Bottom hole assembly for wellbore operations

An embodiment of a method of performing a wellbore operation in an oilfield comprises providing a bottom hole assembly on a conveyance, deploying the bottom hole assembly into the wellbore with the conveyance, determining the depth location of the bottomhole assembly in the wellbore utilizing a mechanical device, moving the bottom hole assembly to a desired location based on the determined depth, circulating a fluid from the oilfield to the bottomhole assembly, and performing at least one wellbore operation while the bottomhole assembly is deployed at the desired location.

FIELD

The present disclosure relates generally to a process for depth correlation and wellbore circulation during abrasive jetting and fracturing operations. In addition, this process can also be applied to conventional cleanouts and fluid/debris circulation.

BACKGROUND

Over the last few decades the utilization of abrasive jetting to create perforations in a subterranean wellbore has increased significantly. More recently the introduction of coiled tubing as a conduit means of the abrasive slurry (as opposed to jointed pipes) has allowed for faster interventions. In order to improve the efficiency on these jobs the requirements have changed and allowed for fracturing a formation with the coiled tubing remaining in the hole while the slurry is pumped to the formation through the annulus between the coiled tubing or jointed pipe and the tubing or casing.

This process was further improved by separating the fracturing stages of a formation with a plurality of pay zones with the placement of a sand plug at the end of the previous fracturing stage, which was never a precise science and could often result in a sand plug being higher or lower than the intended final plug height. This high plug prevents the next stage from being jetted and pumped without performing a remedial operation to adjust the sand plug height. The ability to circulate this sand plug (or the excess of it) with coiled tubing was further enhanced by the use of a reverse circulation valve as part of the coiled tubing bottom hole assembly (BHA), which allows for reverse circulation of the excess sand, or the placement of a new extra sand plug. In some cases, this procedure disadvantageously requires tripping the coiled tubing out of the hole for replacing the BHA with one that allowed that kind of circulation.

At the same time, there were some challenges in regards to depth correlation with coiled tubing and the abrasive jetting nozzle depth, due to stretching and shrinking of the coiled tubing due to several downhole parameters such as temperature, pressure, deviation, and friction, among others, that made the depth control of the nozzle depth very imprecise, which could possibly yield to jetting at the wrong depths. This depth correlation issue has been addressed differently by the industry, initially with correlation runs (running the coiled tubing in hole and pulling out of hole to verify depth) using some sort of correlation device (such as electronic memory casing collar locators, nipple locators or tubing end locators, real-time depth correlation devices based on pumping pressures being choked at the presence of each collar), or in some instances a mechanical device for casing collar location was used during the treatment that would require such item to be placed below the perforations as its external diameter would be very close to the tubing or casing inner diameter and would not allow for fracturing fluid around and/or past it, posing a threat to having the coiled tubing BHA stuck in the hole with proppant packed around the locating device. In general the industry does not have a solution for the depth control and for the wellbore circulation problem in a single trip in the hole.

It is desirable to provide an improved process for depth correlation and wellbore circulation during abrasive jetting and fracturing operations.

SUMMARY

An embodiment of a method of performing a wellbore operation in an oilfield comprises providing a bottom hole assembly on a conveyance, deploying the bottom hole assembly into the wellbore with the conveyance, determining the depth location of the bottomhole assembly in the wellbore utilizing a mechanical device, moving the bottom hole assembly to a desired location based on the determined depth, circulating a fluid from the oilfield to the bottomhole assembly, and performing at least one wellbore operation while the bottomhole assembly is deployed at the desired location. In an embodiment, providing comprises providing a bottom hole assembly on coiled tubing. In an embodiment, providing comprises providing a bottom hole assembly on jointed pipe. In an embodiment, providing further comprises providing a bottom hole assembly comprising a mechanical casing collar locator. Determining the location may comprise determining a depth in the wellbore by use of the mechanical casing collar locator. Providing may further comprise providing a bottom hole assembly comprising a circulation valve.

In an embodiment, providing further comprises providing a bottom hole assembly comprising a circulation valve. In an embodiment, performing at least one wellbore operation comprises circulating a treatment fluid past the mechanical device. In an embodiment, performing comprises forming a sand plug in the wellbore. In an embodiment, performing comprises performing an abrasive jetting operation. In an embodiment, circulating comprises actively selecting the flowpath of the pumped fluid through the different flowpaths in the bottom hole assembly. In an embodiment, circulating comprises circulating fluid from the oilfield past the bottomhole assembly.

An embodiment of a method of performing a wellbore operation comprises providing a bottom hole assembly on a conveyance, the bottom hole assembly comprising a mechanical casing collar locator, a circulation valve, and a cleanout nozzle, deploying the bottom hole assembly into the wellbore with the conveyance, determining the depth location of the bottomhole assembly in the wellbore utilizing a mechanical casing collar locator, moving the bottom hole assembly to a desired location based on the determined depth, circulating a fluid from the oilfield to the bottomhole assembly, and performing at least one wellbore operation while the bottomhole assembly is deployed at the desired location.

In an embodiment, performing at least one wellbore operation comprises circulating a fracturing fluid at fracturing rates past the mechanical device. In an embodiment, performing comprises forming a sand plug in the wellbore. In an embodiment, performing comprises performing an abrasive jetting operation. In an embodiment, performing comprises performing a cleanout operation.

An embodiment of a bottom hole assembly for performing a wellbore operation comprises a mechanical casing collar locator, and at least one nozzle for performing at least one wellbore operation while the bottomhole assembly is deployed at a desired location in the wellbore in a single trip operation. In an embodiment, the assembly further comprising a circulation valve operable to determine a flowpath for treatment fluid within the bottom hole assembly. In an embodiment, the at least one nozzle comprises a jetting nozzle. In an embodiment, the assembly is deployed into a wellbore on coiled tubing. In an embodiment, the mechanical casing collar locator is operable to allow treatment fluid to flow therepast. In an embodiment, the treatment fluid is flowed at fracturing rates past the mechanical casing collar locator.

DETAILED DESCRIPTION

Referring now toFIGS. 1-3, a downhole assembly or bottom hole assembly (BHA) is indicated generally at100. The downhole assembly100is disposed in a wellbore102on a conveyance104, such as coiled tubing, jointed pipe, drill pipe or the like extending from an oilfield surface (not shown) and is connected to suitable oilfield surface equipment (not shown). The wellbore102may be a cased wellbore having a casing106disposed therein. The casing106comprises a plurality of successive casing sections106ajoined by a corresponding plurality of collars108, such as by threaded connections107or the like, as will be appreciated by those skilled in the art. Each of the collars108may define a recess109having an internal diameter110and an interior surface112. The length of the diameter110has a greater length than the length of the nominal diameter114of the interior surface116of the casing106and casing sections106a.

The downhole assembly100comprises a mechanical casing collar locator portion120. The mechanical casing collar locator120comprises a plurality of engagement members122that engage with the interior surface116of the casing106and casing sections106a. The engagement members122are biased by springs or the like to deflect substantially outwardly from the downhole assembly in a radially outward direction indicated by an arrow124. When the downhole assembly100is moved (either in an uphole direction indicated by an arrow128or a downhole direction indicated by an arrow129) such that the mechanical casing collar locator120is adjacent one of the collars108, the engagement members122move in the direction124to engage with the interior surface112of the collars108. The engagement members122define a plurality of circumferential passages126therebetween, which define a space between the mechanical casing collar locator120and the casing106, best seen inFIG. 3. While illustrated inFIG. 3as comprising four engagement members122, those skilled in the art will appreciate that any suitable number of engagement members may be utilized.

The downhole assembly100may comprise a selective circulation valve130disposed above the mechanical casing collar locator120that is operable, in an open position, to allow fluid to flow from the interior of the coiled tubing104and out a cleaning nozzle132disposed at a free end of the downhole assembly100. The cleaning nozzle132may be utilized to direct fluid therethrough generally in the direction129for a cleanout operation or the like. In a closed position, the selective circulation valve130prevents flow from the coiled tubing104to the cleaning nozzle132. The circulation valve130may be cycled between the open position and the closed position by any suitable actuator or actuation method including, but not limited to, mechanical actuation by a pressure pulses, by pressure differential on a seat, by sequential direction changes in the directions128and129of the bottomhole assembly100that actuates an “on-off” mechanism such as by interacting J-slots or the like formed in the bottomhole assembly100, as will be appreciated by those skilled in the art. The circulation valve130may be cycled by the utilizing the tension in the coiled tubing104when the engagement members122are deployed in the casing collar recess109.

The downhole assembly or BHA100may also comprise at least one jetting nozzle or nozzles134disposed above the circulation valve130. The jetting nozzles134are operable to emit a high velocity and or high pressure stream of fluid generally in the radially outward direction124from the interior of the coiled tubing104for perforating a casing section106aor the like, as will be appreciated by those skilled in the art.

In an embodiment, the downhole assembly or BHA100is run into the wellbore102in the direction129on the coiled tubing104to the bottom of the cased wellbore102or to the last of the casing sections106a. After reaching the bottom of the wellbore102, the BHA100is pulled in the direction128to a location adjacent the first collar108, which allows the engagement members122of the mechanical casing collar locator120to latch into the recess109of the casing collar108. When disposed in the recess109, the mechanical casing collar locator120requires additional pulling force to continue moving the BHA100in the direction128. This force may be monitored by the surface equipment to alert an operator that the BHA100is disposed in the collar108and thereby provide the operator with an indication of the location of the BHA100within the wellbore. Each time the additional pulling force is noted, the force may be analyzed and matched to a casing collar profile to allow matching the casing collars108to the formation behind it for the purposes of depth determination and/or correlation of the zones of interest in the formation(s) with the casing108. The casing collar profile is a standard log provided for an individual wellbore102.

After the depth determination and/or correlation process is complete, the circulation valve130may be cycled and/or placed in the closed position. The circulation valve130may be cycled by moving the BHA100up and down in the directions128and129and utilizing the mechanical casing collar locator120as a friction device to mechanically actuate the circulation valve130. The circulation valve130may be designed to be cycled or operated between open and closed positions by pumping fluids through the interior of the conveyance104such as coiled tubing, jointed pipe, drill pipe, or the like, or at certain rates and later stopping pumping and resume pumping, which would allow the circulation valve130to move between the open and close positions. The circulation valve130may be designed to be cycled or operated between open and closed positions by pumping fluids through an annulus103between the interior surface116of the casing106and an exterior surface of the coiled tubing104or at certain rates and later stopping pumping and resume pumping, which would allow the circulation valve130to move between the open and close positions. The circulation valve130may be operated by increasing and decreasing the pumping rates to allow the valve130to open or close at pre-determined pumping rates and pressures.

Referring now toFIGS. 4-15, the downhole assembly or BHA is shown in operation. InFIG. 4, the BHA100is run to the bottom of the cased wellbore102or to the last of the casing sections106a. InFIG. 5, the BHA100is moved upwardly in the direction128to a desired location within the wellbore102, based on the depth correlation information gathered and determined previously. InFIG. 6, fluid flows through the interior of the conveyance104, such as coiled tubing, jointed pipe, or the like, and out through the jetting nozzles134with jets140to perforate the casing106at the desired location on the casing106. The valve120is in the closed position inFIG. 6, to direct fluid flow to the nozzles134to form the jets160. InFIG. 7, the fluid flow is stopped and the BHA100is moved upwardly in the direction128away from the newly formed perforations142.

InFIG. 8, treatment fluid such as fracturing fluid or the like flows from the surface (pumped by fracturing pumps or other suitable surface equipment) through the annulus103, past the BHA100and the mechanical casing collar locator120through the passages126, as indicated by arrows144, and through the perforations142, as indicated by arrows146, to form fractures in the formation adjacent the casing106, indicated generally at148. InFIG. 9, the treatment or fracturing is complete and sand-laden fluid is flowed through the conveyance104, such as coiled tubing, jointed pipe, or the like, or along the annulus103to form a sand plug150in the borehole102. InFIG. 10, the valve130is cycled from a closed position (as shown inFIG. 9) to an open position and fluid flows along the interior of the conveyance104and out the nozzle132, as indicated by arrows152to clean out excess sand from the sand plug150to a level shown inFIG. 11that is closer to the perforations142. The excess sand may be removed by pumping the fluid entrained with the excess sand up the annulus103to the surface or by pumping the cleaning fluid down the annulus103and the fluid entrained with the excess sand up the conveyance104to the surface.

InFIG. 12, the BHA100is moved upwardly in the direction128to a desired location within the wellbore102, based on the depth correlation information gathered and/or determined previously. InFIG. 13, fluid flows through the interior of the conveyance104, such as coiled tubing, jointed pipe, or the like, and out through the jetting nozzles134with jets160to perforate the casing106at the desired location on the casing106. The valve120is in the closed position inFIG. 13, to direct fluid flow to the nozzles134to form the jets160. InFIG. 14, the fluid flow is stopped and the BHA100is moved upwardly in the direction128away from the newly formed perforations162.

InFIG. 14, treatment fluid, such as fracturing fluid or the like, flows from the surface (pumped by fracturing pumps or other suitable surface equipment) through the annulus103, past the BHA100and the mechanical casing collar locator120through the passages126(similar to that shown inFIG. 8) and through the perforations162, as indicated by arrows164, to form fractures in the formation adjacent the casing106, indicated generally at166. The sand plug150prevents flow down the wellbore102and assists in directing the treatment fluid to the perforations162. InFIG. 15, the treatment or fracturing is complete and sand-laden fluid is flowed through the conveyance104, such as coiled tubing, jointed pipe, or the like, or along the annulus103to form a sand plug168above the sand plug150in the borehole102.

The BHA100may comprise both the mechanical casing collar locator120and the circulation valve130. Alternatively, the BHA100may comprise only the mechanical casing collar locator120or only the circulation valve130. Those skilled in the art will appreciate that the mechanical casing collar locator120and the circulation valve130may be used in conjunction with each other or independently, both to achieve better precision (utilizing the mechanical casing collar locator120) and better efficiency (utilizing the circulation valve130). Some operations may require only the mechanical casing collar locator120, some operations will require only the circulation valve130, and some will require both the mechanical casing collar locator120and the circulation valve130.

In an embodiment, the downhole assembly or BHA100may be utilized to mechanically locate the casing collars108while being able to move the downhole assembly or BHA100up and down within the wellbore102while pumping treatment fluid, such as fracturing fluid. The downhole assembly or BHA100advantageously allows the bottom hole assembly to direct flow to the side ported abrasive jetting nozzles134or to the cleaning nozzle132, which allows the BHA100to perform two functions. While jetting through the nozzles134, the BHA100may jet a fluid (with or without gas) that may contain jetting sand or proppant for the purpose of forming abrasive jetting holes142and162through the casing106, through cement (or even directly in an open hole wellbore and into the formation and across the zone of interest. The BHA100, while circulating, may also be used for replacing the wellbore fluid with another fluid or gas, for cleaning out sand/proppant as in fill, plugs, debris, in a direct circulation manner wherein fluid or gas is pumped down the coiled tubing or jointed pipe104and returned on the annulus103between the coiled tubing104and tubing or casing106to return tanks or to any surface facility. The BHA may also be utilized for pumping fluid being pumped down the annulus103between the coiled tubing104and casing106and returned through the coiled tubing or jointed pipe104to the return tanks or any surface facility.

The downhole assembly or BHA100advantageously allows an operator to locate jetting locations based on determining the location of casing collars, such as the casing collars108. The BHA100advantageously allows for the placement of multiple sand plugs and multiple fracturing stages at more precise locations based on the depth determination of the mechanical casing collar locator120, without requiring tripping the coiled tubing out of the wellbore to replace the BHA100with another BHA that allowed that kind of circulation. The BHA100advantageously provides for depth control and for wellbore circulation in a single trip in the wellbore.

The preceding description has been presented with reference to presently preferred embodiments. Persons skilled in the art and technology to which these embodiments pertain will appreciate that alterations and changes in the described structures and methods of operation may be practiced without meaningfully departing from the principle, and scope of these embodiments. For example, embodiments depicted herein reveal a pressure pulse communication tool in the form of a multilateral tool. However, other embodiments of pressure pulse communication tools may be employed such as a casing collar locator tool. Furthermore, the foregoing description should not be read as pertaining only to the precise structures described and shown in the accompanying drawings, but rather should be read as consistent with and as support for the following claims, which are to have their fullest and fairest scope.

The particular embodiments disclosed above are illustrative only, as the invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the invention. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood as referring to the power set (the set of all subsets) of the respective range of values. Accordingly, the protection sought herein is as set forth in the claims below.