SEALING A PORTION OF A WELLBORE

Description

CROSS-REFERENCE TO RELATED APPLICATION

This application claims priority under 35 U.S.C. § 119 to U.S. Provisional Patent Application Ser. No. 63/560,969, filed on Mar. 4, 2024, the entire contents of which are incorporated by reference herein.

TECHNICAL FIELD

The present disclosure describes apparatus, systems, and methods associated with sealing a portion of a wellbore and, more particularly, sealing a portion of a wellbore with a cement swell packer.

BACKGROUND

Conventional wellbore cementing is an important process in well construction that involves the placement of cement into the annular space between the casing and the wellbore wall. The process serves multiple purposes, including providing zonal isolation, ensuring well integrity, and facilitating efficient production or injection of fluids. During cementing, a specially formulated cement slurry is pumped down the casing and forced up into the annular space. The cement slurry then sets and hardens, creating a durable and impermeable barrier that prevents the migration of fluids between different zones and protects the wellbore from potential environmental or operational risks. Cementing plays a vital role in achieving safe and efficient well operations, enhancing reservoir performance, and maintaining the integrity of all wells.

SUMMARY

In an example implementation, a cement swell packer includes a base tubular that includes at least one end connection; a cement swell assembly configured to mount on the base tubular and including a portion of a dry cementitious material configured to form a hardenable or curable cement when exposed to a fluid in a wellbore, and a mesh configured to hold the portion of the dry cementitious material; and a liquid barrier formed over the dry cementitious material.

An aspect combinable with the example implementation further includes at least one collar configured to retain the cement swell assembly on the base tubular.

In another aspect combinable with one, some, or all of the previous aspects, the at least one collar includes a first collar configured to mount on the base tubular at a first end of the cement swell assembly and a second collar configured to mount on the base tubular at a second end of the cement swell assembly opposite the first end.

In another aspect combinable with one, some, or all of the previous aspects, the liquid barrier includes a removable film or wrap.

In another aspect combinable with one, some, or all of the previous aspects, the liquid barrier includes a sprayed barrier configured to degrade in the presence of the fluid.

Another aspect combinable with one, some, or all of the previous aspects further includes at least one centralizer configured to mount over the base tubular.

In another aspect combinable with one, some, or all of the previous aspects, the at least one centralizer includes a first centralizer configured to mount on the base tubular at or near a first end of the base tubular and a second centralizer configured to mount on the base tubular at or near a second end of the base tubular opposite the first end.

In another aspect combinable with one, some, or all of the previous aspects, the base tubular includes a casing joint of a production casing.

In another aspect combinable with one, some, or all of the previous aspects, the at least one end connection includes a male threaded connection at a first end of the casing joint; and a female threaded connection at a second end of the casing joint opposite the first end.

In another aspect combinable with one, some, or all of the previous aspects, an unconfined compressive strength of the hardenable or curable cement is less than an unconfined compressive strength of a primary cement pumped into the wellbore to adhere the production casing to a well surface.

In another aspect combinable with one, some, or all of the previous aspects, the well surface includes an intermediate casing.

In another example implementation, a method includes positioning a cement swell packer adjacent a wellbore entry. The cement swell packer includes a base tubular that includes at least one end connection, a cement swell assembly mounted on the base tubular and including a portion of a dry cementitious material configured to form a hardenable or curable cement when exposed to a fluid in a wellbore; and a mesh configured to hold the portion of the dry cementitious material, and a liquid barrier formed over the dry cementitious material. The method includes removing the liquid barrier from the dry cementitious material; making up a connection between the at least one end connection and another base tubular within a string of base tubulars; and running the cement swell packer into the wellbore on the string of base tubulars.

An aspect combinable with the example implementation further includes making up another connection between the base tubular and a further base tubular at an end of the base tubular opposite the another base tubular; and running the base tubular, the another base tubular, and the further base tubular into the wellbore on the string of base tubulars.

In another aspect combinable with one, some, or all of the previous aspects, removing the liquid barrier from the dry cementitious material occurs subsequent to making up the connection between the at least one end connection and the another base tubular within the string of base tubulars.

Another aspect combinable with one, some, or all of the previous aspects further includes positioning the base tubular on the string of base tubulars at a particular location in the wellbore; and exposing the dry cementitious material to a liquid in the wellbore to form a hardenable cementitious slurry.

Another aspect combinable with one, some, or all of the previous aspects further includes initiating a hardening or curing process of the hardenable cementitious slurry to form hardened cement over a time duration.

In another aspect combinable with one, some, or all of the previous aspects, exposing the dry cementitious material to the liquid in the wellbore includes circulating the liquid from a terranean surface to the particular location in the wellbore.

In another aspect combinable with one, some, or all of the previous aspects, the liquid includes water.

Another aspect combinable with one, some, or all of the previous aspects further includes pumping a flow of a primary cement that includes the liquid downhole through the string of base tubulars and uphole through an annulus between the string of base tubulars and a well surface; and exposing the dry cementitious material to the liquid in the wellbore to form the hardenable cementitious slurry.

In another aspect combinable with one, some, or all of the previous aspects, the well surface includes an inner radial surface of an intermediate casing string, and the string of base tubulars includes a production casing.

Another aspect combinable with one, some, or all of the previous aspects further includes assembling the cement swell packer by mounting the cement swell assembly on the base tubular; installing at least one collar onto the base tubular to retain the cement swell assembly on the base tubular; and forming the liquid barrier onto the cement swell assembly.

In another aspect combinable with one, some, or all of the previous aspects, forming the liquid barrier onto the cement swell assembly includes covering the cement swell assembly with a film or wrapping to form the liquid barrier; or spraying the cement swell assembly to form the liquid barrier.

In another example implementation, an apparatus includes a plurality of casing joints. Each casing joint includes a tubular section, a male threaded connection, and a female threaded connection. The plurality of casing joints are configured to form a connected production casing string in a wellbore. The apparatus includes a cement swell assembly mounted on at least one of the casing joints. The cement swell assembly includes a portion of a dry cementitious material configured to form a hardenable or curable cement when exposed to a fluid in the wellbore; and a mesh configured to hold the portion of the dry cementitious material.

An aspect combinable with the example implementation further includes a first collar mounted on the at least one casing joint at a first end to retain the cement swell assembly on the casing joint; and a second collar mounted on the at least one casing joint at a second end of the cement swell assembly opposite the first end to retain the cement swell assembly on the casing joint.

Another aspect combinable with one, some, or all of the previous aspects further includes a first centralizer mounted on the casing joint at or near the first end; and a second centralizer mounted on the casing joint at or near the second end.

Another aspect combinable with one, some, or all of the previous aspects further includes a liquid barrier that covers the portion of the dry cementitious material.

In another aspect combinable with one, some, or all of the previous aspects, an unconfined compressive strength of the hardenable or curable cement is less than an unconfined compressive strength of a primary cement pumped into the wellbore to install the connected production casing string.

The details of one or more implementations of the subject matter described in this disclosure are set forth in the accompanying drawings and the description below. Other features, aspects, and advantages of the subject matter will become apparent from the description, the drawings, and the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic diagram of an example implementation of a wellbore system that includes at least one cement swell packer installed in a tubular string according to the present disclosure.

FIG. 2 is an exploded schematic diagram of an example implementation of a cement swell packer according to the present disclosure.

FIG. 3 is a schematic diagram of an example implementation of an assembled cement swell packer according to the present disclosure.

FIG. 4 is a schematic diagram of an example implementation of a cement swell packer readied for installation into a wellbore according to the present disclosure.

FIG. 5 is a graph that shows relative strength development between a cement swell packer and a primary cement according to the present disclosure.

FIGS. 6A-6C show schematic diagrams that illustrate a development over time of a cement swell packer in a wellbore according to the present disclosure.

FIGS. 7A-7C show additional schematic diagrams that illustrate a development over time of a cement swell packer in a wellbore according to the present disclosure.

FIGS. 8A-8D show additional schematic diagrams that illustrate a development over time of a cement swell packer in a wellbore according to the present disclosure.

DETAILED DESCRIPTION

The present disclosure describes example implementations of a cement swell packer that can be installed within a wellbore tubular string, such as a casing string (e.g., production casing string or other casing string), to create a cementitious seal between the string and, for instance, the subterranean formation through which the wellbore is formed. In some aspects, example implementations according to the present disclosure can provide for an enhanced seal between, for example, the production casing and the subterranean formation in locations within the wellbore where a primary cement (circulated to install the casing to the formation) is inadequate or non-existent.

FIG. 1 is a schematic diagram of an example implementation of a wellbore system 10 that includes at least one cement swell packer 100 installed in a tubular string according to the present disclosure. Generally, FIG. 1 illustrates at least a portion of one implementation of the cement swell packer 100 according to the present disclosure in which one or more cement swell packers 100 can be installed in a wellbore as part of a tubular string, such as, for example, a production casing 45 within a wellbore 20. However, cement swell packers 100 according to the present disclosure can also be installed on other wellbore tubular strings, such as other casings, production tubing strings, or otherwise.

Example implementations of the cement swell packer 100 according to the present disclosure can provide for solutions to problems usually associated with inadequate or non-existent cementing of a casing. For example, cement swell packers according to the present disclosure can improve zonal isolation. Achieving effective zonal isolation can be crucial to prevent fluid migration between different formations and to protect a wellbore. Challenges arise from the need to properly design and execute a cementing process to ensure a complete and uniform cement sheath, especially in challenging downhole conditions.

Also, cement swell packers 100 according to the present disclosure can improve cement slurry stability. Maintaining the stability and consistency of a primary cement slurry throughout a pumping operation can be essential. Factors such as temperature, pressure, and wellbore conditions can impact the slurry's properties, leading to issues like premature setting, fluid loss, or poor bonding with the casing or formation (or both).

Further, cement swell packers 100 according to the present disclosure can improve cement placement. Proper placement of a cement slurry is critical for achieving effective zonal isolation. Challenges can arise from complex well geometries, narrow annular spaces, or formations with varying permeability, which can result in uneven distribution of the cement, voids, or channels that compromise zonal isolation.

As another example, cement swell packers 100 according to the present disclosure can improve wellbore integrity. Cement integrity and bonding between the casing and formation can be essential for maintaining wellbore integrity. Challenges may arise from factors such as inadequate cement coverage, poor bonding, or the presence of micro-annuli, which can lead to fluid migration, gas influx, or mechanical failures, such as casing collapse or casing leaks.

Further, cement swell packers 100 according to the present disclosure can help avoid problems with wellbore fluids and additives. For example, the presence of certain wellbore fluids, such as drilling mud or high-salinity brines, can pose challenges during cementing. Incompatibilities between these fluids and the primary cement slurry can result in issues like fluid loss, reduced cement performance, or compromised zonal isolation. Additionally, selecting appropriate additives and their proper dosage can be crucial to address specific wellbore conditions and challenges effectively.

In this example implementation, the cement swell packer 100 (or many cement swell packers 100) are installed as part of the production casing 45 into the wellbore 20, which is used to circulate a wellbore fluid 65, such as a hydrocarbon fluid (for example, oil, gas, or a mixture thereof) from a subterranean reservoir 40, through one or more perforations 55 formed in the production casing 45 (as well as fractures, whether hydraulic or natural or both), and to a terranean surface 12. As shown, the wellbore 20 accesses the subterranean formation 40 and provides access to hydrocarbons (for example, the wellbore fluid 65) located in such subterranean formation 40. In an example implementation of system 10, the system 10 may be used for a production operation in which the hydrocarbons may be produced from the subterranean formation 40 through the production casing 45 (and also, in some cases, other wellbore tubular strings) and to the surface 12.

A drilling assembly (not shown) may be used to form the wellbore 20 extending from the terranean surface 12 and through one or more geological formations in the Earth. One or more subterranean formations, such as subterranean zone 40, are located under the terranean surface 12. As will be explained in more detail below, one or more wellbore casings, such as a surface casing 30, intermediate casing 35, and the production casing 45 can be installed in at least a portion of the wellbore 20. In some aspects, production casing 45 is nested within the intermediate casing 35 such that an annulus 22 is formed between the production casing 45 and intermediate casing 35; however, the annulus can also be defined between the production casing 45 and wellbore 20 (i.e., the rock formation) when these two casings (35 and 45) are not nested.

In some implementations, a drilling assembly used to form the wellbore 20 may be deployed on a body of water rather than the terranean surface 12. For instance, in some implementations, the terranean surface 12 may be an ocean, gulf, sea, or any other body of water under which hydrocarbon-bearing formations may be found. In short, reference to the terranean surface 12 includes both land and water surfaces and contemplates forming and developing one or more downhole pumping systems 10 from either or both locations.

In some implementations of the wellbore system 10, the wellbore 20 is cased with one or more casings. As illustrated, the wellbore 20 includes a conductor casing 25, which extends from the terranean surface 12 shortly into the Earth. A portion of the wellbore 20 enclosed by the conductor casing 25 may be a large diameter borehole. Additionally, in some implementations, the wellbore 20 may be offset from vertical (for example, a slant wellbore). Even further, in some implementations, the wellbore 20 may be a stepped wellbore, such that a portion is drilled vertically downward and then curved to a substantially horizontal wellbore portion. Additional substantially vertical and horizontal wellbore portions may be added according to, for example, the type of terranean surface 12, the depth of one or more target subterranean formations, the depth of one or more productive subterranean formations, or other criteria.

Downhole of the conductor casing 25 may be the surface casing 30. The surface casing 30 may enclose a slightly smaller borehole and protect the wellbore 20 from intrusion of, for example, freshwater aquifers located near the terranean surface 12. The wellbore 20 may than extend vertically downward. This portion of the wellbore 20 may be enclosed by the intermediate casing 35 or the production casing 45 (or both). Any of the illustrated casings, as well as other casings that may be present in the wellbore system 10, may include one or more casing collars.

As shown in this example implementation, the production casing 45 is formed of multiple production casing joints 50 (also called casing joints 50). Indeed, depending on a total length of the production casing 45, there can be hundreds of casing joints 50 coupled together (for example, threadingly) to form the production casing 45. Once the production casing 45 is installed in the wellbore, a primary cement 70 is circulated downhole through the installed production casing 45 and then back uphole in an annulus 22 between an outer radial surface of the production casing 45 and the wellbore 20 (i.e., the subterranean formation through which the wellbore 20 is formed). Generally, the primary cement 70 remains in the annulus 22 to adhere the production casing 45 to the formation(s) through which the wellbore 20 is formed. The primary cement 70 can also provide other functions, such as sealing the wellbore 20 (and annulus 22) against fluid intrusion and providing better wellbore integrity (as compared to having no primary cement 70 between the production casing 45 and the formation(s)).

One or more cement swell packers 100 can be installed within the production casing 45 during a run-in process that places the production casing 45 (joint-by-joint) into the wellbore 20. FIG. 2 is an exploded schematic diagram of an example implementation of a cement swell packer 100 according to the present disclosure. In this example implementation, the cement swell packer 100 includes a casing joint 50 onto which a cement swell assembly 101 is installed (prior to running into the wellbore 20 as part of the production casing 45).

As shown in this example, the casing joint 50 is comprised of a tubular section 52 (e.g., of circular or near circular cross-section) that includes a female connection 54 and a male connection 56. In this example, both the female connection 54 and male connection 56 are threaded connections, with threads formed on an outer radial surface of the casing joint 50 for the male connection 56, and threads formed on an inner radial surface of the female connection 54. However, other forms of connections are possible, such as grooved joint connections (for example, Victaulic® or otherwise).

A diameter, d, of the female connection 54 generally represents the largest diameter in the casing joint 50 (i.e., relative to the diameter of the tubular section 52 and male connection 56). The diameter, d, in this example, is generally set by conventional casing joint sizes of 13 ⅜″ or 18 ⅝″ (but other sizes are also contemplated by the present disclosure). In this example, the casing joint 50 can be 6 ft. or 10 ft. long, but any length is also contemplated by the present disclosure. Also, although shown as a solid tubular (and specifically, a tubular for casing), the casing joint 50 can represent a casing, a liner, a completion pipe, as well as tubular screens of the wire, mesh or pre-perforated variety.

In this example implementation of the cement swell packer 100, the cement swell assembly 101 is comprised of a cementitious mesh packer 102 that is sized to ride on the tubular section 52 of the casing joint 50. The cementitious mesh packer 102 includes a fabric or mesh 104 that is impregnated or embedded with, or otherwise holds or retains a dry cementitious material 106 that, when exposed to one or more fluids of sufficient volume, forms a hardenable or curable cement barrier. The dry cementitious material 106 can be, for example, a Portland cement granular material that, with the addition of liquid (such as water or brine in the wellbore or circulated into the wellbore) swells to form cement.

As further shown in this example, the cement swell assembly 101 includes an upper collar 108 and a lower collar 110. Generally, the collars 108 and 110 ride on the tubular section 52 on either end of the cementitious mesh packer 102 to retain the cementitious mesh packer 102 on the tubular section 52 of the casing joint 50 (for example, during a run in of the cement swell packer 100 when installing the production casing 45 in the wellbore 20).

In this example, a diameter, D, of the cementitious mesh packer 102 represents the largest diameter of the cement swell assembly 101 (which is generally, the diameter of the collars 108 and 110) prior to swelling of the cementitious material 106 and therefore, the diameter of the cement swell assembly 101 when it is installed on the casing joint 50 and run into a wellbore. In some aspects, the diameter, D, can be equal to or less than the diameter, d, of the casing joint 50. Thus, the cement swell assembly 101 installed on the casing joint 50 would not impede installation of the production casing 45 into the wellbore 20. Given this dimension, D, being less than or equal to the dimension, d, the cement swell packer 100 is not expected to contact an inside diameter of the wellbore 20. And with optional centralization (as described herein), even the upper collar 108 and lower collar 110 should not (or should rarely) contact the rock formation through which the wellbore 20 is formed. Further, it is not expected that the casing running speed will need to be altered to avoid wellbore challenges such as “surging.”

In this example implementation of the cement swell assembly 101, a barrier 112 can be installed over or around the cementitious mesh packer 102 during installation of the cement swell assembly 101 onto the casing joint 50. Generally, the barrier 112 can be a mechanical barrier (for example, a film or wrapping such as a plastic or otherwise liquid impenetrable barrier) that protects the cementitious material 106 from, for example, liquids or other intrusive material or damage. The barrier 112 is removable (for example, prior to running the cement swell packer 100 into the wellbore 20) to expose the cementitious mesh packer 102. In alternative implementations of the barrier 112, the barrier 112 can be a spray or other liquid barrier that is applied to the cementitious mesh packer 102 and remains on the cementitious mesh packer 102 during installation of the cement swell packer 100 into the wellbore 20, but eventually wears off or dissolves in the presence of liquid to expose the cementitious material 106 to a liquid swelling fluid in the wellbore 20.

FIG. 3 is a schematic diagram of an example implementation of an assembled cement swell packer 100 according to the present disclosure. As shown in this example, the cement swell assembly 101 has been installed onto the casing joint 50 over the tubular section 52. The cementitious mesh packer 102 rides on the tubular section 52 and is held in place by the upper collar 108 and lower collar 110. Optional centralizers 120 can be installed on the casing joint 50 on either end of the cement swell assembly 101 as shown. In some aspects, one or more of the centralizers 120 can be added to the cement swell packer 100, such as when there is concern that damage might occur to the cement swell assembly 101 during running into the wellbore 20 as part of the production casing 45.

FIG. 3 can represent the cement swell packer 100 (with or without one or more centralizers 120) upon delivery to a well site or at a well site but prior to making up the cement swell packer 100 into the production casing 45 and installing it into the wellbore 20. For example, in this illustration, the barrier 112 is still installed on the cementitious mesh packer 102 and not yet removed to run the cement swell packer 100 into the wellbore 20. In some aspects, the barrier 112 can be removed (if a mechanical barrier) just prior to making up the cement swell packer 100 into the production casing 45 on the rig floor. In some aspects, the barrier 112 can be removed (if a mechanical barrier) after making up the cement swell packer 100 into the production casing 45 on the rig floor but prior to running into the wellbore 20.

FIG. 4 is a schematic diagram of an example implementation of the cement swell packer 100 readied for installation into a wellbore according to the present disclosure. For example, as shown in this figure, the cement swell packer 100 is coupled (for example, threadingly) to another casing joint 50 (which may or may not include a cement swell assembly 101) and is being run into the wellbore 20. In this example, the optional centralizers 120 are positioned on the tubular section 52 of the casing joint 50. Further, in this example, the barrier 112 (as a mechanical barrier such as a film or wrap) has been removed from the cementitious mesh packer 102. The barrier 112 can be removed prior to the cement swell packer 100 being made up with the casing joint 50 that is illustrated as being run into the wellbore 20. Alternatively, the barrier 112 can be removed subsequent to the cement swell packer 100 being made up with the casing joint 50 that is illustrated as being run into the wellbore 20.

In an example operation, once the cement swell packer 100 is assembled as described with reference to FIGS. 2 and 3 (either at a well site or off site), the cement swell packer 100 can be coupled within a production casing 45 that is being run into the wellbore 20 (as described with reference to FIG. 4). If necessary, as described, the barrier 112 is removed prior to the cement swell packer 100 being run into the wellbore. In some aspects, the cement swell packer 100 (or multiple cement swell packers 100) can be installed in a production casing 45 so that the cement swell packer 100 is set at a particular depth in the wellbore 20 (for example, a depth in which an additional or some cement seal is desired). When run into the wellbore 20, the cementitious mesh packer 102 is exposed to wellbore fluids, such as a wellbore fluid circulated into the wellbore (including liquid as part of the primary cement 70 or a separate liquid circulated to the annulus 22). In some aspects, wellbore fluids that are already present in the wellbore 20 cause swelling of the cementitious mesh packer 102.

The cement swell packer 100 is installed at a final depth/location. In some aspects, the cementitious material 106 does not swell immediately on entry into the wellbore 20 due to, for example, built-in retarding agents within the material 106 (or generally, the cementitious mesh packer 102). This can ensure that a diameter of the cementitious mesh packer 102 does not exceed, for example, the diameter, d, of the casing joint 50 for a particular time duration (for example, between 6 hours and 48 hour). Following this time period, the cementitious mesh packer 102 commences to swell by the hydration of the cementitious material 106, which increases a diameter of the cementitious mesh packer 102. Upon reaching a mechanical barrier, such as a wellbore wall, another casing string, or the primary cement 70, the cementitious mesh packer 102 commences setting or building mechanical strength.

In some aspects, an acceptable strength of the cementitious mesh packer 102 is defined as the strength to ensure pressure holding capability across the cement swell packer 100, which is obtained after a configurable range of 1 day to many weeks. For example, FIG. 5 is a graph 500 that shows relative strength development between a cement swell packer and a primary cement according to the present disclosure. Graph 500 includes x-axis 502 (of time, in hours) and y-axis 504 (of compressive strength in mega pascals). Curve 506 represents a compressive strength vs. time of a primary cement that is circulated into a wellbore (such as the primary cement 70). Curve 508 represents a compressive strength vs. time of a cementitious material (such as material 106) that is part of a casing swell packer (such as cement swell packer 100).

As shown in graph 500, five specific time instances and associated compressive strength values are identified for each curve 506 and 508. The time instances are 0 hours, 6 hours (run in time of the cement swell packer), 24 hours (18 hours after run in of the cement swell packer and when a primary cement is circulated), 72 hours to 168 hours (curing time of both the cementitious material of the cement swell packer and the primary cement), and at 168 hours (7 days) the full pressure hold capability of both cement materials. The numbers on the curves 506 and 508 represent the compressive strength in mega pascals.

Graph 500, therefore, shows an example deployment of a cement swell packer (such as cement swell packer 100) in combination with a primary, pumped cement operation (in other words, primary cement 70). Generally, the pumped cement is required to build acceptable (compressive) strength of 35 Mpa in 24 hours after deployment. With the cement swell packer starting to build strength 72 hours after deployment, then achieving a maximum of 17 Mpa, the example shows that the cement swell packer is unable to crush or otherwise damage pumped cement.

FIGS. 6A-6C show schematic diagrams that illustrate a development over time of a cement swell packer in a wellbore according to the present disclosure. Generally, FIGS. 6A-6C show schematic diagrams that illustrate a development over time (upon run in at 6 hours to 7 days after run in) of the cement swell packer 100 when there is no primary cement 70 circulated to the annulus 22 (in other words, behind the production casing 45 once installed in the wellbore). FIG. 6A shows the condition of the location of the wellbore 20 in which the cement swell packer 100 is installed and swelling of the cementitious material 106 starts at 6 hours. FIG. 6B shows the condition of the location of the wellbore 20 in which the cement swell packer 100 is installed and swelling or curing of the cementitious material 106 has been ongoing for 3 days. FIG. 6C shows the condition of the location of the wellbore 20 in which the cement swell packer 100 is installed and swelling or curing of the cementitious material 106 has been ongoing for 7 days (for maximum achievable compressive strength). In this example, the cement swell packer 100 is configured to commence swelling after 6 hours. After 3 days, the cement swell packer 100 (i.e., cementitious material 106) has swollen to fill the available annulus 22 and commences building mechanical strength. After 7 days, the cement swell packer 100 (i.e., cementitious material 106) has cured or built sufficient strength (upon contact with the formation or an outer casing) to achieve the required pressure holding specification.

FIGS. 7A-7C show additional schematic diagrams that illustrate a development over time of a cement swell packer in a wellbore according to the present disclosure. Generally, FIGS. 7A-7C show schematic diagrams that illustrate a development over time (upon run in at 6 hours to 7 days after run in) of the cement swell packer 100 when there is a partial application of primary cement 70 circulated to the annulus 22 (in other words, behind the production casing 45 once installed in the wellbore). FIG. 7A shows the condition of the location of the wellbore 20 in which the cement swell packer 100 is installed and swelling of the cementitious material 106 starts at 6 hours. FIG. 7B shows the condition of the location of the wellbore 20 in which the cement swell packer 100 is installed and swelling or curing of the cementitious material 106 has been ongoing for 24 hours, with the partial primary cement 70 having been circulated into the annulus 22. FIG. 7C shows the condition of the location of the wellbore 20 in which the cement swell packer 100 is installed and swelling or curing of the cementitious material 106 has been ongoing for 7 days (for maximum achievable compressive strength). In this example, the cement swell packer 100 is configured to commence swelling after 6 hours. After 3 days, the cement swell packer 100 (i.e., cementitious material 106) has swollen to fill the available space of annulus 22 not taken up by the primary cement 70 and commences building mechanical strength. After 7 days, the cement swell packer 100 (i.e., cementitious material 106) has cured or built sufficient strength to achieve the required pressure holding specification.

FIGS. 8A-8D show additional schematic diagrams that illustrate a development over time of a cement swell packer in a wellbore according to the present disclosure. Generally, FIGS. 8A-8D show schematic diagrams that illustrate a development over time (upon run in at 6 hours to 7 days after run in) of the cement swell packer 100 when there is a complete application of primary cement 70 circulated to the annulus 22 (in other words, behind the production casing 45 once installed in the wellbore). FIG. 8A shows the condition of the location of the wellbore 20 in which the cement swell packer 100 is installed and swelling of the cementitious material 106 starts at 6 hours. FIG. 8B shows the condition of the location of the wellbore 20 in which the cement swell packer 100 is installed and swelling or curing of the cementitious material 106 has been ongoing for 24 hours, with the primary cement 70 having been circulated into the annulus 22 and curing. FIG. 8C shows the condition of the location of the wellbore 20 in which the cement swell packer 100 is installed and swelling or curing of the cementitious material 106 has been ongoing for 3 days; here, the cementitious material 106 is constrained when it contacts the primary cement 70 (which has a greater unconfined compressive strength than the cementitious material 106) or another surface (such as another casing or wellbore wall). FIG. 8D shows the condition of the location of the wellbore 20 in which the cement swell packer 100 is installed and swelling or curing of the cementitious material 106 has been ongoing for 7 days (for maximum achievable compressive strength). In this example, the cement swell packer 100 is configured to commence swelling after 6 hours. After 3 days, the cement swell packer 100 (i.e., cementitious material 106) has swollen to fill the available space of annulus 22 not taken up by the primary cement 70 and commences building mechanical strength. After 7 days, the cement swell packer 100 (i.e., cementitious material 106) has cured or built sufficient strength to achieve the required pressure holding specification.

While this specification contains many specific implementation details, these should not be construed as limitations on the scope of any inventions or of what may be claimed, but rather as descriptions of features specific to particular implementations of particular inventions. Certain features that are described in this specification in the context of separate implementations can also be implemented in combination in a single implementation. Conversely, various features that are described in the context of a single implementation can also be implemented in multiple implementations separately or in any suitable subcombination. Moreover, although features may be described above as acting in certain combinations and even initially claimed as such, one or more features from a claimed combination can in some cases be excised from the combination, and the claimed combination may be directed to a subcombination or variation of a subcombination.

A number of implementations have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the disclosure. For example, example operations, methods, or processes described herein may include more steps or fewer steps than those described. Further, the steps in such example operations, methods, or processes may be performed in different successions than that described or illustrated in the figures. Accordingly, other implementations are within the scope of the following claims.