Mid-string mud cap downhole tool and methods of use

Abstract

A well system includes a drillstring extended within a wellbore penetrating first and second lost circulation zones, a drill bit arranged at a downhole end of the drillstring, and a mid-string mud cap tool included in the drillstring and arranged uphole from the drill bit. The mid-string mud cap tool includes a body that defines an interior, one or more ports defined in the body to facilitate fluid communication between the interior and the annulus, and a ball seat provided within the interior. A wellbore projectile is conveyable into the drillstring to land on the ball seat. The mid-string mud cap tool is arranged at a location between the lost circulation zones, and landing the wellbore projectile on the ball seat causes a portion of drilling fluid circulating within the drillstring to circulate into the annulus via the ports and between the lost circulation zones.

Description

FIELD OF THE DISCLOSURE

[0001] The present disclosure relates generally to downhole circulating tools and, more particularly, to downhole circulating tools used in formations with multiple loss zones.BACKGROUND OF THE DISCLOSURE

[0002] Formations capable of producing hydrocarbons and / or water may be naturally weak in structure, where they may be naturally fractured or cavernous and similarly, naturally highly permeable. Formations that are not naturally weak or highly fractured may become so over time as they are drilled and / or stimulated by man-made processes. In either scenario, formations that are or become weak, fractured, cavernous and / or highly permeable may be subject to lost circulation zones or “thief zones.” Lost circulation zones, as aptly named, are portions of formations that “take” the fluids circulated into a wellbore for the purposes of maintaining hydrostatic pressure within the wellbore while it is being drilled. When the necessary amount of hydrostatic pressure is not maintained, the wellbore may experience hole caving and / or the potential for stuck pipe. More difficulty exists in wellbores subject to multiple lost circulation zones.

[0003] A system and method capable of maintaining adequate hydrostatic pressure in wellbores including multiple lost circulation zones is, therefore, desirable.SUMMARY OF THE DISCLOSURE

[0004] Various details of the present disclosure are hereinafter summarized to provide a basic understanding. This summary is not an extensive overview of the disclosure and is neither intended to identify certain elements of the disclosure, nor to delineate the scope thereof. Rather, the primary purpose of this summary is to present some concepts of the disclosure in a simplified form prior to the more detailed description that is presented hereinafter.

[0005] According to an embodiment consistent with the present disclosure, a well system may include a drillstring extended within a wellbore such that an annulus is defined between the drillstring and the wellbore. The wellbore may penetrate a formation including first and second lost circulation zones. The drillstring may further include a drill bit arranged at a downhole end of the drillstring, a mid-string mud cap tool may be included in the drillstring and arranged uphole from the drill bit wherein the mid-string mud cap tool may include a body that defines an interior, one or more ports defined in the body to facilitate fluid communication between the interior and the annulus and a ball seat provided within the interior downhole from the one or more ports. The well system may further include a wellbore projectile conveyable into the drillstring and sized to land on the ball seat, wherein the mid-string mud cap tool may be arranged within the wellbore at a location between the first and second lost circulation zones, and wherein landing the wellbore projectile on the ball seat causes a portion of drilling fluid circulating within the drillstring to circulate into the annulus via the one or more ports and at the location between the first and second lost circulation zones.

[0006] According to an embodiment consistent with the present disclosure, a method may include extending a drillstring into a wellbore penetrating a formation including first and second lost circulation zones, and the drillstring may include a drill bit and a mid-string mud cap tool arranged uphole from the drill bit. The mid-string mud cap tool may include a body that defines an interior, one or more ports defined in the body to facilitate fluid communication between the interior and an annulus defined between the drillstring and an inner wall of the wellbore and a ball seat provided within the interior. The method may further include advancing the drillstring until the mid-string mud cap tool is positioned within the wellbore to axially interpose the first and second lost circulation zones and pumping a first volume of drilling fluid through the drillstring. The method may further include conveying a wellbore projectile into the drillstring and landing the wellbore projectile on the ball seat and diverting a portion of the first volume of the drilling fluid into the annulus via the one or more ports and at the location between the first and second lost circulation zones.

[0007] Any combinations of the various embodiments and implementations disclosed herein can be used in a further embodiment, consistent with the disclosure. These and other aspects and features can be appreciated from the following description of certain embodiments presented herein in accordance with the disclosure and the accompanying drawings and claims.BRIEF DESCRIPTION OF THE DRAWINGS

[0008] FIG. 1 is a schematic diagram of a well system that may embody or otherwise employ one or more principles of the present disclosure.

[0009] FIG. 2 is an enlarged schematic view of the downhole tool and formation depicted in FIG. 1, that may embody or otherwise employ one or more principles of the present disclosure.

[0010] FIG. 3 is a schematic flowchart of an example method of mud cap drilling that may incorporate one or more principles of the present disclosure.DETAILED DESCRIPTION

[0011] Embodiments of the present disclosure will now be described in detail with reference to the accompanying Figures. Like elements in the various figures may be denoted by like reference numerals for consistency. Further, in the following detailed description of embodiments of the present disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the claimed subject matter. However, it will be apparent to one of ordinary skill in the art that the embodiments disclosed herein may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description. Additionally, it will be apparent to one of ordinary skill in the art that the scale of the elements presented in the accompanying Figures may vary without departing from the scope of the present disclosure.

[0012] Embodiments in accordance with the present disclosure generally relate to downhole circulating tools and, more particularly, to a mid-string mud cap tool operable to divert a portion of fluid flow from a drillstring for use in formations with multiple lost circulation zones. Conventional methods exist to treat and / or maintain hydrostatic pressure (via drilling fluid) in wellbores with multiple lost circulation zones. However, these methods often result in little to no drilling fluid placement in portions of the wellbore that are located between axially offset lost circulation zones. The mid-string mud cap tool disclosed herein may be capable of delivering drilling fluid to zones (wellbore sections) located between multiple lost circulation zones, thus reducing the risk of stuck pipe due to hole caving across these zones. A lowered risk of stuck pipe minimizes potential non-productive time, and results in time and cost efficiency. Moreover, the mid-string mud cap tool may be capable of targeted drilling fluid delivery, both in drilling fluid volume and placement. This may improve drilling efficiency over other downhole circulating tools and methods because friction is reduced where drilling fluid may be strategically delivered to difficult to reach portions of a wellbore. Operating the mid-string mud cap tool may be highly beneficial in maintaining well control.

[0013] FIG. 1 is a schematic diagram of an example well system 100, according to one or more principles of the present disclosure. In the illustrated embodiment, the well system 100 may include a service rig 104 positioned above a hydrocarbon-bearing formation 106 located below a terranean surface 108 (e.g., the “well surface”). The service rig 104 in the example embodiment is a drilling rig. In other embodiments, however, the service rig 104 may comprise a completion rig, a workover rig, or similar. Moreover, while the well system 100 is depicted as a land-based operation, it will be appreciated that the principles of the present disclosure could equally be applied in any offshore, sea-based, or sub-sea application where the service rig 104 may be a floating platform, a semi-submersible platform, or a sub-surface wellhead installation as generally known in the art.

[0014] A wellbore 110 may extend from a wellhead 112 (positioned at the terranean surface 108) and into (penetrating) the formation 106. The wellbore 110 may include a configuration of casing 114 that extends into portions of the wellbore 110 and the formation 106. The casing 114 may comprise a plurality of tubulars coupled end-to-end, but may alternatively comprise one or more liners. In the example embodiment, the casing 114 may be cemented into place using cement 116. As shown in FIG. 1, casing 114 is omitted from an open-hole portion 118 of the wellbore 110 that extends below a deepest set casing shoe 120.

[0015] The well system 100 may further include a bottom hole assembly 122 that may be conveyed into the wellbore 110 on a conveyance 124 extending from the service rig 104. According to embodiments of the present disclosure, the bottom hole assembly 122 may include a mid-string mud cap tool to be discussed in detail with reference to FIG. 2. The bottom hole assembly 122 may include any configuration of downhole tools that may be operationally desirable, including but not limited to, measurement while drilling (MWD) tools, logging while drilling (LWD) tools, a motor, a rotary steerable assembly and the like.

[0016] The conveyance 124 may comprise an extension of drill pipe (drillstring) operatively and fluidly coupled to the bottom hole assembly 122. In other embodiments, the conveyance 124 may be, but is not limited to, casing, coiled tubing, wired drill pipe, tubing or the like.

[0017] A drill bit 126 may be operatively and fluidly coupled to the distal (downhole) end of the bottom hole assembly 122 and operable to drill and thereby deepen (lengthen) the wellbore 110.

[0018] During example drilling operations, the wellbore 110 may be extended by advancing the conveyance 124, the bottom hole assembly 122, and the drill bit 126 (collectively referred to herein as the “drillstring 127”) into the formation 106. A drilling fluid 128 is circulated / pumped down the drillstring 127 and discharged from the drill bit 126 via one or more orifices. The drilling fluid 128 cools the drill bit 126 and further assists in lifting drill cuttings to the well surface 108 via an annulus 130 defined between the drillstring 127 and an inner wall of the wellbore 110 (or the casing 114).

[0019] The wellbore 110, as shown, may be drilled in a formation 106 that may include one or more lost circulation zones, shown as first and second lost circulation zones 132a and 132b. The first lost circulation zone 132a, as shown, is positioned above or uphole from the second lost circulation zone 132b. The lost circulation zones 132a,b, alternatively referred to as “thief zones”, comprise portions of the formation 106 that may be naturally highly permeable and / or cavernous. Each lost circulation zone 123a,b may exhibit a pore pressure that is less than the pore pressure of wellbore zones directly adjacent thereto (e.g., uphole or downhole therefrom). Additionally, the lost circulation zones 132a,b may exhibit a pore pressure that is less than the hydrostatic pressure, density, or “weight” of the drilling fluid 128 circulated within the wellbore 110. Accordingly, when drilling through a lost circulation zone 123a,b, a portion of the drilling fluid 128 in the annulus 130 may migrate (flow) from the wellbore 110 and be “lost” or sacrificed to the lost circulation zone 132a,b.

[0020] In conventional operations where a formation 106 includes at least two axially offset lost circulation zones (e.g., first and second lost circulation zones 132a-b), operators often use a drilling technique known as “mud cap drilling”. In mud cap drilling, drilling fluid is pumped down the annulus 130 for the purposes of maintaining wellbore stability and preventing wellbore collapse. This drilling fluid is often referred to as a “mud cap”. Simultaneously, drilling fluid is pumped / circulated down the drillstring 127 as in conventional drilling operations, but not returned back to the surface 108 for continuous circulation. The drilling fluids pumped downhole by way of the annulus 130 and the drillstring 127 are sacrificed to the lost circulation zones 132a,b. The drilling fluid pumped into the annulus 130 migrates (flows) into and is thereby “lost” to the first lost circulation zone 132a. The drilling fluid pumped down the drillstring 127 exits the drill bit 126 and is thereafter circulated uphole within the annulus 130 and eventually migrates (flows) into and is “lost” to the second lost circulation zone 132b.

[0021] Traditional mud cap drilling techniques may be problematic in formations comprising multiple lost circulation zones 132a,b because the drilling fluid may not be able to reach the portion (section) of the annulus 130 between the lost circulation zones 132a,b. Consequently, a gap in the hydrostatic fluid column results within the annulus 130 and extends between the axially adjacent lost circulation zones 132a,b. According to embodiments of the present disclosure, drilling fluid may be specifically targeted and discharged into the portion (section) of the annulus 130 interposing the lost circulation zones 132a,b and left untreated by conventional mud cap drilling techniques.

[0022] FIG. 2 is an enlarged schematic view of the bottom hole assembly 122, according to one or more embodiments. As illustrated, the bottom hole assembly 122 is arranged within the wellbore 110 and penetrating the formation 106. The bottom hole assembly 122 includes a mid-string mud cap tool 200 operable to divert and thereby specifically discharge a portion of the drilling fluid 128 circulating within the drillstring 127 out of the drillstring 127 and into the annulus 130. As illustrated, the mid-string mud cap tool 200 (hereafter the “mud cap tool 200”) may include a generally elongated, tubular exterior body 202 having opposing upper and lower ends 204a and 204b. In some cases, the upper end 204a may form the uphole end of the bottom hole assembly 122 and, therefore, may be operatively coupled to the downhole end of the conveyance 124. In such cases, the lower end 204b may be operatively coupled to the remaining portions of the bottom hole assembly 122. In other embodiments, however, the mud cap tool 200 may be positioned within the bottom hole assembly 122 such that it interposes one or more other components / tools within the bottom hole assembly 122. In yet other embodiments, the mud cap tool 200 may be the lower-most component within the bottom hole assembly 122.

[0023] The interior of the body 202 is generally hollow, thereby permitting the flow of drilling fluid 128 therethrough. A ball seat 206 (shown in dashed lines) may be provided within the interior of body 202 and configured to receive and retain (seat) a wellbore projectile 208 (shown in dashed lines) conveyable through the drillstring 127. The wellbore projectile 208 may comprise a ball or a dart, as generally known in the art. The opening (diameter) of the ball seat 206 may be smaller than the size (diameter) of the wellbore projectile 208 in order to catch the wellbore projectile 208 and stop its descent within the drillstring 127.

[0024] The mud cap tool 200 may further include and otherwise define one or more ports 210 located uphole from the ball seat 206. In some embodiments, the ports 210 may be defined through the side wall of the body 202, but in other embodiments, the ports 210 may be provided in a separate sub operatively coupled to the body 202. The ports 210 provide fluid communication between the interior of the body 202 and the annulus 130 and thereby enable the flow of drilling fluid 128 from the interior of the drillstring 127 into the annulus 130.

[0025] In some embodiments, the ports 210 may be actuatable between open and closed positions (states). This could be accomplished via a variety of mechanical or electro-mechanical means or systems. In at least one embodiment, for example, the ball seat 208 may be operatively coupled to a sleeve 212 actuatable and otherwise movable between a first or “closed” position, where the sleeve 212 occludes the ports 210, and a second or “open” position, where the ports 210 become exposed. In such embodiments, landing the wellbore projectile 208 on the ball seat 208 may cause the ball seat 208 to shift downhole and thereby transition the sleeve 212 between the closed and open positions to expose the ports 210. In other embodiments, however, the sleeve 212 may be shifted or moved using a motor, a servo, or a hydraulic actuation system, without departing from the scope of the disclosure. In other embodiments, however, the ports 210 may be continually (perpetually) open.

[0026] In an example operation, the drillstring 127 may be extended into the wellbore 110 such that the mud cap tool 200 is positioned (located) between the first and second lost circulation zones 132a,b; i.e., the first lost circulation zone 132a will be located uphole from the mud cap tool 200 and the second lost circulation zone 132b will be located downhole from the mud cap tool 200. The first and second lost circulation zones 132a,b may be located via logs or other formation evaluation information acquired previously or in real-time. The drilling fluid 128 may then be pumped / circulated down the drillstring 127 from the service rig 104 (FIG. 1) and discharged from the drill bit 126 into the annulus 130.

[0027] To enable operation of the mud cap tool 200, the operator may convey the wellbore projectile 208 into the drillstring 127 from the service rig 104 (FIG. 1) and allow the wellbore projectile 208 to advance along the conveyance 124. In embodiments where the conveyance 124 comprises extensions of drill pipe, the operator may “break” a connection at the rotary table at the service rig 104 (FIG. 1) so that the wellbore projectile 208 may be manually introduced into the conveyance 124. Once the wellbore projectile 208 is placed within the conveyance 124, the connection at the service rig 104 may be remade. Gravity, as well as the pumping of the drilling fluid 128, advances the wellbore projectile 208 through the conveyance 124 to the ball seat 206 defined within the interior of the mud cap tool 200.

[0028] The wellbore projectile 208 may be advanced within the drillstring 127 until locating the mud cap tool 200 and being received at the ball seat 206. As illustrated, the ball seat 206 is located downhole from the ports 210. In embodiments where the ports 210 are actuatable, the ports 210 may be shifted and otherwise transitioned to an “open” position, thereby permitting a portion of the drilling fluid 128 circulating within the drillstring 127 to be discharged from the mud cap tool 200 and into the annulus 130. In at least one embodiment, as mentioned above, the ports 210 may be transitioned to the open position once the wellbore projectile 208 is landed on the ball seat 206, and fluid pressure is increased within the drillstring 127 and applied against the ball seat 206. The increased fluid pressure may cause the ball seat 206 to move downhole, and correspondingly moving the sliding sleeve 212 operatively coupled thereto in the same direction. As the sliding sleeve 212 moves downhole, the ports 210 become exposed and fluid communication between the interior of the mud cap tool 200 and the annulus 130 is achieved. In other embodiments, however, the ports 210 may be perpetually open.

[0029] In some embodiments, landing the wellbore projectile 208 on the ball seat 206 may not form a complete seal within the mud cap tool 200. Rather, when the wellbore projectile 208 is properly landed on the ball seat 206, only about 10% to 20% of the drilling fluid 128 circulated through the conveyance 124 may be diverted through the ports 210, while the remaining portion of the drilling fluid 128 (e.g., 80% to 90%) will bypass the wellbore projectile 208 and continue downhole to the drill bit 126. Accordingly, a first portion of the drilling fluid 128 may enter the annulus 130 at the mud cap tool 200 via the ports 210, and a second portion of the drilling fluid 128 enters the annulus 130 from the drill bit 126 and circulates back uphole, as shown by the arrow A. Simultaneously, a second volume of drilling fluid may be pumped into the annulus 130 from the well surface 108 (FIG. 1), as shown by the arrow B, and thereby form a “mud cap” within the annulus.

[0030] The drilling fluid pumped into the annulus 130 from the well surface 108 (FIG. 1) may migrate (flow) into and be “lost” to the first lost circulation zone 132a upon reaching said zone, and the portion of the drilling fluid 128 that exits the drill bit 126 and is circulated uphole within the annulus 130 may migrate (flow) into and be “lost” to the second lost circulation zone 132b. The drilling fluid 128 diverted into the annulus 130 at the mud cap tool 200 via the ports 210 helps ensure that a hydrostatic column of the drilling fluid 128 is axially positioned in the annulus 130 between the lost circulation zones 132a,b. Accordingly, the risk of wellbore 110 collapse is lessened and drilling efficiency is improved due to a lack of friction and increased cuttings removal. Further, the placement of the drilling fluid 128 between the first and second lost circulation zones 132a,b helps in preventing an influx of formation fluids (e.g., gas) into the annulus 130, thereby adding to well control measures and lessening the likelihood of an uncontrolled release of formation fluids to the atmosphere.

[0031] FIG. 3 is a schematic flowchart of an example method 300, according to one or more principles of the present disclosure. The method 300 may include extending a drillstring into a wellbore penetrating a formation including a first and second lost circulation zones, the drillstring including a drill bit and a mid-string mud cap tool arranged uphole from the drill bit, as 302. The mid-string mud cap tool may include a body that defines an interior, one or more ports defined in the body to facilitate fluid communication between the interior and an annulus defined between the drillstring and an inner wall of the wellbore and a ball seat provided within the interior. The method 300 may include advancing the drillstring until the mid-string mud cap tool is positioned within the wellbore to axially interpose the first and second lost circulation zones, as at 304. The method 300 may further include pumping a first volume of drilling fluid through the drillstring, as at 306. The method 300 may include conveying a wellbore projectile into the drillstring and landing the wellbore projectile on the ball seat, as at 308. The method 300 may include diverting a portion of the first volume of the drilling fluid into the annulus via the one or more ports and at the location between the first and second lost circulation zones, as at 310.

[0032] The terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting of the invention. As used herein, for example, the singular forms “a,”“an,” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise. It will be further understood that the terms “contains”, “containing”, “includes”, “including,”“comprises”, and / or “comprising,” and variations thereof, when used in this specification, specify the presence of stated features, integers, steps, operations, elements, and / or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and / or groups thereof.

[0033] Terms of orientation are used herein merely for purposes of convention and referencing and are not to be construed as limiting. However, it is recognized these terms could be used with reference to an operator or user. Accordingly, no limitations are implied or to be inferred. In addition, the use of ordinal numbers (e.g., first, second, third, etc.) is for distinction and not counting. For example, the use of “third” does not imply there must be a corresponding “first” or “second.” Also, if used herein, the terms “coupled” or “coupled to” or “connected” or “connected to” or “attached” or “attached to” may indicate establishing either a direct or indirect connection, and is not limited to either unless expressly referenced as such.

[0034] While the disclosure has described several exemplary embodiments, it will be understood by those skilled in the art that various changes can be made, and equivalents can be substituted for elements thereof, without departing from the spirit and scope of the invention. In addition, many modifications will be appreciated by those skilled in the art to adapt a particular instrument, situation, or material to embodiments of the disclosure without departing from the essential scope thereof. Therefore, it is intended that the invention not be limited to the particular embodiments disclosed, or to the best mode contemplated for carrying out this invention, but that the invention will include all embodiments falling within the scope of the appended claims. Moreover, reference in the appended claims to an apparatus or system or a component of an apparatus or system being adapted to, arranged to, capable of, configured to, enabled to, operable to, or operative to perform a particular function encompasses that apparatus, system, or component, whether or not it or that particular function is activated, turned on, or unlocked, as long as that apparatus, system, or component is so adapted, arranged, capable, configured, enabled, operable, or operative.

[0035] The use of directional terms such as above, below, upper, lower, upward, downward, left, right, uphole, downhole and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure, the uphole direction being toward the surface of the well and the downhole direction being toward the toe of the well.

Claims

1. A well system, comprising:a drillstring extended within a wellbore such that an annulus is defined between the drillstring and the wellbore, the wellbore penetrating a formation including first and second lost circulation zones;a drill bit arranged at a downhole end of the drillstring;a mid-string mud cap tool included in the drillstring and arranged uphole from the drill bit, the mid-string mud cap tool including:a body that defines an interior;one or more ports defined in the body to facilitate fluid communication between the interior and directly into the annulus; anda ball seat provided within the interior downhole from the one or more ports; anda wellbore projectile conveyable into the drillstring and sized to land on the ball seat,wherein the mid-string mud cap tool is arranged within the wellbore at a location between the first and second lost circulation zones, andwherein landing the wellbore projectile on the ball seat causes a portion of drilling fluid circulating within the drillstring to circulate into the annulus via the one or more ports and at the location between the first and second lost circulation zones.

2. The well system of claim 1, wherein the drill bit and the mid-string mud cap tool form part of a bottom hole assembly.

3. The well system of claim 1, wherein the mid-string mud cap tool further includes a sleeve arranged within the interior and operatively coupled to the ball seat such that landing the wellbore projectile on the ball seat causes the ball seat to shift and thereby transition the sleeve between a closed position, where the sleeve occludes the one or more ports, and an open position, where the one or more ports are exposed.

4. The well system of claim 3, wherein increasing a pressure within the drillstring causes the ball seat and the sleeve to shift within the interior.

5. The well system of claim 3, wherein the sleeve is actuated using at least one of a motor, a servo, a hydraulic actuation system, and any combination thereof.

6. The well system of claim 3, wherein transitioning the sleeve to the open position causes a first portion of the drilling fluid within the drillstring to be diverted through the one or more ports, while a second portion of the drilling fluid bypasses the wellbore projectile and is discharged into the annulus at the drill bit.

7. The well system of claim 6, wherein the first portion of the drilling fluid comprises about 10% to about 20% of the drilling fluid within the drillstring.

8. The well system of claim 6, wherein a second volume of drilling fluid is pumped into the annulus from a well surface and migrates into the first lost circulation zone, wherein the second portion of the drilling fluid migrates into the second lost circulation zone, and wherein the first portion of the drilling fluid maintains a hydrostatic column of the drilling fluid within the annulus between the first and second lost circulation zones.

9. The well system of claim 1, wherein the first and second lost circulation zones exhibit a pore pressure that is less than a hydrostatic pressure of the drilling fluid circulating in the drillstring.

10. The well system of claim 1, wherein the diameter of the ball seat is sized smaller than the diameter of the wellbore projectile.

11. A method, comprising:extending a drillstring into a wellbore penetrating a formation including first and second lost circulation zones, the drillstring including a drill bit and a mid-string mud cap tool arranged uphole from the drill bit, the mid-string mud cap tool including:a body that defines an interior;one or more ports defined in the body to facilitate fluid communication between the interior and directly into an annulus defined between the drillstring and an inner wall of the wellbore; anda ball seat provided within the interior;advancing the drillstring until the mid-string mud cap tool is positioned within the wellbore to axially interpose the first and second lost circulation zones;pumping a first volume of drilling fluid through the drillstring;conveying a wellbore projectile into the drillstring and landing the wellbore projectile on the ball seat; anddiverting a portion of the first volume of the drilling fluid directly into the annulus via the one or more ports and at the location between the first and second lost circulation zones.

12. The method of claim 11, wherein the mid-string mud cap tool further includes a sleeve arranged within the interior and operatively coupled to the ball seat, and wherein landing the wellbore projectile on the ball seat comprises:increasing a fluid pressure within the drillstring; andmoving the ball seat downhole within the interior and thereby transitioning the sleeve from a closed position, where the sleeve occludes the one or more ports, to an open position, where the one or more ports are exposed.

13. The method of claim 11, wherein the portion of the first volume of the drilling fluid comprises a first portion, the method further comprising:bypassing the ball seat and the wellbore projectile with a second portion of the first volume of the drilling fluid; anddischarging the second portion of the first volume of the drilling fluid from the drill bit and into the annulus.

14. The method of claim 13, wherein the first portion of the first volume of the drilling fluid comprises about 10% to about 20% of the drilling fluid within the drillstring.

15. The method of claim 13, further comprising:pumping a second volume of drilling fluid into the annulus from a well surface;flowing the second volume of the drilling fluid to the first lost circulation zone;flowing the second portion of the first volume of the drilling fluid to the second lost circulation zone; andmaintaining a hydrostatic column of the drilling fluid within the annulus between the first and second lost circulation zones with the first portion of the first volume of the drilling fluid.

16. The method of claim 11, wherein the mid-string mud cap tool further includes a sleeve arranged within the interior and operatively coupled to the ball seat, and wherein landing the wellbore projectile on the ball seat comprises:actuating the sleeve with at least one of a motor, a servo, and a hydraulic actuation system and thereby moving the ball seat downhole within the interior to transition the sleeve from a closed position, where the sleeve occludes the one or more ports, to an open position, where the one or more ports are exposed moving the.

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