Patent Application
20170058644
Embodiments herein relate to apparatus and methods for completion of a wellbore and, more particularly, to apparatus and methods for completing a wellbore and fracturing a formation therethrough.
It is well known to line wellbores with a completion string, liners or casing and the like and, thereafter, to create flowpaths through the casing to permit fluids, such as fracturing fluids, to reach the formation therebeyond.
One such conventional method for creating flowpaths is to perforate the casing using apparatus such as a perforating gun, which typically utilize an explosive charge to create localized openings through the casing.
Alternatively, the casing can include pre-machined ports, located at intervals therealong. The ports are typically sealed during insertion of the casing into the wellbore, such as by a dissolvable plug, a burst port assembly, a sleeve or the like. Optionally, the casing can thereafter be cemented into the wellbore, the cement being placed in an annulus between the wellbore and the casing. Thereafter, the ports are typically selectively opened by removing the sealing means to permit fluids, such as fracturing fluids, to reach the formation.
Typically, when sleeves are used to seal the ports, the sleeves are releasably retained over the ports, also known as sleeve valves, and can be actuated to slide within the casing to open and close the respective ports. Many different types of sleeves and apparatus to actuate the sleeves are known in the industry. Fluids are directed into the formation through the open ports. At least one sealing means, such as a packer, is employed to isolate the balance of the wellbore below the sleeve from the treatment fluids.
A variety of tools are known for actuating sleeves in ported subs including the use of shifting tools, profiled tools and packers. In U.S. Pat. No. 6,024,173 to Patel and assigned to Schlumberger, a shifting tool and a position locator is disclosed for locating a downhole device and engaging a packer element within moveable member and operating the device using and applied axial force to shift the member.
In Canadian Patents 2,738,907 and 2,693,676, both to NCS Oilfield Services Canada Inc., a bottom hole assembly (BHA) is deployed at an end of coiled tubing and located adjacent a ported sub by a sleeve locator. The BHA has a sealing member and an anchor such as a releasable bridge plug or well packer, which are set inside the ported sub fit for shifting a sliding sleeve and opening ports to the wellbore. From an uphole end, the BHA is connected to coiled tubing, has a fluid cutting assembly (jet cutting tool), a check valve for actuating the jet cutting tool, a bypass/equalization valve and the sealing member, the releasable anchor and the sleeve locator. A multifunction valve, including reverse circulation and pressure equalization, is positioned between the abrasive fluid jetting assembly and the sealing element. Set down on the coiled tubing closes the multifunction valve, blocking fluid communication to the tubing below the sealing member, and aligning ports in the valve for reverse circulation between the annulus and one way flow up the coiled tubing through the check valve. Pull up on the coiled tubing opens the multifunction valve to permit flow through a port in the valve between the annulus and the tubing the below the sealing member for equalization and though the port in the valve between the annulus and one way flow up the coiled tubing for reverse circulation. The check valve prevents fluid delivered through the coiled tubing from moving beyond the jetting assembly. Thus, fluid delivered through the coiled tubing is only used to cut perforations. Treatment fluid, such as for fracturing, is delivered through the annulus, between the BHA and the casing, to the ports opened by the sleeve.
The sleeve locator, at an intermediate position along locates a bottom of a closed sleeve, fit within a sleeve housing intermediate the BHA. The sealing member and anchor are uphole of the locator and are intended to set within the sleeve. Locating is performed with an uphole action. Actuation If the anchor and sealing member are performed with a downhole action. The length of the sleeve, increasing length of which contributing to an increasing manufacturing cost, is determined by the need to incorporate the length of the locator, the anchor and the sealing member, and accommodate some axial tolerance to successful arrest the anchor in the sleeve. Once the anchor successfully engages the sleeve to arrest its downhole movement and the sealing member expands, fluid pressure thereabove is applied to impart sufficient hydraulic force to actuate the sleeve downhole, typically initially at a force sufficient to release shear screws.
Incorporation of the sealing member, the releasable anchor and the sleeve locator, all of which must be cooperatively locatable within the sleeve housing, requires sleeve housing of significant length and related expense. Further, without additional components, the releaseable anchoring system is generally limited to downhole actuation of the sleeve.
There is interest in the industry for robust apparatus and methods of performing completion operations which are relatively simple, reliable, that could also provide uphole sleeve actuation on demand and which reduce the overall costs involved.
A bottom hole assembly (BHA) or actuator tool is provided for use in cooperation with one or more sleeve valves spaced along a completion string or casing. Each sleeve valve comprises a sleeve housing spaced along the casing, each sleeve housing fit with a sleeve that is axially movable therein to open and close treatment ports formed in the sleeve housing. Sleeve valves are deemed consumables. In other words, the sleeve and sleeve housings are run in hole and remain there for the life of the well. There is an interest in minimizing the cost of such consumables.
As disclosed herein, the present actuator tool is short in length and both locates a sleeve and embodies an element that engages intermediate the sleeve for sleeve release, opening and closing. As a result, the corresponding sleeve housing can be short in length, and less expensive to manufacture. The sleeve valve need not have a separate downhole locator portion within the housing, nor incorporate a separate pup therebelow to facilitate locating. Instead, both locating and sleeve actuation is performed using a profile intermediate the sleeve and which enables bi-directional controlled actuation, such as to selectively open and close ports in the sleeve housing.
The sleeve can be unitary, and in an even more economical form, be a multi-component sleeve, assembled from multiple axially shorter and less expensive tubular components. Each sleeve is fit with an annular recess or profile. Further, by forming the profile in a sleeve collar connected between uphole and downhole sleeve tubulars, the profile can be radially deeper, aiding in positive engagement, confirmation of engagement and actuation.
The profile can have an axial engagement length readily distinguishable from any sleeve's uphole and downhole end gaps and tool connections in the casing string. End gaps exist as result of differentials in the axial sleeve-to-housing lengths to accommodate axial shifting, from sleeve housing connections and collar locations.
The sleeve profile is engageable with radially extending dogs on the tool, the dogs being fit at ends of radially controllable levers or arms manipulated radially for selectable operation. The arms and supported dogs can be outwardly biased and the radial position of which can also be forcibly manipulated, overriding the biasing. Forcible manipulation includes radially inward restraint for running the tool in and out of hole, and for radially outward restraint to lock the dogs radially once engaged in the sleeve profile, and a biased radial outward configuration for location purposes. The manipulation of the dogs is achieved using up and downhole movement of a shifting mandrel, an arm restraining ring and a cam on the arm supporting the dogs. Up and downhole movement of the shifting mandrel is controlled by up and downhole weight on the conveying tubing. The axial position of the shifting mandrel is controlled by a J-Slot mechanism. The shifting mandrel is connected to the conveyance tubing and extends though the tool. The J-Slot can be located downhole of the dogs and thus has no bearing on sleeve length. As above, axial alignment of the shifting mandrel relative to the cams on the dog arms selectively restrains the dog's radial position for enabling sleeve engagement and disengagement. In the embodiment shown, the J-Slot applies four distinct positions to positively engage the sleeve profile for both uphole and downhole operation, yet also be releasable for longitudinal or axial movement to the next sleeve housing.
The dog and sleeve profile combination is also suitable for implementing sleeve release without need for hydraulic-assisted actuation with sleeve release achieved with an uphole overpull, or downhole setdown, or a jar device actuated by uphole or downhole weight. To mitigate any downhole setdown challenges in extended length horizontal wells, the sleeve profile can also be used for positive sleeve engagement on an uphole run, with controlled uphole shifting overpull or uphole jar actuation being applied when the dog is confirmed engaged with the sleeve, such as to overcome shear screws.
A sealing element or packer is still provided for isolation downhole of the tool for well treatment thereabove, including the application of fracturing fluids to the formation.
A new economy and flexibility in treatment methodology is now possible with short sleeve valves, assured sleeve locating and selectable opening and closing of some or all sleeves.
Further, in embodiments, one can perform fracturing from toe-to-heel, opening sleeves and treating zone-after-zone while pulling out of hole (POOH) and in other embodiments one can perform fracturing heel-to-toe by opening, treating and closing sleeves one-by-one while running downhole.
Further, where it is desirous to permit a fractured zone to rest or heal for several hours after treatment, a toe-to-heel operation has advantages in one can open a sleeve, treat, close and move uphole to open and treat and close a sleeve at the next zone and so on. After all zones are treated, the actuator tool can be run back downhole, typically a couple of hours later or other such optimal delay in many cases, and begin to open each or various sleeves coming back out of hole. Thus the earliest and downhole-most stages can have up to ½ a day or, even days, before they are finally opened.
As the locating and sleeve engagement is positive, the one tool movement and sleeve engagement is all that is necessary to reliably locate, open or close the sleeve.
In an embodiment, J-slot tool manipulation reliably shifts the tool between:
In one broad aspect, a system of downhole sleeves and actuation thereof comprises a completion string having a plurality of sleeve valves therealong, each sleeve valve having a sleeve housing and an axially shiftable sleeve, each sleeve having an annular profile formed intermediate the sleeve; and a shifting tool having an activation mandrel connected to a J-Slot mechanism having a J-Pin operable in a J-Slot housing and a drag block for restraining the housing, one or more dogs movable axially along the activation mandrel and radially actuable between a radially outward biased position, a sleeve profile-engaged position, and a radially inward collapsed position, a cone movable axially along the activation mandrel between two positions, an engaged position with the dogs to lock them in the profile-engaged position and disengaged position, and a packer for sealing to the sleeve, the packer sealing to the sleeve in the cone's engaged position, wherein the axial length of the sleeve valve is about the axial length of the packer, cone and dogs.
In one embodiment, the J-slot mechanism suitable for optional sleeve closing after treatment comprises a slot profile having: a first intermediate downhole position to shift the dogs to the radially inward collapsed position without engaging the cone with the dogs, a first extreme uphole position to shift the dogs to the radially outward biased position and profile engaging position when so located; an extreme downhole position to open the sleeve and move the cone to the engaged position for treatment; a second extreme uphole position with the dogs remaining in the profile-engaging position; a second intermediate downhole position to shift the dogs to the radially inward collapsed position for releasing the tool from the sleeve; and an intermediate uphole position to shift the dogs to the radially inward collapsed position for pulling out of hole; and a return to the first intermediate downhole position to restart the sequence. In another embodiment, the J-slot slot profile is absent the second extreme uphole position and the second intermediate downhole position, for moving directly to the intermediate uphole position for pulling out of hole.
In another embodiment, a shifting tool for sleeve valves comprises an activation mandrel connected to a J-Slot mechanism having a J-Pin operable in a J-Slot housing and a drag block for restraining the housing; one or more dogs supported on one or more pivotable arms, the arms and dogs supported about and movable axially along the activation mandrel, each dogs being radially actuable between a radially outward biased position, a sleeve profile-engaged position, and a radially inward collapsed position; springs for biasing each dog radially outwardly from the activation mandrel; and a retainer ring movable axially along the activation mandrel for actuating the one or more arms the between the radially outward biased position and the radially inward collapsed position.
In embodiments, tubing conveyed system provided comprising a treatment tool that is used to manipulate a large number of sleeve valves (cemented or uncemented) in an oil or gas well (vertical, deviated or horizontal) by opening or closing the sleeves therein at any time for various reasons without tripping the tool from the wellbore. The tool can be conveyed on coiled or jointed tubing. Herein the tool is described as being conveyed on coil tubing and hence, a “coil tool”.
Embodiments of the treatment tool are operable to open the sleeve before the frac to provide access to the reservoir, while isolating the rest of the well. An operator can close the sleeve after the frac treatment if desired to isolate the newly stimulated zone to: prevent cross flow to previous stimulated stages, and to allow the frac to “heal”, minimizing sand flow back into the well on production. Opening and closing of sleeves can be done in any sequence, heel to toe, toe to heel or any sequence of stages thereof. As introduced above, a sleeve valve comprises a sleeve housing having a bore fit with a sleeve, the sleeve being axially movable to open and close ports in the sleeve housing. Depending on the context, sleeve valves may be generally referred to herein as sleeves.
Embodiments of the treatment tool are operable to close selected sleeves during the life of the well to control unwanted production from a particular stage or stages (e.g. water production in a water flood situation). Water flood development plays typically include wells that are injectors and producers. Water flow through the reservoir can be determined by several industry existing methods, e.g. production logging, radioactive/chemical tracers etc. Once the location of water flow is determined one can then decide to close sleeves to minimize water production and maximize oil production.
Embodiments of the treatment tool are operable to drill and complete a having many sleeves installed and only sections of them being opened and stimulated at one time. This maximizes production and drawdown of the hydrocarbons along the length of the well, particularly in long deviated or horizontal wells.
Embodiments of the treatment tool are operable to provide sleeves having full bore access to the well after treatment. Unlike prior art ball-drop type apparatus, the current tool avoid flow restriction for effective post-treatment production or for remedial work over access to the well.
Embodiments of the treatment tool are operable to pinpoint stimulation-type treatment, such as for fracturing, acid injection and the like, with sleeves in a more controllable “placement” of the stimulation versus limited entry such as “plug and perf” or open hole systems such as open hole packers with ball drop activated sleeves.
With reference to
The primary design drivers for this assembly are primarily; to simplify the tool, increase functionality of the tool, provide well flow control capability and reduce the cost of the consumable component, in this case the sleeve valves.
Including sleeve engagement components, the tool design contains a selector valve for controlling flow to and through the tool. The selector valve enables flow to the formation while blocking flow past the tool, and alternately for enabling flow though the tool such as during repositioning. The selector valve, as shown in embodiments herein, can include telescoping tubulars with aligning and misaligned wall ports and a plug valve for opening and closing the tool bore. The form of selector valve may be available in various configurations and is not required for the manipulation of sleeve capability of the shifting tool.
With reference to
The sleeve profile is intermediate the sleeve's length. The profile is annular can has generally right angle uphole and downhole interfaces. The tool's dog also has generally right angle uphole and downhole interfaces. As discussed herein, the tool is manipulated to be restrained radially inwardly for RIH and POOH operations and need not use chamfered edges for movement within the completion string.
The tool's dog and compatible sleeve profile component eliminates the need for an independent location device such as a collar or sleeve end locator. An uphole shoulder of the dog is used to locate an upper shoulder of the sleeve profile for location purposes and for optional release, shifting uphole for re-closing or both. There is no need to compromise the locator function with prior device that is a compromise between locating sleeve ends or casing collars as is performed in conventional tools.
With reference to
The activation mandrel is connected to the convenience string for axial manipulation therewith. The mandrel can be tubular for selectable fluid communication therethrough: blocked when performing treatment operations and open when moving the tool.
Best seen in
Each arm has an upstanding or radial height that varies along its axial length, forming a cam. For shifting modes of the dogs, the annular ring is movable axially along the arms and thus along the arm cam, driven by the axial indexing of the activation mandrel. Indexed axially, the annular ring alternately engages a radially upstanding portion or depressed portion of the arm cam to forcibly drive the arms radially inward or release the arms to move radially outward respectively. When released radially outward, springs bias the arms outwardly to resiliently drag along the completion string and sleeve valve bores such as to axially locate the sleeve profile. When the sleeve is located, further axial shifting of the activation mandrel axially engages a wedge or cone radially under the dogs, forcibly driving the dogs outward and locking them into the profile for positive sleeve manipulation. Alternatively, the arms can be fit with longitudinally extending grooves or tracks form the cam and the retainer ring can support tangential pins to guide the track and arms as discussed.
A downhole or lower shoulder of each dog is used to engage a downhole or lower shoulder of the sleeve profile to enable setdown to shift the sleeve down and open the ports. This can be reversed as well. An uphole or upper shoulder of the dog can also be used to engage the uphole or upper shoulder of the sleeve profile to close the sleeve.
As shown, the engaging surface of the dogs can be designed in multiple configurations depending on the expected application, including with or without button inserts such as those typically fit to slips. The dogs, absent button inserts, can be designed with a profile optimized to engage in the sleeve profile but less so in the casing portion of the completion string, allowing locating in both up or down directions and through the sleeve. Alternatively, button inserts can be designed with a profile optimized to engage in the casing but less optimally in the sleeve. For example button inserts with a down direction engage in the sleeve profile or the casing and locating of the sleeve would be done while pull out; or down direction button inserts that engage in the casing but not the sleeve, again locating of the sleeve would be done while pulling out; or up direction slip configurations maybe utilized for alternate operational sequences.
Button inserts aid in use of the dogs to act as slips in casing such as to anchor the tool anywhere in the completions string. This is useful where an uphole end of the tool includes an optional abrasajet sub wherein the tool can be set anywhere in the completion string and fluid applied to cut ports in the string, such as where a sleeve valve has failed, or where there was no valve placed in the design. Further, insert-equipped dogs enable setting below a sleeve to pressure test the sleeve valve, such as to ensure sleeve closure.
With reference to
As shown, a drag sub can include re-tasking a casing collar locator as a drag block, or one can obtain greater normal loads using a stacked beam drag block as shown in
The present tool, equipped with the stacked beam drag block of
J slot sequencing may be set up in a scenario of patterns selected at surface before running in hole by substitution of the J-Slot sleeve profile. A multiple functioning toe sub can be implemented to open sleeves repeatedly in a well where all other sleeves are closed, forming a hydraulic lock on set tool shifting movement. Shifting a tool string in a closed well often presents a hydraulic lock problem where the shifting tool cannot move into a closed cellar. A toe sub can be provided to allow the hydraulic volume of the fluid to travel somewhere, and be accumulated, so the tool can move. This function may be repeated multiple times in a well.
With reference to the J-slot profile of
Generally, the J-slot sequence as shown in
The remaining modes are intermediate axial positions, both of which restrain the dogs' radial position to enable free movement up and down the conveyance string.
With reference to
With reference to the arrangement of
As shown in isolation in
The dog arms are contained radially by the annular ring. The restrictor ring is axially fixed to the main inner tool activation mandrel and as the activation mandrel travels from position to position the restrictor ring guides the arms radially to their respective position with respect to the J-Slot position. Outward force on the arms is managed by the compression spring under the dogs. This outward force is compressed to the appropriate radial position by the restrictor spring and the force required to manage compression of the spring during axial movement is overcome by the drag block stacked spring assembly.
With reference to the arrangement of
The uphole movement the coiled tubing moves the inner activation mandrel of the tool to transition the J-Pin in the J-Slot to the U position, while the outer housing of the J-slot mechanism is held rotationally static in position by the drag blocks. The drag blocks provide sufficient axial restraining force for the biased energizing of the dogs outward towards the casing. The arms and dogs are held against the casing with a spring force and this force can be adjusted on a per dog basis or group basis as the case may be. The springs are cantilevered leaf or collet-like springs, the ends of each leaf radially biasing the arms outwardly. The force on the dogs is also balanced even if the tool is not centralized in the well. This can aid if the sleeve profile is contaminated with sand or cement and not all the dogs can engage the profile. Only one dog is required to engage the profile to ensure surface-detected location of the tool in the sleeve. The dogs are designed in such a way that one dog alone can withstand the entire load capacity of the coiled tubing injector at surface. This design is a positive location; once engaged, it remains engaged until the J-Slot is cycled or an emergency release is actuated.
Positive location is a significant departure from the conventional sleeve tools. The movement of a tool is often many kilometers downhole, and the coiled tubing string mechanics associated therewith are significant.
In the conventional slip form of sleeve engagement and shifting, two practical problematic situations can occur despite the theory of sleeve locating, slip engagement and sleeve actuation. One, by the time a sleeve location is indicated at surface, through weight change at the injector, the locator may have already moved uphole of the desired or ideal location. Thus when the slips are set, presumably properly positioned at some intermediate point in the sleeve, the tool may actually be set high, and the seal above the slips could interfere with the top of the sleeve and even obstruct the ports. Secondly, even if properly positioned in the sleeve when the set and shift operation is commenced, upon setting down, the slips do not always immediately grip the sleeve and slide therein before cutting in, sometimes only engaging low in the sleeve, resulting in significant annulus that can collect debris, or not even set in the sleeve at all.
Positive sleeve location is an important factor in objectives to minimize sleeve length and cost. Without positive, dog to sleeve indication, optimizing the shortest sleeve possible is difficult if not impossible, else there simply is not enough room for axial placement errors including setting high or too low. On uphole movement during locating, the disclosed dogs will not engage any annular recess but the sleeve's profile, and once engaged, there is no accidental movement to permit one to pull the sleeve profile, the dogs being locked in the profile, unless emergency release tactics are required.
With the dogs engaged in the profile, only extraordinary efforts will permit the coiled tubing string to move, transitioning from locating to shifting the sleeve. If there was a tool failure, the dogs may be released from the sleeve profile by cycling the tool or pulling extreme loads on the coiled tubing to force the dogs into collapse.
The importance of a short sleeve is to achieve a sleeve valve having less material and so avoid the common practice and need for mechanical handling of longer tubulars including preceding and/or following pup joints, the pup joints adding further weight by needed to enable mechanical handing of the already heavy, and now heavier components. Alternatively, with lighter sleeve valves, simply the valve needs be man handled and need not combined with pup joints. Most drilling rigs can accept short components if they are short enough and light enough to be handled by hand, not requiring handling hardware or equipment. If this can be achieved, a cost reduction to the sleeve manufacturing and installation can be realized and significant.
With reference to the arrangement of
With reference to the arrangement of
To lock the dogs into the sleeve profile, the next motion is to RIH with the coiled tubing from the sleeve location cycle. During this transition the tool is held in position by the drag block and the inner activation mandrel travels downhole, also moving the annular restraining ring to its downhole-most position adjacent the pivot, maximizing the arm movement. Similarly the cone moves with the activation mandrel downhole to approach the dogs. The radially outward biasing of the dogs with the compressed spring is locked with the ramped face of the cone and dog engagement. The cone mechanically forces the dogs outwards. During this transition each dog's lower shoulder engages with the bottom shoulder of the sleeve creating an interference fit. The dogs cannot travel down they are trapped ensuring that the tool does not set low in the sleeve. Setting low in the sleeve is an industry problem because if the tool is relying on slips the slips could slide allowing the tool so move downhole. This could create a problem shifting the sleeve because if the slips move off the inner sleeve down hole it's impossible to shift the sleeve. If the sleeve is shifted with the slips at the bottom end of the inner sleeve this allows for more frac debris to be placed on top of the element below the frac entry ports on the sleeve, creating more problems pulling off the zone due to interference with the frac sand that may have accumulated in the space during the frac treatment.
With the dogs engaged, the packer element is compressed between the activation mandrel and the cone to seal within the completions string and the bypass valve through the tool is closed.
If it's required the sleeve can be shifted down with coiled tubing force from surface and/or fluid pressure above the tool. With reference to
Herein, a sleeve is provided where the initial shift of the sleeve can be controlled by overcoming shear screws with a predetermined shear strength. Once the shear value of the screws (number of screws may be adjusted to specific operating parameters) is overcome the inner sleeve is allowed to travel down. Further, a sleeve shift dampening system can be provided (See US20150013991A1 to Applicant, published Jan. 15, 2015). The dampened sleeve controls the acceleration of the internal sleeve and the shock load when the sleeve reaches its shoulder end travel position. By minimizing this shock load the tool longevity is greatly increased and the fluid hammer shock load to the open formation is contained, this is important not exceed the frac breakdown of the formation. Opening the sleeve is indicated at surface by a reduction in coiled tubing string weight. This is important in the event of troubleshooting problems breaking down the formation for example, because it eliminates the concern of sleeve malfunction. Again, having a profile sleeve also eliminates the high or low setting of the tool, which further minimizes troubleshooting formation breakdown. Pull or push loads to close and re-open of the sleeve, after the initial opening of the sleeve, is controlled by an annular detent assembly (See
Particularly for the bottom sleeve, shifting the tool down hole requires relieving the hydraulic compressional forces created in the casing below the tool. Similarly, downhole shifting can be challenging if no other sleeves/ports are open to formation downhole of the sleeve being shifted. A multi-set activation sub is provided to allow fluid to travel somewhere while the tool is shifted, such into the sub. Once the tool is released after the frac the activation sub is reset so another sleeve can be shifted. If a port is open in the well below the tool, the activation sub may be eliminated or remains inactive.
With the dogs locked relative to and below the frac injection point, the ports in the sleeve are optimally aligned every time, minimizing turbulent flow of the frac fluid preventing undesirable circumstances like screening out in the wellbore especially with high frac rates or high density or both. Better alignment also promotes less wear on the tools when frac'ing through the annulus or tubing or both.
With reference to the arrangement of
Setting in casing also provides the ability to isolate pre-perforated perforations with an isolation configuration of the tool or abrasajet cut all the perforations of a new well not using sleeves at all.
The tool may also be utilized in a hybrid well configuration where there are a combination of abrasajet cuts and sleeves, or pre-perforated areas and sleeves or pre-perforated areas and abrasajet perforations.
The tool may be set up with a spring retention element in combination with a bypass valve, or the tension element with or without the bypass (see Applicant's U.S. application Ser. No. 15/013,983, entitled Tension Release Packer For A Bottom Hole Assembly, filed Feb. 2, 2016), incorporated herein by reference in its entirety. Another significant advantage is an optional elimination of the bypass valve. Bypass passage and valves enable bypass fluid flow, however, if a suitable annular bypass is possible, a valve-bore need not be made available. The tension element is designed to pull away from the annular walls and pressure after a frac with more efficiency than the conventional spring retention element, this seal release mechanism providing an annular release means to eliminate the bypass valve. Bypass valves are sliding members, the elimination which would simplify the overall tool.
Setting in casing can be achieved by cycling the J-Slot to RIH-M2 and pull locate U and positioning the tool, then setting down to the set-shift-frac (U) mode.
With reference to the arrangement of
When the sleeve was first opened the detent, such as an annular lip about the sleeve at the downhole end of the sleeve engaged a corresponding annular detent, ratchet or receiver to retain the sleeve in the open position until purposefully actuated. The tool can be cycled uphole by overcoming the detent and then cycled downhole again at some later time downhole. Cycling uphole either enables J-Slot transition to the next stage, or confirms the sleeve was engaged. Cycling downhole thereafter transitions to the next stage.
One can cycle the tool uphole, at a weight indicated at less than a threshold to leave the sleeve open, and then be cycled down. Alternately, one can cycle the tool uphole, at a weight indicated greater than a threshold to overcome the detent, close the sleeve, and only then cycle the tool down.
Thus, upon completion of the frac, the sleeve may be closed or left open. Thereafter, the coiled tubing is cycled down to release the cone from the dogs, and cycle the J-Slot to M2 in preparation for moving uphole or POOH. During uphole movement, for closing the sleeve, the inner activation mandrel of the tool starts to move uphole, opening the bypass valve and tension release of the annular packer seal. The pressure across the tool is equalized and debris is flushed from the tool. The cone disengages from under the dogs and the inner activation mandrel transitions from locked dogs to spring biased or supported dogs. During this transition the dogs do not move in the sleeve, still being engaged with the profile. The dogs do travel axially from the lower shoulder in the sleeve locator to the upper shoulder.
When the dogs engage the upper shoulder the net weight indication is indicated at surface. This weight indication can be set to any loading or threshold, in this case 5,000-15,000 daN over coiled tubing string weight. This weight range is selected because the loading is significant enough to realize at surface. The purpose of closing the sleeve right after the frac includes:
isolation of the frac treatment in the reservoir by not allowing it to flow back into the well. By isolating the frac treatment this allows for the formation to heel containing the frac sand and reducing sand production in the well which ultimately would have to be recovered at some expense; isolation the frac treatment from other previously frac'd sleeves/stages to prevent cross flow in the well; and minimizing the amount of clean fluid required to clean the tools up travelling to the next stage. The sleeves may be re-opened at any time, for example if a well is frac'd from the toe to the heel, once the last sleeve is closed at the heel the coiled tubing can travel back to the toe and the process of locating and opening all the sleeves can begin back to the heel. The sleeves can be opened days/weeks/months later as another option. Generally, these time periods are all reservoir and area specific.
The sleeve is set up with detents for opening and closing the sleeve. The detents in this example are set to release between about 5,000 to about 10,000 daN with maximum upper thresholds being in the order of 13,000 to 15,000 daN. When the upward force on the dogs exceeds the threshold, the detent releases and the sleeve transfers from the open position, see
When the sleeve transfers from the open to the closed position, the sleeve is dampened in reverse (see Applicant's U.S. application Ser. No. 15/013,983, entitled Tension Release Packer For A Bottom Hole Assembly, filed Feb. 2, 2016) and the shock load of the closing action is transferred to surface through indication of a coiled tubing string weight loss.
When the sleeve is closed the coiled tubing may be over pulled, for example at weight greater than 10,000 daN, at surface to confirm closure, however in most cases this is not necessary. Surface weight indication for locating the sleeve, shifting it open and shifting it closed is useful with regards to operational confidence and optimizing operations at surface.
With reference to the arrangement of
When the sleeve is closed, the well at that zone is isolated. The tool dogs are released from the sleeve by RIH with the coiled tubing shifting the J-Slot to M2. The inner activation mandrel travels downhole to the dog release position in the J-Slot. The annular retainer ring forces the dogs' arms to the radially withdrawn position. The outer J-Slot housing is restrained by the drag block and the inner activation mandrel and associated J-Pin travels to the release position. Once the mandrel travel sufficiently downhole, the arm cam's are forced by the retainer ring to collapse the dogs from the sleeve profile, the dogs are unlocked from the sleeve and the tool is free to travel downhole.
With reference to the arrangement of
Leaving the sleeve open, may be done in a couple ways. The first method is when confirming the engagement with the sleeve, the string weight load plus 5,000 daN, the net weight, is not exceeded. If the detent firing load in the sleeve is not exceeded the sleeve will not shift and verification of this is indicated at surface. If the sleeve does not shift there will not be a weight loss at surface pulling up on the coiled tubing. As in closing the sleeve the tool goes through the same inner activation mandrel transition of unlocking the dogs.
After pulling the coiled tubing uphole to a load less than the about 5,000 daN over coiled tubing string load, one proceeds to travel down with the coiled tubing. The tool again transitions from dogs being forced outwardly position to forcing the dogs inwardly via the retainer ring acting on the arm cams surface. Once the retainer ring forces the dogs to the collapsed position, the tool can travel downhole.
Another method of leaving the sleeve open after the frac or stimulation treatment is to provide an alternate J-Slot sleeve and pattern so that the sequence to optionally close the sleeve is eliminated. Rather than an uphole path to the extreme uphole position (U), the slot could terminate at the intermediate M1 position for pulling out of hole. This would allow the tool to be pulled off the sleeve without having to travel down to release the tool. The J-Slot mechanism may have various configurations and sequence patterns to provide a means to change several operating parameters of the tool.
With reference to the arrangement of
With reference to the arrangement of
With reference to the arrangement of
With reference to
Downhole—Run in with mandrel restrained no lower than an intermediate (MID-2/M2) STOP;
Uphole—pull up to full UP/U STOP position to locate the dog in the sleeve profile;
Downhole—set down to a downhole DOWN/D STOP to open the sleeve, actuate the seal, and conical wedge of cone into the dogs and permit treatment, the J-Pin may or may not reach full bottom of the slot;
Uphole—pull up to the fully UP/U STOP and either
One of the aspects of being able to close sleeves, as set forth above, is to be able to shut off stages that are affecting the well, including producing mainly water. There are various laborious techniques to determine if a zone is no longer hydrocarbon-producing, but is merely producing more water. Rather than wellbore testing that requires significant access, time and testing procedures, Applicant instead will provide instrumented sleeve.
Low-cost transducers are fit to each sleeve for determination of well parameters that are indicative of a change in flow or flow quality (direct flow sensor or through temperature, pressure, vibration. For example, software could permit analysis for converting a change in temperature can indicate an increase in flow rate and coupled with surface observations of a higher water cut, could identify that zone as the problem zone and initiate a closing of the sleeves for that zone. The information could be real time with instrumentation cabling external to the sleeved casing, or radio transmission, or other continuous transmission. Examples include fibre-optic, electric per hydraulic line external to the casing. Alternately, the sleeve's electronics package could include memory chip and battery for periodic retrieval with a tool run downhole, such as one per month.
As described in Applicant's co-pending U.S. application Ser. No. 14/405,609, filed as a national phase from WO 2013/185225, incorporated herein by reference in its entirety, data collected by a linear array of fiber optic sensors is utilized for mapping the background noise in the wellbore. The noise mapping is useful to “clean up” data which is obtained from the one or more microseismic sensors, such as 3-component geophones in a frac imaging tool (FIM), which is deployed within the same wellbore below the fracturing tool.
In embodiments, having fiber optic cables attached externally to casing cemented into the wellbore for detection of temperature and acoustic energy related to flow, the fiber optics can also be used as the linear array of fiber optic sensors. Thus, a separate array of fiber optic sensors is not required within the coiled tubing. While less suitable for detecting microseismic events within the formation, the fiber optics attached to the outside of the casing is particularly well suited for noise detection as described in the co-pending application as the fiber optics are well coupled.
The fiber optic sensors can be used with the FIM in real time or in memory for monitoring noise and frac placement and thereafter can be used to monitor flow.
The fiber optic sensor array is installed once with the casing. Sleeves are opened as taught herein and fracturing is completed. Microseismic events in the formation are monitored using a tool such as the FIM tool and noise is detected by the fiber optic sensor array for cleaning up the microseismic data and providing data regarding fracture placement. Thereafter, flow at each of the sleeves is monitored using the fiber optic sensors. Based upon the flow at each of the sleeves, intelligence can be provided to the operator such as to decide whether sleeves need to be closed for preventing undesirable production or injection at particular zones.
With reference to
In yet another embodiment, a jar tool is provided above the treatment tool. The dogs of the treatment tool are engaged with the sleeve profile and conveyance tubing/coiled tubing weight is used to actuate the jar tool to release the sleeve either uphole or downhole and enable sleeve shifting. Mechanical movement of the conveyance tubing actuates the sleeve.
In yet another embodiment, each sleeve is fit to the sleeve housing with a primary hydraulic chamber filled with an incompressible fluid, such as an oil, hydraulic fluid or grease. An orifice is provided to provide and outlet for the fluid from the primary chamber. The dogs are set to the sleeve's profile and a persistent force, uphole or downhole, is applied to the sleeve to displace the fluid from the primary chamber over time to enable free axial shifting movement thereafter. In an embodiment, the hydraulic fluid moves from the primary chamber and into the sleeve bore or the wellbore annulus. In another embodiment, the fluid can move between the primary chamber to a secondary and larger chamber formed between the sleeve housing and sleeve, moving fluid from one end of the sleeve to the other.
| Number | Date | Country | |
|---|---|---|---|
| 62155365 | Apr 2015 | US |
