Patent Application
20170204698
Hydrocarbon-producing wells commonly consist of a wellbore extending through a subterranean formation and lined with a tubular casing. Cement is pumped into an annulus between the wellbore and the casing to fix the casing within the wellbore. Once the casing is cemented in place, a perforating gun is lowered to depth within the casing and fired to create one or more perforations extending through the casing and cement and into the surrounding formation. The perforations generally permit communication of fluid between the internal volume of the casing and the surrounding formation.
Once perforated, wells are often stimulated using various stimulation treatments to improve production. In hydraulic fracturing treatments, for example, a viscous fracturing fluid is pumped into a perforated production zone at sufficiently high pressure to create fractures within the production zone and to propagate existing or newly created fractures. The fractures improve production by providing new or enhancing existing pathways for fluid to move between the formation into the casing.
An acidizing is another example of a treatment that may be performed on a wellbore. Acidizing treatments involve the introduction of an acid or similar fluid into the formation. The acid dissolves debris introduced into the formation during perforation and fracturing. Acidizing may also be used to improve permeability of the formation by partially dissolving the formation, enlarging existing fluid pathways.
A well may include multiple production zones, with each production zone requiring its own perforation and treatment. Production zones are typically perforated and treated beginning with the farthest downhole production zone and proceeding sequentially uphole. To properly treat an uphole production zone, an operator may need to isolate the uphole production zone from downhole production zones that have been previously perforated and treated. For example, in fracturing treatments, isolating an uphole production zone to be fractured from a downhole production zone that has already been fractured enables more efficient build-up of pressure within the production zone to be fractured because fracturing fluid is not lost to the formation via the previously fractured production zone. Isolation in the fracturing context may also protect the previously fractured production zone from additional, unwanted fracturing.
Given the prevalence of stimulation treatments, there is a consistent drive among operators to lower costs and improve efficiencies associated with completion and fracturing operations.
A more complete understanding of the present embodiments and advantages thereof may be acquired by referring to the following description taken in conjunction with the accompanying drawings, in which like reference numbers indicate like features.
While embodiments of this disclosure have been depicted and described and are defined by reference to exemplary embodiments of the disclosure, such references do not imply a limitation on the disclosure, and no such limitation is to be inferred. The subject matter disclosed is capable of considerable modification, alteration, and equivalents in form and function, as will occur to those skilled in the pertinent art and having the benefit of this disclosure. The depicted and described embodiments of this disclosure are examples only, and not exhaustive of the scope of the disclosure.
The present disclosure relates generally to stimulation treatment operations and specifically to a collapsible baffle sub for isolating production zones to be treated.
Illustrative embodiments of the present invention are described in detail herein. In the interest of clarity, not all features of an actual implementation may be described in this specification. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation specific decisions must be made to achieve the specific implementation goals, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of the present disclosure.
To facilitate a better understanding of this disclosure, the following examples of certain embodiments are given. In no way should the following examples be read to limit, or define, the scope of the claims.
The outer housing 102 houses components of the collapsible baffle sub 100 and connects the collapsible baffle sub 100 to adjacent sections of the casing string. Depending on the configuration of the casing string, the outer housing 102 may be configured to connect to adjacent casing string sections using various threaded connections. For example, in a typical casing string, pipe joints having male-threads on both ends and are connected to each other by couplings having female-threaded ends. In such casing strings, the outer housing 102 may include two female-threaded connections for installation between two pipe joints, two male-threaded connections for installation between two couplings, or one each of a male-threaded connection and a female-threaded connection for installation between a pipe joint and a coupling.
The specific lengths and arrangement along the casing of pipe joints, couplings, collapsible baffle subs, and other casing string sections will vary based on the wellbore in which the casing string is to be installed. For example, wellbore depth and directionality and the location of production zones within the subterranean formation through which the wellbore extends will dictate the length of particular sections of pipe joints and the location of the collapsible baffle subs. To facilitate treatment of a particular production zones, the collapsible baffle subs are positioned along the casing string such that when the casing string is installed within the wellbore, a collapsible baffle sub for isolating the particular production zone is positioned downhole of the particular production zone. Accordingly, the position of any collapsible baffle sub along the casing string may be determined by a combination of wellbore geometry and geological information about the subterranean formation through which the wellbore extends.
Once a casing string including the collapsible baffle sub 100 is installed in a wellbore, the collapsible baffle sub 100 may be actuated using a shifting tool. To actuate the collapsible baffle sub 100, the shifting tool moves the sleeve 104 from a first position within the outer housing 102, as depicted in
In the collapsed position, the collapsible baffle 106 may receive an untethered object, such as a ball, inserted into the wellbore. The untethered object and the collapsible baffle 106 are designed such that when the collapsible baffle 106 receives the untethered object, a seal is formed between the collapsible baffle 106 and the untethered object. As a result, the collapsible baffle and untethered object act as a blockage within the casing string, preventing fluid flow between casing string uphole of the seal and casing string downhole of the seal.
As depicted in
To actuate the collapsible baffle sub 100, the sleeve 104 is moved with a setting tool, permitting collapse of the collapsible baffle 106. The setting tool is conveyed into the wellbore using wireline, e-line, coiled tubing or a similar conveyance system and is configured to engage the sleeve 104. As depicted in
In any embodiment, the shifting tool may be run downhole as part of a tool string that also includes a perforating gun. A tool string with both a setting tool and perforating gun allows an operator to actuate a collapsible baffle sub and perforate the casing string in a single run. To do so, after actuation, the setting tool is disengaged from the sleeve 104 and the tool string is repositioned within the wellbore such that the perforating gun is aligned with a section of the casing string to be perforated. After the perforating guns are fired, the tool string, including the perforating gun and the setting tool, may be withdrawn.
The setting tool may engage the sleeve 104 in various ways. For example, the setting tool may include one or more deployable keys configured to extend from the setting tool and engage the sleeve 104. In such an embodiment, engagement of the sleeve 104 would first require conveying the setting tool beyond the collapsible baffle sub. The deployable keys may then be deployed and the setting tool pulled back uphole such that the now-deployed deployable keys catch on and engage the sleeve 104 via the lip 108. In embodiments in which the shifting tool is conveyed by a system including a wire, the deployable keys may be deployed in response to an electronic signal sent to the setting tool via the wire. To disengage the sleeve 104 after movement, the setting tool may be configured to retract the deployable keys in response to a second similar signal. Alternatively, the deployable keys may be designed to shear off to release the setting tool. In such embodiments, the collapsible baffle sub would include an internal shoulder against which the sleeve abuts when the sleeve is moved into the second position. The shoulder prevents additional movement of the sleeve. As a result, by pulling on the setting tool with sufficient force after the sleeve 104 has been shouldered, the deployable keys may be sheared and the setting tool released from engagement with the sleeve 104.
Another example of a mechanism for engaging the sleeve 104 is an inflatable bladder disposed on the setting tool. The inflatable bladder may be inflated within the sleeve 104 to contact an inside surface the sleeve 104, sufficiently gripping the sleeve 104 such that the sleeve 104 may be moved into the second position by pulling the setting tool uphole. Once the sleeve 104 is moved into the second position, the inflatable bladder may be deflated, permitting withdrawal of the setting tool.
Once the sleeve 104 is moved and no longer retains the collapsible baffle 106, the collapsible baffle 106 may collapse within the outer housing 102. In the embodiment depicted in
In any embodiment, the collapsible baffle 206 may include a liner or coating applied to some or all of the collapsible baffle 206. For example, a rubber liner may be applied to an inner seating surface 222. As previously discussed, when collapsed, the collapsible baffle 206 may receive and seal against an untethered object, such as a ball. A rubber liner on the inner seating surface 222 may be used to improve sealing between the ball and the collapsible baffle 206. The inner surface 222 may also be coated to improve erosion or chemical resistance.
An outer surface 226 of the collapsible baffle 206 may be similarly coated or lined. A liner or coating on the outer surface 226 may serve various purposes. For example, a coating or lining may be used to improving sealing of the outer surface 226 of the collapsible baffle 206 with an inner surface of the collapsible baffle sub housing. As another example, polytetrafluoroethylene (PTFE) or a similar material may be applied to reduce friction or prevent wear of the collapsible baffle 206.
At step 302, collapsible baffle subs are run into the wellbore as part of a casing string. Installation of the collapsible baffle subs within the casing string may be done as the casing string is run into the wellbore using techniques and equipment commonly used when running casing string. Once the casing string and the collapsible baffle subs incorporated therein are positioned within the wellbore, the casing string is cemented in place, as indicated at step 304.
At step 306, a shifting tool, which in this example is incorporated into a tool string that also includes a perforating gun, is conveyed via wire, e-line, coiled tubing, or a similar conveyance system through the inside of the casing string and past the collapsible baffle sub corresponding to a first production zone to be treated. During this process, fluid may also be pumped into the casing string to facilitate conveyance of the tool string.
For purposes of this example, the setting tool includes deployable keys, as previously discussed in this disclosure. After the setting tool is conveyed past the collapsible baffle sub, the deployable keys may be deployed. Then, at step 308, the shifting tool may be pulled uphole to engage a sleeve within the collapsible baffle sub. Once the shifting tool has engaged the sleeve, the next step 310 is to shift the sleeve within the collapsible baffle sub by further pulling the shifting tool uphole by the wire, e-line, coiled tubing or similar conveyance.
With the sleeve now shifted, a collapsible baffle within the collapsible baffle sub collapses at step 312. The setting tool may then be disengaged from the sleeve at step 314, and repositioned to align the perforating gun with the first production zone at step 316. The perforating guns may then be fired at step 318, perforating the adjacent casing string, cement, and formation. After firing the perforating guns, the tool string may be removed from the wellbore at step 320.
In embodiments in which the setting tool is not incorporated with a perforating gun into a single tool string, the setting tool may be removed from the wellbore after disengaging from the sleeve. After the setting tool is removed, a second tool including a perforating gun may be run into the wellbore to perforate the casing at the first production zone.
With the collapsible baffle collapsed within the collapsible baffle sub, the collapsible baffle is able to receive an untethered object, such as a ball. Accordingly, in step 322, a ball is dropped into the casing string and seats against the collapsible baffle, forming a seal between the collapsible baffle and the ball. As alternatives to dropping the ball, the ball may be shot or pumped into the casing string as well.
With the production zone now isolated, treatment fluid, such as fracturing fluid, may be pumped into the casing string to perform the desired stimulation treatment, as indicated at step 324. The treatment fluid is permitted to flow though the perforations and into the production zone, but is prevented from travelling within the casing string beyond the collapsible baffle and ball due to the seal between them above.
Once stimulation treatment for the production zone is complete, the above process generally consisting of actuating the collapsible baffle sub, perforating the casing, inserting a ball, and pumping treatment fluid, may be repeated for a second production zone and any other remaining production zones thereafter.
After all production zones have been stimulated, step 326 involves removal of any balls used to isolate each of the production zones. Removal of the balls permits formation fluids to flow through the casing string to the surface. The balls may be removed in various ways. For example, in one embodiment, a pump at or near the surface may pump fluid from the wellbore. Doing so reverses the pressure within the casing string, causing the balls to unseat from the collapsible baffles and to be drawn to the surface for removal. The balls may also be made of a dissolvable material and removed by circulating through the wellbore a fluid suitable for dissolving the balls. For example, the fluid may be an abrasive fluid that erodes the balls or may be a chemical selected to react with and decompose the particular material from which the balls were made. The balls may also be mechanically removed or destroyed by running a milling bit or similar tool through the casing string.
As previously mentioned, the method described above and depicted in
In embodiments where multiple production zones are prepared for treatment in a single run, the collapsible baffles of the collapsible baffle subs may vary in their inside diameters when collapsed. Varying inside diameters permits the use of different sizes of untethered objects to selectively isolate volumes of the casing string. For example, in a casing string having an uphole baffle and a downhole baffle, the uphole baffle may be configured to have a larger inside diameter when collapsed than the downhole baffle. This would permit a ball having a diameter measuring between the inside diameters of the uphole and downhole baffles to be inserted into the wellbore and sealed against the downhole baffle despite the uphole baffle being collapsed.
Although numerous characteristics and advantages of embodiments of the present invention have been set forth in the foregoing description and accompanying figures, this description is illustrative only. Changes to details regarding structure and arrangement that are not specifically included in this description may nevertheless be within the full extent indicated by the claims.
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/US2014/052314 | 8/22/2014 | WO | 00 |
