Patent Application
20210285295
This specification relates generally to example processes for curing a lost circulation zone in a wellbore.
In a well, such as an oil well, a lost circulation zone is a region in a subterranean formation that inhibits, or prevents, return of mud or other materials following introduction of drilling fluid. For example, during creation and completion of a well, drilling fluid is introduced into the wellbore. Then, mud and other materials from the wellbore flow back to the surface of the well. However, in a lost circulation zone, the introduction of drilling fluid into the wellbore does not produce a corresponding flow back to the surface of the well.
There can be various causes for lost circulation zones. In some cases, the formation may be highly permeable and have a less-than-normal hydrostatic pressure. In some cases, the formation may contain faults, such as fractures, into which the drilling fluid escapes, thereby interrupting the circulation of fluids into, and out of, the wellbore. Such faults in the formation can also adversely affect cementing operations performed to complete the well. For example, fluids in the formation can prevent, or prolong, hardening of cement slurry. This may be due, at least in part, to mixing of the fluids with the cement slurry. For example, this mixing of fluids may prevent the slurry from ever setting enough to harden.
In some situations, lost circulation material (LCM) pills, cement plugs, and X-linked polymer plugs have been injected into a lost circulation zone in a well in attempts to cure the lost circulation zones.
An example method for curing a wellbore includes treating a lost circulation zone in the wellbore. The method includes identifying a lost circulation zone in a wellbore. The lost circulation zone includes a fracture in a formation adjacent to the wellbore. The method includes deploying an example system in a vicinity of the lost circulation zone. The example system includes a stop lost-circulation balloon (SLCB) tool. An example SLCB tool includes an inflatable balloon and a tubing string including a fluid conduit. The string is in fluid connection with the balloon. The method includes deploying, from the SLCB tool, the balloon and forcing slurry into the balloon to cause at least part of the balloon containing the slurry into the fracture. The method includes allowing the slurry to set for a period of time to produce a solid. The method includes drilling through the solid in the balloon in the wellbore, leaving the solid in the fracture.
An example SLCB tool may include a multiport sub. The multiport sub may be in fluid communication with the string at an uphole end of the multiport sub and in fluid communication with the balloon at a downhole end of the multiport sub. The multiport sub may include one or more ports in a wall of the multiport sub to allow wellbore fluid to enter the multiport sub.
An example SLCB tool may include a balloon holder for at least partially housing and releasably retaining at least a part of the balloon.
An example SLCB tool may include a flapper valve disposed between the multiport sub and the balloon to prevent wellbore fluids from entering the balloon when the flapper valve is shut.
An example SLCB tool may be releasably connected at an uphole end of the SLCB tool to a release sub at a downhole end of the string.
The example method may include deploying a shut-off dart. The shut-off dart may include a shut-off plug for sealing off one or more ports in a multiport sub. The shut-off dart may include a tube disposed within the shut-off dart establishing a fluid connection between an uphole end and a downhole end of the shut-off dart. Deploying the shut-off dart may include causing a balloon holder to at least partially release the balloon from the holder, thereby deploying the balloon. Releasing the balloon may include shearing, by the shut-off dart, one or more balloon holding pins. Deploying the shut-off dart may include sealing off one or more ports in the multiport sub, opening a flapper valve disposed between the multiport sub and the balloon, and establishing a fluid connection between the fluid conduit of the string, the tube, and the balloon.
An example method may include deploying, after forcing slurry into the balloon, a releasing plug. Deploying the releasing plug may cause the SLCB tool to be released from the string. Releasing the SLCB tool may include shearing, by the releasing plug, one or more SLCB holding pins.
An example method may include, after forcing slurry into the balloon, retracting the string uphole while the SLCB tool remains in position in the wellbore.
An example system is configured to operate within a lost circulation zone in a wellbore. An example system includes a tubing string include as a fluid conduit and a release sub. An example system includes a stop lost-circulation balloon (SLCB) tool releasably connected to the release sub. An SLCB tool includes an inflatable balloon in fluid connection with the string and a balloon holder at least partially housing and releasably retaining at least a part of the balloon. An SLCB tool includes a multiport sub in fluid communication with the string at an uphole end of the multiport sub and in fluid communication with the balloon at a downhole end of the multiport sub.
An example system may include a flapper valve disposed between the multiport sub and the balloon to prevent wellbore fluids from entering the balloon when the flapper valve is shut. The multiport sub may be connected to the releasing sub via one or more SLCB holding pins. The balloon may be at least partially retained by the balloon holder via one or more balloon holding pins.
An example system may include a shut-off dart including a shut-off plug for sealing off one or more ports in a multiport sub. A shut-off dart may include a tube disposed within the shut-off dart establishing a fluid connection between an uphole end and a downhole end of the shut-off dart. The shut-off dart may be configured to shear one or more balloon holding pins thereby releasing the balloon.
An example system may include a releasing plug for shearing one or more SLCB holding pins and releasing the SLCB tool from the string.
Any two or more of the features described in this specification, including in this summary section, may be combined to form implementations not specifically described in this specification.
All or part of the processes, methods, systems, and techniques described in this specification may be controlled by executing, on one or more processing devices, instructions that are stored on one or more non-transitory machine-readable storage media. Examples of non-transitory machine-readable storage media include read-only memory, an optical disk drive, memory disk drive, random access memory, and the like. All or part of the processes, methods, systems, and techniques described in this specification may be controlled using a computing system comprised of one or more processing devices and memory storing instructions that are executable by the one or more processing devices to perform various control operations.
The details of one or more implementations are set forth in the accompanying drawings and the description subsequently. Other features and advantages will be apparent from the description and drawings, and from the claims.
Described in this specification are example technologies, devices, and processes for curing a lost circulation zone in a wellbore. The example processes include detecting a lost circulation zone in a wellbore. A lost circulation zone may include a part of the wellbore that traverses a rock formation containing faults, such as fractures, into which drilling fluid escapes, thereby interrupting the circulation of fluids into, and out of, the wellbore. An inflatable device, such as a balloon, is arranged in the vicinity of the lost circulation zone. For example, the inflatable device may be arranged within or uphole of the lost circulation zone. The inflatable device may be connected to a joint or other appropriate structure in a conduit introduced into the wellbore. Slurry, such as cement slurry, is forced into the inflatable device to cause its expansion. As the inflatable device expands, one or more parts of the inflatable device containing the slurry expand into fractures in the formation. In some implementations, the inflatable device may be configured and arranged to enable expansion throughout the lost circulation zone. As a result, all or some faults in the lost circulation zone are wholly or partly filled with slurry contained within the inflatable device. The slurry is then set for a period of time to produce a solid, such as cement, which may be present both in the wellbore and in the formation fractures. A drill may then cut through the solid in the wellbore, leaving the solid in the fractures. The solid thus fills the fractures, thereby curing the lost circulation zone.
Generally, to produce a well, a drill bores through earth, rock, and other materials to form a wellbore. In some implementations, a casing may support the sides of the wellbore. The drilling process includes, among other things, pumping drilling fluid down into the wellbore, and receiving return fluid containing materials from the wellbore at surface. In some implementations, the drilling fluid includes water- or oil-based mud and, in some implementations, the return fluid contains mud, rock, and other materials to be evacuated from the wellbore. This circulation of fluid into, and out of, the wellbore, may occur throughout the drilling process. In some cases, this circulation is interrupted, which can have an adverse impact on drilling operations. For example, loss of circulation can result in dry drilling, which can damage the drill bit, the drill string, or the drilling rig itself. In some cases, loss of circulation can cause a blow-out and result in loss of life.
There are degrees of lost circulation that may be addressed. For example, a total loss of circulation occurs when no return fluid reaches the surface following introduction of drilling fluid into the wellbore. A total loss of circulation may result from faults, such as fractures, in a subterranean formation. For example, the drilling fluid, the return fluid, or both may escape into fractures in a surrounding formation, causing the loss of circulation. Depending upon the size of the fracture and the volume of fluids involved, the escaping fluids may cause a total loss in circulation or a partial loss in circulation. In this regard, a partial loss of circulation results in less return fluid than anticipated for a given amount of drilling fluid. A partial loss of circulation may also be caused by subterranean formations that are highly permeable, that have a less-than-normal hydrostatic pressure, or both. In some cases, drilling with total loss of circulation may result in hole collapse due lack of hydrostatic pressure supporting the wellbore. This can lead to drilling equipment being lost or stuck downhole.
In some implementations, a lost circulation zone may be identified based on the volume of return fluid removed from a wellbore. For example, the volume of return fluid may be measured using one or more detection mechanisms, and compared to an expected volume of return fluid for a given amount of drilling fluid pumped into the wellbore. If the amount of return fluid deviates by more than a threshold amount from the expected amount of return fluid for a given depth in a wellbore, a lost circulation zone is detected. In some implementations, computer programs may be used to process information about the volumes of drilling fluid and return fluid, and to make a determination about whether a lost circulation zone has been encountered. In some implementations, this determination may be made in real-time (such as during drilling) so that the situation can be remedied before damage occurs. In some implementations, the computer programs may be used to alert drilling engineers about a detected lost circulation zone, to begin automatic remedies, or both. In some implementations, a lost circulation zone may be detected using other methods based on the quantity or quality of the return fluid.
In some implementations, lost circulation zones may affect cementing operations. In this regard, drilling cuts through rock formations to form a wellbore that reaches a subterranean reservoir. The sides of the wellbore, however, typically require support. A casing is inserted into the wellbore and is used for supporting the sides of the wellbore, among other things. In some implementations, the casing—also called a setting pipe—may be a metal tubing that is inserted into the wellbore in sections. A space between the casing and the untreated sides of the wellbore may be cemented to hold the casing in place.
During normal cementing operations—for example, cementing operations solely to support a casing in a wellbore—cement slurry is pumped into the wellbore and allowed to set to hold the casing in place. The cement slurry may occupy a space between the wellbore and the casing, and may harden there to form cement. After the cement has hardened at least a threshold amount, the bottom of the well may be drilled, and the process for completing the well proceeds. In lost circulation zones, such as those involving fractures, the cement slurry may also escape into the fracture, may mix with formation fluid in the fracture, or both. This may prevent the cement from hardening, and thus supporting the casing. Accordingly, a lost circulation zone may also affect cementing operations.
An example system may include a stop lost-circulation balloon (SLCB) tool 100. In some implementations, SLCB tool 100 may be connected to a string 30. In some implementations, an uphole end of SLCB tool 100 may be releasably connected to a release sub 40. In some implementations, an SLCB tool 100 may be releasably connected to a release sub 40 through a mechanism including one or more SLCB tool holding pins 41. An example SLCB tool holding pin 41 may be configured or arranged such that mechanically shearing or otherwise breaking one or more SLCB tool holding pins 41 disrupts the connection between SLCB tool 100 and release sub 40, thereby disconnecting SLCB tool 100 and release sub 40.
In some implementations, SLCB tool 100 includes a multiport sub 110. In some implementations, multiport sub 110 may have a substantially tubular structure and may be connected to a string 30 or connected to release sub 40. A multiport sub 110 may be in fluid communication with string 30, for example, at an uphole (proximal) end of multiport sub 110. In some implementations, a multiport sub 110 may be in fluid communication with string 30, for example, via a release sub 40 at a downhole end of string 30. A multiport sub 110 may be in fluid communication with a balloon 140 or a balloon holder 130, or both, for example, at a downhole (distal) end of multiport sub 110. A multiport sub 110 may include one or more ports 111 in a wall of the multiport sub to allow wellbore fluids to enter the multiport sub 110 and string 30, as illustrated by the arrows in
In some implementations, SLCB tool 100 may include a valve, for example, a flapper valve 120 held in a valve housing 121 at or near a downhole (distal) end of multiport sub 110. In some implementations, a valve, for example, flapper valve 120 may insulate an inflatable device, for example, a balloon 140 or a balloon holder 130, or both, from wellbore fluids entering the multiport sub 110 when flapper valve 120 is closed. In some implementations, a flapper valve 120 may include one or more substantially flat elements having an uphole (proximal) side and a downhole (distal) side. In some implementations, the flat elements may be configured or arranged (of both) such that they remain closed when fluid pressure is applied from an uphole side, for example, when pressure is applied substantially to the entire surface area of an uphole side of a flat element. The flat elements may be configured or arranged such that they open when a force or pressure is applied to only a fraction of the surface are of an uphole side (for example, less than half the surface area), for example, causing one or more flat elements to pivot.
SLCB tool 100 includes an inflatable device, for example, a balloon 140 that may be in fluid communication to valve housing 121, multiport sub 110, and string 30. In some implementations, balloon 140 is at least partially housed by a balloon holder 130 that may be positioned at a downhole (distal) end of multiport sub 110 or valve housing 121. In some implementations, balloon 140 may be in a deflated or folded (or both) configuration while SLCB tool 100 is being transferred downhole. In some implementations, a portion of a balloon 140 may be releasably retained within balloon holder 130 at least in part through a mechanism including one or more balloon holding pins 131. An example balloon holding pin 131 may be configured or arranged such that mechanically shearing or otherwise breaking one or more balloon holding pins 131 disrupts a mechanical connection between balloon 140 and balloon holder 130, thereby at least partially releasing the balloon 140 from balloon holder 130. After at least partial release of balloon 140 from balloon holder 130, balloon 140 may remain in connected to one or more components of SLCB tool 100, for example, multiport sub 100, such that fluid communication with string 30 is maintained.
The size of the balloon, and therefore the amount of expansion the balloon can tolerate, may be based on the subterranean geography of the lost circulation zone. For example, a lost circulation zone having large fractures may require a larger balloon than a lost circulation zone having smaller fractures. The geography of the lost circulation zone may be mapped prior to inserting the balloon into the lost circulation zone. The size, composition, and other attributes of the balloon may be selected based on downhole features, such as the depth of the lost circulation zone, the sizes and numbers of fractures contained in the lost circulation zone, and the diameter of the wellbore. The size, composition, and other attributes of the balloon may also be selected based on downhole environmental conditions, such as temperature and pressure.
Still referring to
Referring to
Referring to
Referring to
The time needed for the slurry to set to produce a solid may vary based on a number of conditions including, but not limited to, the composition of the slurry, the temperature in the wellbore, and the pressure in the wellbore. In some implementations, the solid may have a hardness that is less than a complete hardness of cement. In some implementations, the solid may have a hardness that is at least as hard as a complete hardness of cement.
A curing a lost circulation zone as described in this specification may include additional or alternative components. In some implementations, a circulating sub may be positioned uphole (proximally) to SLCB tool 100. The circulating sub may be configured to displace drilling fluid prior to, or during, forcing slurry into a balloon 140. For example, the wellbore may contain drilling fluid prior to expansion of the balloon. The circulating sub may be operated to remove that drilling fluid. The circulating sub may continue its operation while slurry is pumped into the balloon 140. In some implementations, the circulating sub is configured to discontinue operation in response to the slurry reaching a circulating valve in the circulating sub. For example, at that point, the balloon may be expanded a desired amount. The operation of the circulating sub may be discontinued to allow the slurry in the inflatable to set. In some implementations, additional slurry may be pumped into the inflatable even after the circulating sub has discontinued operation.
Although vertical wellbores are show in the examples presented in this specification, the processes described previously may be implemented in wellbores that are, in whole or part, non-vertical. For example, the processes may be performed for a fracture that occurs in a horizontal, or partially horizontal, wellbore. where horizontal is measured relative to the Earth's surface in some examples.
Elements of different implementations described may be combined to form other implementations not specifically set forth previously. Elements may be left out of the processes described without adversely affecting their operation or the operation of the system in general. Furthermore, various separate elements may be combined into one or more individual elements to perform the functions described in this specification.
Other implementations not specifically described in this specification are also within the scope of the following claims.
