disposed within the housing and comprising a seat and an orifice, the sliding sleeve being movable from a first position to a second position, and a fluid delay system comprising a fluid chamber containing a fluid, transitioning the sliding sleeve from the first position in which the ports of the housing are obstructed by the sliding sleeve to the second position in which the ports of the housing are unobstructed by the sliding sleeve, wherein the fluid delay system causes the sliding sleeve to transition from the first position to the second position at a delayed rate, wherein the delayed rate of transition from the first position to the second position causes an elevation of pressure within casing string, verifying that the sliding sleeve has transitioned from the first position to the second position, and communicating a wellbore servicing fluid via the ports.
Further disclosed herein is a wellbore servicing method comprising activating a wellbore servicing apparatus by transitioning the wellbore servicing apparatus from a first mode to a second mode, wherein the wellbore servicing apparatus is configured to transition from the first mode to the second mode at a delayed rate and to cause an elevation of pressure within a flowbore of the wellbore servicing apparatus, and detecting the elevation of the pressure within the flowbore, wherein detection of the elevation of the pressure within the flowbore for a predetermined duration, to a predetermined magnitude, or both serves as an indication that the wellbore servicing apparatus is transitioning from the first mode to the second mode.
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:
In the drawings and description that follow, like parts are typically marked throughout the specification and drawings with the same reference numerals, respectively. In addition, similar reference numerals may refer to similar components in different embodiments disclosed herein. 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 not intended to limit the invention to the embodiments illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed herein may be employed separately or in any suitable combination to produce desired results.
Unless otherwise specified, use of the terms “connect,” “engage,” “couple,” “attach,” or any other like 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.
Unless otherwise specified, use of the terms “up,” “upper,” “upward,” “up-hole,” “upstream,” or other like terms shall be construed as generally from the formation toward the surface or toward the surface of a body of water; likewise, use of “down,” “lower,” “downward,” “down-hole,” “downstream,” or other like terms shall be construed as generally into the formation away from the surface or away from the surface of a body of water, regardless of the wellbore orientation. Use of any one or more of the foregoing terms shall not be construed as denoting positions along a perfectly vertical axis.
Unless otherwise specified, use of the term “subterranean formation” shall be construed as encompassing both areas below exposed earth and areas below earth covered by water such as ocean or fresh water.
Disclosed herein are embodiments of wellbore servicing apparatuses, systems, and methods of using the same. Particularly, disclosed herein are one or more embodiments of a wellbore servicing system comprising one or more activation-indicating stimulation assemblies (ASAs), configured for selective activation in the performance of a wellbore servicing operation. In an embodiment, an ASA, as will be disclosed herein, may be configured to indicate that it has been and/or is being activated by inducing variations in the pressure of a fluid being communicated to the ASA.
Referring to
As depicted in
The wellbore 114 may extend substantially vertically away from the earth's surface over a vertical wellbore portion, or may deviate at any angle from the earth's surface 104 over a deviated or horizontal wellbore portion. In alternative operating environments, portions or substantially all of the wellbore 114 may be vertical, deviated, horizontal, and/or curved and such wellbore may be cased, uncased, or combinations thereof.
In an embodiment, the wellbore 114 may be at least partially cased with a casing string 120 generally defining an axial flowbore 121. In an alternative embodiment, a wellbore like wellbore 114 may remain at least partially uncased. The casing string 120 may be secured into position within the wellbore 114 in a conventional manner with cement 122, alternatively, the casing string 120 may be partially cemented within the wellbore, or alternatively, the casing string may be uncemented. For example, in an alternative embodiment, a portion of the wellbore 114 may remain uncemented, but may employ one or more packers (e.g., Swellpackers™ commercially available from Halliburton Energy Services, Inc.) to isolate two or more adjacent portions or zones within the wellbore 114. In an embodiment, a casing string like casing string 120 may be positioned within a portion of the wellbore 114, for example, lowered into the wellbore 114 suspended from the work string. In such an embodiment, the casing string may be suspended from the work string by a liner hanger or the like. Such a liner hanger may comprise any suitable type or configuration of liner hanger, as will be appreciated by one of skill in the art with the aid of this disclosure.
Referring to
In the embodiment of
In one or more of the embodiments disclosed herein, one or more of the ASAs (cumulatively and non-specifically referred to as an ASA 200) may be configured to be activated while disposed within a wellbore like wellbore 114 and to indicate when such activation has occurred and/or is occurring. In an embodiment, an ASA 200 may be transitionable from a “first” mode or configuration to a “second” mode or configuration.
Referring to
Referring to
Referring to
Referring to the embodiments of
In an embodiment, the housing 220 may be characterized as a generally tubular body generally defining a longitudinal, axial flowbore 221. In an embodiment, the housing may comprise an inner bore surface 220a generally defining the axial flowbore 221. In an embodiment, the housing 220 may be configured for connection to and/or incorporation within a string, such as the casing string 120 or, alternatively, a work string. For example, the housing 220 may comprise a suitable means of connection to the casing string 120 (e.g., to a casing member such as casing joint or the like). For example, in the embodiment of
In an embodiment, the housing 220 may comprise one or more ports 225 suitable for the communication of fluid from the axial flowbore 221 of the housing 220 to a proximate subterranean formation zone when the ASA 200 is so-configured. For example, in the embodiment of
In an embodiment, the housing 220 may comprise a unitary structure (e.g., a continuous length of pipe or tubing); alternatively, the housing 220 may comprise two or more operably connected components (e.g., two or more coupled sub-components, such as by a threaded connection). Alternatively, a housing like housing 220 may comprise any suitable structure; such suitable structures will be appreciated by those of skill in the art upon viewing this disclosure.
In an embodiment, the housing 220 may comprise a recessed, sliding sleeve bore 224. For example, in the embodiments of
In an embodiment, the housing 220 may further comprise a recessed bore in which the delay system 260 may be at least partially disposed, that is, a delay system recess 226. In an embodiment, the delay system recess 226 may generally comprise a circumferential recess extending a length along the longitudinal axis and may extend circumferentially from the surfaces of the sliding sleeve bore 224 (e.g., to a depth beneath that of the first and second recessed bore surfaces 224c and 224d). For example, in the embodiment of
In an embodiment, the sliding sleeve 240 generally comprises a cylindrical or tubular structure. In an embodiment, the sliding sleeve 240 generally comprises an upper orthogonal face 240a, a lower orthogonal face 240b, an inner cylindrical surface 240c at least partially defining an axial flowbore 241 extending therethrough, a downward-facing shoulder 240d, a first outer cylindrical surface 240e extending between the upper orthogonal face 240a and the shoulder 240d, and a second outer cylindrical surface 240f extending between the shoulder 240d and the lower orthogonal face 240b. In an embodiment, the diameter of the first outer cylindrical surface 240e may be greater than the diameter of the second outer cylindrical surface 240f. In an embodiment, the axial flowbore 241 defined by the sliding sleeve 240 may be coaxial with and in fluid communication with the axial flowbore 221 defined by the housing 220. In the embodiment of
In an embodiment, the sliding sleeve 240 may be slidably and concentrically positioned within the housing 220. As illustrated in the embodiment of
In an embodiment, the sliding sleeve 240, the housing 220, or both may comprise one or more seals at the interface between the first outer cylindrical surface 240e of the sliding sleeve 240 and the first recessed bore surface 224c of the sliding sleeve bore 224 and/or between the second outer cylindrical surface 240f of the sliding sleeve 240 and the second recessed bore surface 224d of the sliding sleeve bore 224. For example, in an embodiment, the first sliding sleeve 240 may further comprise one or more radial or concentric recesses or grooves configured to receive one or more suitable fluid seals, for example, to restrict fluid movement via the interface between the first outer cylindrical surface 240e of the sliding sleeve 240 and the first recessed bore surface 224c of the sliding sleeve bore 224 and/or between the second outer cylindrical surface 240f of the sliding sleeve 240 and the second recessed bore surface 224d of the sliding sleeve bore 224. Suitable seals include but are not limited to a T-seal, an O-ring, a gasket, or combinations thereof. For example, in the embodiments of
In an embodiment, the sliding sleeve 240 may be slidably movable from a first position to a second position within the housing 220. Referring again to
Referring to
In an alternative embodiment, a first sliding sleeve like first sliding sleeve 240 may comprise one or more ports suitable for the communication of fluid from the axial flowbore 221 of the housing 220 and/or the axial flowbore 241 of the first sliding sleeve 240 to a proximate subterranean formation zone when the master ASA 200 is so-configured. For example, in an embodiment where such a first sliding sleeve is in the first position, as disclosed herein above, the ports within the first sliding sleeve 240 will be misaligned with the ports 225 of the housing and will not communicate fluid from the axial flowbore 221 and/or axial flowbore 241 to the wellbore and/or surrounding formation. When such a first sliding sleeve is in the second position, as disclosed herein above, the ports within the first sliding sleeve will be aligned with the ports 225 of the housing and will communicate fluid from the axial flowbore 221 and/or axial flowbore 241 to the wellbore and/or surrounding formation.
In an embodiment, the first sliding sleeve 240 may be configured to be selectively transitioned from the first position to the second position. For example, in the embodiment of
In an alternative embodiment, a first sliding sleeve like first sliding sleeve 240 may be configured such that the application of a fluid and/or hydraulic pressure (e.g., a hydraulic pressure exceeding a threshold) to the axial flowbore thereof will cause such the first sliding sleeve to transition from the first position to the second position. For example, in such an embodiment, the first sliding sleeve may be configured such that the application of fluid pressure to the axial flowbore results in a net hydraulic force applied to the first sliding sleeve in the direction of the second position. For example, the hydraulic forces applied to the first sliding sleeve may be greater in the direction that would move the first sliding sleeve toward the second position than the hydraulic forces applied in the direction that would move the first sliding sleeve away from the second position, as may result from a differential in the surface area of the downward-facing and upward-facing surfaces of the first sliding sleeve. One of skill in the art, upon viewing this disclosure, will appreciate that a first sliding sleeve may be configured for movement upon the application of a sufficient hydraulic pressure.
In an embodiment, the delay system 260 generally comprises one or more suitable devices, structures, assemblages configured to delay the movement of the sliding sleeve 240 from the first position to the second position, for example, such that at least a portion of the movement of the sliding sleeve 240 from the first position to the second position occurs at a controlled rate.
In the embodiment of
In an embodiment, the fluid chamber 265 may be cooperatively defined by the housing 220 and the sliding sleeve 240. For example, in the embodiment of
In an embodiment, the fluid chamber 265 may be characterized as having a variable volume, dependent upon the position of the sliding sleeve 240 relative to the housing 220. For example, when the sliding sleeve 240 is in the first position, the volume of the fluid reservoir 265 may be a maximum and, when the sliding sleeve 240 is in the second position, the volume of the fluid reservoir may be relatively less (e.g., a minimum). For example, in the embodiment of
In an embodiment, the fluid chamber 265 may be filled, substantially filled, or partially filled with a suitable fluid. In an embodiment, the fluid may be characterized as having a suitable rheology. In an embodiment, for example, in an embodiment where the fluid chamber 265 is filled or substantially filled with the fluid, the fluid may be characterized as a compressible fluid, for example a fluid having a relatively low compressibility. In an alternative embodiment, for example, in an embodiment where the fluid chamber 265 is incompletely or partially filled with the by the fluid, the fluid may be characterized as substantially incompressible. In an embodiment, the fluid may be characterized as having a suitable bulk modulus, for example, a relatively high bulk modulus. For example, in an embodiment, the fluid may be characterized as having a bulk modulus in the range of from about 1.8 105 psi, lbf/in2 to about 2.8 105 psi, lbf/in2 from about 1.9 105 psi, lbf/in2 to about 2.6 105 psi, lbf/in2, alternatively, from about 2.0 105 psi, lbf/in2 to about 2.4 105 psi, lbf/in2. In an additional embodiment, the fluid may be characterized as having a relatively low coefficient of thermal expansion. For example, in an embodiment, the fluid may be characterized as having a coefficient of thermal expansion in the range of from about 0.0004 cc/cc/° C. to about 0.0015 cc/cc/° C., alternatively, from about 0.0006 cc/cc/° C. to about 0.0013 cc/cc/° C., alternatively, from about 0.0007 cc/cc/° C. to about 0.0011 cc/cc/° C. In another additional embodiment, the fluid may be characterized as having a stable fluid viscosity across a relatively wide temperature range (e.g., a working range), for example, across a temperature range from about 50° F. to about 400° F., alternatively, from about 60° F. to about 350° F., alternatively, from about 70° F. to about 300° F. In another embodiment, the fluid may be characterized as having a viscosity in the range of from about 50 centistokes to about 500 centistokes. Examples of a suitable fluid include, but are not limited to oils, such as synthetic fluids, hydrocarbons, or combinations thereof. Particular examples of a suitable fluid include silicon oil, paraffin oil, petroleum-based oils, brake fluid (glycol-ether-based fluids, mineral-based oils, and/or silicon-based fluids), transmission fluid, synthetic fluids, or combinations thereof.
In an embodiment, the meter or means for allowing escape and/or dissipation of the fluid from the fluid chamber may comprise an orifice. For example, in the embodiment of
In an embodiment, the orifice 245 may be formed by any suitable process or apparatus. For example, the orifice 245 may be cut into the first sliding sleeve 240 with a laser, a bit, or any suitable apparatus in order to achieve a precise size and/or configuration. In an embodiment, an orifice like orifice 245 may be fitted with nozzles or fluid metering devices, for example, such that the flow rate at which the fluid is communicated via the orifice is controlled at a predetermined rate. Additionally, an orifice like orifice 245 may be fitted with erodible fittings, for example, such that the flow rate at which fluid is communicated via the orifice varies over time. Also, in an embodiment, an orifice like orifice 245 may be fitted with screens of a given size, for example, to restrict particulate flow through the orifice.
In an additional or alternative embodiment, the orifice 245 may further comprise a fluid metering device received at least partially therein. In such an embodiment, the fluid metering device may comprise a fluid restrictor, for example a precision microhydraulics fluid restrictor or micro-dispensing valve of the type produced by The Lee Company of Westbrook, Conn. However, it will be appreciated that in alternative embodiments any other suitable fluid metering device may be used. For example, any suitable electro-fluid device may be used to selectively pump and/or restrict passage of fluid through the device. In further alternative embodiments, a fluid metering device may be selectively controlled by an operator and/or computer so that passage of fluid through the metering device may be started, stopped, and/or a rate of fluid flow through the device may be changed. Such controllable fluid metering devices may be, for example, substantially similar to the fluid restrictors produced by The Lee Company.
Referring to
In an alternative embodiment, the delay system may comprise an alternative means of controlling the movement of the sliding sleeve 240 from the first position to the second position. A suitable alternative delay system may include, but is not limited to, a friction rings, (e.g., configured to cause friction between the sliding sleeve and the housing), a crushable or frangible member, or the like, as may be appreciated by one of skill in the art upon viewing this disclosure.
One or more embodiments of an ASA 200 and a wellbore servicing system 100 comprising one or more ASAs 200 (e.g., ASAs 200a-200c) having been disclosed, one or more embodiments of a wellbore servicing method employing such a wellbore servicing system 100 and/or such an ASA 200 are also disclosed herein. In an embodiment, a wellbore servicing method may generally comprise the steps of positioning a wellbore servicing system comprising one or more ASAs within a wellbore such that each of the ASAs is proximate to a zone of a subterranean formation, optionally, isolating adjacent zones of the subterranean formation, transitioning the sliding sleeve within an ASA from its first position to its second position, detecting the configuration of the first ASA, and communicating a servicing fluid to the zone proximate to the ASA via the ASA.
In an embodiment, the process of transitioning a sliding sleeve within an ASA from its first position to its second position, detecting the configuration of that ASA, and communicating a servicing fluid to the zone proximate to the ASA via that ASA, as will be disclosed herein, may be repeated, for as many ASAs as may be incorporated within the wellbore servicing system.
In an embodiment, one or more ASAs may be incorporated within a work string or casing string, for example, like casing string 120, and may be positioned within a wellbore like wellbore 114. For example, in the embodiment of
In an embodiment where the ASAs (e.g., ASAs 200a-200c) incorporated within the casing string 120 are configured for activation by an obturating member engaging a seat within each ASA, as disclosed herein, the ASAs may be configured such that progressively more uphole ASAs are configured to engage progressively larger obturating members and to allow the passage of smaller obturating members. For example, in the embodiment of
In an embodiment, once the casing string 120 comprising the ASAs (e.g., ASAs 200a-200c) has been positioned within the wellbore 114, adjacent zones may be isolated and/or the casing string 120 may be secured within the formation. For example, in the embodiment of
In an embodiment, the zones of the subterranean formation (e.g., 2, 4, and/or 6) may be serviced working from the zone that is furthest down-hole (e.g., in the embodiment of
In an embodiment where the wellbore is serviced working from the furthest down-hole progressively upward, once the casing string comprising the ASAs has been positioned within the wellbore and, optionally, once adjacent zones of the subterranean formation (e.g., 2, 4, and/or 6) have been isolated, the first ASA 200a may be prepared for the communication of a fluid to the proximate and/or adjacent zone. In such an embodiment, the sliding sleeve 240 within the ASA (e.g., ASA 200a) proximate and/or substantially adjacent to the first zone to be serviced (e.g., formation zone 2), is transitioned from its first position to its second position. In an embodiment wherein the ASA is activated by an obturating member engaging a seat within the ASA, transitioning the sliding sleeve 240 within the ASA 200 to its second position may comprise introducing an obturating member (e.g., a ball or dart) configured to engage the seat 248 of that ASA 200 (e.g., ASA 200a) into the casing string 120 and forward-circulating (e.g., pumping) the obturating member to engage the seat 248.
In such an embodiment, when the obturating member has engaged the seat 248, continued application of a fluid pressure to the flowbore 221, for example, by continuing to pump fluid, may increase the force applied to the seat 248 and the first sliding sleeve 240 via the obturating member. Referring to
In an embodiment, the ASA 200 may be configured to allow the fluid to escape and/or dissipate from the fluid chamber 265 at a controlled rate over the entire length of the stroke (e.g., movement from the first position to the second position) of the sliding sleeve 240 or some portion thereof. For example, referring to the embodiments of
In an embodiment, as the first sliding sleeve 240 moves from the first position to the second position, the first sliding sleeve 240 ceases to obscure the ports 225 within the housing 220.
In an embodiment, the ASA 200 may be configured such that the sliding sleeve 240 will transition from the first position to the second position at a rate such that the obstruction of the axial flowbore creates an increase in pressure (e.g., the fluid pressure within the axial flowbore 121 of the casing string 120) that is detectable by an operator (e.g., a pressure spike). For example, because the obturating member obstructs the movement of fluid via the axial flowbore 221 and because the ports remain obstructed (and, therefore, unable to communicate fluid) during the time (e.g., the delay or transition time) while the sliding sleeve 240 transitions from the first position to the second position, the pressure within the axial flowbore 221 of the ASA 200, and therefore, the pressure within the flowbore 121 of the casing string 120 may increase and/or remain at elevated pressure until the ports 225 begin to open, at which point the pressure make begin to decrease. Upon the sliding sleeve 240 reaching the second position, the ports 225 are unobstructed and the pressure may be allowed dissipate.
In such an embodiment, an operator may recognize that such a “pressure spike” may indicate the engagement of an obturating member by the seat of an ASA. In addition, the operator may recognize that such a “pressure spike,” followed by a dissipation of the pressure may indicate the engagement of an obturating member by the seat of an ASA and the subsequent transitioning of the sliding sleeve of that ASA from the first position to the second position, thereby indicating that the obturating member has been engaged by the seat (e.g., landed on the seat) and that the ASA is configured for the communication of a servicing fluid to the formation or a zone thereof. As will be appreciated by one of skill in the art with the aid of this disclosure, such a “pressure spike” may be detectable by an operator, for example, at the surface. As will also be appreciated by one of skill in the art, the magnitude and/or duration (e.g., time of pressure spike, which may be about equal to an expected or designed delay or transition time) of such a “pressure spike” may be at least partially dependent upon the configuration of the ASA, for example, the volume of the fluid chamber, the rate at which fluid is allowed to escape and/or dissipate from the chamber, the length of the stroke of the sliding sleeve, or combinations of these and other like variables.
For example, an ASA may be configured to provide a pressure increase, as observed at the surface, of at least 300 psi, alternatively at least 400 psi, alternatively, in the range of from about 500 psi to about 3000 psi. Also, for example, an ASA may be configured to provide a pressure increase, as observed at the surface, for a duration of at least 0.1 seconds, alternatively, in the range of from about 1 second to about 30 seconds, alternatively, from about 2 seconds to about 10 seconds. In an additional embodiment, the duration of any such deviation in the observed pressure may be monitored and/or analyzed with reference to a predetermined or expected design value (e.g., for comparison to threshold value).
In an embodiment, when the operator has confirmed that the first ASA 200a is configured for the communication of a servicing fluid, for example, by detection of a “pressure spike” as disclosed herein, a suitable wellbore servicing fluid may be communicated to the first subterranean formation zone 2 via the ports 225 of the first ASA 200a. Nonlimiting examples of a suitable wellbore servicing fluid include but are not limited to a fracturing fluid, a perforating or hydrajetting fluid, an acidizing fluid, the like, or combinations thereof. The wellbore servicing fluid may be communicated at a suitable rate and pressure for a suitable duration. For example, the wellbore servicing fluid may be communicated at a rate and/or pressure sufficient to initiate or extend a fluid pathway (e.g., a perforation or fracture) within the subterranean formation 102 and/or a zone thereof.
In an embodiment, when a desired amount of the servicing fluid has been communicated to the first formation zone 2, an operator may cease the communication of fluid to the first formation zone 2. Optionally, the treated zone may be isolated, for example, via a mechanical plug, sand plug, or the like, placed within the flowbore between two zones (e.g., between the first and second zones, 2 and 4). The process of transitioning a sliding sleeve within an ASA from its first position to its second position, detecting the configuration of that ASA, and communicating a servicing fluid to the zone proximate to the ASA via that ASA may be repeated with respect the second and third ASAs, 200b and 200c, respectively, and formation zones 4 and 6, associated therewith. Additionally, in an embodiment where additional zones are present, the process may be repeated for any one or more of the additional zones and the associated ASAs.
In an embodiment, an ASA such as ASA 200, a wellbore servicing system such as wellbore servicing system 100 comprising an ASA such as ASA 200, a wellbore servicing method employing such a wellbore servicing system 100 and/or such an ASA 200, or combinations thereof may be advantageously employed in the performance of a wellbore servicing operation. For example, as disclosed herein, as ASA such as ASA 200 may allow an operator to ascertain the configuration of such an ASA while the ASA remains disposed within the subterranean formation. As such, the operator can be assured that a given servicing fluid will be communicated to a given zone within the subterranean formation. Such assurances may allow the operator to avoid mistakes in the performance of various servicing operations, for example, communicating a given fluid to the wrong zone of a formation. In addition, the operator can perform servicing operations with the confidence that the operation is, in fact, reaching the intended zone.
The following are nonlimiting, specific embodiments in accordance with the present disclosure:
A wellbore servicing apparatus comprising:
a housing defining an axial flowbore and comprising one or more ports providing a route of fluid communication between the axial flowbore and an exterior of the housing;
a sliding sleeve disposed within the housing and comprising a seat and an orifice, the sliding sleeve being movable from a first position in which the ports are obstructed by the sliding sleeve to a second position in which the ports are unobstructed by the sliding sleeve, and the seat being configured to engage and retain an obturating member; and
a fluid delay system comprising a fluid chamber containing a fluid, wherein the fluid delay system is operable to allow the sliding sleeve to transition from the first position to the second position at a delayed rate.
The wellbore servicing apparatus of embodiment A, wherein the orifice of the sliding sleeve is not in fluid communication with the fluid chamber when the sliding sleeve is in the first position.
The wellbore servicing apparatus of embodiment B, wherein the orifice of the sliding sleeve comes into fluid communication with the fluid chamber upon movement of the sliding sleeve from the first position in the direction of the second position.
The wellbore servicing apparatus of embodiment A, B, or C, wherein the orifice is configured to allow at least a portion of the compressible fluid to escape from the fluid chamber at a controlled rate.
The wellbore servicing apparatus of embodiment A, B, C, or D, wherein the wellbore servicing apparatus is configured such that an application of pressure to the sliding sleeve via an obturating member and the seat, a force is applied to the sliding sleeve in the direction of the second position.
The wellbore servicing apparatus of embodiment E, wherein the wellbore servicing apparatus is configured such that the force causes the compressible fluid to be compressed.
The wellbore servicing apparatus of embodiment A, B, C, D, E, or F, wherein the sliding sleeve is retained in the first position by a shear-pin.
The wellbore servicing apparatus of embodiment A, B, C, D, E, F, or G, wherein the fluid has a bulk modulus in the range of from about 1.8 105 psi, lbf/in2 to about 2.8 105 psi, lbf/in2.
The wellbore servicing apparatus of embodiment A, B, C, D, E, F, G, or H, wherein the compressible fluid comprises silicon oil.
A wellbore servicing method comprising:
positioning a casing string within a wellbore, the casing string having incorporated therein a wellbore servicing apparatus, the wellbore servicing apparatus comprising:
transitioning the sliding sleeve from the first position in which the ports of the housing are obstructed by the sliding sleeve to the second position in which the ports of the housing are unobstructed by the sliding sleeve, wherein the fluid delay system causes the sliding sleeve to transition from the first position to the second position at a delayed rate, wherein the delayed rate of transition from the first position to the second position causes an elevation of pressure within casing string;
verifying that the sliding sleeve has transitioned from the first position to the second position; and
communicating a wellbore servicing fluid via the ports.
The wellbore servicing method of embodiment J, wherein transitioning the sliding sleeve from the first position to the second position comprises:
introducing an obturating member into the casing string;
flowing the obturating member through the casing string to engage the seat within the wellbore servicing apparatus;
applying a fluid pressure to the sliding sleeve via the obturating member and the seat.
The wellbore servicing method of the embodiment K, wherein applying the fluid pressure to the sliding sleeve results in a force applied to the sliding sleeve in the direction of the second position.
The wellbore servicing method of embodiment L, where the force applied to the sliding sleeve in the direction of the second position causes the sliding sleeve to move in the direction of the second position and compresses the compressible fluid within the fluid chamber.
The wellbore servicing method of embodiment M, wherein the orifice is not in fluid communication with the fluid chamber when the sliding sleeve is in the first position.
The wellbore servicing method of embodiment N, wherein movement of the sliding sleeve a distance from the first position in the direction of the second position causes the orifice to come into fluid communication with the fluid chamber.
The wellbore servicing method of embodiment O, wherein the compressible fluid is allowed to escape from the fluid chamber via the orifice after the orifice comes into fluid communication with the fluid chamber.
The wellbore servicing method of embodiment J, K, L, M, N, O, or P, wherein verifying that the sliding sleeve has transitioned from the first position to the second position comprises observing the elevation of pressure within the casing string.
The wellbore servicing method of embodiment J, K, L, M, N, O, P, or Q, wherein the elevation of pressure within the casing string dissipates upon the sliding sleeve reaching the second position.
The wellbore servicing method of embodiment R, wherein verifying that the sliding sleeve has transitioned from the first position to the second position comprises observing the elevation of pressure within the casing string followed by the dissipation of the elevated pressure from the casing string.
The wellbore servicing method of embodiment S, wherein verifying that the sliding sleeve has transitioned from the first position to the second position comprises observing the elevation of pressure to at least a threshold magnitude.
The wellbore servicing method of embodiment S, wherein verifying that the sliding sleeve has transitioned from the first position to the second position comprises observing the elevation of pressure for at least a threshold duration.
A wellbore servicing method comprising:
activating a wellbore servicing apparatus by transitioning the wellbore servicing apparatus from a first mode to a second mode, wherein the wellbore servicing apparatus is configured to transition from the first mode to the second mode at a delayed rate and to cause an elevation of pressure within a flowbore of the wellbore servicing apparatus; and
detecting the elevation of the pressure within the flowbore, wherein detection of the elevation of the pressure within the flowbore for a predetermined duration, to a predetermined magnitude, or both serves as an indication that the wellbore servicing apparatus is transitioning from the first mode to the second mode.
The wellbore servicing method of embodiment V, further comprising:
communicating a wellbore servicing fluid via the wellbore servicing apparatus.
While embodiments of the invention 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 invention. The embodiments described herein are exemplary only, and are not intended to be limiting. Many variations and modifications of the invention disclosed herein are possible and are within the scope of the invention. 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 invention. Thus, the claims are a further description and are an addition to the embodiments of the present invention. The discussion of a reference in the Detailed Description of the Embodiments is not an admission that it is prior art to the present invention, 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.
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Number | Date | Country | |
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20130284451 A1 | Oct 2013 | US |