This disclosure relates to wellbore drilling.
In wellbore drilling situations that use a drilling rig, a drilling fluid circulation system circulates (or pumps) drilling fluid (for example, drilling mud) with one or more mud pumps. The drilling fluid circulation system moves drilling mud down into the wellbore through a drill string that is made up of special pipe (referred to as drill pipe) and drill collars and or other downhole drilling tools. The fluid exits through ports (jets) in the drill bit, picking up cuttings and carrying the cuttings up the annulus of the wellbore. At the surface, the mud and cuttings leave the wellbore through an outlet, and are sent to a cuttings removal system, for example, via a mud return line. At the end of the return lines, the mud and the cuttings are flowed onto a vibrating screen known as a shale shaker. Finer solids may be removed by a sand trap such as a dedicated solid removal equipment. The mud may be treated with chemicals stored in a chemical tank and then provided into the mud tank, where the process is repeated.
The drilling fluid circulation system delivers large volumes of mud flow under pressure during drilling rig operations. The circulation system delivers the mud to the drill string to flow down the string of drill pipe and out through the drill bit appended to the lower end of the drill string. In addition to cooling the drill bit, the mud hydraulically washes away the face of the wellbore through a set of jets in the drill bit. The mud additionally washes away debris, rock chips, and cuttings, which are generated as the drill bit advances. The circulation system flows the mud in an annular space on the outside of the drill string and on the interior of the open hole formed by the drilling process. In this manner, the circulation system flows the mud through the drill bit and out of the wellbore.
Sometimes a severe lost circulation zone (also known as a high-loss zone) is encountered during the drilling operation. A severe lost circulation zone is a highly permeable or fractured section in the formation where the pressure of the formation is significantly lower than the hydrostatic pressure of the drilling mud. The permeability (ease of flow through the rock formation) allows the drilling mud to enter the formation rather than return to the surface through the annulus of the wellbore. When drilling in a lost circulation zone, a large portion of or all of the drilling fluid that exits the drilling bit can be lost into the lost circulation zone instead of flowing to the surface. Such loss in drilling fluid, in a lost circulation zone can result, among other issues, in expensive downtime and loss of well control.
This disclosure describes technologies relating to mitigate drilling fluid circulation loss, for example, in lost circulation zones.
Certain aspects of the subject matter described here can be implemented as a wellbore drilling system that includes a drilling liner and a drill head assembly. The drilling liner is configured to be positioned in a lost circulation zone of a subterranean formation in which a wellbore is being drilled. The drilling liner is configured to flow wellbore drilling fluids from a surface of the wellbore to the subterranean formation while avoiding the lost circulation zone. The drill head assembly is attached to a downhole end of the drilling liner, and is configured to drill the subterranean formation to form cuttings, receive the wellbore drilling fluids, and flow the cuttings and the wellbore drilling fluids into the drilling liner while avoiding the lost circulation zone and towards the surface of the wellbore.
This, and other aspects, can include one or more of the following features. The system can include an inner work string configured to be positioned in the drilling liner. A liner annulus can be defined between an outer surface of the inner work string and an inner surface of the drilling liner. The system can include a mud motor attached to the inner work string between the drill head assembly and the inner work string. The mud motor can rotate the drill head assembly. The drill head assembly can be attached to a downhole end of the inner work string to form a closed flow path through which the wellbore drilling fluids flow to avoid the lost circulation zone. The drill head assembly can receive the wellbore drilling fluids flowed through the inner work string and can flow the wellbore drilling fluids and the cuttings into the liner annulus. The drill head assembly can include a coring tool and a drilling bit. The coring tool can core the subterranean formation in which the wellbore is being drilled. The drilling bit can be attached to the inner work string and can cut a core cored by the coring tool. The coring tool can be positioned between the drilling bit and the subterranean formation. A distance between a downhole end of the coring tool and the drilling bit can be substantially three feet. Multiple bearings can be positioned at an interface of the drilling liner and the coring tool, and can allow the coring tool to rotate independently of the drilling liner. The drilling bit can include cutter arms that can include a first end attached to the drilling bit, and a second end protruding away from the drilling bit and toward the subterranean zone. The coring tool can include a notch on an inner surface of the coring tool, which can receive the cutter arms of the drilling bit. The multiple bearings can be positioned uphole of the notches. The cutter arms of the drilling bit can be pivoted about respective pivot locations on the drilling bit toward and away from a longitudinal axis of the drilling liner. A liner running and setting tool can be attached to an uphole end of the drilling liner. The liner running and setting tool can position the drilling liner in the lost circulation zone and to transfer torque to rotate the drilling liner. A return flow control subsystem can be attached to an uphole end of the drilling liner. The return flow control subsystem can receive and flow the wellbore drilling fluid and the cuttings to flow towards the surface of the wellbore. The return flow control subsystem can include an inflatable packer that can seal the drilling liner against the wellbore casing, and flow passages to flow the drilling fluids mixed with the cuttings from the liner annulus to the wellbore casing annulus. The return flow control subsystem can include an inner body surrounded by the inflatable packer, and multiple bearings positioned between the inner body and the inflatable packer. The multiple bearings can allow rotation of the inner body independently of the inflatable packer. At least a portion of the return flow control subsystem can be positioned within a wellbore casing. The drilling liner can include a stop ring that can be attached at a location downhole from the return flow control subsystem. The stop ring can divert the wellbore drilling fluids mixed with the cuttings towards the flow passages. At least an uphole portion of the drilling liner can be positioned within a wellbore casing.
Certain aspects of the subject matter described here can be implemented as a method. A flow path through which a wellbore drilling fluid is flowed to a subterranean formation is isolated from a lost circulation zone of the subterranean formation. While drilling a wellbore through the lost circulation zone, the wellbore drilling fluid is circulated through the flow path while avoiding contact between the wellbore drilling fluid and the lost circulation zone.
This, and other aspects, can include one or more of the following features. The wellbore drilling fluid can be flowed from a surface of the wellbore through the flow path to drill the wellbore. Cuttings resulting from drilling the wellbore and the wellbore drilling fluid can be flowed through the flow path to the surface while avoiding contact between the cuttings and the lost circulation zone. The wellbore can be drilled by removing a core from the subterranean zone using a coring tool, and cutting the core using a drilling bit attached to coring tool.
The details of one or more implementations of the subject matter described in this specification 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.
This disclosure describes downhole wellbore drilling liner systems and methods for implementing the same. As described in detail with reference to the following figures, an example system includes a drilling liner that isolates wellbore drilling fluid from a subterranean formation while permitting the drilling fluid to flow to a drill head assembly that drills a wellbore and carries cuttings away from the drilled portion of the subterranean formation. In particular, the drilling liner avoids contact between a lost circulation zone through which the wellbore is being drilled and the wellbore drilling fluid.
By implementing the downhole wellbore drilling system described, the drilling liner system can proactively limit the uncontrolled loss of drilling fluids into the subterranean formation, particularly, into severe lost circulation zones. The tools described can be implemented to be simple and robust, thereby decreasing cost to manufacture the tools. In some instances, the tool system can be used any time a lost circulation zone is encountered during drilling operations. The drilling liner system can be packaged as a bottom-hole assembly (BHA) that can be kept on a drilling platform and deployed quickly once a lost circulation zone is encountered, or prior to entering into the loss zone. The tool system can be used from the beginning of the lost circulation zone downhole to the next casing point. Implementing the techniques described can also reduce rig delays or non-productive time (NPT) and eliminate or minimize the need to use loss circulation mitigation materials within the drilling fluid. The cost of wellbore drilling fluids and the cost of implementing loss circulation mitigation materials currently available can also be reduced. Downtime that can result from needing to stop drilling after encountering severe losses, to pump conventional heavy-loaded loss circulation mitigation or specialty pills, or run and set a drillable plug to perform squeeze of cement slurry followed by drill-out can be avoided. The described system has no floating equipment or liner shoe to drill out. Cuttings from lost circulation zones can be recovered at the surface allowing studies of such cuttings to better understand lost circulation zones, which otherwise is not possible to be obtained in conventional drilling mode. Also because of cuttings obtained from the lost circulation zones, the drilling liner setting depth can be better or more securely determined by the formation lithology with more competent rock characteristics. The drilling liner system described can also avoid formation damage in the reservoir section by eliminating a large dynamic mud pressure variation conventionally imposed onto the rock formation. The drilling liner system is also presenting a secure or safer technique to drilling severe lost circulation zones in terms of well control during drilling operations, particularly in nationally fractured sour gas reservoirs highly prone to severe mud loss problems.
The system 100 includes a drill head assembly 101 that is attached to a downhole end of the drilling liner 105. In particular, the drill head assembly 101 is attached to a downhole end of the inner work string 109 to form an internal flow path 107 (arrows) through which the wellbore drilling fluid flows to avoid the subterranean formation that surrounds the drilling liner 105. In addition to drilling the subterranean formation to form cuttings, the drill head assembly 101 can receive the wellbore drilling fluids flowed through the drilling liner 105, and flow the cuttings and the wellbore drilling fluids towards the surface through an interior region of the drilling liner 105. As shown by the wellbore drilling fluid flow path 107, the wellbore drilling fluid is flowed from the surface (not shown) in the downhole direction through the inner work string 109, through the drill head assembly 101, and to the surface in the uphole direction through the liner annulus 115. Contact between the wellbore drilling fluid and the lost circulation zone can be minimized or avoided by positioning the drilling liner 105 in the lost circulation zone.
The drill head assembly 101 includes a coring tool 102 and a drilling bit 103 that is attached to the downhole end of the inner work string. The coring tool 102 can include, for example, a tungsten carbide cutter. Certain details of the coring tool 102 and the drilling bit 103 are described later with reference to
In some implementations, a rotary table, top drive, or similar device at a surface of the wellbore (for example, in a topside facility) can rotate the inner work string 109 to drill the wellbore. In such implementations, such as those shown in
The system 100 can include a safety sub 108 between a downhole end of the inner work string 109 and an uphole end of the mud motor 106 or directly the drill bit 103 if the mud motor 106 is not used. The safety sub 108 is a short joint where the inner work string 109 can be easily connected with and can be released at the sub from the tools below in case of emergence where the drill bit or drill head assembly is stuck, unable to move, so that less tools or tubular work string are left in the liner for subsequent fishing operation. The system 100 can include a drilling liner running and setting tool 111 uphole of the inner work string 109 that can position the drilling liner 105, the drill head assembly 101 and the mud motor 106 (if provided) in the subterranean formation in which the wellbore is being drilled. A slip joint 110 can connect the downhole end of the drilling liner running and setting tool 111 and the uphole end of the inner work string 109. In addition, the system 100 can include a return flow control sub-assembly 113 at an uphole end of the system 100 to prevent or mitigate loss of wellbore drilling fluids and to ensure that the wellbore drilling fluids with the cuttings return to a topside facility (not shown). The uphole end of the flow-control sub-assembly 113 is connected to a series of drill pipes that extend the length of the wellbore towards the topside facility. As described later, the drilling liner running and setting tool 111 can pass through a lost circulation zone while fluidically isolating the wellbore drilling fluid from the lost circulation zone. Also, the system 100 can include a liner hanger sub-assembly 112 that can retain the drilling liner 105 across the lost circulation zone after the drilling liner 105 has passed through the lost circulation zone, as shown in
Details of the drill head assembly 101 are described with reference to
Multiple bearings 104 (for example, ball bearings or other bearings) can be disposed at an interface between the drill head assembly 101 and the drilling liner 105. The multiple bearings 104 can allow the drill head assembly 101 to rotate independently of the drilling liner 105 shown in
The drilling bit 103, as shown in
Turning to the mud motor 106, as shown in
Example techniques to drill through a lost circulation zone using the system 100 are described with reference to
The second zone 209 is a lost circulation zone that is downhole of the cased first zone 207. For example, the second zone 209 includes large and naturally fractured formation with open fractures with width potentially in the order of inches. In the second zone 209, the fracture domain is inter-connected throughout a wide area. The pre-existing pore pressure in the second zone 209 is lower or substantially lower than the mud column hydrostatic pressure in the wellbore 208. Consequently, a portion of or all of fluid flowed through the second zone 209 in the uphole direction can be lost in the second zone 209. For example, when a volume of fluid is flowed through the wellbore 208 in contact with the second zone 209, there is no circulating mud returned to the surface even though the surface mud pumps are operational, this is commonly called total loss environment, drilling in this environment consumes a large of volume of mud per hour, considering also of a mud cap process commonly adopted in the field (i.e., pumping mud in the backside between drillpipe and surface casing to fill the wellbore with mud for well control or safety concern), hence this kind of drilling practice can't last long since it would be a major logistical concern with a large cost implication daily. However, if the problem is less severe, the fraction of the volume that is lost in the second zone 209 is higher than the fraction of the volume that flows to the surface of the wellbore 208, commonly called loss of circulation, or strictly speaking partial mud losses into the second zone 209. The system disclosed here is designed to address the severe problem of the total mud losses, it can also of course address the lesser problem such as partial mud losses.
The third zone 211 is downhole of the second zone 209 and is a competent formation that does not experience significant loss of wellbore drilling fluid. That is, the third zone 211 is not a lost circulation zone like the second zone 209. Without the drilling system 100 described, if the wellbore drilling fluid were flowed through the drill string 204 and through a drill head assembly while drilling in the second zone 209, a significant portion of the wellbore drilling fluid would be lost to the second zone 209. Thus, upon determining that the zone in which the wellbore 208 is being drilled is a lost circulation zone, like the second zone 209, the drilling system 100 described earlier can be deployed to drill through the second zone 209 while mitigating loss of the wellbore drilling fluid to the second zone 209.
The system 100 can be deployed upon encountering the second zone 209 or prior to drilling into the zone 209. For deployment, the system 100 (shown in
Multiple bearings 404 can be positioned between the inner body 400 and the inflatable packer 402. The multiple bearings 404 allow rotation of the inner body 400 independently of the inflatable packer 402. A stop ring 406 is attached to the flow control sub-assembly 113 downhole of the packer 402. The stop ring 406 resides at a top of the drilling liner 105 and diverts the wellbore drilling fluids mixed with the cuttings away from the uncased wellbore 208 (shown in
The return flow control sub-assembly 113 includes a central flow passage 408 that is connected to the inner work string 109 and carries drilling fluids in a downhole direction from the surface through the drill string 204 (shown in
After drilling through the second zone 209 (shown in
A number of implementations been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the disclosure.
This application is a continuation of and claims the benefit of priority to U.S. patent application Ser. No. 15/606,501, filed on May 26, 2017, the contents of which is hereby incorporated by reference.
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Number | Date | Country | |
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Child | 16287746 | US |