Patent Grant
10883313
In the production of hydrocarbons, it is common to drill one or more secondary wellbores (alternately referred to as lateral or branch wellbores) from a primary wellbore (alternately referred to as parent or main wellbores). The primary and secondary wellbores, collectively referred to as a multilateral wellbore may be drilled, and one or more of the primary and secondary wellbores may be cased and perforated using a drilling rig.
Thereafter, once a multilateral wellbore is drilled and completed, production equipment such as production casing is installed in the wellbore, the drilling rig is removed and the primary and secondary wellbores are allowed to produce hydrocarbons.
During any stage of the life of a wellbore, techniques may be used to stimulate the wellbore after production has begun. For example, a portion of a wellbore may be re-perforated to enhance hydrocarbon flow. Likewise, various treatment fluids may be used to stimulate the wellbore. As used herein, the terms treatment or treating refer to any subterranean operation that uses a fluid in conjunction with a desired function and/or for a desired purpose. The terms do not imply any particular action by the fluid or any particular component thereof.
One common production stimulation operation that employs a treatment fluid is hydraulic fracturing (occasionally referred to simply as “fracking”). Hydraulic fracturing operations generally involve pumping a treatment fluid (e.g., a fracturing fluid) into a well, which penetrates a subterranean formation at a sufficient hydraulic pressure to create a network of cracks (commonly referred to as fissures) in the subterranean formation through which hydrocarbons flow more freely. This increases production by increasing flow from the formation into the wellbore. In some cases, hydraulic fracturing can be repeated in a previously fractured wellbore to further enhance flow, which is a process commonly referred to as re-fracking. Re-fracturing may include extending or enlarging one or more natural or previously created fractures in the subterranean formation.
During the initial production life of a well, typically referred to as the primary phase, production of hydrocarbons generally occurs either under natural pressure, or by means of pumps that are deployed within the wellbore. This may include wellbores that have undergone production stimulation operations, such a hydraulic fracturing, during the drilling and completion process.
Over the life of a well, the natural driving pressure will decrease to a point where the natural pressure is insufficient to drive the hydrocarbons to the surface at a technically and/or economically viable rate, at which point the reservoir pressure can sometimes be enhanced by external means to increase flow. In secondary recovery, for example, treatment fluids are injected into the reservoir to supplement the natural pressure. Such treatment fluids may include water, natural gas, air, carbon dioxide or other gas.
Likewise, in addition to enhancing the natural pressure of the reservoir, it is also common through tertiary recovery, to increase the mobility of the hydrocarbons themselves in order to enhance extraction, again through the use of treatment fluids. Such methods may include steam injection, surfactant injection and carbon dioxide flooding.
In both secondary and tertiary recovery, hydraulic fracturing may also be used to enhance production of a well, as may re-perforating.
Depending on the nature of the secondary or tertiary operation, it may be necessary to redeploy a rig, often referred to as a “workover rig” to the wellbore to assist in these operations, which operations may require additional equipment be installed in the wellbore. For example, subjecting a producing wellbore to hydraulic fracturing pressures after it has been producing may damage certain casings, installations or equipment already in the wellbore. Thus, it may be necessary to install additional equipment to protect the various equipment and tools already in the wellbore before proceeding with such operations. Such additional equipment is typically of sufficient size and weight that requires the use of a workover rig. As the number of secondary wellbores in a multilateral wellbore increases, the difficulty in protecting the various equipment in the primary wellbore and the secondary wellbores becomes even more pronounced.
All of the forgoing efforts focus on stimulating or enhancing production from existing secondary wellbores in a multilateral well.
It would be desirable to provide a system that allows production from a wellbore to be enhanced by providing additional secondary wellbores in the multilateral well.
Various embodiments of the present disclosure will be understood more fully from the detailed description given below and from the accompanying drawings of various embodiments of the disclosure. In the drawings, like reference numbers may indicate identical or functionally similar elements.
The disclosure may repeat reference numerals and/or letters in the various examples or figures. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Further, spatially relative terms, such as beneath, below, lower, above, upper, uphole, downhole, upstream, downstream, and the like, may be used herein for ease of description to describe one element or feature's relationship to another element(s) or feature(s) as illustrated, 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 wellbore, the downhole direction being toward the toe of the wellbore. Unless otherwise stated, the spatially relative terms are intended to encompass different orientations of the apparatus in use or operation in addition to the orientation depicted in the figures. For example, if an apparatus in the figures is turned over, elements described as being “below” or “beneath” other elements or features would then be oriented “above” the other elements or features. Thus, the exemplary term “below” can encompass both an orientation of above and below. The apparatus may be otherwise oriented (rotated 90 degrees or at other orientations) and the spatially relative descriptors used herein may likewise be interpreted accordingly.
Moreover even though a figure may depict a horizontal wellbore or a vertical wellbore, unless indicated otherwise, it should be understood by those skilled in the art that the apparatus according to the present disclosure is equally well suited for use in wellbores having other orientations including vertical wellbores, deviated wellbores, multilateral wellbores or the like. Likewise, unless otherwise noted, even though a figure may depict an offshore operation, it should be understood by those skilled in the art that the apparatus according to the present disclosure is equally well suited for use in onshore operations and vice-versa. Further, unless otherwise noted, even though a figure may depict a cased hole, it should be understood by those skilled in the art that the apparatus according to the present disclosure is equally well suited for use in open hole operations.
As used in this Detailed Description, the term primary wellbore may refer to any wellbore from which another, intersecting wellbore has been or is to be subsequently drilled; whereas the term secondary wellbore may refer to any subsequently-drilled wellbore extending from (intersecting with) that primary wellbore. Thus, in any multilateral wellbore system, the initial wellbore drilled from surface will invariably be the primary wellbore with respect to any one or more intersecting wellbores drilled therefrom, which are the secondary wellbores with respect to that initial wellbore drilled from surface. Each secondary wellbore may then itself become the “primary” wellbore with respect to any further (“secondary”) wellbore(s) drilled therefrom.
Generally, in one or more embodiments, a new, secondary wellbore is drilled from a primary wellbore that already has a production string deployed therein. The production string is cut or severed at or below a desired kick-off location for the new secondary wellbore. The portion of the production string upstream or above the location of the cut is withdrawn from the primary wellbore, and a sleeve is deployed in the primary wellbore and mounted on the exposed upstream end of the production string that remains in the primary wellbore. The sleeve may be a lateral orientation device formed of a tubular body having a first end and a second end with a bore extending therebetween. A lower shoulder is formed on a surface of the tubular body and seats against the exposed end of the production string. Between the lower shoulder and the first end of the tubular body, an upper shoulder may be formed on a surface of the tubular body for landing of a tool, such as a whipstock. The tubular body may be elongated as necessary to account for the distance between the location of the cut and a location adjacent the desired kick-off. The first end of the tubular body may include a contoured surface for orientation of a tool, such as the whipstock deployed to engage the lateral orientation device. A first anchoring mechanism, such as slips or a packer, may be provided to secure the lateral orientation device to an adjacent tubular. Seals may be provided to seal between the lateral orientation device and an adjacent tubular. A second anchoring mechanism, such as slips or a packer, may likewise be deployed along the outer surface of the tubular body to stabilize the lateral orientation device within the adjacent tubular surrounding the tubular body. An engagement mechanism may be provided to secure a tool, such as the whipstock, seated on the lateral orientation device once the tool has been radially oriented by the contoured surface. Once seated on and oriented by the lateral orientation device, the tool may be utilized to perform an operation, such as a work-over operation, in a wellbore. In one or more embodiments, the tool may be a whipstock, and the whipstock may be utilized to guide a cutting mechanism for milling a window in adjacent casing (if any) and/or drilling the new secondary wellbore in the adjacent formation from a primary wellbore. Alternatively, once the lateral orientation device is deployed, a work string may be deployed and coupled with the lateral orientation device in order to perform pumping services, such as hydraulic fracturing, in a primary or secondary wellbore below the lateral orientation device.
Turning to
Drilling and production system 10 may include a drilling rig or derrick 20. Drilling rig 20 may include a hoisting apparatus 22, a travel block 24, and a swivel 26 for raising and lowering a conveyance vehicle such as tubing string 30. Other types of conveyance vehicles may include tubulars such as casing, liner, drill pipe, work string, coiled tubing, production tubing (including production liner and production casing), and/or other types of pipe or tubing strings collectively referred to herein as tubing string 30. Still other types of conveyance vehicles may include wirelines, slicklines or cables. In
Drilling rig 20 may be located proximate to a wellhead 40 as shown in
For offshore operations, as shown in
Tubing string 30 extends down from drilling rig 20, through riser 46 and BOP 42 into wellbore 12.
A fluid source 52, such as a storage tank or vessel, may supply a working or service fluid 54 pumped to the upper end of tubing string 30 and flow through tubing string 30. Fluid source 52 may supply any fluid utilized in wellbore operations, including without limitation, drilling fluid, cementious slurry, acidizing fluid, liquid water, steam, hydraulic fracturing fluid, propane, nitrogen, carbon dioxide or some other type of fluid.
Wellbore 12 may include subsurface equipment 56 disposed therein, such as, for example, the completion equipment illustrated in
Wellbore drilling and production system 10 may generally be characterized as having a pipe system 58. For purposes of this disclosure, pipe system 58 may include casing, risers, tubing, drill strings, completion or production strings, subs, heads or any other pipes, tubes or equipment that attaches to the foregoing, such as tubing string 30 and riser 46, as well as the primary and secondary wellbores in which the pipes, casing and strings may be deployed. In this regard, pipe system 58 may include one or more casing strings 60 that may be cemented in wellbore 12, such as the surface, intermediate and production casing strings 60 shown in
As shown in
Extending uphole and downhole from lower completion assembly 82 is one or more communication cables 100, such as a sensor or electric cable, that passes through packers 86, 90 and 94 and is operably associated with one or more electrical devices 102 associated with lower completion assembly 82, such as sensors positioned adjacent sand control screen assemblies 88, 92, 96 or at the sand face of formation 14, or downhole controllers or actuators used to operate downhole tools or fluid flow control devices. Cable 100 may operate as communication media, to transmit power, or data and the like between lower completion assembly 82 and an upper completion assembly 104.
In this regard, disposed in secondary wellbore 12a, the upper completion assembly 104 is coupled at the lower end of tubing string 30. The upper completion assembly 104 includes various tools such as a packer 106, an expansion joint 108, a packer 110, a fluid flow control module 112 and an anchor assembly 114.
Extending uphole from upper completion assembly 104 are one or more communication cables 116, such as a sensor cable or an electric cable, which passes through packers 106, 110 and extends to the surface 16. Cable(s) 116 may operate as communication media, to transmit power, or data and the like between a surface controller (not pictured) and the upper and lower completion assemblies 104, 82.
Fluids, cuttings and other debris returning to surface 16 from wellbore 12 may be directed by a flow line 118 back to storage tanks, fluid source 52 and/or processing systems 120, such as shakers, centrifuges and the like.
In each of
Turning to
A tubular string 210, or more narrowly, a production string 210 (also generally referenced above as tubing string 30), is shown in fluid communication with secondary wellbore 12a. Persons of ordinary skill in the art will appreciate that while the lateral orientation device 130 will be described primarily herein with reference to tubular string 210 being a “production string”, the foregoing is for illustrative purposes only and is not limited to use with only production strings, but may be utilized with any tubular strings deployed within a wellbore 12, including tubing, liner, casing and pipe. Thus, additionally or alternatively, lateral orientation device 130 may be employed with any existing tubing, liner, casing or pipe in a wellbore so long as it can be severed as described herein for receipt of a sleeve, the lateral orientation device 130 or other tool, as described herein. Likewise, persons of ordinary skill in the art will appreciate that the described primary and secondary wellbores 12, 12a, 12b are for illustrative purposes only, and are not intended to be limiting. The lateral orientation device 130 as described herein, and the methods of use, may be deployed in any type of wellbore. For example, secondary wellbore casings 206 are not limited to a particular size or manner of support, and other systems for supporting secondary wellbore casing 206 may be utilized. It will further be appreciated that the disclosure is not limited to a particular configuration for secondary wellbore 12a or the subsurface equipment 56 installed therein. The overall well system includes a tubular, such as tubular string 210 (working string (not shown) or tubing string 30), deployed therein that can be cut and on which lateral orientation device 130 may be deployed.
Tubular string 210 can be characterized as having an upper portion 210a and a lower portion 210b. At least lower portion 210b is substantially fixed within the primary wellbore 12 so that tubular string 210 is not readily movable axially without taking some additional action, like releasing anchors or other mechanisms securing lower portion 210b within the primary wellbore 12. Upper portion 210a may also be fixed to the extent an additional action may be taken (such as releasing slips or anchors, in order to allow manipulation as described below).
In any event, also illustrated in
With reference to
An orientation mechanism 250 may be disposed or otherwise formed at the first end 236a of tubular body 236. Although orientation mechanism 250 may be any mechanism or device that permits radial orientation of a tool or equipment engaging tubular body 236, in one or more embodiments, orientation mechanism 250 may be a scoop head, a muleshoe or a ramped or angled surface or edge (such as the illustrated ramped edge).
Lateral orientation device 130 may further include one or more engagement mechanisms 252a, 252b (generally or collectively engagement mechanisms 252) disposed along a surface, such as inner surface 240. In one or more embodiments, the engagement mechanisms 252 are disposed between upper shoulder 244, and the first end 236a of tubular body 236. Engagement mechanisms 252 may be any engagement or coupling device that that allows a tool or other device to be secured to lateral orientation device 130. In one or more embodiments, engagement mechanisms 252 may include a latch coupling 252a for engagement with a latch (not shown). In one or more embodiments, engagement mechanisms 252 may include a notch 252b formed in inner surface 240. Latch coupling 252a and notch 252b are for illustrative purposes only and could be other mechanisms or devices that are well known in the art.
Lateral orientation device 130 may further include one or more seals disposed along one or both surfaces 240, 242. In the illustrated embodiment, a first inner seal 254 is disposed along inner surface 240 between shoulders 244 and the first end 236a of tubular body 236. First inner seal 254 may be between the engagement mechanisms 252 and the shoulder 244. A second inner seal 256 is disposed along inner surface 240 between shoulders 244 and the second end 236b of tubular body 236. An outer seal 258 is disposed along outer surface 242 between the first and second ends 236a, 236b. The seals are not limited to any particular type of seal as long as they seal the space between adjacent components. In one or more embodiments, seals 254 and 256 are each one or more elastomeric elements. In one or more embodiments, seal 258 may include elastomeric elements.
Lateral orientation device 130 may further include anchoring mechanisms disposed along one or both surfaces 240, 242 to secure the lateral orientation device to an adjacent tubular surface and/or wellbore wall. Thus, an anchoring mechanism 260 is illustrated. In one or more embodiments where anchoring mechanism 260 is slips, the slips may be disposed along outer surface 242. Anchoring mechanism 260 may be deployed between the outer seal 258 and the first end 236a of tubular body 236. An anchoring mechanism 262 may also be provided along inner surface 240 adjacent second end 236b of tubular body 236.
Anchoring mechanism 262 may be slips. Anchoring mechanism 262 may be provided between shoulders 244 and second inner seal 256. In some embodiments (not shown) the positioning of the anchoring mechanism 262 and the seals 256 may be reversed, e.g., the anchoring mechanism 262 may be below the seals 262. If the anchoring system 262 is below the seals 256, the anchoring system 262 may not need to withstand the pressures contained by the seals 256. In one or more embodiments, anchoring mechanism 262 may include elastomeric elements. In one or more embodiments, anchoring mechanism 260 may include elastomeric elements, in which case, in some embodiments, anchoring mechanism 260 and outer seal 258 may be the same component, functioning to both seal the annulus 222 (
Turning to
As illustrated in
Likewise, slips or other anchoring mechanism 262 may be manipulated or otherwise deployed to engage the outer surface 234 of tubular lower portion 210b, anchoring tubular body 236 to tubular lower portion 210b. When the foregoing slips or anchoring mechanisms 260, 262 are set, lateral orientation device 130 is thus anchored in position at a location adjacent the desired kick-off point for the new secondary wellbore. In particular, lateral orientation device 130 is locked in place both axially and radially. In addition, lateral orientation device 130 functions to support and/or axially centralize the otherwise free end 230 of the lower portion 210b of tubular string 210 (
Similarly, with lateral orientation device 130 in position, a packer or other outer seal 258 may be deployed to seal annulus 222 between lateral orientation device 130 and primary wellbore casing 200. Seals 256 seal the annulus 222 between tubular lower portion 210b and lateral orientation device 130.
In one or more embodiments, before removal from the primary wellbore 12, run-in tool 266 (
As illustrated in
It should be appreciated that as described herein, when tool 276 is a whipstock, the whipstock is not limited to any particular type of whipstock, but may be any device which will deflect, direct or otherwise guide a tool or device in the direction of desired opening 290. In some embodiments, tool 276 may be a solid body, while in other embodiments, tool 276 may include an interior passage extending therethrough. Similarly, more than one tool 276 may be deployed for different purposes. Thus, for example a first whipstock may be deployed in the lateral orientation device 130 for milling and/or drilling, while a different whipstock may be deployed in the lateral orientation device 130 for other operations, such as installation of a liner in new secondary wellbore 12b (
It should further be appreciated that the upper and lower shoulders 244a, 244l are provided as a seat or no-go mechanism for engaging another tubular. Thus, both shoulders 244u, 244l may be provided on the same surface 240, 242 (
Turning to
Turning to
Packer 308 may be particularly useful in the case of failure of one seals 254, 306, limiting exposure of the primary wellbore casing 200 to the high pressure of the pressurized fluid. Another advantage of such an arrangement is that pressure can be applied in the annulus 222 between the work string 300 and the primary wellbore casing 200 during pumping operations. If a leak in the work string 300 develops, an increase in the annulus pressure would occur, alerting an operator and allowing the operator to take appropriate action.
It will be appreciated that while a secondary wellbore 12a is utilized in the description, the lateral orientation device 130 as described herein may simply be utilized with production casing, production liner, production tubing, and/or a combination thereof or other tubing, or tubings, associated with production equipment in the primary wellbore 12.
Furthermore, while only a single lateral orientation device 130 has been described heretofore, it will be appreciated that a wellbore may have multiple lateral orientation devices 130a, 130b as illustrated in
Likewise, the lateral orientation device 130 may be deployed in a secondary wellbore to drill a new twig wellbore therefrom.
Turning to
Method 400 generally involves cutting the substantially fixed tubular string disposed within the wellbore in order to expose an end of the cut tubular string. The upper portion of the substantially fixed tubular string upstream or above the location of the cut is withdrawn from the wellbore, and a sleeve is deployed in the wellbore and mounted on the exposed upper end of the tubular string remaining in the wellbore. It will be appreciated that the points of fixation of the substantially fixed tubular string may be below the location of the cut, thus enabling the upper portion of the tubular string to be withdrawn. The sleeve is thereafter used to perform an operation in the wellbore, such as drilling a new secondary wellbore or high pressure pumping to a portion of the wellbore below and/or above the sleeve. In this regard, a tool may be deployed to engage the sleeve. The sleeve may orient the tool and secure the tool in a desired orientation for use in the particular operation.
In one or more embodiments, the operation may be the drilling a secondary wellbore from a primary wellbore, such as is described above and generally illustrated in
Thus, in step 402, a first or primary wellbore 12 is drilled and a tubular string 210 is deployed in the primary wellbore 12. The primary wellbore 12 may be cased or uncased.
The tubular string 210 is substantially fixed, anchored or otherwise secured (either temporarily or more permanently) in the primary wellbore 12 so that it cannot readily move axially without further manipulation, such as disengaging an anchor. In one or more embodiments, the tubular string 210 is substantially fixed by activating slips or a packer. Alternatively or in addition thereto, in one or more embodiments, subsurface equipment 56, such as production equipment, is deployed in the primary wellbore 12 or a secondary wellbore 12a extending therefrom, and the tubular string 210 is production tubing extending from the production equipment to a wellhead 40. In one or more embodiments, a deviated secondary wellbore 12a may be drilled from the primary wellbore 12 and secondary wellbore casing 206 or a liner string may be deployed at least partially in the deviated secondary wellbore 12a. In one or more embodiments, hydrocarbons are produced from or through the primary wellbore 12 for a period of time following drilling and deployment of a tubular string 210 in step 402. In one or more embodiments, the primary wellbore may be a main wellbore or it may be a lateral wellbore, depending on the secondary wellbore to be drilled. Thus, in one or more embodiments, the primary or “first” wellbore may be a lateral wellbore drilled off of a main wellbore and the “second” wellbore is a twig wellbore. In the event that the primary wellbore already exists, the task of drilling in step 402 may be omitted or modified.
In step 404, the tubular string 210 deployed in step 402 is cut until severed to expose an upper end 230 of a lower portion 210b of the tubular string 210. The location of the cut is selected based on the intended operations to subsequently be performed. Thus, in one or more embodiments, to the extent a new deviated secondary wellbore 12b, 12c is to be drilled, the location of the cut is selected to be below a desired kick-off point for the new deviated secondary wellbore 12b, 12c. The tubular string 210 may be severed from inside or outside the tubular string 210 by a cutting tool 220. In one or more embodiments, a cutting tool 220 (
Although the lateral orientation device 130 may be used with any type of tubular string 210 deployed within a wellbore, in one or more embodiments, the tubular string 210 to be cut is spaced apart from a primary wellbore casing 200 or other casing string cemented into the primary wellbore 12 (or the wall of the wellbore in uncased wellbores) such that an annulus 222 exists between the tubular string 210 to be cut and the casing 200 (or wall). In this regard, in one or more embodiments, the tubular string 210 to be cut is production casing or tubing deployed in a wellbore 12. More generally, the tubular string 210 may be any casing, production string or tubing that can be manipulated, i.e., severed and withdrawn to expose an end, as described herein.
In step 406, a sleeve or other tool is mounted on the exposed upper end 230 of the lower tubular string portion 210b. The sleeve or tool may be mounted over the exposed end 230 or within the interior of the exposed end 230. In one or more embodiments, the sleeve or tool is a lateral orientation device 130 as described above. For purposes of the following discussion, the sleeve or tool will be described as a lateral orientation device 130, but persons of skill in the art will appreciate that the method need not be limited in certain embodiments to the specific lateral orientation device 130 described above. Likewise, while a sleeve is more generally described, the method may be used to mount any type of tool on the cut, exposed end of a tubular string. In any event, in one or more embodiments, the lateral orientation device 130 is deployed using a run-in tool 266. In one or more embodiments, the lateral orientation device 130 is seated on the end 230 of the tubular string lower portion 210b so that a shoulder 244t formed on the lateral orientation device 130 abuts the end 230 of the tubular string lower portion 210b. In one or more embodiments, at least a portion of the inner diameter D1 (
In other embodiments, preferably at step 404 or 406, the upper end, e.g. upper end 230 of the lower portion 210b of tubular string 210 (
In any case, as part of step 406, a shoulder on the sleeve or tool is landed on the exposed end of the lower tubing string portion. The landing of a shoulder 244 on the end 230 of tubular string 210 establishes an axial position for the sleeve, tool or lateral orientation device. The sleeve, tool or lateral orientation device may likewise be rotated to establish a desired radial position. The disclosure is not limited to a particular method for ensuring radial orientation. In one or more embodiments, the conditioned end 230 of tubular string lower portion 210b may be utilized to establish both an axial position and a radial position. For example, apertures 227 may be provided in a known radial and or axial orientation.
While in some embodiments, the sleeve, tool or lateral orientation device 130 is oriented based on conditioning of the end 230, in other embodiments, the orientation of the lateral orientation device 130, or more generally, a sleeve, does not have to be related to end 230. In this regard, the orientation of the lateral orientation device 130 may made from the surface by knowing the direction of the deflector face or orientation mechanism 250 of the lateral orientation device 130 and the desired orientation of the planned secondary wellbore. Typically, operators will plan secondary wellbores 12b, 12c to intersect the natural fractures of a geologic formation in a perpendicular direction. The orientation of the lateral orientation device's face, and hence the orientation of the secondary wellbore, can be set by 1) rotating the work string or run-in tool 266 that is carrying the lateral orientation device into the wellbore, 2) and actuating an engagement mechanism to anchor the lateral orientation device as described below.
More particularly, once lateral orientation device 130 is positioned as desired, various slips or other anchoring mechanisms 260 may be actuated to anchor the lateral orientation device 130 to adjacent tubulars. In one or more embodiments, a set of slips may be actuated to engage the lateral orientation device 130 to the primary wellbore casing 200, securing the lateral orientation device 130 relative to the primary wellbore 12. Additionally, in one or more embodiments, a set of slips or other anchoring mechanisms 262 may be actuated to engage the lateral orientation device 130 to the tubular string lower portion 210b, securing the lateral orientation device 130 relative to the tubular string lower portion. The slips may consist of individual slips that will prevent the lateral orientation device 130 from rotating relative to the upper end 230 of the lower portion 210b of the tubular string 210. In another embodiment, the slips may have a slight bias to their teeth so the slips hold the lateral orientation device 130 from moving up and down and a slight bias to prevent the lateral orientation device 130 from rotating with respect to the upper end 230 of the lower portion 210b of the tubular string 210. Other anchoring mechanisms 260, 262, such as a packer, may also be used to anchor the lateral orientation device 130. In other embodiments, the anchoring mechanisms may include an expandable liner hanger where rubber elements are expanded to anchor the lateral orientation device 130 axially and rotationally, while also providing a seal.
Finally, sealing may be established between the lateral orientation device 130 and adjacent tubulars. In one or more embodiments, a packer may be actuated to seal the annulus 222 (
Actuation of the packers and the seals is not limited to a particular manner of actuation.
A plug 268 (
While the lateral orientation device 130 is most preferably mounted on the exposed end of the lower portion of the tubular string so as to be in direct fluid communication with the lower portion of the tubular string 210b, in other embodiments, lateral orientation device 130 may be positioned in primary wellbore casing 200 above the location 226 where tubular string 210 is severed. In such case, it will be appreciated that lateral orientation device 130, or more broadly, a sleeve, can be anchored to casing string 200 utilizing anchoring mechanism 260 and sealed utilizing seals 258 as described herein. In any event, when so positioned, lateral orientation device 130, or more broadly a sleeve, may still be used to seat a tool 276, such as a whipstock, as described herein.
In step 408, a tool 276, such as a whipstock, is deployed in the wellbore and seated on the lateral orientation device. In one or more embodiments, to the extent the tool 276 is a whipstock the whipstock is seated so that a guide surface or contoured surface 282 of the whipstock faces in the direction of the new secondary wellbore 12b, 12c to be drilled. A follower 281 or similar device on the whipstock may move along an orientation mechanism, such as orientation mechanism 250, of the lateral orientation device 130 in order axially and radially position the whipstock in the wellbore.
In step 410, once the whipstock has been deployed, the new secondary wellbore 12b, 12c can be constructed utilizing the whipstock. In one or more embodiments, where the primary wellbore 12 is cased, the whipstock may guide a cutting tool 292 (
It will be appreciated that in certain wellbore arrangements, multiple strings of casing and/or tubing strings may surround the deployed lateral orientation device. In such case, in order to create the new secondary wellbore, the whipstock may be utilized to mill windows through multiple strings of casing and/or tubing strings before proceeding with formation drilling. Thus, in one or more embodiments, the whipstock may be utilized to cut through each of a tubing string, and/or production liner and/or production casing and/or intermediate casing, and/or surface casing and/or any other pipe at a particular location selected for a new secondary wellbore. In one or more embodiments, where an inner tubing deployed within a production liner can be withdrawn from the wellbore, such tubing is withdrawn and then the production liner is severed as described herein for receipt of the lateral orientation device 130.
It will further be appreciated that multiple new secondary wellbores 12b, 12c may be drilled from a primary wellbore 12. In such case, multiple lateral orientation devices 130a, 130b (
More broadly, to the extent some other operation other than drilling a new secondary wellbore 12b, 12c is to be performed, the steps relating to the whipstock may be eliminated or modified to suit the purposes of the operation. Thus, in one or more embodiments, a tubular string 210 may be severed as described herein and some other type of sleeve or tool is mounted on the exposed upper end of the tubular string lower portion 210b, after which, the sleeve or tool is utilized for the desired operation.
Moreover, while the foregoing has been generally described in terms of a primary wellbore 12 and one or more secondary wellbores 12a, 12b, 12c extending from a primary wellbore 12, it will be appreciated that the lateral orientation device 130 and methods described herein may also be utilized in secondary wellbores in order to drill twig wellbores therefrom. In such case, a secondary wellbore is generally referenced as the “first” wellbore and the proposed deviated wellbore to be drilled utilizing the lateral orientation device is generally referenced as the “second” wellbore.
Prior to, or subsequent to drilling the new secondary wellbore 12b, 12c, in one or more embodiments, a portion of the wellbore below the lateral orientation device 130 may be subjected to high pressure pumping operations. In one or more embodiments, these high pressure pumping operations may be hydraulic fracturing or re-fracturing. In order to conduct these high pressure pumping operations, at step 412, a work string 300 is deployed in the primary wellbore 12. The work string 300 may be selected to have a higher pressure rating than the primary wellbore casing 200. The work string 300 is deployed so that a distal end 302 of the work string 300 seats on the lateral orientation device 130 or otherwise within the primary wellbore casing 200. The work string 300 may be mechanically engaged to the lateral orientation device 130. A packer 308 may be deployed to seal the annulus between the work string 300 and the primary wellbore casing 200.
Once the work string 300 has been stabbed into the lateral orientation device 130 or otherwise affixed relative thereto, at step 414, in various pumping operations, the work string 300 may be used to deliver fluids to the wellbore, e.g., secondary wellbore 12a, below the lateral orientation device 130. These pumping operations may be high pressure pumping operations, such as fracturing or re-fracturing operations, and may be carried out in the primary wellbore 12 or a lower secondary wellbore 12a, after which, flow-back is established. It will be appreciated that this procedure may occur while maintaining the new secondary wellbore 12b, 12c in isolation from the lower primary or lower secondary wellbore 12a.
Thus, a lateral orientation device has been described. Embodiments of the lateral orientation device may generally include a tubular body having a first end, a second end, with a bore extending between the ends, the bore defining an inner tubular body surface and an outer tubular body surface, wherein the first end includes an orientation profile; a lower shoulder provided along the one of the tubular body surfaces; and a first sealing device disposed along the surface on which the shoulder is provided, the first sealing device disposed between the lower shoulder and the second end. Other embodiments of a lateral orientation device may generally include a tubular body having a first end, a second end, with a bore extending between the ends, the bore defining an inner tubular body surface and an outer tubular body surface, wherein the first end includes an orientation profile; a lower shoulder provided along one of the tubular body surfaces; and a first sealing device disposed along the surface on which the shoulder is provided, the first sealing device disposed on the surface between the lower shoulder and the second end. Other embodiments of a lateral orientation device may generally include a tubular body having a first end, a second end, with a bore extending between the ends, the bore defining an inner tubular body surface and an outer tubular body surface, wherein the first end includes an orientation profile; a shoulder provided along the inner tubular body surface; a first sealing device disposed along the inner surface between the lower shoulder and the second end; a second sealing device disposed along the outer tubular body surface; a first anchoring mechanism disposed along the inner tubular body surface between the lower shoulder and the second end; an second anchoring mechanism disposed along the outer tubular body surface. Likewise, a wellbore system has been described. The wellbore system may generally include a tubing string having a proximal cut end, a distal end and an outer string surface; a lateral orientation device engaging the proximal cut end of the tubing string, the lateral orientation device comprising a tubular body having a first end, a second end, with a bore extending between the ends, the bore defining an inner tubular body surface and an outer tubular body surface, wherein the first end includes an orientation profile; a lower shoulder provided along the inner tubular body surface and abutting the proximal cut end of the tubing string; and a first sealing device disposed along the inner surface between the lower shoulder and the second end and sealingly engaging the outer string surface. In other embodiments, the wellbore system may generally include a first elongated wellbore having a proximal end and a distal end; a tubing string deployed in the primary wellbore, the tubing string having a proximal end between the two ends of the wellbore, a distal end and an outer string surface; a lateral orientation device deployed in the primary wellbore and engaging the proximal end of the tubing string, the lateral orientation device comprising a tubular body having a first end, a second end, with a bore extending between the ends, the bore defining an inner tubular body surface and an outer tubular body surface, wherein the first end includes an orientation profile; a lower shoulder provided along the inner tubular body surface and abutting the proximal end of the tubing string; and a first sealing device disposed along the inner surface between the lower shoulder and the second end and sealingly engaging the outer string surface. A wellbore system has also been described and may generally include a primary wellbore; a tubing string deployed in a distal portion of the primary wellbore, the tubing string having a proximal end, a distal end and an outer string surface, the proximal end of the tubing string positioned within the primary wellbore at a location spaced apart from the proximal end of the primary wellbore; a lateral orientation device deployed in the primary wellbore and engaging the proximal end of the tubing string, the lateral orientation device comprising a tubular body having a first end, a second end, with a bore extending between the ends, the bore defining an inner tubular body surface and an outer tubular body surface, wherein the first end includes an orientation profile; a lower shoulder provided along the inner tubular body surface and abutting the proximal end of the tubing string; and a first sealing device disposed along the inner surface between the lower shoulder and the second end and sealingly engaging the outer surface of the proximal end of the tubing string. Likewise, a wellbore system deployed within a primary wellbore extending from a surface into a formation may generally include a casing string having a proximal cut end, a distal end and an outer string surface; a lateral orientation device engaging the proximal end of the casing string, the lateral orientation device comprising a tubular body having a first end, a second end, with a bore extending between the ends, the bore defining an inner tubular body surface and an outer tubular body surface, wherein the first end includes an orientation profile; a lower shoulder provided along the inner tubular body surface and abutting the proximal end of the casing string; and a first sealing device disposed along the inner surface between the lower shoulder and the second end and sealingly engaging the outer string surface.
For any of the foregoing embodiments, the completion assembly may include any one of the following elements, alone or in combination with each other:
This application is a U.S. National Stage patent application of International Patent Application No. PCT/US2016/057757, filed on Oct. 19, 2016, which claims the benefit of U.S. Provisional Application Ser. No. 62/253,560 filed on Nov. 10, 2015, the benefit of both of which are claimed and the disclosure of both of which are incorporated herein by reference in their entireties.
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/US2016/057757 | 10/19/2016 | WO | 00 |
| Publishing Document | Publishing Date | Country | Kind |
|---|---|---|---|
| WO2017/083072 | 5/18/2017 | WO | A |
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