Patent Application
20230392458
This disclosure relates methods and equipment for preventing lost circulation in wellbores during drilling operations.
Lost circulation occurs when drilling fluid such as drilling mud flows into one or more fractures of geological formations instead of returning up the annulus of the wellbore. Lost circulation can cause mud waste, dry drilling, and other downhole problems. Preventing lost circulation can save time and resources by keeping the drilling mud from leaving through formation fractures.
Implementations of the present disclosure include a wellbore assembly that includes a drill string and a housing. The drill string includes a drill bit and is disposed within a wellbore. The drill string defines, with the drill bit, a first fluid pathway extending from the drill string, through the drill bit, and out the drill bit. The wellbore assembly flows a first lost circulation material along the first fluid pathway. The housing is coupled to an outer surface of the drill string and resides uphole of the drill bit. The housing defines a volume between the outer surface of the drill string and a wall of the housing. The housing stores a second lost circulation material including at least one parameter different from the first lost circulation material. The drill string defines, with the housing, a second fluid pathway extending from the drill string, through the housing, and out the housing. The drill string directs, with the first fluid pathway blocked, fluid along the second fluid pathway to flow the second lost circulation material out the housing to a lost circulation zone of the wellbore. The drill string directs, after flowing the second lost circulation material to the lost circulation zone and with the second fluid pathway blocked, fluid along the first fluid pathway to flow the first lost circulation material out the drill bit to the lost circulation zone to plug the lost circulation zone.
In some implementations, the wellbore assembly also includes a ball sit residing along the first fluid pathway and a movable gate residing along the second fluid pathway. The ball sit receives a ball deployed from a terranean surface of the wellbore to block the first fluid pathway and the gate moves to open the second fluid pathway. In some implementations, the movable gate includes a sleeve movable to expose or cover apertures of the drill string. In some implementations, the first circulation material is flown, with the first fluid pathway opened, from the terranean surface of the wellbore, through the drill string and the drill bit, to the lost circulation zone.
In some implementations, the at least one parameter includes an average size of lost circulation material particles. The average size of the lost circulation material particles of the second lost circulation material is greater than an average size of the lost circulation material particles of the first lost circulation material. In some implementations, the average size of the lost circulation material particles of the second lost circulation material is at least twice the average size of the lost circulation material particles of the first lost circulation material.
In some implementations, the housing includes a fluid outlet and is disposed around the drill string. The housing is fluidly coupled, through one or more apertures of the drill string, to a bore of the drill string such that the second fluid pathway extends from the one or more apertures to the fluid outlet of the housing to exit the housing. In some implementations, the second lost circulation material is disposed along the second fluid pathway such that fluid flowing through the second fluid pathway moves the second lost circulation material out the housing through the fluid outlet.
In some implementations, the wellbore assembly also includes a packer attached to the drill string and residing uphole of the housing. The packer expands to further seal or plug the lost circulation zone. In some implementations, the packer is activated by at least one of fluidic pressure, mechanical movement of the drill string, or an activation tool deployed from a terranean surface of the wellbore, through the drill string, to an inner activation component of the packer.
In some implementations, the wellbore assembly also includes nozzles fluidly coupled to the drill string and residing at a surface of the drill string or the housing. The nozzles receive a sealant from the drill string and jet or spray the sealant to the lost circulation zone to fluidly seal the lost circulation zone.
In some implementations, the wellbore assembly also includes one or more cameras residing at a surface of the drill string or the housing. The one or more cameras generate data representing an image of the lost circulation zone. The one or more camera transmit the data to a receiver at or near a terranean surface of the wellbore.
In some implementations, the housing is attached to one of a drill collar or a drill sub of a bottom hole assembly attached to the drill string.
Implementations of the present disclosure also include a wellbore assembly that includes a drill string and a housing. The drill string is disposed within a wellbore. The drill string includes a fluid port and defines a first fluid pathway extending from the drill string, through the fluid port, and out the drill string. The wellbore assembly configured to flow a first lost circulation material along the first fluid pathway. The housing is coupled to the drill string and it defines a volume to store a second lost circulation material. The drill string defines, with the housing, a second fluid pathway extending from the drill string, through the housing, and out the housing. The drill string directs, with the first fluid pathway blocked, fluid along the second fluid pathway to flow the second lost circulation material out the housing to a lost circulation zone of the wellbore. The drill string directs, with the second fluid pathway blocked, fluid along the first fluid pathway to flow the first lost circulation material out the fluid port to the lost circulation zone.
In some implementations, the wellbore assembly also includes a ball sit residing along the first fluid pathway and a movable gate residing along the second fluid pathway. The ball sit receives a ball deployed from a terranean surface of the wellbore to block the first fluid pathway. The gate moves to open and close the second fluid pathway.
In some implementations, the first lost circulation material includes particles including a first average size, and the second lost circulation material includes particles including a second average size greater than the first average size.
In some implementations, the wellbore assembly also has a camera residing at a surface of the drill string or the housing. The camera is arranged such that, with the housing positioned at the lost circulation zone, the lost circulation zone is within a field of view of the camera. The camera generates data representing an image of the lost circulation zone, from which a human operator or a processor communicatively coupled to the camera determines at least one of (a) a condition of the lost circulation zone, (b) whether a sealing operation is required, or (c) a parameter of a lost circulation material to be used to perform a sealing operation.
Implementations of the present disclosure also include a method of plugging a wellbore. The method includes disposing, within a wellbore, a drill string including a housing and defining a first fluid pathway extending from the drill string, through a drill bit of the drill string, and out the drill bit. The drill string directs a first lost circulation material along the first fluid pathway. The housing defines a volume to store a second lost circulation material. The drill string defines, with the housing, a second fluid pathway extending from the drill string, through the housing, and out the housing. The method also includes blocking the first fluid pathway. The method also includes flowing, with the first fluid pathway blocked, fluid along the second fluid pathway to flow the second lost circulation material out the housing to a lost circulation zone of the wellbore. The method also includes blocking the second fluid pathway. The method also includes flowing, with the second fluid pathway blocked, fluid along the first fluid pathway to flow the first lost circulation material out the drill bit to the lost circulation zone.
In some implementations, the drill string further includes one or more cameras residing at a surface of the drill string or the housing. The drill string also has multiple nozzles fluidly coupled to the drill string and residing at a surface of the drill string or the housing. The method further includes, after flowing the fluid along the second fluid pathway to flow the second lost circulation material, spraying, through the nozzles, a sealant to the lost circulation zone to fluidly seal the lost circulation zone. The method also includes determining, based on data generated by the camera representing an image of the lost circulation zone, at least one of (a) a condition of the lost circulation zone, (b) whether a sealing operation is required, or (c) a parameter of a lost circulation material to be used to perform a sealing operation.
In some implementations, the drill string also has a packer attached to the drill string and the determination includes determining that a further sealing operation is required. The method also includes, after spraying the sealant, expanding the packer to further seal or plug the lost circulation zone.
During the drilling of a wellbore, lost circulation (also called loss of circulation) can occur when drilling mud or other fluids enter a naturally occurring (or induced) fracture in the formation. The lost circulation can also occur, for example, due to a crack, hole, void, downhole reservoir, or a region of high porosity. The present disclosure relates to a wellbore assembly 100 and methods used to prevent or reduce lost circulation. The plugging assembly 100 allows the use of two or more different types of lost circulation material (LCM) while using a conventional drill bit to create a bridge or a plug and stop the lost circulation.
Particular implementations of the subject matter described in this specification can be implemented so as to realize one or more of the following advantages. For example, the wellbore assembly of the present disclosure can save time and resources by preventing drilling mud from leaving the wellbore through small, medium, and large fractures of the formation. The present disclosure features an LCM housing that is compatible with conventional drill strings, allowing the wellbore assembly to be implemented quickly and efficiently. Additionally, the wellbore assembly can be used to stop losses before running the casing, which enhances the cementing operation of wellbore casing to increase the life of the well and prevent any behind casing communication. The wellbore assembly can also be quickly deployed without the need of specialized personnel.
The wellbore assembly 100 includes a drill string 104 and a housing or bank 106 attached to the drill string 104. In some implementations, the housing 106 can be part of the drill string 104. The drill string 104 can be attached to a rig 114 at the terranean surface 103 of the wellbore. The drill string 104 forms, with a wall of the wellbore 102, an annulus 105.
The drill string 104 has a drill bit 108 that cuts through the formation 101 to form the wellbore 102. The drill string 104 can flow fluid “F” (e.g., drilling mud) to aid during the drilling operation or for other purposes. During drilling, lost circulation can occur due to damage to the formation, characteristics of the formation, or for other reasons. For example, the wellbore 102 can have a lost circulation zone 118 that may include fractures 119, cracks, holes, voids, regions of high porosity, etc. Lost circulation occurs when all or part of the drilling fluid “F” flows into one or more geological formations instead of returning up the annulus 105.
The drill string 104 can flow fluid (e.g., drilling mud) with LCM and sealants to plug the lost circulation zone 118 of the wellbore 102. The drill string 104 flows the fluid and the LCM from the terranean surface 103 of the wellbore to the downhole end 111 of the wellbore 102. For example, the drill string 104 can be fluidly coupled to a surface pump 116 and receive, from the pump 116, the fluid, LCM, and sealants to plug the wellbore. In some implementations, the LCM and sealant can be introduced into the drill string 104 from a location downstream of the pump 116. The LCM can include organic or synthetic particles, and different concentrations can be used. The LCM forms a pile or a plug to stop or reduce the losses in formation fractures.
The drill string 104 can also have a bottom hole assembly (BHA) 112. The housing 106 can be attached to one of a drill collar or a drill sub or another component of the BHA 112. In some implementations, the drill bit 108 and/or the housing 106 can be part of the BHA 112. The drill string 104 also has an expandable tube 110 (e.g., a packer) that can be used to further seal or plug the wellbore 102. The expandable tube 110 can be attached to or part of the BHA 112.
The wellbore assembly 100 defines a first fluid pathway “P1” and a second fluid pathway “P2.” The first fluid pathway “P1” extends from the drill string (or from the BHA 112), through the drill bit 108, and out the drill bit 108 through a fluid outlet 226 of the drill bit 108. The fluid outlet 226 can be, for example, a nozzle at the end of a bore 124 or an internal fluid channel of the drill bit 108. In some implementations, the drilling fluid “F” can exit through another fluid outlet (in addition to or instead of through the nozzles) such as a fluid port in the wall of the drill string 104. The drill bit 108 can be a conventional drill bit with one or more fluid nozzles, such as a rolling cutter drill bit, a fixed cutter drill bit, or a hybrid cutter bit. As further described in detail below with respect to
As depicted in
The housing 106 (or the drill string 104) has a first gate 207 and a second gate 208 that move to open or close the second fluid pathway “P2.” The first gate 207 moves to cover or expose one or more apertures 206 of the drill string 104. The second gate 207 moves to open or close a fluid outlet 210 at the bottom of the housing 106. Thus, with the gates opened, the second fluid pathway “P2” extends from the drill string 104 (e.g., the bore of the drill string 104), through the housing 106, and out the housing 106 through the fluid outlet 210 of the housing.
The gates 207, 208 can be moved by an actuator (not shown) or by fluidic pressure pushing on the gates 207, 208. For example, the first gate 207 can be a spring-loaded sleeve that moves downhole under fluid pressure or by an actuator (not shown) controlled from the surface to expose the fluid ports. The second gate 208 can be similarly pushed open by fluidic pressure or by an actuator.
The nozzles 204 can be attached to the housing 106 and be fluidly coupled t the drill string 104 through the aperture 206 of the drill string 104. As further described in detail below with respect to
The cameras 203 can be used before, during, or after flowing the LCM to aid during the plugging wellbore operation. For example, the cameras 203 residing at a surface of the drill string 104 (or the BHA 112) or the housing 106 and are arranged such that, with the BHA 112 positioned at the lost circulation zone 118, the lost circulation zone 118 is within a field of view of the camera 203. The camera 203 generates data (e.g., a picture) representing an image of the lost circulation zone 118. The camera 203 transmits the data to a receiver at or near a terranean surface of the wellbore. Based on that data, a human operator or a processor communicatively coupled to the camera 203 determines steps to be taken during the plugging operation. For example, based on the data, one can determine a condition and location of the lost circulation zone and one can determine whether a sealing operation is required. One can also determine parameters (e.g., size, amount, concentration, type, etc.) of the LCM to be used to perform a sealing operation. The camera can transmit live video or real-time images to the surface to allow an operator or an automatic rig to know where to position the BHA 112 to perform the plugging operation.
Still referring to
The ball sit 218 resides along the first fluid pathway “P1” such that, with a ball 220 sitting on the ball sit 218, the ball 220 blocks the first fluid pathway “P1.” The ball sit 218 can be releasably attached (e.g., through shear pins 217) to an annular ball sit retainer 216 (e.g., an annular shoulder). When the shear pins 217 break, the ball sit 218 can land on the ball sit catcher 214 (e.g., one or more pins or arms), which allows fluid to flow through it to move along the first fluid pathway “P1.”
To begin a plugging operation, the ball 220 is dropped from the surface of the wellbore 102 to land on the ball sit 218 and block the first fluid pathway “P1.” The ball sit 218 is attached to the ball seat retainer 216 with a connection sufficiently strong to undergo fluid pressure sufficient to activate the gates 207, 208 and to flow the second LCM “L2” without breaking.
Referring now to
The second LCM “L2” prevents the small particles of the first LCM “L1” from being lost into the formation. For example, the second LCM “L2” forms a first plug in the fracture 119 to form a kind of “bridge” for the first LCM “L1” to build on and accumulate on top of to further plug the formation. In other words, the second LCM “L2” plugs the larger openings and forms a partial plug that is complemented by the first LCM “L1” to complete or partially complete the plug. Thus, the large LCM “L2” forms a base at the formation fracture for any fluid-loss control material such as a granular material to build up and form a plug.
Once the second LCM “L2” has been flown to the fracture 119, the gates 207, 208 of the housing 106 can be closed to block the second fluid pathway “P2.” The second fluid pathway “P2” is blocked to then flow the second LCM “L2.” To close the gates 207, 208, the drill string 104 can be depressurized or an actuator moving the gates can mechanically move the gates to the closed position.
Referring now to
The first LCM “L1” can be introduced from the terranean surface (e.g., from a surface valve or pump) of the wellbore 102 to be flown downhole, through the drill string 104, with the drilling fluid “F.” The first LCM “L1” accumulates at the fracture 119 to further plug the wellbore 102. The first LCM “L1” can have fine or medium-sized particles. The size, shape, and type of particles of the first LCM “L1” can be selected based on the aperture size of the dill bit nozzles. The first LCM “L1” can cover the perms caused in the circulation zone 118 by the second LCM “L2.”
Now referring to
The nozzles 204 can move to point toward the fracture 119 or the drill string 104 can be moved to position the nozzles 204 as needed to spray the formation. In some implementations, the nozzles 204 can have movable vents (e.g., movable by a controller at the surface of the wellbore) to direct, based on the location of the fracture 119 as determined from the camera images, the sealant “S” toward the fracture 119. The sealant can be directed toward the nozzles 204 through a different fluid pathway between the drill bit and the housing, or by moving the gate 203 again using fluidic pressure or another means such as with an actuator. 106 After spraying the sealant “S,” the camera 203 can capture more images of the lost circulation zone to determine the condition of the lost circulation zone and to determine whether another sealing operation is required. For example, before or after applying the sealant, more LCM can be pumped downhole to further plug the wellbore 102. In some implementations, the drill string 104 can be pulled up to refill the housing 106 with large LCM particles and continue to plug the formation with large and small LCM particles.
All of the above plugging operations can be performed automatically, partially automatically, or manually. For example, the drill string 104 can be automatically moved along the wellbore by an automatic rig mechanism until the camera finds the fracture. The flowing of LCM materials can also be done automatically or with the aid of a human operator at the surface of the wellbore.
Although the following detailed description contains many specific details for purposes of illustration, it is understood that one of ordinary skill in the art will appreciate that many examples, variations and alterations to the following details are within the scope and spirit of the disclosure. Accordingly, the exemplary implementations described in the present disclosure and provided in the appended figures are set forth without any loss of generality, and without imposing limitations on the claimed implementations.
Although the present implementations have been described in detail, it should be understood that various changes, substitutions, and alterations can be made hereupon without departing from the principle and scope of the disclosure. Accordingly, the scope of the present disclosure should be determined by the following claims and their appropriate legal equivalents.
The singular forms “a”, “an” and “the” include plural referents, unless the context clearly dictates otherwise.
As used in the present disclosure and in the appended claims, the words “comprise,” “has,” and “include” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps.
As used in the present disclosure, terms such as “first” and “second” are arbitrarily assigned and are merely intended to differentiate between two or more components of an apparatus. It is to be understood that the words “first” and “second” serve no other purpose and are not part of the name or description of the component, nor do they necessarily define a relative location or position of the component. Furthermore, it is to be understood that the mere use of the term “first” and “second” does not require that there be any “third” component, although that possibility is contemplated under the scope of the present disclosure.
