WO2020170044A1 - Outil de nettoyage de puits de forage multi-cylcle - Google Patents

Outil de nettoyage de puits de forage multi-cylcle Download PDF

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Publication number
WO2020170044A1
WO2020170044A1 PCT/IB2020/000161 IB2020000161W WO2020170044A1 WO 2020170044 A1 WO2020170044 A1 WO 2020170044A1 IB 2020000161 W IB2020000161 W IB 2020000161W WO 2020170044 A1 WO2020170044 A1 WO 2020170044A1
Authority
WO
WIPO (PCT)
Prior art keywords
clean
plunger
tool
wellbore
mandrel
Prior art date
Application number
PCT/IB2020/000161
Other languages
English (en)
Inventor
Jonathan M. STANG
Daryl E. MAGNER
Original Assignee
Stang Technologies Ltd.
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
Priority claimed from US16/280,364 external-priority patent/US10907447B2/en
Priority claimed from US16/686,955 external-priority patent/US10927623B2/en
Application filed by Stang Technologies Ltd. filed Critical Stang Technologies Ltd.
Publication of WO2020170044A1 publication Critical patent/WO2020170044A1/fr

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B37/00—Methods or apparatus for cleaning boreholes or wells
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
    • E21B21/10—Valve arrangements in drilling-fluid circulation systems

Definitions

  • the present disclosure relates to the field of hydrocarbon recovery operations. More specifically, the invention relates to wellbore completions and remediation operations. Further still, the invention relates to a tool that may be connected to a string of coiled tubing (or other working string) and used for wellbore clean-out.
  • a simple nozzle may be run into a wellbore at the end of a coiled tubing string.
  • a coiled tubing connector may be used to connect the coiled tubing string with the nozzle.
  • An aqueous circulating fluid is pumped down the working string, through the nozzle and then up the back side (or annulus) of the working string.
  • a surfactant, an acid or other chemical is injected down the coiled tubing string following the aqueous circulating fluid as part of the clean-out.
  • a separate type of tool that also involves circulating fluid down a working string is an abrasive perforating tool.
  • Abrasive perforating tools utilize custom lateral jetting ports that allow a fluid containing abrasive particles, e.g., sand, to be pumped downhole through the working string at high pressures and then out of the jetting ports laterally.
  • the abrasive fluid erodes through the surrounding casing at a designated depth, then through the cement, and out into the surrounding rock formation. This is an alternative to explosive charge perforating or so-called plasma perforating.
  • an abrasive perforating tool may be part of a bottom hole assembly containing a reverse ball check valve.
  • the BHA components include a so-called CT connector, a disconnect, a stabilizer, an abrasive cutting sub having at least one jetting nozzle, the reverse ball check valve, and then the nozzle.
  • a schematic view of such a device is shown in Figure 1 of U.S. Patent No. 9,115,558, the entirety of which is incorporated herein by reference.
  • the reverse ball check valve of the‘558 patent includes a pin and a ball.
  • the reverse ball check valve When fluid is pumped down the coiled tubing, the reverse ball check valve is forced closed, preventing fluid from exiting the nozzle at the bottom of the BHA. Fluid is then directed through the lateral jetting ports for hydraulic perforating. Subsequently, when sand or other particulates are required to be cleaned out, a“reverse clean-out” procedure is conducted.
  • the BHA cannot take advantage of gravity to bring the fill material down to the nozzle as is present in a vertical well.
  • the annular velocity (governed by gauge pressure at the surface) likely will not be high enough to sweep the entire fill to the end of the bottom hole assembly.
  • the‘558 patent disclosed a novel abrasive perforating tool capable of being cycled during pumping operations to provide clean-out.
  • fluids can be pumped down the bore of the working string in the same direction for both abrasive perforating and for clean-out, using a cycling mechanism. This allows for a multi-cycle adjustment of tool function carried out by manipulating pumping rates.
  • a multi -cycle clean-out tool for controlling a direction of a clean-out fluid within a wellbore is first provided herein.
  • the wellbore is lined with a string of production casing.
  • the wellbore further includes a string of production tubing.
  • the multi cycle clean-out tool is dimensioned to be run into the production tubing.
  • the clean-out tool is designed to be run into a wellbore from the surface.
  • a conveyance medium such as a coiled tubing string is used.
  • a CT connector may be provided to connect the coiled tubing string to the clean-out tool.
  • the clean-out tool first includes a tubular housing.
  • the tubular housing provides an elongated bore through which clean-out fluid may flow.
  • the tubular housing includes one or more back jetting ports disposed at an upward angle therein. The upward angle is preferably at 15° to 60°, and more preferably at 45°, relative to the longitudinal central axis of the tool.
  • the tubular housing may comprise an upper sub having an upper end and a lower end.
  • the upper end may serve as a box end that threadedly connects to the CT connector or other bottom hole assembly.
  • the tubular housing may further comprise a lower sub also having an upper end and a lower end. The first end of the lower sub is abutted to a lower end of the seat, while the lower end may be threadedly connected to a downhole tool such as a nozzle or a positive displacement motor.
  • the clean-out tool also includes a piston.
  • the piston defines a short cylindrical body that is disposed at an upstream end of the tubular housing.
  • the piston has an orifice configured to deliver fluids from the coiled tubing string to the elongated bore of the housing.
  • the piston forms a pressure shoulder as fluids are injected through the coiled tubing string.
  • the clean-out tool additionally includes a tubular mandrel.
  • the tubular mandrel is slidably positioned within the housing.
  • the mandrel has a proximal end connected to or otherwise acted upon by the piston, and an open distal end, wherein the distal end forms a plunger.
  • the plunger is a separate body threadedly or adhesively connected to the distal end of the mandrel.
  • one or more slots are provided equi- radially just above a lower end of the plunger.
  • the clean-out tool further includes a seat.
  • the seat is disposed along the tubular housing below the distal end of the mandrel. As shown in the Figure 12 series of drawings, the seat has a central through-opening that is dimensioned to receive the plunger when the piston and connected tubular mandrel slide from a raised position to a lowered position along the tubular housing.
  • the central through-opening provides a means for sealingly receiving the plunger.
  • the plunger and the central through-opening of the seat remain engaged in overlapping relation during the entire fluid circulation operation, with the degree of overlap changing as the piston, the mandrel and the connected plunger move between the raised and lowered positions.
  • a lower end of the plunger provides a restricted opening, creating a pressure drop during use.
  • the lower end of the plunger may be completely closed off.
  • a separate nozzle may be disposed below the tubular housing for wellbore cleanout.
  • a positive displacement motor is disposed below the tubular housing.
  • a lower annular region is formed between the mandrel and the surrounding tubular housing.
  • the lower annular region provides fluid communication between the elongated bore of the tubular housing and the back jetting ports when the radial slots of the plunger are above the seat.
  • the radial slots will pass across the seat, precluding clean-out fluid from flowing back up the lower annular region. In this case, all clean-out fluid will pass through the plunger below the seat.
  • the wellbore clean-out tool includes a spring.
  • the spring resides in an upper annular region between the tubular mandrel and the surrounding tubular housing above the lower annular region.
  • the spring is pre-loaded in compression to bias the mandrel and connected plunger in the raised position.
  • the upper annular region (with the spring) and the lower annular region (with the back-jetting ports) are sealingly separated.
  • the clean-out tool is configured to cycle a position of the mandrel and connected plunger in response to fluid pumping rate into the wellbore.
  • the clean-out tool is configured to cycle between two operating modes - a back-jetting mode and a flow-through mode.
  • a back-jetting mode clean-out fluid is pumped into the bore of the tubular housing at a first flow rate.
  • this mode at least a portion of the clean-out fluid flows through the mandrel, back up the lower annular region, and then through the back-jetting ports. This leaves the remaining portion of the clean-out fluid to flow through the seat and out of the clean-out tool.
  • the clean-out tool is also configured to cycle to a flow-through mode. This occurs when the clean-out fluid is pumped into the bore of the tubular housing at a second higher flow rate, above an activation rate. In this mode, all (or certainly substantially all) of the clean-out fluid flows through the mandrel, through the seat, and out of the bottom of the clean-out tool.
  • the clean-out tool may further be configured to remain in a back- jetting mode when the clean-out fluid is pumped into the bore of the tubular housing at a rate higher than the first flow rate. In this position, a similar portion of the clean-out fluid flows through the mandrel, back up the annular region, and through the back jetting ports.
  • the mandrel and connected plunger remain in a raised position during run-in.
  • the plunger is maintained a sufficient distance above the seat to permit sufficient fluid to travel through radial slots in the plunger, and then up to the back jetting ports without a significant pressure drop.
  • the plunger is lowered to a point along or through the central through-opening of the seat, providing for the flow-through mode. More specifically, the radial slots move below the seat when the mandrel and connected plunger move to its lowered position.
  • the relative ratio of fluid that flows through the back jetting ports and that flows through the bottom of the tool during the back-jetting mode is a matter of design’s choice. This ratio can be adjusted based on the cross-sectional area of the radial slots in the plunger, the cross-sectional area of the lower annular region, the cumulative cross-sectional area of the back jetting ports, the size of the flow through area in the seat, and the flow restriction from downhole tool that may be below the clean-out tool as part of a bottom hole assembly.
  • the wellbore clean-out tool also includes a sequencing mechanism.
  • the sequencing mechanism is responsive to a sequence of flow rates applied above the piston.
  • the sequencing mechanism comprises a cylindrical body configured to cycle the mandrel between its back-jetting mode (wherein the flow of clean-out fluids is split according to the operator’s needs) and its flow-through mode (wherein all clean-out fluids exit through the seat).
  • an intermediate position is provided wherein the mandrel and connected plunger reside between the raised position and the lowered position but the mandrel remains in its back-jetting mode.
  • the sequencing mechanism is a J-slot sequencing mechanism.
  • the J- slot mechanism will cooperate with one or perhaps two pins that are disposed along the tubular housing as a J-slot collar.
  • the pins are configured to ride in slots along the J-slot mechanism to cycle the mandrel and connected plunger between the raised position and the lowered position.
  • the pins are fixed from axial movement and ride in the slots of the J-slot channel of the mandrel to restrict axial movement of the mandrel on alternating downward strokes.
  • the clean-out tool will only cycle between a single back-jetting mode and the flow-through mode.
  • This may be worked out by providing a J-slot mechanism that is configured to cycle between three settings, comprising:
  • a method of cleaning out a wellbore using a clean-out tool is also provided.
  • the method first includes running a clean-out tool into the wellbore.
  • the clean-out tool is run in on a lower end of a string of coiled tubing.
  • the clean-out tool is arranged in accordance with the clean-out tool as described above, in any of its embodiments.
  • the method additionally includes locating the clean-out tool at a selected depth along the wellbore.
  • the wellbore has been completed with a string of production tubing.
  • the clean-out tool is run into the production tubing in order to clean out fill that may have accumulated within the production tubing and casing.
  • the method further includes pumping a clean-out fluid down the coiled tubing and into the bore of the tubular housing. This injection is done at a first flow rate. This injection causes a portion of the clean-out fluid to flow into the plunger, out of the radial ports of the plunger, and then back up the tubular housing where this portion will pass through the lower annular region and then exit the clean-out tool through the back jetting ports. The remaining portion of clean-out fluid will flow out of the seat. This is a back- jetting mode.
  • the method also includes further pumping the clean-out fluid down the coiled tubing and into the bore of the tubular housing at a second flow rate.
  • the second flow rate is higher than the first flow rate. This increases a hydraulic force acting on the pressure shoulder of the piston, and causes the mandrel and connected plunger to slide downward along the tubular housing.
  • flow is dropped back down to the first flow rate.
  • Pump rate is then increased through the clean-out tool, thus increasing hydraulic pressure, until the fluid is pumped at or above the second flow rate.
  • the mandrel and connected plunger move down the tubular housing until the radial slots have cleared the seat. In this position, all of the clean-out fluid now flows through the plunger as located below the seat. This is a flow-through mode.
  • the mandrel may be cycled between the back-jetting mode and the flow-through mode using a sequencing mechanism that is sensitive to pump rate.
  • the sequencing mechanism is preferably a J-slot mechanism.
  • the J-slot mechanism has slots that cycle the plunger between the back-jetting mode and the flow-through mode.
  • the J-slot mechanism is configured to:
  • Figure 1A is a cross-sectional view of a clean-out tool (or“flow diverter”) of the present invention, in one embodiment.
  • the clean-out tool is in its run-in position.
  • a significant portion of the injected fluid flows to back jetting ports, while the remainder of the fluid flows through the end of the tool.
  • Figure IB is a second cross-sectional view of the clean-out tool of Figure 1 A.
  • the clean-out tool has been cycled to an intermediate position. In this position, a significant portion of the injected fluid continues to flow to the back jetting ports while the remainder of the fluid flows through the end of the tool.
  • Figure 1C is a third cross-sectional view of the clean-out tool of Figure 1 A.
  • the tool has been cycled to its fully lowered position. In this position, a plunger has landed on a seat, and all of the injected fluid travels through the clean-out tool with virtually no clean out fluid being diverted to the back jetting ports.
  • Figure 2A is a cross-sectional view of a clean-out tool of the present invention, in a second embodiment.
  • the clean-out tool is again in its run-in position wherein a significant portion of injected clean-out fluid flows to back jetting ports, while a remaining portion flows through the end of the tool.
  • a more restricted orifice or central flow-through opening is used in the seat.
  • Figure 2B is a second cross-sectional view of the flow diverter of Figure 2A.
  • the flow diverter has been cycled to an intermediate position. In this position, a significant portion of the injected fluid continues to flow to the back jetting ports while the remainder of the fluid flows through the end of the tool.
  • Figure 2C is a third cross-sectional view of the flow diverter of Figure 2A.
  • the tool has been cycled to its lowered position. In this position, the plunger has landed on the seat, with virtually no clean-out fluid being diverted to the back jetting ports.
  • Figure 3 A is a perspective view of a positive displacement motor as may be placed below the clean-out tool of either Figure 1 A or Figure 2A.
  • Figure 3B is an example of a suitable sliding sleeve shifting tool that may be used as part of a bottom hole assembly with the flow diverter of Figure 2A.
  • Figure 3C is an example of a bridge plug that may be set, retrieved or drilled out using a bottom hole assembly that includes the flow diverter of Figure 2A.
  • Figure 4A is a side view of a j-slot mechanism. In this view, pins are in a default position along the slots.
  • Figure 4B is another side view of the j-slot mechanism of Figure 4A. In this view, the pins have advanced along the channel and are in an intermediate position.
  • Figure 4C is another side view of the j-slot mechanism of Figure 4A. In this view, the pins have advanced along the channel to a second slot but have returned to the default position of Figure 4 A.
  • Figure 4D is still another side view of the j-slot mechanism of Figure 4A.
  • the pins have advanced to a new slot along the channel and are now in a fully raised position.
  • the piston and connected mandrel have moved the plunger of the clean-out tool to its lowered position such that the plunger will land on the seat per Figure 1C or Figure 2C.
  • Figure 5 A is side view of the mandrel of Figures 1 A and 2A. So called J-slots are visible along the outer diameter of the mandrel. These are part of the sequencing mechanism.
  • Figure 5B is a cross-sectional view of the mandrel of Figure 5 A. The view of the J-slots is retained in phantom.
  • Figure 6A is cross-sectional view of a J-slot collar.
  • the J-slot collar includes a pair of opposing pins that ride in the J-slots of Figure 5A.
  • the J-slot collar is also part of the sequencing mechanism.
  • Figure 6B is a perspective view of the J-slot collar of Figure 6A.
  • Figure 7 is a cross-sectional view the back jet housing of Figures 1 A and 2A. Back jetting ports are visible in the body of the housing.
  • Figure 8A is a side view of the piston assembly of Figures 1 A and 2A.
  • Figure 8B is a cross-sectional view of the piston assembly of Figure 8 A.
  • Figure 8C is a perspective view of the piston assembly of Figure 8 A.
  • Figure 9A is a side view of the plunger of Figures 1A and 2A.
  • Figure 9B is a cross-sectional view of the plunger of Figure 9A.
  • Figure 9C is a perspective view of the plunger of Figure 9A.
  • Figure 10A is a side view of the stem of Figures 1 A, IB and 1C.
  • Figure 10B is cross-sectional view of the stem of Figure 10A.
  • Figure IOC is a perspective view of the stem of Figure 10A, taken from the distal end.
  • Figure 11A is a side view of the of the combined stem and seat of Figures 1A, IB and 1C.
  • Figure 1 IB is a cross-sectional view of the combined stem and seat of Figure 11 A.
  • Figure 12A is a cross-sectional view of a clean-out tool of the present invention, in a third embodiment. In this view, the clean-out tool (or“flow diverter”) is again in its run-in position wherein a significant portion of injected clean-out fluid flows to back jetting ports, while a remaining portion flows through the end of the tool. In this embodiment, no stem is provided with the seat.
  • Figure 12A-P1 is an enlarged cross-sectional view of portion PI of Figure 12A. The relationship between the plunger and seat is more clearly seen.
  • Figure 12B is a cross-sectional view of the clean-out tool of Figure 12A.
  • the clean-out tool has been cycled to an intermediate position. In this position, a significant portion of the injected fluid continues to flow to the back jetting ports while the remainder of the fluid flows through the end of the tool.
  • Figure 12B-P2 is an enlarged cross-sectional view of portion P2 of Figure 12B. Here, it can be seen that the plunger has approached the seat.
  • Figure 12C is a third cross-sectional view of the clean-out tool of Figure 12A.
  • the tool has been cycled to its lowered position. In this position, radial slots along the plunger have passed through the seat, causing virtually all clean-out fluid to flow through the seat and through the bottom of the clean-out tool.
  • Figure 12C-P3 is an enlarged cross-sectional view of portion P3 of Figure 12B. Here, it can be seen that the plunger has passed across the seat.
  • Figure 12-P4 is another enlarged cross-sectional view of portion PI of Figure 12A.
  • the radial slots once again are positioned above the seat. However, in this arrangement a lower portion of the plunger has a restricted flow-through channel.
  • Figure 12-P5 is still another enlarged cross-sectional view of portion PI of Figure 12A.
  • the radial slots once again are positioned above the seat. However, in this arrangement a lower portion of the plunger has a closed off bottom.
  • Figure 13 is a cross-sectional view of a wellbore. Here, the wellbore has received the clean-out tool of Figure 1A.
  • Figure 14 is a flow chart showing operational steps for controlling a flow of fluid through the clean-out tool, in one arrangement.
  • hydrocarbon refers to an organic compound that includes primarily, if not exclusively, the elements hydrogen and carbon. Hydrocarbons may also include other elements, such as, but not limited to, halogens, metallic elements, nitrogen, carbon dioxide, and/or sulfuric components such as hydrogen sulfide.
  • hydrocarbon fluids refers to a hydrocarbon or mixtures of hydrocarbons that are gases or liquids.
  • hydrocarbon fluids may include a hydrocarbon or mixtures of hydrocarbons that are gases or liquids at formation conditions, at processing conditions, or at ambient condition.
  • the terms“produced fluids,”“reservoir fluids” and“production fluids” refer to liquids and/or gases removed from a subsurface formation, including, for example, an organic-rich rock formation.
  • Produced fluids may include both hydrocarbon fluids and non-hydrocarbon fluids.
  • Production fluids may include, but are not limited to, oil, natural gas, pyrolyzed shale oil, synthesis gas, a pyrolysis product of coal, nitrogen, carbon dioxide, hydrogen sulfide and water.
  • the term“fluid” refers to gases, liquids, and combinations of gases and liquids, as well as to combinations of gases and fines, combinations of liquids and fines, and combinations of gases, liquids, and fines.
  • the term“wellbore fluids” means water, hydrocarbon fluids, formation fluids, or any other fluids that may be within a wellbore during a production operation.
  • subsurface refers to geologic strata occurring below the earth's surface.
  • the term“formation” refers to any definable subsurface region regardless of size.
  • the formation may contain one or more hydrocarbon-containing layers, one or more non-hydrocarbon containing layers, an overburden, and/or an underburden of any geologic formation.
  • a formation can refer to a single set of related geologic strata of a specific rock type, or to a set of geologic strata of different rock types that contribute to or are encountered in, for example, without limitation, (i) the creation, generation and/or entrapment of hydrocarbons or minerals, and (ii) the execution of processes used to extract hydrocarbons or minerals from the subsurface region.
  • the term“wellbore” refers to a hole in the subsurface made by drilling or insertion of a conduit into the subsurface.
  • the term“well,” when referring to an opening in the formation, may be used interchangeably with the term“wellbore.”
  • Figure 1A is a cross-sectional view of a clean-out tool (or“flow diverter”) 100 of the present invention, in one embodiment.
  • the clean-out tool 100 is used to inject fluids into a wellbore for clean-out.
  • An illustrative wellbore is shown at 1300 in Figure 13 and is discussed below.
  • the clean-out tool 100 defines a generally tubular body formed from a series of components. As shown, the clean-out tool 100 has a first (or upstream) end 102 and a second (or downstream) end 104. A central bore 105 is formed within the body extending from the first end 102 to the second end 104. [0089] As will be discussed, the clean-out tool 100 is configured to cycle a position of a mandrel 155 and connected plunger 160 in response to fluid pumping rates into the wellbore 1200 by an operator. In this way, a flow of clean-out fluid through the tool 100 may be adjusted.
  • the clean-out tool 100 is in its run-in position wherein a portion of the injected fluid flows through the tool 100 from the top (or upstream) end 102 to the bottom (or downstream) end 104 en route to a next downhole tool or to the bottom of the wellbore 1300, as the case may be.
  • a portion of the injected fluid flows through the tool 100 from the top (or upstream) end 102 to the bottom (or downstream) end 104 en route to a next downhole tool or to the bottom of the wellbore 1300, as the case may be.
  • at least some of the injected fluid will exit a back jet housing 140 and exit the clean-out tool 100 through radial back jetting ports 148
  • the clean-out tool 100 first includes a top sub 110.
  • the top sub 110 defines a tubular body wherein a first (or upstream) end 112 comprises female threads while a second (or downstream) end 114 comprises male threads.
  • the female threads are configured to threadedly connect to a bottom hole assembly (or“BHA”) above (not shown).
  • BHA bottom hole assembly
  • the upper BHA is connected to a string of coiled tubing or other working string, such as through a CT connector (not shown).
  • the clean-out tool 100 next includes a spring housing 120.
  • the spring housing 120 also defines a generally tubular body wherein a first (or upstream) end 122 comprises female threads while a second opposite end 124 comprises male threads.
  • the first end 122 of the spring housing 120 threadedly connects to the second (or downstream) end 114 of the top sub
  • the clean-out tool 100 also includes a spring 125.
  • the spring 125 resides along an inner diameter of the spring housing 120.
  • the spring 125 is held in compression within the tool 100.
  • the spring 125 is an Inconel ® spring.
  • the spring material is 17-7 stainless steel.
  • a shoulder 126 resides along an inner diameter of the spring housing 120. The shoulder 126 serves as a face against which the spring 125 resides.
  • the clean-out tool 100 next includes a mandrel seal sub 130.
  • the mandrel seal sub 130 also defines a generally tubular body wherein a first (or upstream) end 132 comprises female threads while a second opposite (or downstream) end 134 comprises male threads.
  • the upstream end 132 threadedly connects to the second (or downstream) end 124 of the spring housing 120.
  • the mandrel seal sub 130 encompasses a portion of a sequencing mechanism 400, discussed below.
  • the clean-out tool 100 also comprises a back jet housing 140.
  • the back jet housing 140 also defines a generally tubular body wherein a first (or upstream) end 142 comprises female threads while a second (or downstream) opposite end 144 also comprises female threads.
  • the back jet housing 140 resides downstream from the top sub 110 and the spring housing 120.
  • the first end 142 of the back jet housing 140 threadedly connects to the second end 134 of the mandrel seal sub 130.
  • the back jet housing 140 comprises one or more back jetting ports
  • the back jetting ports 148 are placed within the back jet housing 140 at an upward angle. Preferably, the angle is between 10° and 60°, and more preferably at about 45° from the central longitudinal axis.
  • the back jetting ports 148 may be also be disposed radially about the back jet housing 140, such as at 15° radially.
  • a plurality of back jetting ports 148 are placed radially around the back jet housing 140 along at least two levels, and optionally at different angles.
  • top sub 110, the spring housing 120, the mandrel seal sub 130, the back jet housing 140 and the lower sub 190 together make up a tubular housing for the clean-out tool 100.
  • a shoulder 146 resides along an inner diameter of the back jet housing 140.
  • the shoulder 146 forms a profile above the back jetting ports 148.
  • a separate shoulder 136 resides at the bottom end 134 of the mandrel seal sub 130. O-rings are placed inside the bottom end 134, helping to keep clean-out fluid from flowing from the annular area between the mandrel 155 and the spring housing 120 and to the ports 148 during the flow-through mode.
  • the clean-out tool 100 additionally includes a piston assembly 150.
  • the piston assembly 150 defines a series of components that are configured to slide together along the spring housing 120 in response to fluid pressure.
  • the piston assembly 150 includes an orifice retainer 151, a piston body 156, a piston orifice 153 and a piston scraper retainer 157.
  • the piston assembly 150 essentially serves as a pressure shoulder, moving down the spring housing 120 in response to fluid pressure applied from the surface.
  • the orifice retainer 151 secures the piston assembly 150 in place below the top sub 110.
  • the orifice retainer 151 abuts the lower end 114 of the top sub 110 to hold the piston assembly 150 in place.
  • Various o-rings may be disposed around the piston body 156 and the piston orifice 153 to prevent pressure communication between the areas above and below the piston assembly 150. Additional details concerning the piston assembly 150 are provided below in connection with Figures 8A through 8C.
  • the piston assembly 150 is operatively connected to a mandrel 155.
  • the mandrel 155 has an upper (or upstream) end 152 connected to the piston assembly 150, and a lower (or downstream) end 154.
  • the upper end 152 of the mandrel 155 is threadedly connected to the piston body 156.
  • the piston assembly 150 and connected mandrel 155 reside within the inner diameter of the spring housing 120.
  • hydraulic pressure (generated by fluid flow through the piston orifice 153) acts on the shoulder that is the upper side of the piston assembly 150 above the piston orifice 153.
  • the piston assembly 150 and connected mandrel 155 move down the tubular housing together.
  • the piston assembly 150 (and connected mandrel 155) moves from its raised position (shown in Figure 1A), to an intermediate position (shown in Figure IB) and then to a lowered position (shown in Figure 1C).
  • An annular area 145 is reserved between the mandrel 155 and the surrounding back jet housing 140.
  • the annular area 145 has an upper portion where the spring 125 resides, and a lower portion where back jetting ports 148 are placed.
  • Appropriate o-rings reside around and inside the downstream end 134 of the mandrel seal sub 130 to provide a fluid seal between the upper and lower annular regions 145.
  • the annular region the spring 125 resides in is pressure balanced via ports 129 in the mandrel 155. These ports 129 let the fluid volume inside the spring housing 120 change as the piston body 156 moves up and down.
  • the back jet housing 140 has an enlarged inner diameter portion 147. This has the effect of increasing the cross-sectional area of the lower portion of the annular region 145.
  • the larger cross-sectional area of the enlarged inner diameter portion 147 enables a free flow of clean-out fluid en route to the ports 148.
  • Clean-out fluid is used to clean the wellbore within the casing, preferably at the conclusion of or in conjunction with a completion operation. Alternatively, clean-out fluid may be used to clean production tubing following a period of production or other wellbore operation.
  • the plunger 160 defines a short tubular body having an upper (or upstream) end 162 and an opposing lower (or downstream) end 164.
  • a bore 165 is formed from the upper 162 to the lower 164 end, allowing the clean-out fluid to flow through the plunger 160.
  • the upper end 162 comprises male threads that connect to the lower end 154 of the mandrel 155. In this way, the plunger 160 moves up and down along the bore 105 of the clean-out tool 100 with the mandrel 155.
  • the clean-out tool 100 includes a lower sub 190.
  • the lower sub 190 defines an elongated tubular body having an upper end 192 and a lower end 194.
  • the upper end 192 comprises male threads that connect to the bottom end of the back jet housing 140.
  • the lower sub 190 forms a bore 195 that is in fluid communication with and forms a part of the bore 105.
  • the clean-out tool 100 comprises a seat 170.
  • the seat 170 shown in Figure 1A is a standard seat having a flow-through orifice 175 (shown in Figure 11B).
  • the seat 170 is configured to receive the lower end 164 of the plunger 160 when the piston body 150 is moved to a lowered position (seen in Figure 1C). Specifically, the lower end 164 of the plunger 160 lands on a high-density, elastomeric annular seal 171 residing within the seat 170.
  • the orifice 175 is sized to provide little to no restriction in downhole fluid flow.
  • the orifice 175 of the seat 170 receives a stem 180.
  • the stem 180 defines an elongated tubular body.
  • the stem 180 has a proximal (or upper) end 182 (shown in Figures 10A and 10B) and a distal (or downstream) end 184.
  • a bore 185 extends from the proximal end 182 to the distal end 184.
  • Flow-through slots 181 are provided along the stem 180.
  • four equi-radially disposed slots 181 are provided. Additional details concerning the stem 180 are provided and discussed below in connection with Figures 10A- 10C
  • the piston body 150 is at is uppermost position. This is its default (or raised) position wherein the orifice retainer 151 is abutting the lower end 114 of the top sub 110. The piston body 150 is held in this default position due to the upward mechanical force provided by the spring 125.
  • a piston o-ring may be disposed around the piston body 156 to prevent pressure communication between the area above the piston body 156 and below the piston body 156 when fluid is passing through the orifice 153.
  • an orifice o-ring may be disposed around the orifice 153 to prevent pressure communication between the area above the orifice 153 and below the orifice 153 when fluid is passing through the orifice 153.
  • the aperture size of the orifice 153 defines the activation rate.
  • the plunger 160 remains above the four radially-disposed slots 181. As clean-out fluid is injected into the wellbore 1200 at the first flow rate, fluid will pass through the bore 165 of the plunger 160. A portion of the injected fluid will travel through the slots
  • a back pressure valve (not shown) is placed below the lower sub 190.
  • the back pressure valve can either be threaded to the distal end 194 of the lower sub 190 or it can be used as the lower sub 190 itself.
  • the back pressure valve works on the principle of biasing force of a spring which blocks the flow of fluids through a passage. The pressure of the fluids above act on an area and against the spring. The user can adjust the force of the spring, which in turn will adjust the force it takes to open an area of flow to the tools below the sub 190.
  • a back pressure valve can be configured to divert all of the flow to the back jetting ports 148 up to a pre-determined pressure, set by the operator. For example, if the planned back jetting rate corresponds to a 200 psi pressure drop across the back jetting ports 148, the back pressure valve can be set to open at 300 psi. When the tool 100 is in its back-jetting mode, all of the flow will go to the ports 148. When the plunger 160 contacts the seat 170 for flow-through mode, the back pressure valve will be forced open at 300 psi and will provide a pressure indication. This is useful when the operator wants to pump a fluid that it does not want to go through the tools below when in back-jetting mode, such as an acid or nitrogen.
  • a stem is not used in the seat; instead, a plunger 1260 with radial slots 1281 is used within clean-out tool 1200.
  • the radial slots 1281 are disposed above the seat 1270 when the clean-out tool 1200 is in its initial or intermediate position, and then moves below the seat 1270 when the clean-out tool 1200 is in its lowered position. No through-bore is provided below the radial slots 1281. In this way, clean-out fluid communicates exclusively with either the back jetting housing 140 or to the tools below the seat 1270 separately.
  • a positive displacement motor is used below the lower sub 190, wherein the motor has a high off-bottom pressure. In this instance, virtually all of the injected fluid in the plunger’s raised position will be diverted to the back jetting ports 148.
  • the percentage of fluids flowing back through the ports 148 during the back-jetting mode is a function of various factors. These include the diameter of the ports 148, the number of the ports 148, the combined cross-sectional area of the flow through slots 181, and the cross-sectional area of the annular region 145.
  • the total volume of fluid pumped through the clean-out tool 100 is a function of the inner diameter of the piston orifice 153 and the diameter of the bore 105.
  • the operator determines the number of ports to be used, the size of the ports, the inner diameter of the piston orifice 153, the area of the slots 181, the diameter of the bore 155 and the size of the annular region 145 around the bore 155. These steps are indicated at Box 1460 of the flow chart of Figure 14, discussed below.
  • Figure IB is a cross-sectional view of the clean-out tool 100 of Figure 1A.
  • the clean-out tool 100 is translating (that is, sliding down the spring housing 120) to its intermediate position. This is done by increasing the hydraulic force acting on the piston assembly 150.
  • the increased hydraulic force is achieved by increasing pump rate of the hydraulic fluid into the wellbore from the surface.
  • the piston body 150 and connected plunger 160 have slid down to a position where the lower end 164 of the plunger 160 approaches the radial slots 181 in the stem 180.
  • the radial slots 181 remain exposed to the lower annular region 147 and the tool 100 continues to operate in its back-jetting mode.
  • Figure 1C is a third cross-sectional view of the clean-out tool of Figure 1A.
  • the clean-out tool 100 has been cycled to its lowered position. This is done by further increasing the pump rate above an activation rate, thereby increasing the hydraulic force acting on the shoulder that is the piston assembly 150.
  • the plunger 160 moves below the radial slots 181, substantially all of the clean-out fluid will flow down through the seat 170, into the bore 195 of the lower sub 190, and out of the tool 100.
  • the cycling of the tool 100 between its raised position (Figure 1 A), its intermediate position ( Figure IB) and its lowered position ( Figure 1C) is preferably accomplished by using a sequencing mechanism.
  • the sequencing mechanism is preferably a J-slot mechanism as shown in Figures 4A-4D, discussed below.
  • the sequencing mechanism 400 allows the operator to cycle the flow rates to move the tool 100 between settings so that:
  • hydraulic pumping rate is reduced to its first rate, or any rate below the first rate, and the clean-out tool 100 remains in its back- jetting mode; and (iv) in a third setting, the plunger 160 is forced down into a lowered position in response to the injection of hydraulic fluid through the piston assembly 150 and into the clean-out tool 100 at a second rate, or at any rate higher than the second rate, moving the J-slot mechanism 400 to a next slot and causing the plunger 160 to slide from the raised position to the lowered position, placing the clean-out tool 100 in its flow-through mode.
  • the stem 180 is a standard-sized stem that simply receives the plunger 160 when the piston body 150 is urged down to its lowered position.
  • the O.D. of the stem 180 is configured to slidably receive the lower end 164 of the plunger 160 until the plunger 160 passes below the slots 181 in the stem 180. This may be referred to as“landing the plunger on the seat” as the plunger 160 is contacting a seal which is considered as integral to the seat 170. No significant pressure drop takes place through the standard stem 180.
  • the operator may believe that the standard stem 180 allows too much fluid to pass through the bottom end 104 of the clean-out tool 100, limiting the amount of pressure provided by fluids passing through the back jetting ports 148.
  • the operator may choose to use a restricted orifice seat. This is done by reducing the I.D. of the stem 180.
  • FIG. 2A is a cross-sectional view of a clean-out tool 200 of the present invention, in a second embodiment.
  • the clean-out tool 200 is again in its run-in position wherein a substantial portion of injected fluid flows to the back jetting ports 148, while the remaining fluid flows through the lower sub 190 of the tool 200 en route to a next downhole tool.
  • the clean-out tool 200 is built in accordance with the clean-out tool 100 described above.
  • a restricted orifice stem 280 has been placed below the plunger 160 in lieu of the stem 180.
  • the restricted orifice stem 280 has a more restrictive through opening 285, limiting the amount of working fluid that can pass through the stem 280.
  • the stem 280 provides a better indicator at the surface as to the position of the plunger 160 (via pump pressure) during cycling. Also as noted, the use of the restricted- orifice stem 280 and its flow-through opening 285 directs a greater percentage of injected fluid to the back jetting ports 148. For example, in the embodiment of Figure 2A the percentage of redirected fluid might be 30% to 40%, or 40% to 50%, or 50% to 90% of the injected fluid. This is true even where the components below the tool 100 have low back pressure.
  • the clean-out tool 200 of Figure 2A is configured to move from its raised position (Figure 2A) down to its lowered position ( Figure 2C). This again is done through the use of a cycling mechanism, such as the J-slot mechanism 400 shown in Figures 4 A through 4D.
  • Figure 2B is a cross-sectional view of the clean-out tool 200 of Figure 2A.
  • the clean-out tool 200 is translating from its raised position to its intermediate position.
  • a portion of the injected fluid will continue to be diverted through the radial slots 181 and on to the back jetting ports 148.
  • a portion of the hydraulic fluid will flow back up the lower annular region 147, and then through the back jetting ports 148.
  • the remaining portion of injected fluid will continue to flow down through the stem 280, into the bore 195 of the lower sub 190, and out of the tool 200. Because the orifice 285 is restricted, this will urge a greater portion of inj ected clean-out fluid to travel back to the back jetting ports 148.
  • Figure 2C is a third cross-sectional view of the flow diverter 200 of Figure 2A.
  • the flow diverter 200 has been cycled to its fully lowered position. In this position, all of the injected fluid travels through the flow diverter 200, with substantially no clean-out fluid being diverted to the back jetting ports 148. This may be done by increasing hydraulic pressure within the bore 105 of the clean-out tool 200 from the first pressure to the second greater activation pressure. Hydraulic pressure again is increased by increasing pump rate from the surface.
  • Hydraulic pressure again is increased by increasing pump rate from the surface.
  • the bottom end 194 of the sub 190 is configured to threadedly connect to a separate tool that may be placed in the wellbore 1300 below the clean out tool 100 or 200.
  • a positive displacement motor (presented in Figure 3) may be placed downstream from the clean-out tool 200.
  • the restricted-orifice stem 280 replaces the standard-sized stem 180 to provide an improved feedback signal through pressure increase of approximately 200 psi (with 1.01 SG Fluid) at the same pump-rate to indicate the flow-through mode.
  • the restricted-orifice stem 280 provides a secondary function of limiting the flow to the motor 300 while in back-jetting mode.
  • Figure 3 is a perspective view of a positive displacement motor 300. This provides an example of a tool that may be connected to the lower sub 190. Preferably, the positive displacement motor 300 would be used in connection with the embodiment 200 of Figures 2A - 2C. It is understood that the positive displacement motor 300 is merely illustrative; other positive pressure tools may be placed downstream of the seat 170.
  • the motor 300 includes an elongated tubular body 310.
  • the body 310 defines a fluid in-take end 312 and a fluid outlet end 314.
  • the positive displacement motor 300 operates with a rotor and a stator residing within the tubular body 310.
  • the positive displacement motor 300 is used as an agitator, sending pressure pulses across the wellbore downhole while cleaning.
  • a small drill bit (not shown) is connected to the outlet end 314, and is turned by the rotor of the motor 300. The drill bit may also be used for clean-out.
  • the use of the restricted-orifice stem 280 is particularly appropriate if the“off-bottom” pressure of the positive displacement motor 300 is low.
  • the larger orifice 185 provided in the standard stem 180 may also be acceptable to use.
  • a separate nozzle may be placed below the lower sub 190.
  • a standard stem 180 would be used.
  • the separate nozzle is preferably the HelixTM nozzle provided by Coil Solutions Inc. of Calgary, Alberta. The nozzle would be used for wellbore clean-out below the tool 100.
  • a sliding sleeve shifting tool is placed below the lower sub 190.
  • the operator may increase pressures incrementally. Based upon piston orifice 153 I.D., stem 180 or 2801.D. and total back jetting port 148 through-opening area, the operator will know at what rate to pump for each cycle. For example, the operator will know a second rate to pump that places the plunger 160 at its lowest, or seated position ( Figures 1C and 2C). The difference in tubular pressure between the two modes at the same pump rate serves as a position indicator for cycling.
  • a sequencing mechanism such as a J-slot mechanism may be provided.
  • a J-slot mechanism is a cylindrical device having a circuitous channel forming slots. One or more pins ride along the slots, rotating from slot-to-slot in response to changes in fluid pressure.
  • Figure 4A is a side view of a portion of a J-slot mechanism 400. It can be seen that a pair of pins 482 reside in respective lower slots 484A. This is a slot position that would correlate with the default, or raised position of the plunger 160 as presented in Figures 1A and 2A. In this position, the pump rate is below the activation rate. This cycle position will allow injected fluid to flow to the back jet housing 140 while sending the remaining portion of the fluid on through the bottom end 194 of the lower sub 190.
  • Figure 4B is another side view of the J-slot mechanism 400 of Figure 4A.
  • the pins 482 have advanced one slot 484B.
  • slot 484B the pins 482 are in an intermediate position. This is a slot position that would correlate to the operator increasing pump rate from the surface as shown in Figures IB and 2B.
  • the location of the J-slot pins 482 restricts the movement of the plunger 160 while allowing the flow-rate to beneficially move above the activation rate.
  • the plunger 160 will not advance along the stem 180 even when the pump rate is well above the activation rate, allowing vigorous back jetting through ports 148.
  • Figure 4C is another side view of the J-slot mechanism 400 of Figure 4A.
  • Figure 4D is still another side view of the J-slot mechanism 400 of Figure 4A.
  • the pump rate has again been increased above the activation rate, causing the pins 482 to advance along the channel to a next slot 484D .
  • the plunger 160 is seated, isolating the back jetting ports 148 from fluid injection per Figures 1C and 2C.
  • the operator may inject at high rates to operate a motor 300 or to direct all fluids through a downhole jetting nozzle (not shown). Once the plunger 160 has landed, increases in pump rate will not move the pins 482 any higher in slots 484D.
  • the pins 482 advance from slot-to-slot in response to alternating cycles of the piston body 150 and connected internals moving longitudinally.
  • the pins 482 cause the piston assembly 150 and connected internals to ratchet, or rotate, in a circular path.
  • the component housing the J-slot pin or pins 482 may ratchet, or rotate, in a circular path.
  • the J- slot grooves (484A, 484B, 484D) are configured so that the piston body 150 and connected internals travel is unrestricted in the upward direction so that every time the flow rate is brought below the activation rate the plunger 160 is in its raised position and cannot seal against the seat 170 or 270.
  • the J-slot grooves (484A, 484B, 484D) restrict the travel of the piston body 150 and connected internals so the plunger 160 cannot seal against the seat 170 or 270.
  • FIG. 5A is side view of the mandrel 155 of Figures 1A and 2A. So called J-slots 410 are visible along the outer diameter of the mandrel 155.
  • Figure 5B is a cross-sectional view of the mandrel 155 of Figure 5A.
  • slot 484D of the J-slots 410 is visible.
  • the J-slots 410 are shown in phantom.
  • J-slots 410 of Figures 5A and 5B are part of the sequencing mechanism 400.
  • the J-slots 410 work in tandem with a J-slot collar (shown at 420 in Figure 6A).
  • Figure 6A is cross-sectional view of a J-slot collar 420.
  • the J-slot collar 420 includes a pair of opposing pins 482 that ride in the J-slots 410 of Figure 5A.
  • Figure 6B is a perspective view of the J-slot collar 420 of Figure 6A. Visible in this view is one of the pins 482 extending inwardly into a bore 425.
  • Figure 7 is a cross-sectional view of the back jet housing 140 of Figures 1A and 2A.
  • the proximal (or upstream) end 142 and the distal (or downstream) end 144 are visible. It is observed that the back jet housing 140 defines a wall 141 forming a bore 145.
  • the bore 145 extends from the proximal 142 to the and distal 144 end.
  • the back jetting ports 148 are visible in the wall 141 making up the housing 140.
  • Figure 8A is a side view of the piston assembly 150 of Figures 1A and 2A.
  • Figure 8B is a cross-sectional view of the piston assembly 150 of Figure 8A.
  • Figure 8C is a perspective view of the piston assembly 150 of Figure 8A.
  • the piston assembly 150 will be discussed with reference to Figures 8A - 8C together.
  • the piston assembly 150 includes an orifice retainer 151, a piston body 156, a piston orifice 153 and a piston scraper retainer 157.
  • the piston orifice 153 resides below the orifice retainer 151.
  • the piston orifice 153 comprises a shoulder, with the shoulder being exposed to fluid pressure above the fluid assembly 150.
  • the piston orifice 153 includes a central through-opening that permits working fluids to flow through the piston assembly 150 during clean-out operations. Piston scrapers (not shown) may be disposed around the piston body 156 to ensure debris is not able to reach the piston body o-ring.
  • Figure 9A is a side view of the plunger 160 of Figures
  • Figure 9B is a cross-sectional view of the plunger 160 of Figure 9A.
  • Figure 9C is a perspective view of the plunger of Figure 9A, taken from a distal end.
  • the plunger 160 will be discussed with reference to Figures 9A - 9C together.
  • the plunger 160 has an upper end 162, a lower end 164 and a bore 165 formed there between.
  • the bore 165 has an inner diameter (ID).
  • ID is dimensioned to slidingly receive the stem 180 when moving between its back-jetting mode and its flow through mode.
  • the plunger 160 is made up of a wall 161 that forms the bore 165.
  • Figure 10A is a side view of the stem 180 of Figures 1A, IB and 1C.
  • Figure 10B is cross-sectional view of the stem 180 of Figure 10A.
  • Figure IOC is a perspective view of the stem 180 of Figure 10A, taken from the distal end.
  • the stem 180 will be discussed with reference to Figures 10A, 10B and IOC together.
  • the stem 180 defines an elongated tubular body.
  • the stem 180 has a proximal (or upper) end 182 and a distal (or downstream) end 184.
  • a bore 185 extends from the proximal end 182 to the distal end 184.
  • Through-openings (or“slots”) 181 are provided along the stem 180.
  • four equi-radially disposed slots 181 are provided.
  • the proximal end 182 of the stem 180 has an outer diameter OD.
  • the OD is dimensioned to be slidably received within the ID of the plunger 160.
  • the bottom of the plunger 160 advances past the slots 181. In this position, most (and preferably all) of the jetting fluids flow down through the bore 185 of the stem 180 and to a tool below. In either the back-jetting mode or the flow-through mode the plunger 160 is disposed over the OD of the stem 180. In other words, the stem 180 is always overlapping the plunger 160 to at least some extent. In one embodiment, when the piston assembly 150 and connected mandrel 155 are in their upper position, the plunger 160 will overlap with the stem 180 by about 1 ⁇ 2”.
  • the stem 180, 280 is received within the plunger 160.
  • the alternate telescopic relationship may also be employed, that is, the plunger 160 is received within the stem 180.
  • Figure 11A is a side view of the combined seat 170 and stem 180 of Figures 1A, IB and 1C.
  • Figure 1 IB is a cross-sectional view of the combined seat 170 and stem 180 of
  • a shoulder of the seat 170 rests on the proximal end 192 of the lower sub 190.
  • the distal end 184 of the stem 180 flanges out to serve as a base for threadedly connecting the stem 180 and seat 170.
  • An annular seal 171 is placed between an inner diameter of the seat 170 and an outer diameter of the stem 180.
  • the seat 170 and stem 180 are connected to form an integral body, supported by the lower sub 190.
  • annular seal 171 is placed along an inner diameter of the seat 170 and an outer diameter of the stem 180.
  • the annular seal 171 represents an enlarged, high density o-ring that may be fabricated, for example, from synthetic rubber and fluoropolymer elastomers.
  • An example is a polymer seal provided by The Chemours Company FC, LLC of Wilmington, Delaware. Seals and o-rings are available from The Chemours Company under the Viton ® brand.
  • the pump- rate should be increased by approximately 10% for the plunger 160 to provide sufficient compression on the Viton ® material in order to create a true fluid seal. This all happens within the pump-rate specified for the orifice size the tool 100 or 200 is configured with; however, some users may see the pressure increase (indicated flow-thru/milling mode) and assume the transition was complete, but this is not necessarily the case since there would still be fluid weeping out of the annular ports 181 at this time.
  • Figure 12A is a cross-sectional view of the clean-out tool 1200, in the third embodiment.
  • the clean-out tool (or“flow diverter”) 1200 is again in its run-in position wherein a significant portion of injected clean-out fluid flows to back jetting ports 148, while a remaining portion flows through the end of the tool 1200.
  • a portion of the clean-out fluids flow through the bore 195 of the lower sub 190.
  • the clean-out tool 1200 is built in accordance with the clean-out tool 100 described above. However, in Figure 12A a new seat design 1270 is provided. Of importance, the stem 180 from Figure 1A has been removed from the seat 1270. In addition, the slots 181 that previously resided within the stem 180 are now placed within a modified plunger 1260. [00170]
  • the seat 1270 represents an essentially tubular body secured proximate the lower end 144 of the back jet housing 140. Specifically, the seat 1270 resides along an inner diameter of the back jet housing 140, and sits on top of the top end 192 of the lower sub 190. O-rings (not numbered) are suitably placed along the inner and outer diameters of the seat 1270. In this way, seals are placed along the interfaces with the back jet housing 140 and the lower sub 190. In addition, the through-opening of the seat 1270 is dimensioned to slidably receive the plunger 160.
  • Figure 12A-P1 is a cross-sectional view of portion PI of Figure 12A.
  • PI represents an enlarged view of area PI, showing the relationship between a modified plunger 1260 and the modified seat 1270.
  • the modified plunger 1260 has an upper (or upstream) end 1262 and an opposing lower (or downstream) end 1264.
  • a bore 1265 is formed from the upper 1262 to the lower 1264 end, allowing the clean-out fluid to flow through the plunger 1260.
  • the upper end 1262 comprises male threads that connect to the lower end 154 of the mandrel 155. In this way, the modified plunger 1260 still moves up and down along the bore 105 of the clean-out tool 1200 with the mandrel 155.
  • the plunger 1260 has only partially entered the through-opening of the seat 1270. This is the default, or run-in position of the clean-out tool 1200.
  • the clean-out tool 1200 is in its back-jetting (or“clean-out”) mode. In the back-jetting mode, the operator pumps clean-out fluid into the working string and the bore 105 of the tubular housing below the activation rate.
  • the radial slots 1281 are positioned above the seat 1270. This allows a significant portion of the clean-out fluids to flow back up the annular region 145 around the mandrel 155, and through the jetting ports 148. Beneficially, no stem 180 is required.
  • Figure 12B is a second cross-sectional view of the clean-out tool 1200 of Figure 12A.
  • the clean-out tool 1200 is translating from its raised position to an intermediate position. In this position, a significant portion of the injected fluid continues to flow through the radial slots 1281 and on to the back jetting ports 148. The remaining portion of injected fluid will continue to flow down through the seat 1270 and the end of the tool 1200.
  • Figure 12B-P2 is an enlarged cross-sectional view of portion P2 of Figure 12B.
  • the plunger 1260 has approached the seat 1270.
  • the radial slots 1281 still reside above the seat 1270.
  • Figure 12C is a third cross-sectional view of the clean-out tool 1200 of Figure 12A.
  • the flow diverter tool 1200 has been cycled to its fully lowered position.
  • the plunger 1260 has landed on the seat 1270.
  • a shoulder 1278 along the plunger 1260 has landed on an upper end of the seat 1270.
  • Figure 12C-P3 is an enlarged cross-sectional view of portion P3 of Figure 12B.
  • the plunger 1260 has passed across the seat 1270.
  • the radial slots 1281 have passed the seat 1270, forcing all clean-out fluids to flow through the bottom of the tool. In this position, virtually no clean-out fluid is diverted to the back jetting ports 148.
  • the benefit to this third embodiment 1200 is that the tool does not rely on the Viton ® seal 171 to close off flow to the back-jetting ports 148. This avoids the potential issue of the seal 171 degrading over time. Instead, much smaller o-rings 1275 (or, optionally, PTFE seals energized by o-rings) are provided along the inner and outer diameters of the seat 1270, providing a more reliable design.
  • an inner diameter of the plunger 1260 below the radial slots 1281 can be tuned to adjust a flow split of clean-out fluid while the clean-out tool 1200 is in its back- jetting mode. This enables the inner diameter of the plunger 1260 below the radial slots 1281 to be reduced completely to zero in order to direct the entire flow to the back-jetting ports during back-jetting mode.
  • Figure 12-P4 is another enlarged cross-sectional view of portion PI of Figure 12A.
  • the radial slot 1281 once again are positioned above the seat 1270.
  • a lower portion 1264’ of the plunger 1260 has a restricted flow-through channel 1268. This is similar to what was done with the distal end 184 of the stem 180 shown in
  • Figure 12-P5 is still another enlarged cross-sectional view of portion PI of Figure 12A.
  • the radial slots 1281 once again are positioned above the seat 1270.
  • a lower portion 1264” of the plunger 1260 is closed off.
  • the lower portion 1264” is a solid body.
  • the solid body may be fabricated from steel, plastic or an elastomeric material.
  • the clean-out tool 100, 200, 1200 (with or without tool 300 or some bottom hole assembly below) is intended to be run into a wellbore.
  • Figure 13 is a cross- sectional view of an illustrative wellbore 1300.
  • the wellbore 1300 penetrates into a subsurface formation 1350.
  • the wellbore 1300 has been completed as a cased-hole completion for producing hydrocarbon fluids. More importantly for purposes of the present disclosure, the wellbore 1300 has received a multi-cycle clean-out tool such as the tool 1200 of Figure 12A.
  • the wellbore 1300 has been completed with a series of pipe strings referred to as casing.
  • a string of surface casing 1310 has been cemented into the formation 1350.
  • the cement resides in an annular region 1315 around the casing 1310, forming an annular sheath 1312.
  • the surface casing 1310 has an upper end in sealed connection with a bottom wellhead valve 1364.
  • At least one intermediate string of casing 1320 is cemented into the wellbore 1300.
  • the intermediate string of casing 1300 is in sealed fluid communication with a top wellhead valve 1362.
  • a cement sheath 1322 resides in an annular region 1325 of the wellbore 1300.
  • the combination of the casing 1310 / 1320 and the cement sheaths 1312, 1322 in the annular regions 1315, 1325 strengthens the wellbore 1300 and facilitates the isolation of aquitards and formations behind the casing 1310 / 1320. It is understood that a wellbore 1300 may, and typically will, include more than one string of intermediate casing.
  • a production string 1330 is provided.
  • the production string 1330 is hung from the intermediate casing string 1320 using a liner hanger 1331.
  • the production string 1330 is a liner that is not tied back to the surface 1301.
  • a cement sheath 1332 is provided around the liner 1330. The cement sheath 1332 fills an annular region 1335 between the liner 1330 and the surrounding rock matrix in the subsurface formation 1350.
  • the production liner 1330 has a lower end 1334 that extends to an end 1354 (or “toe”) of the wellbore 1300. For this reason, the wellbore 1300 is said to be completed as a cased-hole well.
  • the liner 1330 will be perforated after cementing to create fluid communication between a bore 1345 of the liner 1330 and the surrounding rock matrix making up the subsurface formation 1350.
  • the production string 1330 is not a liner but is a casing string that extends back to the surface. In this instance, the cement sheath 1332 will not be extended to the surface 1301
  • end 1354 of the wellbore 1300 may include joints of sand screen (not shown).
  • sand screens with gravel packs allows for greater fluid communication between the bore 1345 of the liner 1330 and the surrounding rock matrix 1350 while still providing support for the wellbore 1300.
  • the wellbore 1300 would include a slotted base pipe as part of the sand screen joints.
  • the sand screen joints would not be cemented into place.
  • the bottom end 1354 of the wellbore 1300 is completed substantially horizontally. This is a common orientation for wells that are completed in so- called“tight” or“unconventional” formations. Indeed, in the United States well over half of all wells are now completed horizontally. In the wellbore 1300 of Figure 13, the horizontal portion extends along a“pay zone” 1355.
  • Horizontal completions not only dramatically increase exposure of the wellbore to the producing rock face, but also enable the operator to create fractures that are substantially transverse to the direction of the wellbore.
  • a rock matrix will generally“part” in a direction that is perpendicular to the direction of least principal stress. For deeper wells, that direction is typically substantially vertical.
  • the present inventions have equal utility in vertically completed wells or in multi lateral deviated wells.
  • the wellbore 1300 When completed, the wellbore 1300 will include a string of production tubing (not shown). However, before that is done, it is desirable to clean out the wellbore 1300. Accordingly, the wellbore 1300 includes the clean-out tool 1200 as shown in Figures 12A- 12C.
  • the clean-out tool 1200 is connected to a string of coiled tubing 1340.
  • the coiled tubing string 1340 serves as a working string for delivering an aqueous fluid under high pressures downhole. Such pressures may exceed 500 psi, or even 3,000 psi.
  • the clean out tool 1200 is preferably extended along the horizontal leg of the wellbore 1300 through the pay zone 1355.
  • a lubricator 1360 or firac tree is placed over the wellbore 1300.
  • the lubricator 1360 is positioned at the surface 1301 to control wellbore pressures during a completion (or other wellbore) operation and to isolate tools such as a string of coiled tubing 1340 being moved into and back out of the wellbore 1300.
  • a surfactant may be added to the clean-out fluid to assure that the fluid moves through the clean-out tool 1200 and up the wellbore 1300.
  • the fluid is filtered to minimize plugging of back jetting ports 148.
  • the coiled tubing string 1340 is dimensioned to be inserted into a string of production tubing (not shown). In this way, the production tubing may be cleaned out after a period of production.
  • a method 1400 of conducting a wellbore operation is also provided. The method 1400 is presented in the flow chart of Figure 14.
  • the method 1400 first includes providing a wellbore. This is indicated at Box 1410.
  • the wellbore is being completed for the production of hydrocarbon fluids.
  • the wellbore has been formed with a string of casing, including a string of production casing along a selected subsurface formation.
  • the wellbore may be completed vertically.
  • the wellbore may be a deviated well formed from a lateral drilling operation. More preferably, the wellbore is completed horizontally as shown in Figure 13.
  • the methods are not limited to the orientation of the wellbore unless expressly stated in the claims.
  • the term“providing” includes but is not limited to“forming” or“completing.”
  • the term“providing” may also mean that a service company accesses a wellbore that has already been drilled and completed, or accesses a wellbore that has been undergoing production operations for a period of time.
  • the method 1400 also includes running a clean-out tool into the wellbore. This is provided in Box 1420.
  • the clean-out tool is run into the wellbore at the lower end of a string of coiled tubing 1340.
  • the clean-out tool may be constructed in accordance with any of the embodiments 100, 200, 1200 described above.
  • the clean-out tool is a multi-cycle tool having a tubular housing that includes an elongated bore. Fluids are pumped from the surface, down the string of coiled tubing, and into the bore.
  • the clean-out tool includes one or more back jetting ports. At least some of the ports are disposed at an upward angle. In this way, injected clean-out fluids flow through the ports and exit the clean-out tool at an upward angle to sweep any particles or debris in the casing toward the surface (or at least upstream).
  • the method 1400 additionally includes locating the clean-out tool. This is seen at Box 1430.
  • the clean-out tool is located at a selected depth along a tubular body within the wellbore.
  • Subsurface formation 1355 of Figure 13 is an example of a location or depth for the clean-out tool.
  • the term“depth” may include“total depth” a selected distance along a horizontal wellbore.
  • the method 1400 further includes pumping a clean-out fluid down the coiled tubing string.
  • the fluid is a hydraulic fluid that is pumped into the wellbore under pressure.
  • the fluid is pumped down the coiled tubing and into the bore of the tubular housing making up the clean-out tool at a first flow rate.
  • the first flow rate is below an activation rate.
  • the pumping at the first flow rate causes at least a portion of clean-out fluid to flow through the mandrel, through radial slots, back up the lower annular region and through the back jetting ports.
  • This step of Box 1440 is illustrated in Figure 12A.
  • the method 1400 also includes further pumping the clean-out fluid down the coiled tubing and into the bore of the tubular housing at a second flow rate.
  • the second flow rate is higher than the first flow rate.
  • the higher flow rate increases a hydraulic force acting on a pressure shoulder of a piston, causing a mandrel and connected plunger to slide along a tubular housing such that the plunger passes along a through-opening in the seat.
  • the radial slots in the plunger move below the seat.
  • the result is that all of the injected clean-out fluid now flows through a distal end of the tool.
  • This step of Box 1450 is illustrated in Figure 12C.
  • a sequencing mechanism be placed along the tubular housing.
  • the sequencing mechanism may be a J-slot mechanism.
  • the J-slot mechanism may be configured to cycle between three settings. Those include:
  • the second increased rate is an activation rate.
  • the pump rate in both the second setting and the third setting may be higher than the activation rate.
  • Additional steps may be taken in connection with the method 1400. These relate to tuning the various openings along the tool in order to provide a desired total cross-sectional area of fluid flow. Such steps are presented in Box 1460.
  • Box 1460 may include a step of adjusting an aperture size of an orifice associated with the piston. This has the effect of varying flow rates associated with the raised and lowered positions.
  • the piston orifice needs to be sized small enough to ensure the required activation rate will be achievable during the operation.
  • the clean-out tool will change modes correctly, sizing the piston orifice too small for a planned pump-rate will cause excessive and unnecessary pressure drop that may limit the total flow capacity of the operation in back-jetting mode.
  • the piston orifice is sized appropriately to ensure the activation rate will be achievable in both modes throughout the operation with minimal back-pressure.
  • the step of Box 1460 may also include adjusting a through-opening size of an orifice associated with the seat.
  • the orifice is part of a stem placed within the seat.
  • the step of Box 1460 may include adjusting a through-opening size at the bottom of the plunger.
  • a larger through-opening enables more working fluid to flow through the bore of the clean-out tool and less fluid to back flow to the back jetting ports during back-jetting mode.
  • a smaller through-opening allows less fluid to flow through the bore of the clean-out tool and more fluid to back flow to the back jetting ports during back-jetting (or“clean-out”) mode.
  • Box 1460 may also include a step of adjusting a size of the back jetting ports.
  • the back jetting ports When used with a clean-out tool below the seat, such as a HelixTM nozzle, the back jetting ports should be sized large enough to provide a significantly reduced pressure drop to enable increasing the annular velocity and desirable rate split between the back-jet housing and the Helix while in back-jetting mode. At the same time, the ports should be small enough to provide ample flow restriction for effective jetting.
  • the Box 1460 may include the step of selecting a cross-sectional area for the flow through the radial slots in the stem. The process of selecting total cross-sectional areas through which clean-out fluids may flow is shown in Box 1460.
  • Box 1460 is shown at the end of the flow chart for the method 1400 of Figure 14, it is understood that these steps may and likely will be taken during tool design and before the tool is run into the wellbore in Box 1420.
  • unique multi-cycle wellbore clean-out tools have been provided.
  • the clean-out tools act as a flow diverter that increases the efficiency of fill removal operations. Fluid flow can also be sent through the tool to an optional bottom hole assembly below while having fluid communication with a back-jetting housing.
  • the cycling of fluid flow modes is possible an unlimited number of times and does not require dropping a ball or reversing circulation.
  • the modes of the clean-out tool may be manipulated through a combination of flow rate and sequence. Feedback is received at the surface through pump pressure indication. In a first setting, flow rate to the clean-out tool is below an activation rate. This allows the fluid flow to be in communication with the back jet housing as well as a nozzle or any bottom hole assembly or other tool that may be placed below the clean-out tool. In other words, the flow is split between the back jetting ports and a downstream nozzle. This is shown in Figures 1A, 2A and 12A as well as Figure 4A.
  • An activation rate is selected for moving the clean-out tool from its first setting to a second setting. In the second setting, the mandrel and connected plunger begin to slide down the tubular housing towards the seat.
  • the activation rate is based on orifice cross-sectional area selection and may be pre-determined for a specific application.
  • the plunger will not pass through the seat; instead, downward movement will be restricted by the sequencing mechanism.
  • the use of a sequencing mechanism for cycling allows the operator to pump at a high flow rate (that is, above the activation rate) during back-jetting mode, increasing annular velocity for fill removal in the second setting. Additionally, orientation and selected cross-sectional area of the ports in the back-jetting housing aids in sweeping solids from the casing. This is shown in Figures IB, 2B and 12B as well as Figure 4B.
  • the clean-out tool 1200 will need to be configured to provide a difference in pressures between a majority of the flow rate being directed to the back-jetting ports versus through to the bottom-hole assembly below. In this way, a surface indication of the clean-out tool’s mode may be detected.
  • the flow rate may be reduced to a minimum pump-rate until pump pressure has stabilized.
  • the tool will remain in back-jetting mode ( Figures IB, 2B and 12B) following a subsequent increase in flow rates, even above the activation rate.
  • the tool will continue to remain in this back-jetting mode when the flowrate is lowered down to the minimum pump-rate ( Figures 1A, 2A and 12A).
  • an improved flow diverter tool 100, 200, 1200 for wellbore clean out operations has been provided.
  • the tool can be used for almost any coiled tubing application wherein fluid is circulated downhole.
  • the clean-out tool is part of a bottom hole assembly that includes a downhole tool.
  • the downhole tool is threadedly (or otherwise operatively) connected to the lower end of the lower sub.
  • An upper end of the lower sub supports or is abutted against or otherwise resides proximate to the seat.
  • the downhole tool is a positive displacement motor.
  • the positive displacement motor is configured to rotate a connected mill bit in response to hydraulic pressure received when the clean-out tool is in its clean-out mode.
  • the downhole tool is a positive displacement motor, such as motor 300 and is used for a milling operation.
  • milling operations are used to remove scale, cement or consolidated fill in a wellbore. Milling operations may also be conducted to remove plugs that have been placed in the well bore. For milling, the operator may mill a first plug using the fluid flow-through mode, then switch the tool to back to its back-jetting mode to circulate out cuttings at a higher rate. The tool can then be cycled back to the fluid flow-through mode and continue to the next plug for milling again. The tool allows for higher circulation rates without over-running the motor, achieving higher annular velocities.
  • a nozzle may be placed below the flow diverter tool.
  • the nozzle may be any type of nozzle such as a so-called wash nozzle, a hydraulic jetting nozzle, a high pressure rotary nozzle or a pulsating wash tool.
  • the nozzle serves to agitate fill that may have collected in the wellbore, facilitating clean-out in the wellbore while the tool is translated.
  • nozzles alternative to the HelixTM nozzle mentioned above may be used below the clean-out tool 100, 200, 1200.
  • a nozzle for jet drilling such as is disclosed in U.S. Patent No. 6,668,948 may be used.
  • any of the rotary nozzles as disclosed in U.S. Patent Publ. No. 2016/0160619 may be employed.
  • the internally rotating nozzle of U.S. Patent No. 9,845,641 may be used.
  • the lower sub may be threadedly connected to a bottom hole assembly that includes a sliding sleeve shifting tool.
  • the clean-out tool allows the operator to generate a back jetting flow rate above the activation rate of the sliding sleeve shifting tool for wellbore cleanout while the bottom hole assembly is in the wellbore. This may be done without prematurely activating the sliding sleeve shifting tool.
  • the sliding sleeve shifting tool may be part of a BHA containing an extended reach tool, such as an NOV ® agitator tool.
  • Wellbore clean-out can be conducted to a target depth before activating the sliding sleeve shifting tool at its activation rate.
  • Figure 3B presents an example of a suitable sliding sleeve shifting tool 300B. This illustrative tool 300B is a bi-directional shifting tool that is available from Hunting Energy Services, LLC of Houston, Texas.
  • the flow diverter tool 100, 200, 1200 is run into a lateral bore hole.
  • a whipstock is placed immediately below the lateral bore hole and the flow diverter tool is then run into the wellbore and against the concave face of the whipstock.
  • the flow diverter tool 100, 200, 1200 may also be used in connection with drilling operations. Specifically, the tool can be placed along a coiled tubing string wherein a well is being deepened, or wherein a side tracking operation is being conducted. In operation, the operator drills out a section of the well with the flow diverter tool in the fluid flow-through mode using a milling tool or a drill bit. The operator then switches the tool to its back-jetting mode and circulates out cuttings at a higher pumping rate. The operator then switches back to the fluid flow-through mode and drills another section of the wellbore. In a drilling operation, the tool again allows for higher circulation rates without over running the motor, achieving higher annular clean-out velocities.
  • the flow diverter tool 100, 200, 1200 may further be used with a back pressure valve during underbalanced situations.
  • the operator may use a column of nitrogen to lighten the hydrostatic head. After milling a plug and any fill that is encountered, the operator switches back to the back-jetting mode. During this mode, the operator can circulate nitrified fluid down the working string without circulating through the motor. It is noted that with many motors, nitrogen can shorten the life of the stator. Upon circulating the string back to fluid again the operator can switch modes and continue the milling operation.
  • the flow diverter tool 100, 200, 1200 can also be run with setting tools or shifting tools. These include sliding sleeves and multi-stage firac sleeves.
  • the flow diverter tool allows high clean-out circulations rates without activating a completion tool below, e.g., circulating above a shifting tool at a rate above the activation rate of the shifting tool— without the possibility of activating the shifting mechanism in the tool.
  • the operator may set a resettable bridge plug for a multi-stage fracturing operation with the flow diverter tool 100, 200, 1200 installed above the resettable bridge plug. In this instance, circulation remains possible through the back jetting ports without activating a hydraulically activated bridge plug below.
  • the flow diverter allows the operator to switch between circulating through the bottom of the plug when the plug is not set, and circulating above the plug when the plug is set.
  • Figure 3C presents an example of a suitable bridge plug 300C.
  • This illustrative tool 300C is a CrownstoneTM GTV tubing-retrievable well barrier (or retrievable bridge plug) that is available from Baker Hughes (a GE Company) also of Houston, Texas.
  • the flow diverter tool 100, 200, 1200 can be run in connection with an acid stimulation operation.
  • a high pressure jetting tool may be run below the flow diverter to remove scale, or clean perforations prior to acidizing. If the rate the formation takes the stimulation fluid is not a limiting factor, the tool can be shifted to divert flow to the larger back jet ports and the rate at which the job is pumped can be increased reducing time and increasing efficiency.
  • a back pressure valve may also be useful where a sensitive tool is positioned on the tool string below the flow diverter, and the operator wishes to ensure that the sensitive tool will not activate when in back-jetting mode.
  • any operation where a tool below may restrict the amount of flow that is reasonably possible with the current work string.
  • the tool can increase operational efficiency by either eliminating unneeded trips out of the hole to change tools or reduce operational time by allowing the operator to increase the flow rate and subsequently complete the job faster.

Abstract

L'invention concerne un outil de nettoyage et un procédé de nettoyage d'un puits de forage. L'outil de nettoyage est placé à l'extrémité d'un tube spiralé ou d'un autre train de tiges d'acheminement. L'outil de nettoyage comprend un logement tubulaire établissant un alésage allongé à travers lequel s'écoule le fluide. Le logement tubulaire comporte des orifices de lançage inverse disposés en son sein à un certain angle vers le haut. L'outil de nettoyage est conçu pour fonctionner dans un mode de lançage inverse lorsque le fluide de nettoyage est pompé dans le logement tubulaire à un premier débit. Dans ce mode, au moins une partie du fluide de nettoyage s'écoule à travers l'alésage, jusqu'à une région annulaire, puis à travers les orifices de lançage inverse. L'outil de nettoyage est en outre conçu pour fonctionner dans un mode d'écoulement traversant de fluide lorsque les fluides de nettoyage sont pompés dans l'alésage du logement tubulaire à un second débit. Dans ce mode, la totalité du fluide de nettoyage s'écoule à travers l'outil de nettoyage.
PCT/IB2020/000161 2019-02-20 2020-02-13 Outil de nettoyage de puits de forage multi-cylcle WO2020170044A1 (fr)

Applications Claiming Priority (6)

Application Number Priority Date Filing Date Title
US16/280,364 US10907447B2 (en) 2018-05-27 2019-02-20 Multi-cycle wellbore clean-out tool
US16/280,364 2019-02-20
US201962902471P 2019-09-19 2019-09-19
US62/902,471 2019-09-19
US16/686,955 US10927623B2 (en) 2018-05-27 2019-11-18 Multi-cycle wellbore clean-out tool
US16/686,955 2019-11-18

Publications (1)

Publication Number Publication Date
WO2020170044A1 true WO2020170044A1 (fr) 2020-08-27

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Citations (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20110203847A1 (en) * 2010-02-25 2011-08-25 Randall Bruce L Downhole Hydraulic Jetting Assembly, and Method for Stimulating a Production Wellbore
US9115558B2 (en) * 2010-07-23 2015-08-25 Stang Technologies Ltd. Apparatus and method for abrasive perforating and cleanout
US20180371857A1 (en) * 2017-06-22 2018-12-27 Unseated Tools LLC Unseating Tool For Downhole Standing Valve

Patent Citations (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20110203847A1 (en) * 2010-02-25 2011-08-25 Randall Bruce L Downhole Hydraulic Jetting Assembly, and Method for Stimulating a Production Wellbore
US9115558B2 (en) * 2010-07-23 2015-08-25 Stang Technologies Ltd. Apparatus and method for abrasive perforating and cleanout
US20180371857A1 (en) * 2017-06-22 2018-12-27 Unseated Tools LLC Unseating Tool For Downhole Standing Valve

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