Patent Application
20160145959
Drilling operations have become increasingly expensive as the need to drill deeper, in harsher environments, and through more difficult materials have become reality. Additionally, testing and evaluation of completed and partially finished well bores has become commonplace, such as to increase well production and return on investment.
In working with deeper and more complex wellbores, it becomes more likely that tools, tool strings, and/or other downhole apparatus may become stuck within the bore. In addition to the potential to damage equipment in trying to retrieve it, the construction and/or operation of the well must generally stop while tools are fished from the bore. The fishing operations themselves may also damage the wellbore and/or the downhole apparatus.
Furthermore, downhole tools used in fishing operations are regularly subjected to high temperatures, temperature changes, high pressures, and the other rigors of the downhole environment. Consequently, internal components of the downhole tools may be subjected to repeated stresses that may compromise reliability. Downhole conveyance means, such as a wireline, slickline, e-line, coiled tubing, drill pipe, and/or production tubing, may withstand stresses that may exceed the structural integrity of the downhole tools they deploy.
One such downhole tool, referred to as a jar, may be operable to dislodge a downhole apparatus when it becomes stuck within a wellbore. The jar is positioned in the tool string and/or otherwise deployed downhole to free the downhole apparatus. Tension load is applied to the tool string via the conveyance means to trigger the jar, thus delivering an impact intended to dislodge the stuck portion of the tool string. High tension loads applied by the conveyance means may be within operational parameters of the jar, however, the impacts delivered at such high tension loads may generate stresses exceeding such operational parameters, thus damaging other components of the tool string.
The present disclosure is best understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.
It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for simplicity and clarity, and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.
The wellbore 120 is depicted in
The tensioning device 170 is operable to apply an adjustable tensile force to the tool string 110 via the conveyance means 160. Although depicted schematically in
The first and second portions 140 and 150 of the tool string 110 may each be or comprise one or more downhole tools, modules, and/or other apparatus operable in wireline, while-drilling, coiled tubing, completion, production, and/or other implementations. The first portion 140 of the tool string 110 also comprises at least one electrical conductor 210 in electrical communication with at least one component of the surface equipment 175, and the second portion 150 of the tool string 110 also comprises at least one electrical conductor 220 in electrical communication with at least one component of the surface equipment 175, wherein the at least one electrical conductor 210 of the first portion 140 of the tool string 110 and the at least one electrical conductor 220 of the second portion 150 of the tool string 110 may be in electrical communication via at least one or more electrical conductors 205 of the DAIA 200. Thus, the one or more electrical conductors 205, 210, 220, and/or others may collectively extend from the conveyance means 160 and/or the first tool string portion 140, into the DAIA 200, and perhaps into the second tool string portion 150, and may include various electrical connectors along such path.
The DAIA 200 may be employed to retrieve a portion of the tool string 110 that has become lodged or stuck within the wellbore 120, such as the second portion 150. The DAIA 200 may be coupled to the second portion 150 of the tool string 110 before the tool string 110 is conveyed into the well-bore, such as in prophylactic applications, or after at least a portion of the tool string 110 (e.g., the second portion 150) has become lodged or stuck in the wellbore 120, such as in “fishing” applications.
Referring to
The DAIA 200 and/or associated apparatus is operable to detect an electrical characteristic of the electrical conductor 205, impart a first impact force on the second portion 150 of the tool string 110 when the electrical characteristic is detected, and impart a second impact force on the second portion 150 of the tool string 110 when the electrical characteristic is not detected. The second impact force is substantially greater than or otherwise different from the first impact force. For example, the first impact force may be about 3,500 pounds (or about 15.6 kilonewtons), whereas the second impact force may be about 9,000 pounds (or about 40.0 kilonewtons). However, other quantities are also within the scope of the present disclosure. For example, the first impact force may range between about 1,000 pounds (or about 4.4 kilonewtons) and about 6,000 pounds (or about 26.7 kilonewtons), and the second impact force may range between about 6,000 pounds (or about 26.7 kilonewtons) and about 12,000 pounds (or about 53.4 kilonewtons). A difference between the first and second impact forces may range between about 1,000 pounds (or about 4.4 kilonewtons) and about 6,000 pounds (or about 26.7 kilonewtons), although other differences are also within the scope of the present disclosure. The impact forces may be substantially equal to the tensile forces applied to the tool string 110 at the time the DAIA 200 is triggered, as described below.
The electrical characteristic detected by the DAIA 200 may be a substantially non-zero voltage and/or current, such as in implementations in which the electrical characteristic is a voltage substantially greater than about 0.01 volts and/or a current substantially greater than about 0.001 amperes. For example, the electrical characteristic may be a voltage substantially greater than about 0.1 volts and/or a current substantially greater than about 0.01 amperes. However, other values are also within the scope of the present disclosure.
As at least partially shown in
The latching mechanism 240 comprises a female latch portion 275, a male latch portion 280, and an anti-release member 285. The female latch portion 275 is slidably retained within the upper first housing 250 between a detector housing 290 and at least a portion of an upper adjuster 295. A floating separator 305 may be disposed between the female latch portion 275 and the detector housing 290. In the depicted implementation, the separator 305 is a Belleville washer sandwiched between the female latch portion 275 and a lock ring 310. The lock ring 310 may be threadedly engaged with the detector housing 290 to retain mating engagement between corresponding conical or otherwise tapered mating surfaces 315 external to the detector housing 290 with corresponding conical or otherwise tapered mating surfaces 317 internal to the upper sub 245, thus positionally fixing the detector housing 290 relative to the upper sub 245.
The male latch portion 280 comprises a plurality of flexible members 320 collectively operable to detachably engage the female latch portion 275. While only two instances are visible in the figures, a person having ordinary skill in the art will readily recognize that more than two instances of the flexible member 320 collectively encircle the anti-release member 285. The male latch portion 280 is coupled to or otherwise carried with the shaft 270, such as via threaded means, fasteners, pins, press/interference fit, and/or other coupling 272. Thus, the female latch portion 275 is carried with and/or by the upper portion DAIA section 230 and, thus, the first or upper portion 140 of the tool string 110, whereas the male latch portion 280 is carried with and/or by the lower DAIA section 235 and, thus, the second or lower portion 150 of the tool string 110. The detachable engagement between the female and male latch portions 275 and 280, respectively, is between an internal profile 325 of the female latch portion 275 and an external profile 330 of each of the plurality of flexible members 320, as more clearly depicted in
The anti-release member 285 is moveable within the male latch portion 280 between a first position, shown in
The upper adjuster 295 is threadedly engaged with the female latch portion 275, such that the upper adjuster 295 and the female latch portion 275 float axially between, for example, the lock ring 310 and an internal shoulder 335 of the upper housing 250, and such that rotation of the female latch portion 275 relative to the upper adjuster 295 adjusts the relative axial positions of the female latch portion 275 and the upper adjuster 295. The DAIA 200 also comprises a lower adjuster 340 disposed within the upper housing 250 and threadedly engaged with the connector 255, such that the axial position of the lower adjuster 340 is adjustable in response to rotation of the lower adjuster 340 relative to the connector 255 and/or the upper housing 250. The DAIA 200 also comprises a carrier 345 slidably retained within the upper housing 250, an upper spring stack 350 slidably disposed within the annulus defined within the carrier 345 by the shaft 270 and/or the male latch portion 280, and a lower spring stack 355 slidably retained between the carrier 345 and the lower adjuster 340. The upper and lower spring stacks 350 and 355, respectively, may each comprise one or more Belleville washers, wave springs, compression springs, and/or other biasing members operable to resist contraction in an axial direction.
The lower spring stack 355 biases the carrier 345 away from the lower adjuster 340 in an uphole direction, ultimately urging an uphole-facing shoulder 360 of the carrier 345 towards contact with a corresponding, downhole-facing, interior shoulder 365 of the upper housing 250. The upper spring stack 350 biases the upper adjuster 295 away from the carrier 345 (perhaps via one or more contact ring, washers, and/or other annular members 370), thus urging the interior profile 325 of the female latching portion 275 into contact with the exterior profile 330 of the plurality of flexible members 320, when the anti-release member 285 is positioned within the ends of the flexible members 320. The upper spring stack 350 also urges the female latching portion 275 (via the adjuster 295) towards contact with the separator 305, when permitted by engagement between the female and male latch portions 275 and 280, respectively.
Thus, as explained in greater detail below: (1) the lower adjuster 340 is disposed in the upper housing 250 at an axial location that is adjustable relative to the upper housing 250 in response to rotation of the lower adjuster 340 relative to the upper housing 250, (2) the upper spring stack 350 is operable to resist relative movement (and thus disengagement) of the female and male latch portions 275 and 280, respectively, and (3) the lower spring stack 355 is also operable to resist relative movement (and thus disengagement) of the female and male latch portions 275 and 280, respectively, wherein: (A) the female latch portion 275 is axially fixed relative to the upper housing 250, (B) the male latch portion 280 is axially fixed relative to the upper housing 250, (C) the difference between a first magnitude of the first impact force and a second magnitude of the second impact force is adjustable via adjustment of the relative locations of the female latch portion 275 and the upper adjuster 295 in response to relative rotation of the female latch portion 275 and the upper adjuster 295, (D) the second magnitude of the second impact force is adjustable in response to adjustment of the location of the lower, “static” end of the lower spring stack 355 relative to the upper housing 250, which is accomplished by adjusting the location of the lower adjuster 340 via rotation relative to the upper housing 250 and/or connector 255.
Rotation of the female latch portion 275 relative to the upper housing 250 may be via external access through an upper window 375 extending through a sidewall of the upper housing 250. The upper window 375 may be closed during operations via one or more of: a removable member 380 sized for receipt within the window 375; and a rotatable cover 385 having an opening (not numbered) that reveals the window 375 when rotationally aligned to do so but that is also rotatable away from the window 375 such that the cover 385 obstructs access to the window 375. A fastener 390 may prevent rotation of the cover 385 during operations.
Rotation of the lower adjuster 340 relative to the upper housing 250 may be via external access through a lower window 395 extending through a sidewall of the upper housing 250. The lower window 395 may be closed during operations via one or more of: a removable member 405 sized for receipt within the window 395; and a rotatable cover 410 having an opening (not numbered) that reveals the window 395 when rotationally aligned to do so but that is also rotatable away from the window 395 such that the cover 410 obstructs access to the window 395. A fastener 415 may prevent rotation of the cover 410 during operations.
The detector housing 290 contains, for example, a detector 420 operable to detect the electrical characteristic based upon which the higher or lower impact force is imparted by the DAIA 200 to the lower tool string portion 150. For example, as described above, the detector 420 may be operable to detect the presence of current and/or voltage on the electrical conductor 205, such as in implementations in which the detector is and/or comprises a transformer, a Hall effect sensor, a Faraday sensor, a magnetometer, and/or other devices operable in the detection of current and/or voltage. The detector 420 may be secured within the detector housing 290 by one or more threaded fasteners, pins, and/or other means 425.
The detector 420 also is, comprises, and/or operates in conjunction with a solenoid, transducer, and/or other type of actuator operable to move the anti-release member 285 between the first position (shown in
The detector housing 290 and the mandrel 435 may each comprise one or more passages 520 through which the electrical conductor 205 may pass and then extend through the anti-release member 285 and the shaft 270. Accordingly, the electrical conductor 205 may be in electrical communication with the electrical conductor 220 of the lower tool string portion 150.
The anti-release member 285 may comprise multiple sections of different diameters. For example, the head 450 of the anti-release member 285 may have a diameter sized for receipt within the recess 445 of the mandrel 435 and containment therein via the retaining means 455. For example, a blocking section 465 of the anti-release member 285 has a diameter sized for receipt within the male latch portion 280 (e.g., within the plurality of flexible members 320) such that the anti-release member 285 prevents disengagement of the female and male latch portions 275 and 280, respectively, when the blocking section 465 is positioned within the male latch portion 280. For example, the blocking section 465 of the anti-release member 285 may be sufficiently sized and/or otherwise configured so that, when positioned within the ends of the plurality of flexible members 320, the flexible members 320 are prevented from deflecting radially inward in response to contact between the inner profile 325 of the female latch portion 275 and the outer profile 330 of each of the flexible members 320 of the male latch portion 280.
The detector 420, plunger 430, mandrel 435, and biasing member 460 may also cooperatively operate to axially translate the anti-release member 285 between its first and second positions described above. For example, in the example implementation and operational stage depicted in
In the example implementation depicted in
Moreover, in the example implementation and operational stage depicted in
In the example implementation depicted in
As described above, the detector 420, plunger 430, mandrel 435, and/or biasing member 460 may be collectively operable to move the blocking section 465 of the anti-release member 285 from the first position shown in
Moreover, the detector 420, plunger 430, mandrel 435, and/or biasing member 460 may also be collectively operable to move the blocking section 465 of the anti-release member 285 to a third position between the first position shown in
The detector 420, plunger 430, mandrel 435, and/or biasing member 460 may also or instead collectively operate to position the blocking section 465 of the anti-release member 285 at a third position offset between the first and second positions by an amount proportional to the difference between the measured electrical characteristic and the first and second predetermined levels. For example, if the first predetermined level is ten (10) units (e.g., volts or amperes), the second predetermined level is zero (0) units, the measured electrical characteristic is three (3) units, and the distance between the first and second positions is about ten (10) centimeters, then the third position may be about three (3) centimeters from the from the second position, which is also about seven (7) centimeters from the first position.
During such conveyance 805, the DAIA 200 may be in the configuration shown in
During subsequent operations, the lower tool string portion 150 may be lodged or stuck in the wellbore 120. Consequently, the method 800 comprises performing 810 a power stroke of the DAIA 200, such as is depicted in
Consequently, the upper ends of the flexible members 320 of the male latch portion 280 are able to deflect radially inward, thus permitting the disengagement of the female and male latch portions 275 and 280, respectively, such that the upper DAIA section 230 rapidly translates away from the lower DAIA section 235 until one or more shoulders, bosses, flanges, and/or other impact features 490 of the upper DAIA section 230 collide with a corresponding one or more shoulders, bosses, flanges, and/or other impact features 495 of the lower DAIA section 235. Such impact may be as depicted in
The resulting impact force is imparted to the lower tool string portion 150, such as along a load path extending from the impact features 495 to the lower tool string portion 150 via the lower sub 265 (and perhaps additional components not explicitly shown in the figures). The impact force may be substantially equal to, or perhaps a few percentage points less than, the tensile force being applied by the tensioning device 175 and/or otherwise acting across the DAIA 200 and/or the tool string 110 at or near the instant in time when the female and male latch portions 275 and 270, respectively, became disengaged.
The method 800 may subsequently comprise reengaging 815 the female and male latch portions 275 and 280, respectively. For example, the tensioning device 175 may be operated to reduce the tension being applied to the tool string 110 such that, as depicted in
Continued relative axial translation of the upper and lower DAIA sections 230 and 235, respectively, as depicted in
The method 800 may comprise multiple iterations of performing 810 the power stroke and subsequently reengaging 815 the female and male latch portions 275 and 280, respectively, utilizing the DAIA 200 in the “low-force” configuration depicted in
Consequently,
The method 820 comprises conveying 805 the DAIA 200 within the wellbore 120, whether as part of the tool string 110 before the tool string 110 gets stuck, or after the tool string 110 is already stuck in the wellbore 120. During the conveying 805, the DAIA 200 may be in the configuration shown in
During subsequent operations, the lower tool string portion 150 may be lodged or stuck in the wellbore 120. Consequently, the method 820 may comprise confirming 825 that the DAIA 200 is in the configuration depicted in
The method 820 subsequently comprises reconfiguring 830 the DAIA 200 to the configuration depicted in
Operations according to one or more aspects of the present disclosure, including performance of the method 800 shown in
Thus, implementations of the DAIA 200 introduced herein may be utilized to initially attempt dislodging of the tool string 110 with a lower force while one or more downhole tools of the tool string 110 remain powered, or “on”, which corresponds to the detector 420, plunger 430, mandrel 435, and/or biasing member 460 being collectively operated to move the blocking section 465 of the anti-release member 285 to (or at least towards) the above-described first position, shown in
Ones of
Furthermore, the shaft 270 may comprise a central bore 271 extending longitudinally therethrough. The central bore 271 may be in communication with the passages 520 and contain therein the electrical conductor 205 extending from the passages 520. The lower annulus portion 612 may be in fluid communication with a central bore 271, such as though one or more shaft ports 615 extending radially through the shaft 270 between the central bore 271 and the lower annulus portion 612.
The walls of the housing ports 620 may comprise a smooth surface or may comprise internal threads, such as may be operable for engaging with threaded members. One such threaded member may be a flow restrictor 630, such as may be operable to reduce or otherwise control the rate of fluid flow through a housing port 620. The DAIA 200 may comprise a plurality of housing ports 620, wherein each housing port 620 may comprise a flow restrictor 630 therein.
The DAIA 200 may contain an internal fluid (not shown) within the pressure compensation annulus 610, the central bore 271, the passages 520, and a plurality of spaces and/or cavities (not numbered) that are formed between the plurality of components described above and fluidly connected with the central bore 271 and passages 520. The internal fluid may comprise hydraulic oil or other fluid, such as may be operable to lubricate the plurality of components during operation and/or to enable pressure equalization between the internal portion of DAIA 200 and the space external to the upper housing 260, such as a portion of the wellbore 120 in which the DAIA 200 is deployed. Prior to conducting impact operations, the internal fluid may be fed into the DAIA 200 through strategically located fill ports (not shown). Prior to or during introduction of the internal fluid into the DAIA 200, substantially all of the air may be extracted from within DAIA 200 and replaced with internal fluid. Once the DAIA 200 is satisfactorily filled with the internal fluid, the fill ports may be closed by plugs.
The pressure compensation annulus 610, the housing ports 620, and the floating piston 605 may be operable to equalize the pressure of internal fluid within the upper annulus portion 611, the lower annulus portion 612, and the portion of the wellbore 120 in which the DAIA 200 is deployed. For example, when the upper annulus portion 611 contains wellbore fluid at a first pressure and the wellbore 120 contains wellbore fluid at a second pressure, the housing ports 620 enable fluid communication therethrough to equalize the pressure differential between the upper annulus portion 611 and the wellbore 120. Furthermore, the floating piston 605 slides or otherwise moves within the pressure compensation annulus 610 to equalize the pressure differential between the upper annulus portion 611 and the lower annulus portion 611.
During impact operations, as the upper DAIA section 230 moves axially relative to the lower DAIA section 235, the internal fluid may be communicated into and out of the lower annulus portion 612 of the pressure compensation annulus 610 through the shaft ports 615. The connector 255 and the floating piston 605 may be operable to prevent the wellbore fluid contained in the upper annulus portion 611 from leaking into and contaminating the internal fluid contained within the lower annulus portion 612, the central bore 271, the passages 520, and other portions of DAIA 200. The floating piston 605 may comprise surfaces 606 operable for sealingly engaging the shaft 270 and the upper housing 260, such as may reduce or prevent fluid communication between the upper annulus portion 611 and the lower annulus portion 612. For example, the outer surfaces 606 may comprise a finish that is sufficiently smooth to form a metal-to-metal seal against the shaft 270 and the upper housing 260. The floating piston 605 may also comprise one or more O-rings and/or other fluid-sealing elements 607, such as may reduce or prevent fluid communication across the contact areas between the floating piston 606, the shaft 270, and the upper housing 260.
Also during impact operations, as the upper DAIA section 230 moves uphole relative to the lower DAIA section 235, a portion of the shaft 270 is extended from within the upper DAIA section 230, thus forming one or more open spaces or cavities within upper DAIA section 230. Because the DAIA 200 is filled with internal fluid, as the upper DAIA section 230 moves uphole, the volumetric area of the shaft 270 being extended from the upper DAIA section 230 is continuously replaced by internal fluid being redistributed within the upper DAIA section 230. For example, some of the internal fluid in the lower annulus portion 612 of the pressure compensation annulus 610 is drawn into the central bore 271 through the shaft ports 615 and communicated uphole to the upper portion of the upper DAIA section 230. Simultaneously, the wellbore fluid may be drawn into the upper annulus portion 611 of the pressure compensation annulus 610 through the housing ports 620 to replace the redistributed internal fluid in the lower annulus portion 612. As the volume of the upper annulus portion 611 increases and the volume of the lower annulus portion 612 decreases, the floating piston 605 moves downhole with respect to the lower housing 260.
During impact operations, a relatively large diameter and/or cross-sectional area (i.e., flow area) of the housing port 620 may allow for the wellbore fluid surrounding the DAIA 200 to be drawn into the upper annulus portion 611 of the pressure compensation annulus 610 at a high flow rate. The high flow rate may allow the upper DAIA section 230 to move at a high rate of speed with respect to the lower DAIA section 235 to create an impact between the impact features 490, 495, to possibly free the stuck tool string 110. For example, the diameter of the housing port 620 may be about 0.5 in (about 12.7 mm) and the cross-sectional area of the housing port 620 may be about 0.196 in2 (about 127 mm2).
However, under certain conditions when high tensile forces are applied to the tool string 110 via the conveyance means 160, such as when DAIA 200 is in the “high-force” configuration described above, the high rate of speed of the upper DAIA section 230 may not be desirable. For example, a high tensile force may be operable to free a stuck tool string 110 without triggering the DAIA 200. If such high tensile force imparted by the tensioning device 170 to the DAIA 200 exceeds a predetermined threshold and does not free the stuck tool string 110, the DAIA 200 may then be triggered to create an impact to generate additional tensile force to free the stuck tool string 110. However, when high tensile forces are applied to the DAIA 200, the upper DAIA section 230 may move uphole at speeds that may generate excessive stress forces in the DAIA 200 and/or other portions of the tool string 110 during the impact and, therefore, damage the DAIA 200 and/or other portions of the tool string 110.
By restricting or otherwise controlling the flow rate at which the wellbore fluid is introduced into the upper annulus portion 611, the force of impact between the impact feature 490 of the upper DAIA section 230 and the corresponding other impact feature 495 of the lower DAIA section 235 may be reduced and/or controlled. As stated above, the rate of flow of the wellbore fluid into the upper annulus portion 611 of the pressure compensation annulus 610 through the housing ports 620 may be controlled with the flow restrictor 630.
The orifice 636 may have a predetermined cross-sectional area or an adjustable cross-sectional area. For example, the flow restrictor 630 may comprise an adjustable plunger or a needle (not shown) extending along or into the orifice 636, wherein the needle or the plunger may be operable to progressively open or close the cross-sectional area of the orifice 636. The flow restrictor 630 may comprise a single orifice 636, such as shown in
Flow restrictors 630 comprising different sizes and/or configurations may be utilized in the DAIA 200 based on different operational parameters. For example, flow restrictors 630 having different orifice diameters 637 and/or cross-sectional areas may be used interchangeably to reduce the magnitude of the impact to below a predetermined threshold, to reduce the rate of relative axial movement between the upper housing 260 and the shaft 270 to below a predetermined threshold, and/or to reduce a maximum rate of fluid flow from the wellbore 120 to the upper annulus portion 611. These considerations may depend on operational parameters, such as the structural strength and/or impact resistance of the tool string 110 and/or the tensile/impact forces imparted by the tensioning device 170. Because the rate of flow through the orifice 636 is proportional to the pressure differential between the wellbore 120 and the upper annulus portion 611, the fluid pressures generated within the pressure compensation annulus 610 during operations may also be considered in selecting a flow restrictor 630. For example, the diameter 637 of the orifice 636 may be about 1/16 in (about 1.6 mm), about ⅛ in (about 3.2 mm), about ¼ in (about 6.4 mm), or about ⅜ in (about 9.5 mm), and the cross-sectional area of the orifice 636 may be about 0.003 in2 (about 1.98 mm2), about 0.012 in2 (about 7.92 mm2), about 0.049 in2 (about 31.7 mm2), or about 0.110 in2 (about 71.2 mm2). However, other dimensions are also within the scope of the present disclosure.
As a rate of flow through an opening may be proportional to the diameter and/or cross-sectional area of such opening, the rate at which wellbore fluid flows into the upper annulus portion 611 may also be reduced by appropriate selection diameter 637 of the orifice 636 and/or other parameter of the flow restrictor 630. Therefore, since the internal fluid and the wellbore fluid is substantially incompressible, reducing the rate of flow of the wellbore fluid into the DAIA 200 may reduce the rate of speed at which the upper DAIA section 230 moves with respect to the lower DAIA section 235, which may, in turn, reduce the magnitude of the impact on the tool string 110 and the stresses generated in the tool string 110 during the impact.
Thus, the present disclosure introduces conveying a tool string within a wellbore extending between a wellsite surface and a subterranean formation, wherein the tool string comprises: a first portion comprising a first electrical conductor in electrical communication with surface equipment disposed at the wellsite surface; a second portion; and a downhole-adjusting impact apparatus (DAIA) interposing the first and second portions and comprising a second electrical conductor in electrical communication with the first electrical conductor, wherein the DAIA is operable to impart, to the second portion of the tool string, a selective one of first and second different impact forces each corresponding to one of detection and non-detection of the electrical characteristic by the DAIA. At least one of the surface equipment and the DAIA is then operated to impart a selective one of the first and second impact forces to the second portion of the tool string.
Operating at least one of the surface equipment and the DAIA to impart a selective one of the first and second impact forces to the second portion of the tool string may comprise: operating the surface equipment to apply the electrical characteristic to the first and second electrical conductors, thereby selecting which one of the first and second impact forces will be imparted by the DAIA to the second portion of the tool string; and operating the surface equipment to impart a tensile load to the first portion of the tool string, and thus to the DAIA, wherein the tensile load is not substantially less than the selected one of the first and second impact forces. Operating the surface equipment to apply the electrical characteristic to the first and second electrical conductors may comprise establishing a voltage and/or current detectable by the DAIA on the second electrical conductor.
Furthermore, operating at least one of the surface equipment and the DAIA to impact a selective one of the first and second impact forces to the second portion of the tool string may comprise operating the at least one of the surface equipment and the DAIA to impart to the second portion of the tool string a smaller one of the first and second impact forces, such as the “low-force” impact described above and corresponding to
Such methods may further comprise, before conveying the tool string within the wellbore, externally accessing an adjuster internal to the DAIA to rotate the adjuster relative to an external housing of the DAIA and thereby adjust one but not both of the first and second impact forces.
Such methods may further comprise, before conveying the tool string within the wellbore, externally accessing each of first and second adjusters internal to the DAIA to rotate the first and second adjusters relative to other components of the DAIA and thereby adjust the first and second impact forces and/or a quantitative (e.g., magnitude) difference between the first and second impact forces.
Referring to
As above, the DAIA 200 is operable to impart, to the second portion 150 of the tool string 110, a selective one of: a first impact force when the electrical characteristic is detected by the detector 240 of the DAIA 200 and the tensioning device 175 is applying a first tensile force to the tool string 110; and a second impact force when the electrical characteristic is not detected (or its absence is detected) by the detector 240 and the surface equipment is applying a second tensile force to the tool string 110. As described above, the first impact force (e.g., the above-described “low-force”) may be substantially less in magnitude than the second impact force (e.g., the above-described “high-force”), and the first tensile force may similarly be substantially less than the second tensile force.
The method (835) further comprises operating at least one of the surface equipment 170 and the DAIA 200 to impart (845) an intervening impact force to the second portion 150 of the tool string 110 by: confirming that the electrical characteristic is not existent on (and/or at least not being applied to and/or detected on) electrical conductors of the tool string 110 and/or the DAIA 200; then applying an intervening tensile force to the tool string 110, wherein the intervening tensile force is substantially greater than the first tensile force and substantially less than the second tensile force; and then applying the electrical characteristic to the electrical conductors of the tool string 110 and/or the DAIA 200, wherein the intervening impact force is substantially greater than the first impact force and substantially less than the second impact force. When performing the method (835), the first impact force and the first tensile force may be substantially similar in magnitude, the second impact force and the second tensile force may be substantially similar in magnitude, and the intervening impact force and the intervening tensile force may be substantially similar in magnitude.
The method (835) may further comprise, before operating the surface equipment 170 and/or the DAIA 200 to impart (845) the intervening impact force to the second portion 150 of the tool string 110, operating the surface equipment 170 and/or the DAIA 200 to impart (850) the first impact force to the second portion 150 of the tool string 110 by: applying the electrical characteristic to the electrical conductors of the tool string 110 and/or the DAIA 200; and then applying the first tensile force to the tool string 110.
The method (835) may further comprise, after operating the surface equipment 170 and/or the DAIA 200 to impart (845) the intervening impact force to the second portion 150 of the tool string 110, operating the surface equipment 170 and/or the DAIA 200 to impart (855) the second impact force to the second portion 150 of the tool string 110 by: confirming that the electrical characteristic is not being applied to the electrical conductors of the tool string 110 and/or the DAIA 200; and then applying the second tensile force to the tool string 110.
The method (900) comprises conveying (910) a tool string 110 within a wellbore 120 and operating (920) an impact jar 200 included within the tool 110 to impart an impact to the downhole portion 150 of the tool string 110. The tool string 110 may comprise the impact jar 200 coupled between uphole and downhole portions 140, 150 of the tool string 100. The impact jar 200 may comprise a housing 260 having one or more ports 620 therein, a shaft 270 extending within at least a portion of the housing 260, and one or more flow restrictors 630 each operable to reduce a flow area of the corresponding ports 620. The housing 260 and the shaft 270 may move axially relative to each other. The ports 620 may each fluidly connect a space external to the housing with an annulus 610 defined between the housing 260 and the shaft 270.
The method (900) may further comprise selecting (902) the flow restrictors 630 and assembling (903) the flow restrictors 630 to the impact jar 200 prior to conveying (910) the tool string 110 within the wellbore 120 and operating (920) the impact jar to impart the impact to the downhole portion 150 of the tool string 110.
As disclosed above, the flow restrictors 630 may each comprise a passage 636 extending between the space 120 external to the housing 260 and the annulus 610, wherein the passage 636 of each of the plurality of flow restrictors 630 may have a different size relative to the passages 636 of the others of the plurality of flow restrictors 630. Therefore, selecting (902) the flow restrictor 630 may comprise selecting (904) the flow restrictors 630 from a plurality of flow restrictors 630 of different sizes and/or other characteristics.
Selecting (904) the flow restrictors 630 may be based on reducing a magnitude of the impact to below a predetermined threshold, reducing a rate of relative axial movement between the housing 260 and the shaft 270 to below a predetermined threshold, and/or reducing a maximum rate of fluid flow from the wellbore 120 to the annulus 610 through the port 620. For example, selecting (904) the flow restrictors 630 may include selecting from a plurality of flow restrictors 630 comprising a first flow restrictor having a first flow area of about 0.003 in2 (about 1.98 mm2), a second flow restrictor having a second flow area of about 0.012 in2 (about 7.92 mm2), a third flow restrictor having a third flow area of about 0.049 in2 (about 31.7 mm2), or a fourth flow restrictor having a fourth flow area of about 0.110 in2 (about 71.2 mm2). Similarly, selecting (904) the flow restrictors 630 may include selecting from a plurality of flow restrictors 630 comprising a first flow restrictor having a first passage with a first diameter of about 1/16 in (about 1.6 mm), a second flow restrictor having a second passage with a second diameter of about ⅛ in (about 3.2 mm), a third flow restrictor having a third passage with a third diameter of about ¼ in (about 6.4 mm), or a fourth flow restrictor having a fourth passage with a fourth diameter of about ⅜ in (about 9.5 mm). However, these are merely examples, and other flow restrictors are also within the scope of the present disclosure.
In the method (900), operating (920) the impact jar 200 to impart the impact to the downhole portion 150 of the tool string 110 may comprise applying (930) a predetermined tension to the impact jar 200, such as to move the housing 260 and the shaft 270 axially relative to each other, and drawing (940) fluid from the wellbore 120 into the annulus 610 through the one or more flow restrictors 630.
In view of all of the entirety of the present disclosure, including
The housing may be substantially tubular.
The port may permit equalization of a first pressure of non-wellbore fluid within the impact jar with a second pressure of wellbore fluid external to the housing.
The apparatus may further comprise a piston slidably disposed within the annulus to define a first annulus portion and a second annulus portion. The piston may fluidly isolate the first annulus portion from the second annulus portion, and the port may fluidly connect the space external to the housing with the first annulus portion. The first annulus portion may comprise wellbore fluid at a first pressure, the second annulus portion may comprise non-wellbore fluid at a second pressure, and the port and the piston may collectively permit equalization of the first and second pressures.
The flow area may be a first flow area, the flow restrictor may comprise a passage extending between the annulus and the space external to the housing, and the passage may have a second flow area that is substantially smaller than the first flow area. The first flow area may be about 0.196 in2 (about 127 mm2). The second flow area may be selected from the group consisting of: about 0.003 in2 (about 1.98 mm2); about 0.012 in2 (about 7.92 mm2); about 0.049 in2 (about 31.7 mm2); and about 0.110 in2 (about 71.2 mm2). The second flow area may be selected from the group consisting of: about 0.003 in2 (about 1.98 mm2); about 0.012 in2 (about 7.92 mm2); about 0.049 in2 (about 31.7 mm2); and about 0.110 in2 (about 71.2 mm2). The port may have a first diameter of about 0.5 in (about 12.7 mm), and the passage may have a second diameter selected from the group consisting of: about 1/16 in (about 1.6 mm); about ⅛ in (about 3.2 mm); about ¼ in (about 6.4 mm); and about ⅜ in (about 9.5 mm).
The port and the flow restrictor may be threadedly engaged.
The shaft may comprise a first impact feature, the housing may comprise a second impact feature, and the first and second impact features may impact in response to a tensile force applied to the impact jar exceeding a predetermined threshold.
The port may comprise a plurality of ports, and the flow restrictor may comprise a plurality of flow restrictors each reducing a flow area of a corresponding one of the plurality of ports.
The housing may comprise a longitudinal bore, the port may fluidly connect the space external to the housing with the longitudinal bore, and the shaft may be disposed within the housing to form the annulus around the shaft within the longitudinal bore. The apparatus may further comprise a piston slidably disposed within the annulus to define a first annulus portion and a second annulus portion, wherein: the piston may fluidly isolate the first annulus portion from the second annulus portion; the port may fluidly connect the space external to the housing with the first annulus portion; the longitudinal bore may be a first longitudinal bore; and the shaft may comprise a second longitudinal bore and a radial bore extending between the second longitudinal bore and the second annulus portion.
The flow restrictor may be operable to reduce a rate of fluid flow through the port. The rate of fluid flow through the port may be dependent upon a difference in a first fluid pressure within the space external to the housing and a second fluid pressure within the annulus.
The space external to the housing may comprise a portion of a wellbore in which the impact jar is deployed.
The present disclosure also introduces a method comprising: conveying a tool string within a wellbore, wherein an impact jar coupled between uphole and downhole portions of the tool string comprises: a housing having a port therein; a shaft extending within at least a portion of the housing, wherein the housing and the shaft move axially relative to each other, and wherein the port fluidly connects a space external to the housing with an annulus defined between the housing and the shaft; and a flow restrictor reducing a flow area of the port; and operating the impact jar to impart an impact to the downhole portion of the tool string.
The method may further comprise, prior to conveying the tool string within the wellbore and operating the impact jar to impart the impact to the downhole portion of the tool string: selecting the flow restrictor; and assembling the flow restrictor to the impact jar. The flow restrictor may comprise a passage extending between the space external to the housing and the annulus, wherein selecting the flow restrictor may comprise selecting the flow restrictor from a plurality of flow restrictors, and wherein the passage of each of the plurality of flow restrictors may have a different size relative to the passages of the others of the plurality of flow restrictors. Selecting the flow restrictor may be based on reducing a magnitude of the impact to below a predetermined threshold. Selecting the flow restrictor may be based on reducing a rate of relative axial movement between the housing and the shaft to below a predetermined threshold. Selecting the flow restrictor may be based on reducing a maximum rate of fluid flow from the wellbore to the annulus through the port. The plurality of flow restrictors may comprise: a first flow restrictor having a first flow area of about 0.003 in2 (about 1.98 mm2); a second flow restrictor having a second flow area of about 0.012 in2 (about 7.92 mm2); a third flow restrictor having a third flow area of about 0.049 in2 (about 31.7 mm2); and a fourth flow restrictor having a fourth flow area of about 0.110 in2 (about 71.2 mm2). The plurality of flow restrictors may comprise: a first flow restrictor having a first passage with a first diameter of about 1/16 in (about 1.6 mm); a second flow restrictor having a second passage with a second diameter of about ⅛ in (about 3.2 mm); a third flow restrictor having a third passage with a third diameter of about ¼ in (about 6.4 mm); and a fourth flow restrictor having a fourth passage with a fourth diameter of about ⅜ in (about 9.5 mm).
Operating the impact jar to impart the impact to the downhole portion of the tool string may comprise: applying a predetermined tension to the impact jar to move the housing and the shaft axially relative to each other; and drawing fluid from the wellbore into the annulus through the flow restrictor.
The foregoing outlines features of several embodiments so that a person having ordinary skill in the art may better understand the aspects of the present disclosure. A person having ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. A person having ordinary skill in the art should also realize that such equivalent constructions do not depart from the scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.
The Abstract at the end of this disclosure is provided to comply with 37 C.F.R. §1.72(b) to allow the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.
