WO2020076310A1 - Outil de fond de trou avec zone d'écoulement interne réglable de l'extérieur - Google Patents

Outil de fond de trou avec zone d'écoulement interne réglable de l'extérieur Download PDF

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Publication number
WO2020076310A1
WO2020076310A1 PCT/US2018/055061 US2018055061W WO2020076310A1 WO 2020076310 A1 WO2020076310 A1 WO 2020076310A1 US 2018055061 W US2018055061 W US 2018055061W WO 2020076310 A1 WO2020076310 A1 WO 2020076310A1
Authority
WO
WIPO (PCT)
Prior art keywords
nozzle
mandrel
flow path
outer sub
downhole tool
Prior art date
Application number
PCT/US2018/055061
Other languages
English (en)
Other versions
WO2020076310A8 (fr
Inventor
Mark Adam
Original Assignee
Turbo Drill Industries, Inc.
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Turbo Drill Industries, Inc. filed Critical Turbo Drill Industries, Inc.
Priority to PCT/US2018/055061 priority Critical patent/WO2020076310A1/fr
Publication of WO2020076310A1 publication Critical patent/WO2020076310A1/fr
Publication of WO2020076310A8 publication Critical patent/WO2020076310A8/fr

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
    • E21B41/0078—Nozzles used in boreholes
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/06—Valve arrangements for boreholes or wells in wells

Definitions

  • the present disclosure relates to downhole tools, and specifically to fluid actuated downhole tools.
  • Some downhole drilling tools contain an outer housing with a mandrel positioned therein.
  • the mandrel may be tubular and may define a mandrel bore.
  • the mandrel bore may define a bore fluid path allowing fluid flow from drilling pumps to pass through downhole drilling tool.
  • the annular area formed between the outer surface of the mandrel and the inner surface of the outer housing may define an annular fluid path.
  • Some downhole tools may contain both a bore fluid path and an annular fluid path. It may be desirable to control or limit fluid flow from the bore fluid path to the annular fluid path or vice versa.
  • One method of achieving this is to install nozzles in a barrier portion between the bore fluid path and the annular fluid path, such that the desired total flow area (TFA) between bore fluid path and annular fluid path may be configured during downhole tool assembly.
  • the nozzles may be positioned for access should the downhole tool set-up change, such as to require a different TFA, a tubular connection between the outer sub and another tubular of the tool string may be broken out allowing access such that the nozzles may be removed and replaced.
  • the present disclosure provides for a downhole tool.
  • the downhole tool may include an outer sub, the outer sub being tubular.
  • the downhole tool may include a mandrel.
  • the mandrel may be tubular and may be positioned within the outer sub.
  • the interior of the mandrel may define a bore flow path.
  • the annular space between the mandrel and the outer sub may define at least part of an annular flow path.
  • the mandrel may include at least one nozzle port formed in the mandrel fluidly coupling the bore flow path to the annular flow path.
  • the downhole tool may include a nozzle mechanically coupled to the nozzle port of the mandrel.
  • the nozzle may include a nozzle body having a flow path formed therein to fluidly couple the bore flow path to the annular flow path through the nozzle.
  • the present disclosure also provides for a downhole apparatus.
  • the downhole apparatus may include a downhole tool.
  • the downhole tool may include an outer sub, the outer sub being tubular.
  • the downhole tool may include a mandrel.
  • the mandrel may be tubular and may be positioned within the outer sub.
  • the interior of the mandrel may define a bore flow path.
  • the annular space between the mandrel and the outer sub may define at least part of an annular flow path.
  • the mandrel may include at least one nozzle port formed in the mandrel fluidly coupling the bore flow path to the annular flow path.
  • the downhole tool may include a nozzle mechanically coupled to the nozzle port of the mandrel.
  • the nozzle may include a nozzle body having a flow path formed therein to fluidly couple the bore flow path to the annular flow path through the nozzle.
  • the downhole apparatus may include a downhole tool control apparatus adapted to selectively open or close an unrestricted flow path from the bore flow path to the annular flow path.
  • the present disclosure also provides for a method for adjusting the total flow area between a bore fluid path and an annular flow path of a downhole tool.
  • the method may include providing the downhole tool.
  • the downhole tool may include an outer sub, the outer sub being tubular.
  • the outer sub may have an outer sub port formed therein.
  • the outer sub port may extend through the wall of the outer sub.
  • the downhole tool may include an outer plug mechanically coupled to the outer sub port.
  • the outer plug may be removeable and may fluidly seal the outer sub port.
  • the downhole tool may include a mandrel being tubular and positioned within the outer sub. The interior of the mandrel may define a bore flow path. The annular space between the mandrel and the outer sub may define at least part of the annular flow path.
  • the mandrel may have at least one nozzle port formed in the mandrel fluidly coupling the bore flow path to the annular flow path. The nozzle port may be aligned with the outer sub port.
  • the downhole tool may include a nozzle mechanically coupled to the nozzle port of the mandrel.
  • the nozzle may include a nozzle body having a flow path formed therein to fluidly couple the bore flow path to the annular flow path through the nozzle.
  • the method may further include removing the outer sub plug from the outer sub port, removing the nozzle from the nozzle port of the mandrel through the outer sub port, selecting a second nozzle having a nozzle flow path of a different flow area than the first nozzle, installing the second nozzle to the nozzle port of the mandrel through the outer sub port, and installing the outer sub plug to the outer sub port
  • FIG. 1 depicts a schematic view of a wellbore having a downhole tool positioned therein consistent with at least one embodiment of the present disclosure.
  • FIG. 2 depicts a cross section view of a downhole tool consistent with at least one embodiment of the present disclosure.
  • FIG. 3 depicts a cross section view of the downhole tool of FIG. 2 taken at line 3-3.
  • FIG. 4A depicts a perspective view of a mandrel of a downhole tool consistent with at least one embodiment of the present disclosure.
  • FIG. 4B depicts a cross section view of the mandrel of FIG. 4 A.
  • FIG. 4C depicts a cross section view of the mandrel of FIG. 4 A taken at line 4C-4C.
  • FIG. 5 A depicts a perspective cross section view of an outer sub of a downhole tool consistent with at least one embodiment of the present disclosure.
  • FIG. 5B depicts a cross section view of the outer sub of FIG. 5 A.
  • FIG. 5C depicts a cross section view of the outer sub of FIG. 5A taken at line 5C-5C.
  • FIG. 6 depicts a perspective view of a nozzle consistent with at least one embodiment of the present disclosure.
  • FIG. 6A depicts a side elevation view of the nozzle of FIG. 6.
  • FIG. 6B depicts a cross section view of the nozzle of FIG. 6 A taken at line 6B-6B.
  • FIG. 6C depicts a cross section view of the nozzle of FIG. 6A taken at line 6C-6C.
  • FIG. 7 depicts a perspective view of a blank nozzle consistent with at least one embodiment of the present disclosure.
  • FIG. 7A depicts a side elevation view of the nozzle of FIG. 7.
  • FIG. 7B depicts a cross section view of the nozzle of FIG. 7 A taken at line 7B-7B.
  • FIG. 7C depicts a cross section view of the nozzle of FIG. 7A taken at line 7C-7C.
  • FIGS. 8A-8E depict a nozzle change operation consistent with at least one embodiment of the present disclosure.
  • FIGS. 9A and 9B depict cross section views of a downhole tool consistent with at least one embodiment of the present disclosure.
  • FIGS. 10A and 10B depict cross section views of a downhole tool consistent with at least one embodiment of the present disclosure.
  • FIG. 1 depicts drill string 10 positioned within wellbore 20.
  • Drill string 10 may include downhole tool 100.
  • Drill string 10 may be constructed from a plurality of tubular components that together define drill string bore 12.
  • Wellbore annulus 23 may be defined as the annular space within wellbore 20 about drill string 10.
  • One or more pumps 14 may be positioned to pump fluid through drill string bore 12.
  • one or more pumps 14 may be adapted to provide fluid flow through drill string bore 12.
  • Pumps 14 may be controlled by controller 18 so as to provide different flow rates of fluid through drill string bore 12.
  • “up”,“above”, and“upper” denote a direction within wellbore 20 toward the surface 22
  • “down”,“below”, and“lower” denote a direction within wellbore 20 away from the surface 22.
  • FIG. 1 further depicts downhole tool 100.
  • downhole tool 100 may be any tool, collar, or other component of drill string 10 that includes a bore flow path and an annular flow path as further described below.
  • downhole tool 100 may be a fluid-actuated or flow-controlled tool lOOa configured such that flow within the bore flow path and annular flow path may modify or control the operation of downhole tool 100.
  • Non-limiting examples of downhole tool 100 may be a reamer, underreamer, packer, downhole motor, stabilizer, centralizer, pulse tool, vibration tool, jarring tool, or any other downhole tool.
  • downhole tool 100 may be positioned at any point along drill string 10. Downhole tool 100 may be positioned within drill string 10 proximate to downhole tool control apparatus 30 and may be operatively coupled to downhole tool control apparatus 30. In some embodiments, downhole tool 100 may be a fluid-actuated device to which downhole tool control apparatus 30 controls the flow of fluid. In some embodiments, downhole tool control apparatus 30 may be used to change one or more operational states or parameters of downhole tool 100 by modifying the fluid flow through the bore flow path and annular flow path of downhole tool 100. In some embodiments, downhole tool control apparatus 30 may be a drop-ball seat or may include an actuator or indexer as further described herein below.
  • downhole tool control apparatus 30 may cause downhole tool 100 to change between operating modes, such as from a first operating mode to a second operating mode. Downhole tool 100 may initially be in the first operating mode and then be selectively changed to the second operating mode by the operation of downhole tool control apparatus 30.
  • the first operating mode and second operating mode may, for example, correspond to an activation or deactivation of downhole tool 100.
  • the first operating mode and second operating mode may correspond to different positions of downhole tool 100.
  • downhole tool control apparatus 30 may be omitted such that fluid flow through the bore flow path and the annular flow path are not selectively regulated during use, i.e. such that the amount of fluid flow through the bore flow path and the annular flow path is controlled only by the characteristics of the fluid, flow rate of the fluid, and geometry of downhole tool 100 as further described herein below.
  • drill string 10 may include one or more additional tools below downhole tool 100 including, for example and without limitation bottom hole assembly (BHA) 17.
  • BHA 17 may include any tools for use in a wellbore.
  • BHA 17 may include, for example and without limitation, one or more of drill bit 16, MWD system 19, downhole motor 21, rotary steerable system 24, or other downhole tools.
  • downhole tool control apparatus 30, downhole tool 100, or both may be considered part of BHA 17 or positioned within BHA 17.
  • downhole tool control apparatus 30, downhole tool 100, or both may be considered positioned within drill string 10 substantially above the BHA 17.
  • downhole tool 100 may include outer sub 101.
  • Outer sub 101 may be tubular and may be used to couple downhole tool 100 to the rest of drill string 10 above downhole tool 100, depicted as tubular lOa, by, for example and without limitation, upper coupler 103.
  • outer sub 101 may mechanically couple to outer housing 105 of downhole tool 100 by, for example and without limitation, lower coupler 107 located at the lower end of outer sub 101 and may be used to couple to drill string 10 below downhole tool 100 or other tubular components of downhole tool 100.
  • Outer housing 105 may be tubular and may be used to, for example and without limitation, support other components of downhole tool 100.
  • Upper coupler 103 and lower coupler 107 may be, for example and without limitation, threaded couplers as typically used to mechanically couple the tubular members of drill string 10.
  • downhole tool 100 may include mandrel 111.
  • Mandrel 111 may be tubular and may be positioned within outer sub 101 and outer housing 105 of downhole tool
  • mandrel 111 may define bore flow path 113 of downhole tool 100. Bore flow path 113 connects to drill string bore 12.
  • annular flow path 115 may be defined between the exterior of mandrel 111 and the interior of outer sub 101 and outer housing 105 of downhole tool 100.
  • mandrel 111 may include flange 117 positioned at the upper end of mandrel 111. In some embodiments, flange 117 may be of a larger diameter than the rest of mandrel 111 such that flange 117 abuts the inner surface of outer sub
  • one or more seals 119 may be positioned between flange 117 and outer sub 101 to, for example and without limitation, fluidly isolate drill string bore 12 and bore flow path 113 from annular flow path 115 at the interface between flange 117 and outer sub 101.
  • outer sub 101 may include mandrel hanger 121.
  • Mandrel hanger 121 may be a lip or ridge formed on the inner surface of outer sub 101 such that flange 117 of mandrel 111 may rest on mandrel hanger 121 when mandrel 111 is positioned within outer sub 101.
  • tubular member lOa may, when positioned within upper coupler 103, abut mandrel 111 such that tubular member lOa may at least partially retain mandrel 111 against mandrel hanger 121.
  • spacer 123 may be positioned between mandrel hanger 121 and flange 117 such that mandrel 111 is retained against mandrel hanger 121 when tubular member lOa is fully engaged to outer sub 101.
  • Spacer 123 may be a tubular member having a known length adapted to fit within upper coupler 103 to headspace the connection between mandrel hanger 121 and flange 117.
  • one or more nozzle ports 125 may be formed in mandrel 111.
  • Nozzle ports 125 may provide fluid connection between bore flow path 113 and annular flow path 115 such that fluid provided to downhole tool 100 through drill string bore 12 may flow through both bore flow path 113 and annular flow path 115 as described further below.
  • nozzle ports 125 may be formed as apertures through the wall of mandrel 111.
  • Nozzle ports 125 may be formed orthogonally to the outer surface of mandrel 111 or may be formed at a non-orthogonal angle thereto.
  • each nozzle port 125 may be adapted to receive a nozzle 127.
  • Nozzles 127 may mechanically couple to a respective nozzle port 125 by, for example and without limitation, a threaded connection. Nozzles 127 may, as discussed further herein below, be used to control the cross-sectional flow area of each nozzle port 125 and therefore may control the effective total flow area (TFA) of annular flow path 115, i.e. the cross-sectional flow area available to fluid flowing through annular flow path 115, for fluid flow from bore flow path 113 to annular flow path 115. In some embodiments, TFA may, for example and without limitation, determine a percentage flow split between bore flow path 113 and annular flow path 115, which may alter or define a desired pressure differential between bore flow path 113 and annular flow path 115. In some embodiments, one or more nozzle seals 129 may be positioned between nozzles 127 and mandrel 111 to fluidly seal the interface between nozzles 127 and mandrel 111.
  • outer sub 101 may include one or more outer sub ports 131 such that each nozzle port 125 has a corresponding outer sub port 131 aligned therewith when mandrel 111 is installed into outer sub 101 as depicted in FIGS. 2, 3.
  • outer sub ports 131 may be adapted to receive outer plug 133.
  • Outer plug 133 may be a generally cylindrical, solid body adapted to couple to outer sub ports 131.
  • Each outer plug 133 may mechanically couple to a respective outer sub port 131 by, for example and without limitation, a threaded connection.
  • outer plug 133 may include plug drive adapter 134 positioned on the outer surface of outer plug 133.
  • Plug drive adapter 134 may include one or more features adapted to allow nozzle outer plug 133 to be installed or removed from outer sub 101.
  • plug drive adapter 134 may include one or more bosses or recesses adapted to operatively connect to a tool to allow outer plug 133 to be rotated relative to outer sub 101 such as, for example and without limitation, one or more slots, polygonal bosses, or shaped recesses (such as hexagonal recesses depicted in FIGS. 2, 3) adapted to couple to a corresponding tool.
  • Outer plugs 133 may, for example and without limitation, fluidly seal annular flow path 115 from wellbore annulus 23.
  • outer plugs 133 may be removed from outer sub 101 to allow access to nozzles 127 through outer sub ports 131 without otherwise disassembling downhole tool 100.
  • mandrel 111 may include one or more alignment splines 135. Each alignment spline 135 may be a radial extension from the outer surface of mandrel 111.
  • outer sub 101 may include one or more alignment slots 137 corresponding with alignment splines 135 of mandrel 111. When assembled, as depicted in FIG. 3, alignment splines 135 may fit within alignment slots 137 of outer sub 101 such that nozzle ports 125 and outer sub ports 131 remain in alignment when mandrel 111 is assembled to outer sub 101.
  • FIGS. 6 and 6A-6C depict nozzle 127.
  • Nozzle 127 may include nozzle body 139.
  • Nozzle body 139 may include nozzle shank 141 and nozzle head 143.
  • nozzle shank 141 may include nozzle coupler 145 adapted to couple to nozzle ports 125 of mandrel 111.
  • Nozzle coupler 145 may, in some embodiments, be an external thread adapted to engage a corresponding internal thread of nozzle ports 125.
  • nozzle body 139 may include nozzle drive adapter 144 positioned on nozzle head 143 opposite nozzle shank 141.
  • Nozzle drive adapter 144 may include one or more features adapted to allow nozzle 127 to be installed or removed from mandrel 111 by the application of torque from a tool such as a wrench.
  • nozzle drive adapter 144 may include one or more bosses or recesses adapted to operatively connect to a tool to allow nozzle 127 to be rotated relative to mandrel 111 such as, for example and without limitation, one or more slots, polygonal bosses (such as a square or hexagonal head as depicted in FIG. 6), or shaped recesses adapted to couple to a corresponding tool.
  • Nozzle head 143 may have a larger diameter than nozzle shank 141 such that underside 147 of nozzle head 143 proximate nozzle shank 141 may abut mandrel 111 when nozzle 127 is fully installed to mandrel 111.
  • one or more nozzle seals 129 may be positioned between underside 147 of nozzle head 143 and mandrel 111 when nozzle 127 is fully installed to mandrel 111.
  • nozzle head 143 When installed to mandrel 111, as depicted in FIG. 3, nozzle head 143 is positioned within annular flow path 115 and end l4la of nozzle shank 141 is exposed to bore flow path 113.
  • nozzle 127 may include one or more flow paths formed therein to allow fluid to flow from bore flow path 113 to annular flow path 115 when downhole tool 100 is in operation.
  • nozzle shank 141 may include nozzle entry port 149 formed longitudinally therethrough.
  • nozzle head 143 may include one or more nozzle exit ports 151 formed therein.
  • nozzle exit ports 151 may extend longitudinally, radially, or a combination thereof through nozzle head 143. Nozzle exit ports 151 may intersect and be fluidly coupled to nozzle entry port 149 such that fluid may flow from bore flow path 113 to annular flow path 115 via nozzle entry port 149 and nozzle exit ports 151.
  • Nozzle exit ports 151 may be formed in any pattern in nozzle head 143.
  • two nozzle exit ports 151 may be formed in a cruciform pattern radially through nozzle head 143.
  • fluid exiting nozzle 127 may be directed radially to, for example and without limitation, reduce risk of erosion or other damage to components of downhole tool 100 when compared with a longitudinal nozzle exit port 151.
  • nozzle 127 may be formed such that the cross-sectional flow area through nozzle 127 is known.
  • nozzle entry port 149 may be formed at least partially at a desired diameter such that the cross-sectional area, depicted as Ao, available to fluid flow through nozzle 127 is known.
  • nozzle exit ports 151 may be formed such that the total flow area through nozzle exit ports 151 is larger than Ao, thereby reducing the speed of fluid as it exits through nozzle exit ports 151 into annular flow path 115.
  • nozzles 127 having various total flow areas may be manufactured and provided to an operator of downhole tool 100.
  • each nozzle 127 may include a marking, such as headstamp 153 as depicted in FIG. 6, to indicate the total flow area of the nozzle 127.
  • headstamp 153 as depicted in FIG. 6, to indicate the total flow area of the nozzle 127.
  • nozzles 127 may be provided having multiple flow areas separated by known increments. For example and without limitation, nozzle flow areas may be provided and manufactured in 1/32” increments.
  • headstamps 153 may indicate the flow area of the respective nozzle 127 such that the nozzle depicted in FIG. 6 would have a nozzle entry port 149 of a diameter of 12/32”, resulting in a flow area of approximately 0.110 in 2 .
  • the total flow area between bore flow path 113 and annular flow path 115 may be specifically set.
  • blank nozzle 127 may be utilized. Blank nozzle 127’ may be formed exactly like nozzle 127 described above, however no flow path is formed therethrough. The flow area of blank nozzle 127’ may therefore be described as 0, and flow through nozzle port 125 into which blank nozzle 127’ is installed is zero.
  • the desired total flow area of annular flow path 115 may need to be modified from the original configuration. Such a modification may be necessitated by changing downhole conditions, parameters of the fluid flowing through downhole tool 100, observed issues with the operation of downhole tool 100, or to change one or more aspects of the functionality of downhole tool 100. In such a circumstance, the total flow area of annular flow path 115 may be modified by the replacement of one or more nozzles 127 of downhole tool. In some embodiments, the replacement of nozzles 127 may be accomplished without the need to break out any tubular connections of drill string 10.
  • downhole tool 100 is initially configured with nozzle 127 positioned in nozzle port 125 of mandrel 111.
  • Outer plug 133 is positioned within outer sub port 131 of outer sub 101.
  • outer plug 133 is first removed from outer sub 101 as depicted in FIG. 8B.
  • Outer plug 133 may be removed, for example and without limitation, by rotating outer plug 133 relative to outer sub 101 using plug drive adapter 134 and a corresponding tool from the outside of downhole tool 100.
  • plug drive adapter 134 Once outer plug 133 is removed, nozzle 127 aligned with now-opened outer sub port 131 may be accessed.
  • Nozzle 127 may then be removed from nozzle port 125 of mandrel 111 and removed from downhole tool 100 through outer sub port 131 aligned therewith as depicted in FIG. 8C. Nozzle 127 may be removed, for example and without limitation, by rotating nozzle 127 relative to mandrel 111 using nozzle drive adapter 144 and a corresponding tool from the outside of downhole tool 100.
  • a replacement for nozzle 127 may then be selected.
  • the replacement of nozzle 127 with blank nozzle 127’ as depicted in FIG. 8D is depicted.
  • Blank nozzle 127’ may be inserted through outer sub port 131 and coupled to nozzle port 125 of mandrel 111.
  • Outer plug 133 may then be reinstalled to outer sub port 131, completing the nozzle replacement operation as depicted in FIG. 8E. If desired, these operations may be repeated to replace one or more of the remaining nozzles 127.
  • the replacement of nozzles 127 with nozzles having different cross-sectional flow areas or with blank nozzles may therefore change the TFA of annular flow path 115 of downhole tool 100.
  • the TFA of annular flow path 115 is 0.440 in 2 .
  • the TFA of annular flow path 115 would be 0.330 in 2 .
  • replacement of one or more of nozzles 127 with a nozzle having a different flow area may allow granular selection of TFA of annular flow path 115.
  • nozzles 127 For example, replacing one of nozzles 127 with a nozzle having a flow path diameter of 8/32” would change the TFA to 0.379 in 2 .
  • any number of nozzles 127 may be replaced with any nozzle having any flow path diameter to allow a user to configure the TFA of annular flow path 115 as desired.
  • a downhole tool 100 having four nozzles 127 is described herein, downhole tool 100 may be configured with any number of nozzles 127.
  • downhole tool 100 may be configured such that flow through annular flow path 115 is selectable by downhole tool control apparatus 30 between an unrestricted flow and a flow restricted by one or more nozzles 127 as described herein above.
  • FIGS. 9A and 9B depict embodiments of the present disclosure in which a drop-ball is used to change from unrestricted flow through annular flow path 115 to restricted flow.
  • downhole tool control apparatus 30a may include ball seat 201 positioned to receive a drop-ball 203.
  • Downhole tool control apparatus 30a may include outer collar 205 positioned between outer sub 101 and tubular member lOa of drill string 10.
  • Downhole tool control apparatus 30a may include bore flow path port 207 extending from an annular space about ball seat 201 to bore flow path 113 and may include annular flow path port 209 extending from blind bore 211 formed behind ball seat 201 and annular flow path 115.
  • fluid flowing through downhole tool control apparatus 30a may flow through both bore flow path port 207 and annular flow path port 209 into bore flow path 113 and annular flow path 115 respectively without restriction.
  • nozzles 127 are still included with downhole tool 100, fluid flow through nozzles 127 may not affect the operation of downhole tool 100 due to the unrestricted flow into annular flow path 115 through downhole tool control apparatus 30a.
  • annular flow path port 209 is blocked by drop-ball 203 while bore flow path port 207 continues to allow fluid to flow into bore flow path 113.
  • fluid may flow from bore flow path 113 to annular flow path 115 through nozzles 127 as described herein above.
  • FIGS. 10A and 10B depict embodiments of the present disclosure in which downhole tool control apparatus 30b includes an indexer 301 having indexer mandrel 303 used to change from unrestricted flow through annular flow path 115 to restricted flow.
  • Indexer 301 may be adapted to move indexer mandrel 303 between a retracted position as depicted in FIG. 10A and an extended position as depicted in FIG. 10B.
  • indexer mandrel 303 when indexer mandrel 303 is positioned in the retracted position as depicted in FIG. 10 A, fluid flow through indexer bore 305 of indexer mandrel 303 may flow through bore flow path 113 and annular flow path 115 as, in such an embodiment, mandrel 11 G is not sealed against outer sub 101.
  • nozzles 127 are still included with downhole tool 100, fluid flow through nozzles 127 may not affect the operation of downhole tool 100 due to the unrestricted flow into annular flow path 115 through downhole tool control apparatus 30b.
  • indexer mandrel 303 when indexer mandrel 303 is positioned in the extended position as depicted in FIG. 10B, indexer mandrel 303 may engage with mandrel extension assembly 307 and may fluidly seal thereagainst such that indexer bore 305 is fluidly sealed to bore flow path 113.
  • mandrel extension assembly 307 may include one or more components adapted to allow seating between indexer mandrel 303 and mandrel 11 , and may include, for example and without limitation, follower 309 and spring 311.
  • mandrel extension assembly 307 may further include endcap 313 positioned to retain follower 309 against the force of spring 311.
  • annular flow path 115 is no longer fluidly coupled to indexer bore 305 at indexer mandrel 303 while the connection between indexer mandrel 303 and mandrel extension assembly 307 allows fluid to flow into bore flow path 113.
  • fluid may flow from bore flow path 113 to annular flow path 115 through nozzles 127 as described herein above.

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  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
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Abstract

L'invention concerne un outil de fond de trou comprenant une réduction externe et un mandrin positionné à l'intérieur de la réduction externe. La réduction externe et le mandrin sont tubulaires. L'intérieur du mandrin définit un trajet d'écoulement à orifice, et l'espace annulaire entre la réduction externe et le mandrin définit un trajet d'écoulement annulaire. Un ou plusieurs orifices de buse sont formés dans le mandrin pour coupler fluidiquement le trajet d'écoulement à orifice et le trajet d'écoulement annulaire. Une buse est positionnée dans chaque orifice de buse. La buse comprend un corps de buse ayant un trajet d'écoulement formé à l'intérieur de celui-ci pour coupler fluidiquement le trajet d'écoulement à orifice au trajet d'écoulement annulaire à travers la buse.
PCT/US2018/055061 2018-10-09 2018-10-09 Outil de fond de trou avec zone d'écoulement interne réglable de l'extérieur WO2020076310A1 (fr)

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PCT/US2018/055061 WO2020076310A1 (fr) 2018-10-09 2018-10-09 Outil de fond de trou avec zone d'écoulement interne réglable de l'extérieur

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PCT/US2018/055061 WO2020076310A1 (fr) 2018-10-09 2018-10-09 Outil de fond de trou avec zone d'écoulement interne réglable de l'extérieur

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WO2020076310A8 WO2020076310A8 (fr) 2020-07-02

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