Apparatus and method for abrasive perforating and clean-out

A perforating tool and method of use in a wellbore. The perforating tool is placed at the end of a coiled tubing or other conveyance string. The perforating tool comprises a tubular housing providing an elongated bore through which fluid flows. The tubular housing has jetting ports used for hydraulic perforating. The tool operates in a flow-through mode when working fluid is pumped into the tubular housing at a first flow rate, with all of the fluid flowing through the end of the tool. The perforating tool operates in a perforating mode when the working fluid is pumped into the bore of the tubular housing at a second flow rate. In this mode, all of the working fluid flows through the jetting ports. The perforating tool may include a sequencing mechanism responsive to a sequence of flow rates to cycle the tool through operating modes.

Each of these applications is incorporated herein in its entirety by reference

Not applicable.

THE NAMES OF THE PARTIES TO A JOINT RESEARCH AGREEMENT

Not applicable.

BACKGROUND OF THE INVENTION

Field of the Invention

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.

Discussion of Technology

During the course of a well operation, it is sometimes desirable to clean out the wellbore. For example, after a well is completed and before a string of production tubing is hung, the operator may wish to run a clean-out tool down the hole to circulate out cement chips, sand, and other debris. In addition, it is sometimes desirable to clean out a producing well that has become filled with sand. Such incidents may occur because the well is producing from an unconsolidated formation, or due to a poorly designed fracturing operation.

In either of these instances, 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. Preferably, 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. 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 and the use of detonators and gun barrels.

Some abrasive perforating tools frequently offer a clean-out function using reverse circulation. In one aspect, an abrasive perforating tool may be part of a bottom hole assembly containing a reverse ball check valve. The BHA components include a 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 FIG. 1 of U.S. Pat. No. 9,115,558.

The reverse ball check valve of the '558 patent includes a pin and a ball. 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.

To perform the reverse clean-out, an aqueous fluid is injected down the back side of the coiled tubing. The fluid is pumped downhole where it then flows back up the BHA, through the reverse ball check valve, through the bore of the coiled tubing string and to the surface. The fluid returns will include the abrasive fluid used in the perforating process. A somewhat schematic reverse clean-out flow for a BHA having a known reverse ball check valve is shown in FIG. 2 of the same '558 patent.

As described in greater detail in the '558 patent, the use of reverse flow clean-out valves is often impractical in connection with horizontal wellbores. This is because of the significant likelihood of fill material gathering around the outer diameter of the BHA during the reverse circulation phase. In this respect, the BHA cannot take advantage of gravity to bring the fill material down to the nozzle as is present in a vertical well. Depending on the size of the wellbore, the length of the horizontal leg of the well and the cleanout medium used, 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.

Due to this limitation, the '558 patent disclosed a novel abrasive perforating tool capable of being cycled during pumping operations to provide clean-out. This allows for a multi-cycle adjustment of tool function carried out by manipulating pumping rates. The '558 patent is incorporated herein it its entirety by reference.

The abrasive perforating tool of the '558 patent utilizes a plunger that is moved up and down in response to pumping rates applied at the surface. Depending on the pumping mode, the tool operates in either a flow-through mode where the plunger resides above a seat, or a perforating mode, where the plunger lands on the seat. In the flow-through mode, working fluids are circulated around the plunger, through the seat, and then back up the wellbore along the back side of the coiled tubing string. In the perforating mode, all fluids are forced through lateral nozzles and are directed against the surrounding casing. Beneficially, fluids can be pumped down the bore of the working string and through an end nozzle in the same direction for both abrasive perforating and for clean-out, using a cycling mechanism.

A need exists for an improved abrasive perforating tool that operates with a similar cycling mechanism for wellbore clean-out, but wherein a feature is provided to ensure that circulating fluids do not exit the tool through the lateral nozzles while the tool is in its flow-through mode. Stated another way, a need exists for a multi-cycle wellbore perforating tool that does not offer, as an option, split flow. A need further exists for a method of cleaning out a well, wherein a positive displacement motor is disposed below a perforating tool, with the motor taking advantage of a full flow of fluids moving through the seat during a flow-through mode.

SUMMARY OF THE INVENTION

An abrasive perforating tool for controlling a direction of an injected fluid within a wellbore is first provided herein. The perforating tool is configured to cycle between a flow-through mode wherein all fluid is pumped under pressure through the tool and then circulated back up to the surface on the back side of the tool, and a perforating mode wherein an abrasive fluid is pumped under pressure into the tool and through lateral jetting ports to cut or “perforate” a surrounding casing string.

The perforating tool first includes a tubular housing. The tubular housing defines a series of tubular bodies threadedly connected end-to-end. The tubular housing provides an elongated bore through which fluid may flow. The tubular housing includes one or more jetting ports disposed there along. The jetting ports are designed to receive the abrasive fluid when the tool is in a perforating mode.

The perforating tool also includes a piston. The piston defines a short cylindrical body that is disposed at an upstream end of the housing. The piston has an orifice configured to deliver fluids from a wellbore conveyance tubing to the elongated bore of the housing. Of interest, the piston forms a pressure shoulder as fluids are injected through the conveyance tubing.

The perforating 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 a distal end comprising a plunger. In one embodiment, the plunger is a separate body threadedly connected to the distal end of the mandrel.

As part of the tubular housing, The perforating tool may comprise a spring housing. The spring housing has an internal shoulder that supports a spring. An upper end of the spring acts against the piston, biasing the piston and connected mandrel in the raised position. This is a flow-through mode.

The perforating tool further includes a seat. The seat is disposed along the tubular housing below the distal end of the tubular mandrel. The seat 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. Of interest, the seat provides a central flow-through opening through which fluids flow when the tool is in its flow-through mode.

Preferably, the tubular housing further includes an upper sub having a first upper end and a second lower end, wherein the lower end is threadedly connected to an upper end of the spring housing. Preferably, the tubular housing also includes a lower sub having a first upper end and a lower end, with the lower end being threadedly connected to a downhole rotary tool.

In one aspect, the wellbore clean-out tool further comprises:an annular region formed between the mandrel and the surrounding tubular housing;one or more slots residing along the mandrel;one or more flow ports also residing along the mandrel, but below the slots;an upper seal residing along an inner diameter of the tubular housing; anda separate lower seal also residing along the inner diameter of the tubular housing, wherein the upper and lower seals straddle the jetting ports.

When the perforating tool is in its raised position, pumped fluid exits the mandrel through the flow ports, but the lower seal prevents the pumped fluid from flowing all the way up the annular region and to the jetting ports, thereby forcing all of the fluid to flow around the plunger and through the seat. Reciprocally, when the perforating tool is in its lowered position, abrasive fluid exits the mandrel through the slots, with the abrasive fluid being confined by the upper and lower seals to flow through the jetting ports.

The perforating tool is configured to cycle a position of the mandrel and connected plunger in response to fluid pumping rate into the wellbore. Preferably, the tool is configured to cycle between two operating modes—a flow-through (or a clean-out) mode and a perforating mode. All fluid flows through the flow-through opening in the seat when the mandrel and connected plunger are in the raised position, which is the flow-through mode. Reciprocally, all fluid flows through the jetting ports when the mandrel and connected plunger are in the lowered position, which is the abrasive perforating position.

In one embodiment, a positive displacement motor is disposed below the tubular housing as the rotary tool. The positive displacement motor is operatively connected to the lower sub at its distal end. The positive displacement motor, in turn, is connected to a milling tool or a drill bit.

In the flow-through mode, fluid is pumped into the bore of the tubular housing at a first flow rate. In this mode, all of the pumped fluid flows into the mandrel, through flow ports located along the mandrel, around the plunger, and then through the flow-through opening in the seat.

In the perforating mode, the fluid is pumped into the bore of the tubular housing at a second higher flow rate. In this mode, all of the pumped fluid flows into the mandrel, through the slots located along the mandrel, and then through the jetting ports. In this instance, the pumped fluid is preferably mixed with sand, forming an abrasive perforating fluid.

In the preferred embodiment, 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 fluid to travel through the flow ports in the mandrel and through the seat below. Once the pump rate is raised to an activation rate (referred to in some instances herein as the “second flow rate”), the plunger is lowered onto the seat, providing for the perforating mode. The upper and lower seals serve to direct flow in the two modes, ensuring that there is no split flow.

To facilitate the cycling of injection modes, the abrasive perforating tool may also include a sequencing mechanism. The sequencing mechanism is responsive to a sequence of pump rates applied above the piston. In one aspect, the sequencing mechanism comprises a cylindrical body configured to cycle the mandrel between its flow-through mode (wherein all fluid flows through the seat at the end of the tool) and its perforating mode (wherein all fluid is directed laterally through the jetting ports). In one aspect, 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 flow-through mode.

Preferably, 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. In this instance, 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.

A method of operating an abrasive perforating tool in a wellbore is also provided. The method first includes running a multi-cycle perforating tool into the wellbore. The perforating tool is run in on a lower end of a string of coiled tubing. The perforating tool is arranged in accordance with the perforating tool as described above, in any of its embodiments.

The method additionally includes locating the perforating tool at a selected depth along the wellbore. In one aspect, the wellbore has been completed with a string of production tubing. In this instance, the perforating tool is run into the production tubing in order to clean out fill that may have accumulated within the production tubing and casing. More preferably, the perforating tool is run into production casing during well completion, enabling the tool to both mill out plugs or clean out wellbore debris, and perforate casing. It is observed that the tool is particularly suited for clean-out operations or tool setting operations along a horizontal section of a wellbore.

The method further includes pumping a working 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 the pumped fluid to flow through the bore of the tubular housing, out of the mandrel through radial flow ports and into the annular area, around the plunger, and then through the flow-through opening in the seat. In other words, the pumped fluid flows entirely through the end of the tool. This is a flow-through mode.

The method also includes further pumping the working fluid down the coiled tubing and into the bore of the tubular housing at a second flow rate. Here, 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.

As the mandrel and connected plunger move down the tubular housing, the plunger will land on the seat, sealing flow through the flow-through opening. In this position, the fluid will flow down the mandrel, through slots in the mandrel and into the annular area, and then through the lateral jetting ports. This is a perforating mode. Of interest, in this position the upper and lower seals confine the fluid so that all working fluid exits the tool through the lateral jetting ports. In this mode, the pumped fluid will likely include sand.

In one aspect, the perforating tool employs a sequencing mechanism to cycle the tool between positions. Preferably, the sequencing mechanism is a so-called J-slot mechanism. In one aspect, the J-slot mechanism has slots that cycle the plunger between the flow-through mode and the perforating mode. Specifically, the J-slot mechanism is configured to:(i) maintain the perforating tool in its raised position while pumping at or below the first pump rate, placing the perforating tool in its flow-through mode wherein all of the pumped fluid flows through the bottom of the tool;(ii) maintain the perforating tool in an intermediate position while increasing pump rate above the first pump rate (which may meet or exceed a second pump rate), and wherein all of the pumped fluid continues to flow through the mandrel and out of the bottom of the tool;(iii) upon dropping the pump rate back down to or below the first pump rate, allowing the spring to move the perforating tool back to its raised position, which again is the flow-through mode;(iv) upon raising the pump rate to a rate that meets or exceeds the second pump rate, move the perforating tool to its lowered position, placing the perforating tool in its perforating mode wherein all pumped fluid is forced through the lateral jetting nozzles; and(v) repeat the cycle of steps (i) through (iv), such as at a different depth.

A second embodiment of a perforating tool is also provided herein. The perforating tool is again used for controlling a direction of a working fluid within a wellbore, with the wellbore having been lined with a string of production casing. In this embodiment, the perforating tool comprises:a tubular housing providing an elongated bore through which fluids may be injected, the tubular housing having one or more lateral jetting ports;a piston disposed proximate an upstream end of the housing, the piston forming a pressure shoulder and having an orifice configured to deliver the working fluid from a wellbore conveyance tubing into the elongated bore of the housing;a tubular mandrel slidably positioned within the housing, the mandrel having a proximal end connected to or acted upon by the piston, and a distal end forming a plunger;one or more flow ports; anda seat disposed along the tubular housing and having a through-opening, the through-opening being configured to slidably receive the plunger when the piston and connected mandrel slide from a raised position to a lowered position along the tubular housing.

In this arrangement, the perforating tool is configured to cycle a position of the mandrel and connected plunger in response to changes in fluid pumping rate into the conveyance tubing. The tool is biased to an abrasive perforating position such that (i) all working fluid flows through the flow ports in the mandrel and out of the lateral jetting ports in the tubular housing above the seat when the mandrel and connected plunger are in the raised position. In response to an increase in pump rate (ii) all working fluid flows through the flow ports and out of the tubular housing below the seat when the mandrel and connected plunger are in the lowered position.

The plunger comprises a solid body that is operatively connected to the distal end of the mandrel. Preferably, the perforating tool further comprises a stem wherein an upper end of the stem is threadedly connected to a lower end of the mandrel, and the plunger resides at a lower end of the stem. In this instance, the one or more flow ports comprises two or more flow ports radially disposed around the stem proximate to and above the plunger.

In one aspect, the tubular housing comprises a spring housing having an internal shoulder. The perforating tool then further comprises a spring residing within the spring housing, with an upper end of the spring acting against the piston, biasing the tool in its raised position.

In one arrangement, the tubular housing further comprises an upper sub having a first upper end and a second lower end, wherein the lower end is threadedly connected to an upper end of the spring housing, and a lower sub having a first upper end and a lower end, with the lower end being threadedly connected to a downhole tool. In this way, the perforating tool is part of a larger bottom hole assembly, or BHA.

DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS

Definitions

For purposes of the present application, it will be understood that the term “hydrocarbon” refers to an organic compound that includes primarily, if not exclusively, the elements hydrogen and carbon. Examples of hydrocarbon-containing materials include any form of oil, natural gas, coal, and bitumen that can be used as a fuel or upgraded into a fuel.

As used herein, the term “hydrocarbon fluids” refers to a hydrocarbon or mixtures of hydrocarbons that are gases or liquids. For example, 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.

As used herein, 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.

As used herein, the term “fluid” generally 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.

As used herein, the term “wellbore fluids” means water, hydrocarbon fluids, formation fluids, or any other fluids that may be within a wellbore during a production operation.

As used herein, 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.

As used herein, 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.”

As used herein, the term “subsurface” refers to geologic strata occurring below the earth's surface.

The terms “zone” or “zone of interest” refer to a portion of a formation containing hydrocarbons. Sometimes, the terms “target zone,” “pay zone,” or “interval” may be used.

As used herein, the terms “working fluid” and “clean-out fluid” refer to any fluid that may be pumped into a wellbore in connection with a downhole flow-diverter tool. Such fluids may include aqueous fluids, fluids containing an abrasive material used for perforating casing, a hardware treating fluid, or a fluid containing a surfactant.

The terms “tubular” or “tubular member” refer to any pipe, such as a joint of casing, a portion of a liner, a joint of tubing, a pup joint, or coiled tubing. The terms “production tubing” or “tubing joints” refer to any string of pipe through which reservoir fluids are produced.

Description of Specific Embodiments

The present disclosure relates to hydraulic clean-out operations for pipe. The tools and methods disclosed herein are ideally suited for wellbore operations, including using the perforating tool in combination with a downhole positive displacement motor and mill bit.

FIG. 1Ais a cross-sectional view of a wellbore clean-out tool100of the present invention, in one embodiment. In some cases herein, the perforating tool100may be referred to as a flow diverter. The perforating tool100is used to inject fluids into a wellbore for clean-out and for abrasive perforating. An illustrative wellbore is shown at1000inFIG. 10and is discussed below.

The perforating tool100defines a generally tubular body formed from a series of components. As shown, the perforating tool100has a first (or upstream) end102and a second (or downstream) end104. A central bore105is formed within the body extending from the first end102to the second end104.

As will be discussed, the perforating tool100is configured to cycle or otherwise move a position of a mandrel155and a connected plunger160within the tubular body, in response to fluid pumping rates into the wellbore1000by an operator. In this way, a flow of working fluid through the tool100may be adjusted. In the view ofFIG. 1A, the perforating tool100is in its run-in position wherein all of the injected fluid flows through the tool100from the top (or upstream) end102to the bottom (or downstream) end104en route to a next downhole tool or to the bottom of the wellbore1000or to a plug, as the case may be. Specifically, the fluid will flow into the bore105, out of the mandrel155through side ports185, then through an annular area145around the plunger160, and through a seat170.

Of interest, a lower seal164resides along a lower mandrel seal sub160and inside of a jetting port housing140. This is just above the flow ports185. A seal164prevents working fluids from flowing up the annular area145to a level of lateral jetting nozzles (or jetting ports)148when the tool100is in its flow-through mode.

The perforating tool100is comprised of a series of tubular bodies that are threadedly connected end-to-end. A first of these represents a top sub110. The top sub110defines a tubular body wherein a first (or upstream) end112comprises female threads while a second (or downstream) end114comprises male threads. The female threads are configured to threadedly connect to a CT connector (not shown), which in turn is connected to a string of coiled tubing (or other conveyance medium).

The perforating tool100next includes a spring housing120. The spring housing120also defines a generally tubular body wherein a first end122comprises female threads while a second opposite end124comprises male threads. The first end122of the spring housing120threadedly connects to the second (or downstream) end114of the top sub110.

The perforating tool100also includes a spring125. The spring125resides along an inner diameter of the spring housing120. The spring125is held in compression within the tool100. In one aspect, the spring125is an Inconel® spring. Alternatively, the spring material is 17-7 stainless steel. Of interest, a shoulder126resides along an inner diameter of the spring housing120. The shoulder126serves as a face against which the spring125resides.

Moving down the tool100, the perforating tool100next includes an upper mandrel seal sub130. The upper mandrel seal sub130also defines a generally tubular body wherein a first (or upstream) end132comprises female threads while a second opposite (or downstream) end134comprises male threads. The upstream end132threadedly connects to the second (or downstream) end124of the spring housing120. Of interest, the upper mandrel seal sub130encompasses a sequencing mechanism400, discussed below.

The perforating tool100also comprises a jetting port housing140. The jetting port housing140also defines a generally tubular body wherein a first (or upstream) end142comprises female threads while a second (or downstream) opposite end144also comprises female threads. The jetting port housing140resides downstream from the upper mandrel seal sub130. Specifically, the first end142of the jetting port housing140threadedly connects to the second end134of the upper mandrel seal sub130.

Of importance, the jetting port housing140comprises one or more jetting ports148. Preferably, the jetting ports148are placed within the jetting port housing140at a 90° angle, or transverse to a longitudinal axis of the tool100. In this way, when the tool100is in its perforating mode, jetting fluid may exit the jetting port housing140directly at the surrounding casing to be perforated. Preferably, a plurality of lateral jetting ports148are placed radially around the jetting port housing140along at least two levels.

As a next component, the perforating tool100includes a lower mandrel seal sub180. The lower seal sub180defines a generally tubular body that is essentially a mirror image of the upper mandrel seal sub130. Seal subs130and180are the same component, but with sub160being turned upside down. An upper end182of the lower seal sub180is threadedly connected to the lower end144of the jetting port housing140.

Below the lower seal sub180is a bottom sub190. The bottom sub190also defines a tubular body having an upper end192and a lower end194. The upper end192comprises male threads that connect to a female bottom end184of the lower mandrel seal sub180. The bottom sub190forms a bore195that is in fluid communication with and forms a part of the bore105.

The top sub110, the spring housing120, the upper mandrel seal sub130, the jetting port housing140, the lower mandrel seal sub180and the bottom sub190together make up a tubular housing for the perforating tool100.

The perforating tool100additionally includes a piston assembly150. The piston assembly150defines a series of components that are configured to slide together along the spring housing120in response to fluid pressure. The piston assembly150includes an orifice retainer151, a piston body156, a piston orifice153and a piston scraper retainer157. The piston assembly150essentially serves as a pressure shoulder, moving down the spring housing120in response to fluid pressure applied from the surface.

It is observed here that while it is pressure that moves the piston assembly150down, it is also accurate to refer to changes in flow rate that actuate the piston assembly150. This is because the piston orifice153is configured according to a desired flow rate to cause the tool100to change between operational modes. In this respect, the orifice153is sized to generate the required differential pressure across itself to function. External pressures do not have an impact on the piston assembly150; only pressure from the flow rate through the orifice153changes the tool mode.

The orifice retainer151secures the piston assembly150in place below the top sub110. Specifically, the orifice retainer151abuts the lower end114of the top sub110to prevent the piston assembly150from moving further upstream. Various o-rings (not numbered) may be disposed around the piston body156and the piston orifice153to prevent pressure communication between the area above the piston assembly150and below the piston assembly150. Additional details concerning the piston assembly150are provided below in connection withFIGS. 8A through 8C.

As stated above, the piston assembly150is operatively connected to a mandrel155. The mandrel155has an upper (or upstream) end152connected to (or acted upon by) the piston assembly150, and a lower (or downstream) end154. The upper end152of the mandrel155is threadedly connected to the piston body156. The piston assembly150and connected mandrel155reside within the inner diameter of the spring housing120. Of interest, an upper end of the spring125acts against the piston scraper retainer157, biasing the piston assembly150against the top sub110.

In operation, hydraulic pressure (generated by fluid flow through the piston orifice153) acts on the shoulder that is the upper side of the piston assembly150above the piston orifice153. In response, the piston assembly150and connected mandrel155move down the tubular housing110together. Specifically, the piston assembly150(and connected mandrel155) moves from its raised position (shown inFIG. 1A), to a lowered position (shown inFIG. 2A).

It is noted that the spring125resides in an annular region formed between the mandrel155and the surrounding spring housing120. This first annular region is pressure-balanced via ports159in the mandrel155. These ports let the fluid volume inside the spring housing120change as the piston assembly150moves up and down.

A second annular area145is reserved between the mandrel155and the surrounding jetting port housing140. A pair of annular seals162,164resides within the annular area145. The seals162,164may be mechanically or adhesively affixed to inner diameters of the upper mandrel seal sub130and the lower mandrel seal sub180, respectively. Thus, the seals162,164do not slide along the bore105with the mandrel155.

It is observed that the seals represent an upper seal162and a lower seal164. The two seals162,164straddle the jetting ports148along the jetting port housing140.

At the lower end154of the mandrel155is a plunger160. The plunger160defines a short body that is configured to sealingly land onto a seat170(described below). An upper end162of the plunger160is connected to the lower end154of the mandrel155. In this way, the plunger160moves up and down along the bore105of the perforating tool100with the mandrel155.

The mandrel155also includes one or more flow ports185. The flow ports185preferably reside immediately above the plunger160. The flow ports185provide fluid communication between the bore105of the tool100and the annular region145when the wellbore clean-out tool100is in its flow-through mode.

Finally, the perforating tool100comprises a seat170. The seat170defines a short tubular body having a flow-through opening175. The seat170is configured to sealingly receive the plunger160when the piston body150is moved to a lowered position (seen inFIG. 2A). Of interest, the opening175is sized to provide little to no restriction in downhole fluid flow when the plunger160is in the flow-through mode ofFIG. 1A.

In the view ofFIG. 1A, the piston body150is at is uppermost position. This is its default (or raised) position wherein the orifice retainer155is abutting the lower end114of the top sub110. As noted, the piston body150is held in this default position due to the upward mechanical force provided by the spring125.

A piston o-ring may be disposed around the piston body156to prevent pressure communication between the area above the piston body156and below the piston body156when fluid is passing through the orifice153. Additionally, an orifice o-ring may be disposed around the orifice153to prevent pressure communication between the area above the orifice153and below the orifice153when fluid is passing through the orifice153.

In the raised position ofFIG. 1A, fluid is injected by an operator into the bore105of the perforating tool100under a first pressure. The first pressure correlates to a first flow rate. Those of ordinary skill in the art will understand that there is a correlation between flow rate, tubular dimension and pressure. At the first flow rate, the hydraulic pressure acting on the piston assembly150is not great enough to cause the piston assembly150to compress the spring125.

In the position ofFIG. 1A, the plunger160remains in its raised position above the seat. As working fluid is injected into the wellbore1000at the first flow rate, fluid will pass through the bore105of the tool100, through the flow ports185, into the annular region145, around the plunger160, and then down through the flow-through opening175of the seat170.

FIG. 1Bis another cross-sectional view of the perforating tool100ofFIG. 1A. In this view, line50A is provided to demonstrate a path of the injected fluids for the tool in its flow-through mode. Fluids are shown entering the upper end102of the tool100, and then ultimately passing out of the lower end104according to the flow path described immediately above. Of interest, all pumped fluids pass through the flow ports185, into the annular area145, around the plunger160, through the opening175in the seat170, and on to any bottom hole assembly that may reside below the tool100. Beneficially, the lower seal164prevents pumped fluids from flowing back up the annular area145to a level of lateral jetting nozzles (or jetting ports)148when the tool100is in its flow-through mode.

In operation, once the wellbore clean-out tool100is set at a desired depth within the wellbore1000, the operator will begin pumping. During pumping, the operator will increase the pump rate. This will apply a greater hydraulic force to the shoulder of the piston assembly150and will start to overcome the biasing force of the spring125(plus any friction created by o-rings). The piston assembly150, the mandrel155and its connected plunger160will then start to move down the bore105.

The aperture size of the orifice153defines the activation rate. Thus, one aspect of using the abrasive perforating tool100involves the selection of the aperture size of the orifice153. Alternatively or in addition, the operator may select an opening size for the flow ports185and the seat170.

FIG. 1Cis still another cross-sectional view of the perforating tool100ofFIG. 1A. Here, an increase in fluid pumping pressure from the surface is acting on the piston body156, causing the piston body156and connected mandrel155and plunger160to advance down the spring housing120. Stated another way, hydraulic pressure acting on the piston body156overcomes the upward biasing force of the spring125, causing the mandrel155and plunger160to move towards the seat170.

InFIG. 1C, the perforating tool100is in an intermediate position. In this position, all of the injected fluid continues to flow through the end104of the tool100. In this respect, fluids continue to flow through the flow ports185, into the annular area145, around the plunger160, and through the flow-through opening175of the seat170. Lower seal164prevents the fluids from moving up the annular region145and accessing the jetting ports148.

FIG. 2Ais another cross-sectional view of the multi-cycle perforating tool100ofFIG. 1A. Here, the perforating tool100has further translated (that is, has moved down the spring housing120) to its abrasive perforating position. This is done by further increasing the hydraulic force acting on the piston assembly150. Specifically, an increased flow rate from the surface acts on the body156of the piston assembly150.

The increased hydraulic force is achieved by increasing pump rate of the hydraulic fluid into the wellbore from the surface. In response to the increased pressure (or increasing flow rate), the piston body156and operatively connected mandrel155and plunger160have slid down to a position where the lower end164of the plunger160lands on the seat170.

It is observed fromFIG. 2Athat in addition to flow ports185, the mandrel155also includes slots165. The slots165reside higher up the mandrel155, that is, above flow ports185. The slots165also provide fluid communication between the bore105and the annular region145. In the flow-through mode ofFIGS. 1A and 1Ccirculation fluids that flow through the slots165are blocked from leaving the tool100by the upper seal162. However, in the perforating mode ofFIG. 2A, as the mandrel155has moved down, the slots165have moved into a position adjacent the jetting ports148. Thus, abrasive perforating fluids are injected through the slots165and through the jetting ports148.

FIG. 2Bis another cross-sectional view of the multi-cycle abrasive perforating tool100ofFIG. 2A. The perforating tool100again is in its lowered position, or abrasive perforating mode. In this view, line50B is provided to demonstrate a flow path of the perforating fluids for the tool100. Fluids are shown entering the upper end102of the tool100, and then exiting out of the jetting ports148. Of interest, all fluids exit the tool100through the slots165, and are confined to exit through the jetting ports148by the upper162and lower164seals.

It is also observed that in the perforating position ofFIGS. 2A and 2B, fluid communication remains between the bore105and the annular region145through the flow ports185. However, any fluids that exit the flow ports185or that reside in the annular region145below the lower seal164are trapped. Fluids can exit neither the flow-through opening175of the seat170nor the jetting ports148. Thus, complete fluid isolation is provided in both the flow-through mode and the perforation mode, meaning there is no “split flow.”

As described above, the cycling of the tool100between its raised position (FIG. 1A) and its lowered position (FIG. 2A) may be accomplished by applying pumping pressure against the biasing force of the spring125. However, in a more preferred embodiment a mechanical sequencing mechanism is also used. The sequencing mechanism is preferably a J-slot mechanism as shown at400inFIGS. 4A-4D, discussed below. The sequencing mechanism400allows the operator to cycle the flow rates to move the tool100between settings so that:(i) In a first setting, the plunger160is in a raised position in response to the biasing mechanical force exerted by the spring125on the mandrel155, placing the tool in its flow-through mode. This is the view ofFIG. 1A.(ii) In a second setting, the pumping rate is increased and the J-slot mechanism400advances to a next slot, allowing the plunger160to move down to an intermediate position. In the intermediate position, the tool100remains in its flow-through mode, allowing the operator to inject hydraulic fluid into the bore105of the tubular housing110and through the seat170at a second rate, or at any rate higher than the second rate. This is the view ofFIG. 1C.(iii) In the first setting again, hydraulic pumping rate is reduced to its first rate, or any rate below the first rate, allowing the plunger160to return to its raised position. The perforating tool100remains in its flow-through mode.(iv) Finally, in a third setting, the plunger160is forced down into a lowered position in response to the injection of hydraulic fluid through the piston assembly150and into the perforating tool100at a second rate, or at any rate higher than the second rate. The J-slot mechanism400advances to a next slot, placing the perforating tool100in its abrasive perforating mode. This is the view ofFIG. 2A.

Beneficially, in the second setting the operator may ramp up the pumping pressure and be assured that all fluids are passing through the seat. This allows the operator to place a bottom hole assembly at the end of the bottom sub, conducting an additional wellbore function.

An example of such a function is the milling out of a plug or drilling through the bore of a section of horizontal casing that is screened out or contains debris. In this respect, the bottom end194of the sub190is configured to threadedly connect to a separate tool that may be placed in the wellbore1000below the perforating tool100. For example, a positive displacement motor may be placed downstream from the perforating tool100.

FIG. 3Ais a perspective view of a positive displacement motor300A. This provides an example of a rotary tool that may be connected to the bottom sub190. It can be seen that the motor300A includes an elongated tubular body310. The body310defines a fluid in-take end312and a fluid outlet end314. The positive displacement motor300A operates with a rotor and a stator residing within the tubular body310. In one aspect, the positive displacement motor300A is used as an agitator, sending pressure pulses across the wellbore downhole while cleaning. In another aspect, a small drill bit (not shown) is connected to the outlet end314, and is turned by the rotor of the motor300A. The drill bit may be used to mill through plugs or debris.

It is understood that the positive displacement motor300A is merely illustrative; other positive pressure tools may be placed downstream of the seat170.

FIG. 3Eis an example of a mill bit300E that that may be used to mill out a bridge plug or debris within the wellbore.

As noted, to enable the 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.

FIG. 4Ais a side view of a portion of a J-slot mechanism400. It can be seen that a pair of pins482reside in respective lower slots484A. This is a slot position that would correlate with the default, or raised position of the plunger160as presented inFIGS. 1A and 1B. In this position, the pump rate is below the activation rate. This cycle position will allow injected fluid to flow to the flow ports185, sending the fluid on through the bottom end194of the bottom sub190.

FIG. 4Bis another side view of the J-slot mechanism400ofFIG. 4A. In this view, the pins482have advanced one slot484B. In slot484B, the pins482are in an intermediate position. This is a slot position that would correlate to the operator increasing pump rate from the surface as shown inFIG. 1C. In this position, the location of the J-slot pins482restricts the movement of the plunger160while allowing the flow-rate to beneficially move above the activation rate. In other words, the plunger160will not advance along the mandrel155even when the pump rate is well above the activation rate, allowing operation of the positive displacement motor300A.

FIG. 4Cis another side view of the J-slot mechanism400ofFIG. 4A. In this view, the pumping rate has been dropped back below the activation rate, causing the pins482to follow along the channel and to advanced one slot484A. In this position484A, the plunger160has returned to its raised position perFIG. 1A.

FIG. 4Dis still another side view of the J-slot mechanism400ofFIG. 4A. In this view, the pump rate has again been increased above the activation rate, causing the pins482to advance along the channel to a next slot484D. In this position, the plunger160is seated, exposing the slots165to the jetting ports148perFIG. 2A. In this position, the operator may inject at high rates to perforate a surrounding section of production casing.

In operation, the pins482advance from slot-to-slot in response to alternating cycles of the piston body150and connected internals moving longitudinally. The pins482cause the piston assembly150and connected internals to ratchet, or rotate, in a circular path. Also, the component housing the J-slot pin or pins482may ratchet, or rotate, in a circular path. The J-slot grooves (484A) are configured so that the piston body150and connected internals travel is unrestricted in the upward direction so that every time the flow rate is brought below the activation rate the plunger160is in its raised position and cannot seal against the seat170. Additionally, on alternating cycles of the flow rate being brought to or above the activation rate, the J-slot grooves allow the piston body150and connected internals to move down so the plunger160seals against the seat170.

FIG. 5Ais side view of the mandrel155ofFIGS. 1A and 2A. So called J-slots410are visible along the outer diameter of the mandrel155. Also of interest, flow ports185can be seen below the J-slots410while radial slots165can also be seen below the J-slots410.

FIG. 5Bis a cross-sectional view of the mandrel155ofFIG. 5A. In bothFIGS. 5A and 5B, slot484D of the J-slots410is visible. Here, the J-slots410themselves are shown in phantom.

It is understood that the J-slots410ofFIGS. 5A and 5Bare part of the sequencing mechanism400. The J-slots410work in tandem with a J-slot collar (shown at420inFIG. 6A).

FIG. 6Ais cross-sectional view of the J-slot collar420. The J-slot collar420includes a pair of opposing pins482that ride in the J-slots410ofFIG. 5A.

FIG. 6Bis a perspective view of the J-slot collar420ofFIG. 6A. Visible in this view is one of the pins482extending inwardly into a bore425.

FIG. 7is a cross-sectional view of the jetting port housing140ofFIGS. 1A and 2A. The proximal (or upstream) end142and the distal (or downstream) end144are indicated. It is observed that the jetting port housing140defines a wall141forming a bore146. The bore146extends from the proximal142to the distal144end. The jetting ports148are visible in the wall141making up the housing140.

FIG. 8Ais a side view of the piston assembly150ofFIGS. 1A and 2A.

FIG. 8Bis a cross-sectional view of the piston assembly150ofFIG. 8A.

FIG. 8Cis a perspective view of the piston assembly150ofFIG. 8A. The piston assembly150will be discussed with reference toFIGS. 8A-8Ctogether.

The piston assembly150includes an orifice retainer151, a piston body156, a piston orifice153and a piston scraper retainer157. The piston orifice153resides below the orifice retainer151. The piston orifice153comprises a shoulder, with the shoulder being exposed to fluid pressure above the fluid assembly150. The piston orifice153includes a central through-opening that permits working fluids to flow through the piston assembly150during clean-out operations. Piston scrapers (not shown) may be disposed around the piston body156to ensure debris is not able to reach the piston body o-ring.

FIG. 9Ais a side view of the plunger160ofFIGS. 1A and 2A.FIG. 9Bis a cross-sectional view of the plunger160.FIG. 9Cis a perspective view of the plunger160ofFIG. 9A. The plunger160will be discussed with reference toFIGS. 9A, 9B and 9Ctogether.

The plunger160comprises an upper end162and a lower end164. The upper end162is mechanically or adhesively connected to a lower end of the mandrel155. The lower end164, in turn, is dimensioned to sealingly land onto the seat170, above the flow-through opening175. The plunger160defines a short body166. The body166may comprise a solid steel, plastic or elastomeric material. Preferably, an upper portion (representing the upper end162) of the body166is fabricated from plastic or steel while a lower portion (representing the lower end164) represents a separate elastomeric body. A flat portion168is provided on each of opposing sides of the body166to facilitate threadedly connecting the plunger160to the mandrel155.

An opening161is preserved internal to the body166. The opening161is dimensioned to threadedly receive a bolt163. More specifically, the opening161receives a threaded stud167of the bolt163. An opening169for an Alan wrench is provided in the bolt163for securing the stud167into the opening161.

When the piston assembly150and connected plunger160are in their lowered position (or abrasive perforating mode), the bottom164of the plunger160lands on the seat170. At the same time, the slots165in the mandrel155advance to a position intermediate the upper162and lower164seals, exposing the slots165to the jetting ports148. In this position, all of the jetting fluids flow down through the bore105of the tool100, through the slots165, into the annular region145and through the lateral jetting ports148.

As noted above, the perforating tool100(with or without rotary tool300A or some bottom hole assembly below) is intended to be run into a wellbore.FIG. 10is a cross-sectional view of an illustrative wellbore1000. The wellbore1000penetrates into a subsurface formation1050and is completed for producing hydrocarbon fluids. Of interest, for purposes of the present disclosure, the wellbore1000has received a multi-cycle clean-out tool such as the tool100ofFIG. 1A.

It can be seen that the wellbore1000has been completed with a series of pipe strings referred to as casing. First, a string of surface casing1010has been cemented into the formation1050. The cement resides in an annular region1015around the casing1010, forming an annular sheath1012. The surface casing1010has an upper end in sealed connection with a bottom wellhead valve1064.

Next, at least one intermediate string of casing1020is cemented into the wellbore1000. The intermediate string of casing1020is in sealed fluid communication with a top wellhead valve1062. A cement sheath1022resides in an annular region1025of the wellbore1000. The combination of the casing1010/1020and the cement sheaths1010,1022in the annular regions1015,1025strengthens the wellbore1000and facilitates the isolation of aquitards and formations behind the casing1010/1020. It is understood that a wellbore1000may, and typically will, include more than one string of intermediate casing.

Finally, a production string1030is provided. The production string1030is hung from the intermediate casing string1020using a liner hanger1031. The production string1030is a liner that is not tied back to the surface1001. In the arrangement ofFIG. 10, a cement sheath1032is provided around the liner1030. The cement sheath1032fills an annular region1035between the liner1030and the surrounding rock matrix in the subsurface formation1050.

The production liner1030has a lower end1034that extends to an end1054(or “toe”) of the wellbore1000. For this reason, the wellbore1000is said to be completed as a cased-hole well. Those of ordinary skill in the art will understand that for production purposes, the liner1030will be perforated after cementing to create fluid communication between a bore1045of the liner1030and the surrounding rock matrix making up the subsurface formation1050. In one aspect, the production string1030is not a liner but is a casing string that extends back up to the surface1001. In this instance, the cement sheath1032will not be extended to the surface1001.

As an alternative, end1054of the wellbore1000may include joints of sand screen (not shown). The use of sand screens with gravel packs allows for greater fluid communication between the bore1045of the liner1030and the surrounding rock matrix1050while still providing support for the wellbore1000. In this instance, the wellbore1000would include a slotted base pipe as part of the sand screen joints. Of course, the sand screen joints would not be cemented into place.

It is also noted that the bottom end1054of the wellbore1000is 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.

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. Those of ordinary skill in the art may understand that 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. However, the present inventions have equal utility in vertically completed wells or in multi-lateral deviated wells.

When completed, the wellbore1000will include a string of production tubing (not shown). However, before that is done, it is desirable to clean out the wellbore1000. Accordingly, the wellbore1000includes a perforating tool100as shown inFIG. 1A.

It is noted that the perforating tool100is connected to a string of coiled tubing1040. The coiled tubing string1040serves 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 perforating tool200is preferably extended along the horizontal leg of the wellbore within the subsurface formation1055.

A lubricator1060or frac tree is placed over the wellbore1000. The lubricator1060is positioned at the surface1001to control wellbore pressures during a completion (or other wellbore) operation and to isolate tools such as a string of coiled tubing1040being moved into and back out of the wellbore1000.

As can be seen, a unique abrasive perforating tool100has been provided. The perforating tool acts as a flow diverter that increases the efficiency of fill removal operations. Fluid flow can be entirely in a straight-through path of the tool to an optional bottom hole assembly below. In addition, the fluid flow can also be entirely diverted to jetting ports. The cycling of fluid flow modes is possible an unlimited number of times and does not require dropping a ball or reversing circulation.

Using the perforating tool100described above, a method1100of conducting a wellbore operation is also provided. The method1100is presented in the flow chart ofFIG. 11.

The method1100first includes providing a wellbore. This is indicated at Box1110. The wellbore is being completed for the production of hydrocarbon fluids. Of interest, the wellbore has been completed with a string of casing, including a string of production casing along a selected subsurface formation.

The wellbore may be completed vertically. Alternatively, the wellbore may be a deviated well formed from a lateral drilling operation. More preferably, the wellbore is completed horizontally as shown inFIG. 10. However, the methods are not limited to the orientation of the wellbore unless expressly stated in the claims.

It is understood that for purposes of Box1110, 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 method1100also includes running a perforating tool into the wellbore. This is provided in Box1120. The perforating tool is run into the wellbore at the lower end of a string of coiled tubing1040. The perforating tool may be constructed in accordance with any of the embodiments described above. Particularly, the perforating 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 perforating tool includes one or more lateral jetting ports. The jetting ports are spaced apart radially around the housing, and preferably constitute two levels of ports in close proximity to one another. The jetting ports deliver an abrasive fluid to the casing when the tool is in its perforating mode.

The method1100may additionally include tuning the various openings along the tool in order to provide a desired total cross-sectional area of fluid flow in the perforating tool. This is seen at Box1130. For example, the step of Box1130may include setting or 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.

In order for the perforating tool to change modes, the piston orifice needs to be sized small enough to ensure the required activation rate will be achievable during the operation. Although the perforating 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 flow-through mode. Optimally, the piston orifice is sized appropriately to ensure the activation rate will be achievable in both modes throughout the operation with minimal back-pressure.

Additionally, the Box1130may include a step of selecting or adjusting the cross-sectional area of the flow ports along the mandrel, and/or a step of selecting or adjusting a diameter of the lateral slots associated with the mandrel and the flow-through opening associated with the seat. A larger cross-sectional area in the opening of the seat enables more working fluid to flow from the perforating tool en route to the PDM300A.

Additionally, the Box1130may also include a step of adjusting a size of the lateral jetting ports. The ports should be small enough to provide ample flow restriction for effective jetting.

It is observed that while Box1130is shown after the step of running the perforating tool into the wellbore, it is understood that these adjustments of Box1160will be taken during tool design and before the tool is run into the wellbore in Box1120.

The method1100also includes the step of locating the perforating tool. This is seen at Box1140. The perforating tool is located at a selected depth along a tubular body within the wellbore. Subsurface formation1055ofFIG. 10is an example of a location or depth for the perforating tool, although the operator will choose specific total depths for perforation and clean-out. Thus, the term “depth” includes “total depth” along a horizontal wellbore.

The method1100further includes injecting a working fluid down a coiled tubing string. This is provided at Box1150. 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 perforating tool at a first flow rate. The first flow rate is below an activation rate. The pumping at the first flow rate causes the pumped fluid to flow through the mandrel, through the radial flow ports of the mandrel, into the annular area, around the plunger and through the seat.

The method1100also includes further injecting the working fluid down the coiled tubing and into the bore of the tubular housing at a second flow rate. This is shown at Box1160. The second flow rate is higher than the first flow rate. In this instance, the higher flow rate increases a hydraulic force acting on a pressure shoulder of a piston, causing the mandrel and connected plunger to slide along the tubular housing such that the plunger is landed on the seat. The result is that the tool is moved into its perforating mode. In this mode, all pumped fluid flows into the bore of the tubular housing, down the mandrel, through the radially-disposed slots, into the annular area and through the lateral jetting ports.

As noted above, during the perforating mode the pumped fluid will preferably include abrasive particles such as sand. In addition, a water-soluble polymer may be used in the concentration range of about 10 pounds to about 40 pounds per 1,000 gallons of liquid. The polymer keeps the abrasive particles suspended and reduces friction pressure loss during flow of fluid through the tubing1040. A concentration of abrasive particles may be selected depending on wellbore conditions, but normally concentrations up to about one-half pound of abrasive per gallon may be used. Chemicals such as KCl and HCl may be added to the working fluid to assure that the fluid is compatible with the reservoir rock. Preferably, the fluid pumped is filtered to minimize plugging of jetting ports148.

To effectuate the method1100, it is preferred that 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:(i) a first setting wherein a pin associated with the J-slot mechanism resides in a first slot that places the plunger in a raised position in response to a biasing mechanical force exerted by a spring on the mandrel while pumping at a first rate, maintaining the perforating tool in a flow-through mode (shown inFIG. 1A);(ii) a second setting wherein the pin moves higher in the first slot in response to the injection of fluids into the wellbore at a second increased rate, placing the plunger into an intermediate position while allowing the tool to remain in its flow-through mode (shown inFIG. 1C);(iii) the first setting again wherein the pin resides in a second slot that returns the plunger to its raised position in response to the upward biasing force of the spring; and(iv) a third setting wherein the pin moves higher along a third slot in response to the injection of fluids into the wellbore at a second increased rate, and wherein the plunger slides from the raised position to the lowered position, placing the perforating tool in its abrasive perforating mode (shown inFIG. 2A).

It is observed that 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.

The method1100may include repeating the step of Box1150to provide further clean-out. During this step, a rotary tool below the perforating tool such as (positive displacement motor300A) may be activated in order to mill out a plug or other wellbore obstacle.

In one aspect of the method1000, the perforating tool100is 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 abuts or is otherwise proximate to the seat.

In one embodiment, 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 perforating tool is in its flow-through mode. In this instance, the method further comprises milling out a plug or debris located in the wellbore below the bottom sub using the positive displacement motor.

Milling operations may also be conducted to remove plugs that have been placed in the well bore. The operator may mill through wellbore obstacles using the flow-through mode, then switch the tool to its perforating mode to create perforations at the desired location. The tool can then be cycled back to the flow-through mode to resume circulation through the motor to circulate out the sand that was used for creating the perforations. Changing the flow path to the motor has the benefit of maintaining circulation around the entire BHA to avoid getting stuck, as well as enabling a higher pump rate than would be achievable through the perforating nozzles.

In another embodiment, the downhole tool is a sliding sleeve shifting tool. The setting tool is configured to shift a sliding sleeve along the wellbore in response to hydraulic pressure received when the perforating tool is in its flow-through mode. In this instance, the method further comprises shifting a sliding sleeve located in the wellbore below the bottom sub using the sliding sleeve shifting tool.

FIG. 3Bis an example of a suitable sliding sleeve shifting tool300B that may be used as part of a bottom hole assembly with the perforating tool100ofFIGS. 1A and 2A. This illustrative tool300B is a bi-directional shifting tool that is available from Hunting Energy Services, LLC of Houston, Tex.

In still another embodiment, the downhole tool is a bridge plug. The bridge plug may be either a permanently installed bridge plug or a resettable bridge plug. In this instance, the method further comprises setting the bridge plug in the wellbore below the bottom sub in response to hydraulic pressure received when the perforating tool is in its flow-through mode. In another instance the bridge plug may be set in response to movement of the conveyance tubing.

FIG. 3Cpresents an example of a suitable bridge plug300C. This illustrative tool300C is a Crownstone™ GTV tubing-retrievable well barrier (or retrievable bridge plug) that is available from Baker Hughes (a GE Company) also of Houston, Tex.

In another embodiment, the downhole too is an extended reach tool. The extended reach tool creates pressure pulses in the flow through the coiled tubing, which reduces friction between the coiled tubing and the wellbore. An operator may utilize the extended reach tool while in clean-out (that is, flow-through) mode to achieve deeper depths that would otherwise not be attainable and then switch to perforating mode to perforate the wellbore. In perforating mode, the sand laden fluid is isolated from the extended reach tool, which typically would be damaged by such fluid.

FIG. 3Dresents an example of a suitable extended reach tool300D. This illustrative tool300D is a Toe Tapper™ extended reach tool that is available from CT Energy Ltd. of Calgary, Alberta.

Further, variations of the tool and of methods for operating a flow diverter tool may fall within the spirit of the claims, below. For example, the location of the upper162and lower164seals, and the corresponding locations of the slots165and the flow ports185, may be reconfigured such that the raised position of the perforating tool100correlates to the perforating mode rather than the flow-through mode, and such that the lowered position correlates to the flow-through mode rather than the perforating mode.

FIGS. 12A through 12Cdemonstrate a perforating tool1200wherein the tool is biased in its abrasive perforating mode. This means that in the raised position abrasive perforating fluid is injected through lateral jetting nozzles, while in the lowered position a working fluid is entirely injected through a seat at the bottom of the perforating tool. This allows the fluid to serve as a working fluid for operating a positive displacement motor300A or for activating a sliding sleeve300B or for setting a bridge plug300C in the wellbore.

FIG. 12Ais a first cross-sectional view of the perforating tool (or “flow diverter”)1200. In this view, the perforating tool1200is in an abrasive perforating mode. Here, all of the injected fluids are diverted from the tool1200and through lateral jetting ports1248. Thus, the tool1200is spring-biased to the abrasive perforating mode rather than to the flow-through mode.

The perforating tool1200defines a generally tubular body formed from a series of components. As shown, the perforating tool1200has a first (or upstream) end102and a second (or downstream) end104. A central bore105is formed within the body extending from the first end102to the second end104.

As with clean-out tool100described above, the perforating tool1200is configured to cycle a position of a mandrel155and connected plunger160in response to fluid pumping rates into the wellbore1000by an operator. In this way, a flow of fluid through the tool1200may be adjusted. In the view ofFIG. 12A, the perforating tool1200is in its run-in position wherein all the injected fluid flows through the tool1200from the top (or upstream) end102, then out through side ports1285and into an annular area1245, then through lateral jetting ports1248. Of interest, the lowered end of the plunger160has no through-bore and is sealingly inserted in a seat170, preventing the injected fluids from flowing through the bottom end104of the tool1200.

It is observed here that some of the tubular components in the perforating tool1200correspond to components of the perforating tool100, or at least very closely there to. Examples include the top sub110, the piston assembly150, the spring housing120and spring125, the upper mandrel seal sub130, the jetting port housing140with one or more jetting ports148, the mandrel155and the bottom sub190. Accordingly, those components need not be described again here.

The spring housing120, the mandrel seal sub130and the jetting housing140together make up a tubular housing for the perforating tool1200. Of interest, a shoulder146resides along an inner diameter of the jetting port housing140. The shoulder146forms a profile above the jetting ports148. A separate shoulder136resides at the bottom end134of the mandrel seal sub130. O-rings are placed inside the bottom end134, helping to keep perforating fluid from flowing from an annular area between the mandrel155and the spring housing120during perforating.

An annular area145is reserved between the mandrel155and the surrounding jetting port housing140. The annular area145has an upper portion where the spring125resides, and a lower portion where jetting ports148are placed. Appropriate o-rings reside around and inside the downstream end134of the mandrel seal sub130to provide a fluid seal between the upper and lower annular regions145. The annular region the spring125resides in is pressure balanced via ports159in the mandrel155. These ports159let the fluid volume inside the spring housing120change as the piston body156moves up and down.

At the lower end154of the mandrel155is a stem1280. The stem1280defines a short tubular body having an upper (or upstream) end1282and an opposing lower (or downstream) end1284. A bore1265is formed from the upper1282to the lower1284end, allowing working fluids to flow through the side ports1285. Preferably, two or more equi-radially disposed slots are provided for the side ports1285. The upper end1282comprises male threads that connect to the lower end154of the mandrel155. In this way, the stem1280moves up and down along the bore105of the perforating tool1200with the mandrel155.

The lower end1284of the stem1280is connected to a plunger160. As noted above, the plunger160is a solid body that may be fabricated from plastic, steel or an elastomeric material. In this instance, the plunger160is dimensioned to move through a seat170. Appropriate seals are provided along the I.D. of the seat170to prevent fluids from bypassing the plunger160.

In the raised position ofFIG. 1A, fluid is injected by an operator into the bore105of the perforating tool1200under a first pressure. The first pressure correlates to a first flow rate. Those of ordinary skill in the art will understand that there is a correlation between flow rate, tubular dimension and pressure. At the first flow rate, the hydraulic pressure acting on the piston assembly150is not great enough to cause the piston assembly150to compress the spring125.

FIG. 12Bis a second cross-sectional view of the perforating tool1200ofFIG. 12A. Here, the perforating tool1200has been cycled to an intermediate position. Stated another way, the perforating tool1200is translating (that is, sliding down the spring housing120) to its intermediate position. This is done by increasing the hydraulic force acting on the piston assembly150. In this position, the plunger160has advanced partially down the tool1200, but all of the injected fluid continues to flow through the lateral jetting ports148.

FIG. 12Cis a third cross-sectional view of the perforating tool1200ofFIG. 12A. Here, the tool1200(or the plunger160in the tool1200) has advanced to its lowered position. This is a flow-through mode where all of the injected fluid flows through the side ports1285below the seat170. Advancing the plunger160is done by further increasing the pump rate above an activation rate, thereby increasing the hydraulic force acting on the shoulder that is the piston assembly150.

The cycling of the tool1200between its raised position (FIG. 12A), its intermediate position (FIG. 12B) and its lowered position (FIG. 12C) is preferably accomplished by using a sequencing mechanism. The sequencing mechanism is preferably the J-slot mechanism as shown inFIGS. 4A-4D, discussed above. The sequencing mechanism400allows the operator to cycle the flow rates to move the tool1200between settings so that:(i) in a first setting, the plunger160is in a raised position in response to the biasing mechanical force exerted by the spring125on the mandrel155, placing the perforating tool in an abrasive perforating mode;(ii) in a second setting, pumping rate is increased and the J-slot mechanism400advances to a next slot, allowing the plunger160to move down no more than to its intermediate position and allowing the operator to inject hydraulic fluid (typically the perforating fluid) into the bore105of the tubular housing110and through the piston orifice153at a second rate, or at any rate higher than the second rate, and keeping the perforating tool1200in its abrasive perforating mode;(iii) in the first setting again, hydraulic pumping rate is reduced to its first rate, or any rate below the first rate, and the perforating tool1200remains in its perforating mode; and(iv) in a third setting, the plunger160is forced through the seat170in response to the injection of hydraulic fluid through the piston assembly150and into the perforating tool1200at a second rate, or at any rate higher than the second rate, moving the J-slot mechanism400to a next slot and causing the plunger160to slide from the raised position to the lowered position, placing the perforating tool1200in its flow-through mode.

Using the perforating tool1200ofFIGS. 12A-12C, a method of cleaning out a wellbore is also provided herein. The wellbore may be the wellbore1000ofFIG. 10, for example. In one aspect, the method includes the steps of:(a) placing a perforating tool in the wellbore along a string of production casing;(b) locating the perforating tool and connected downhole tool within the wellbore;(c) pumping working fluid down the wellbore and into the perforating tool at or above an activation rate, causing the tubular mandrel and connected plunger to move through a seat to a lowered position such that all fluid flows through the perforating tool (a flow-through mode);(d) lowering the pumping rate to advance the J slot pins to the next setting, therefore placing the tool in its perforating mode;(e) pumping the working fluid down the wellbore and into the perforating tool at a rate at or above the activation rate such that all fluid flows through lateral jetting ports (a perforating mode); and(f) continuing to pump the working fluid down the wellbore and into the perforating tool at a rate at or above the activation rate in order to hydraulically perforate a surrounding string of production casing.

In one aspect of the method, the perforating 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 the seat.

In one embodiment, 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 perforating tool is in its flow-through mode. In this instance, the method further comprises milling out a plug or debris located in the wellbore below the bottom sub using the positive displacement motor.

In another embodiment, the downhole tool is a sliding sleeve shifting tool. The setting tool is configured to shift a sliding sleeve along the wellbore in response to hydraulic pressure received when the perforating tool is in its flow-through mode. In this instance, the method further comprises shifting a sliding sleeve located in the wellbore below the bottom sub using the sliding sleeve shifting tool.

In still another embodiment, the downhole tool is a bridge plug. The bridge plug may be either a permanently installed bridge plug or a resettable bridge plug. In one instance, the method further comprises setting the bridge plug in the wellbore below the bottom sub in response to hydraulic pressure received when the perforating tool is in its flow-through mode. In another instance, the method further comprises setting the bridge plug in the wellbore below the bottom sub in response to movement of the conveyance tubing.

In another embodiment, the downhole too is an extended reach tool. The extended reach tool creates pressure pulses in the flow through the coiled tubing, which reduces friction between the coiled tubing and the wellbore. An operator may utilize the extended reach tool while in flow-through mode to achieve deeper depths that would otherwise not be attainable and then switch to perforating mode to perforate the wellbore. In perforating mode, the sand laden fluid is isolated from the extended reach tool, which typically would be damaged by such fluid.

It will be appreciated that the inventions are susceptible to other modifications, variations and changes without departing from the spirit thereof.