DRILLING AND STIMULATION OF SUBTERRANEAN FORMATION

Abstract

Apparatus and methods for drilling and stimulating a subterranean formation. The method may comprise drilling a wellbore comprising a deviated wellbore portion extending through a subterranean formation, forming a plurality of lateral tunnels extending from the deviated wellbore portion through the subterranean formation such that at least a portion of each of the plurality of lateral tunnels extends along a plane of maximum horizontal stress of the subterranean formation, and performing stimulation operations of the subterranean formation via the plurality of lateral tunnels.

Description

BACKGROUND OF THE DISCLOSURE

Wellbores are drilled through subterranean formations for the extraction of hydrocarbons. Hydraulic fracturing (“frac”) increases the production rates of hydrocarbons in formations having low fluid and/or gas permeability, such as deep shale formations. That is, frac pumps are used to pump high-pressure frac fluid into the wellbore to create localized fractures in the formation. The frac fluid may include proppant (e.g., sand, bauxite, ceramic, nut shells, etc.) to hold the fractures open after the frac pump pressure is removed, thereby permitting hydrocarbons to flow from the fractured formation into the wellbore. In carbonate reservoirs, the frac fluid may include hydrochloric acid and/or other chemicals intended to etch the fracture faces to improve the flow capacity of the fractures.

The overall process for creating a hydraulically fractured wellbore includes two or three primary operations; a drilling operation, an optional casing operation, and hydraulic fracturing operations. Hydraulic fracturing operations were initially performed in single-stage, vertical or near-vertical wells. In later years, hydraulic fracturing operations became predominantly utilized in horizontal or near-horizontal sections of single- and multi-stage wells, such as to improve productivity of these horizontal or near-horizontal well sections.

SUMMARY OF THE DISCLOSURE

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify indispensable features of the claimed subject matter, nor is it intended for use as an aid in limiting the scope of the claimed subject matter.

The present disclosure introduces a method that includes drilling a wellbore having a deviated wellbore portion extending through a subterranean formation, and forming lateral tunnels extending from the deviated wellbore portion through the subterranean formation such that at least a portion of each of the lateral tunnels extends along a plane of maximum horizontal stress of the subterranean formation. The method also includes performing stimulation operations of the subterranean formation via the lateral tunnels.

The present disclosure also introduces a method that includes drilling a wellbore having a deviated wellbore portion extending through a subterranean formation, and forming lateral tunnels extending from the deviated wellbore portion through the subterranean formation such that at least a portion of each of the lateral tunnels extends at an angle ranging between zero degrees and about 90 degrees with respect to true vertical. The method also includes performing stimulation operations of the subterranean formation via the plurality of lateral tunnels.

The present disclosure also introduces a method that includes drilling a wellbore having a deviated wellbore portion extending through a subterranean formation, and operating a hydraulic jetting tool to form lateral tunnels extending from the deviated wellbore portion through the subterranean formation. The method also includes performing stimulation operations of the subterranean formation via the plurality of lateral tunnels.

These and additional aspects of the present disclosure are set forth in the description that follows, and/or may be learned by a person having ordinary skill in the art by reading the material herein and/or practicing the principles described herein. At least some aspects of the present disclosure may be achieved via means recited in the attached claims.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.

FIG. 1 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 2 is a graph related to one or more aspects of the present disclosure.

FIG. 3 is a schematic view of a portion of a wellbore related to one or more aspects of the present disclosure.

FIG. 4 is a schematic view of a portion of a wellbore related to one or more aspects of the present disclosure.

FIG. 5 is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure.

FIG. 6 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 7 is a schematic view of a portion the apparatus shown in FIG. 6 in a different stage of operation.

FIG. 8 is a schematic view of the apparatus shown in FIGS. 6 and 7 in a different stage of operation.

FIG. 9 is a schematic view of the apparatus shown in FIGS. 6-8 in a different stage of operation.

FIG. 10 is a schematic view of the apparatus shown in FIGS. 6-9 in a different stage of operation.

FIG. 11 is a schematic view of at least a portion of an example implementation of a wellbore system formed via the apparatus shown in FIGS. 6-10.

FIG. 12 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 13 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 14 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 15 is a schematic view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 16 is a schematic view of the apparatus shown in FIG. 15 in a different stage of operation.

FIG. 17 is a schematic view of the apparatus shown in FIGS. 15 and 16 in a different stage of operation.

FIG. 18 is a schematic view of the apparatus shown in FIGS. 15-17 in a different stage of operation.

FIG. 19 is a schematic view of at least a portion of an example implementation of a wellbore system according to one or more aspects of the present disclosure.

FIG. 20 is a schematic view of at least a portion of an example implementation of a wellbore system according to one or more aspects of the present disclosure.

FIG. 21 is a flow-chart diagram of at least a portion of an example implementation of a method according to one or more aspects of the present disclosure.

FIG. 22 is a schematic sectional view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 23 is a schematic view of the apparatus shown in FIG. 22 in a different stage of operation.

FIG. 24 is a schematic view of the apparatus shown in FIGS. 22 and 23 in a different stage of operation.

FIG. 25 is a schematic sectional view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 26 is a schematic sectional view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 27 is a schematic sectional view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 28 is a schematic sectional view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 29 is a schematic sectional view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 30 is a schematic sectional view of at least a portion of an example implementation of apparatus according to one or more aspects of the present disclosure.

FIG. 31 is a schematic view of at least a portion of an example implementation of a wellbore system according to one or more aspects of the present disclosure.

FIG. 32 is a schematic view of a portion of an example implementation of a wellbore system according to one or more aspects of the present disclosure.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for simplicity and clarity, and does not in itself dictate a relationship between the various embodiments and/or configurations discussed.

FIG. 1 depicts a drilling rig 20 as an example environment for implementing the various apparatus and methods of the present disclosure. The rig 20 may be positioned over an oil or gas formation 28 disposed below the Earth's surface 25. The formation 28 may be a horizontal shale formation, such as of the Marcellus Formation in eastern North America. However, aspects of the present disclosure are also applicable or readily adaptable for use in other types of formations.

The rig 20 may include a derrick and a hoisting apparatus for raising and lowering a drill string 30, which extends into a wellbore 40 (e.g., pilot well) and includes a drill bit 32 and a number of downhole tools 52, 54, 56. The downhole tools 52, 54, 56 may include, for example, a steering tool such as a rotary steerable tool, a logging-while-drilling (LWD) tool, a measurement-while-drilling tool (MWD) tool, a downhole drilling motor, a downhole telemetry system, and/or other existing or future-developed downhole tools. The drill string 30 may also include a fracturing-while-drilling (FWD) assembly (not shown). The drill string 30 includes a plurality of threaded pipes 31 connected end-to-end. However, coiled tubing and/or other conveyance means may also be utilized within the scope of the present disclosure.

In the depicted implementation, the wellbore system being formed includes a substantially vertical wellbore 42 (e.g., a substantially vertical wellbore portion or segment), a deviated wellbore 44 (e.g., a substantially horizontal wellbore portion or segment), and two lateral tunnels 46 (e.g., laterals, sidetracks) extending laterally from the deviated wellbore 44. However, other wellbore systems having different numbers and/or trajectories of wellbores/segments and tunnels are also within the scope of the present disclosure.

One or more of the substantially vertical wellbore 42, the deviated wellbore 44, and/or one or more of the lateral tunnels 46 may be at least partially lined with a casing 43 and/or open-hole. The lateral tunnels 46 may extend vertically in an upward direction (i.e., opposite the direction of gravity) or a downward direction (i.e., direction of gravity). The disclosed implementations include various methods for drilling and stimulating (e.g., fracturing) wellbore systems including the lateral tunnels 46 (whether the lateral tunnels 46 extend upward or downward). It will be understood by those of ordinary skill in the art that the deployment illustrated in FIG. 1 is merely an example and is not intended to limit the disclosed implementations.

FIG. 2 depicts a plot of gas production versus the date of the first production of a well in the Barnett Shale reservoir. According to historical records, in the years from about 1990 to about 2003, the vast majority of new wells in the Barnett Shale reservoir were vertical or near-vertical, and were stimulated in a single stage using about 100,000 to about 1,500,000 pounds of proppant in about 2,000 to about 15,000 barrels of fracturing fluid. After about 2010, new wells have predominantly included horizontal or near-horizontal segments. According to historical records, these “horizontal wells” were most commonly stimulated in about five to twelve stages, using about 100,000 to about 450,000 pounds of proppant in about 2,000 to about 20,000 barrels of fracturing fluid for each of the five to twelve stages.

In FIG. 2, the production numbers are as measured over a three-month period. Vertical wells are plotted using darkened circles, and horizontal wells are plotted using open circles. FIG. 2 further depicts a moving average 92 of the gas production for the vertical wells and a moving average 94 of the gas production for the horizontal wells. As depicted, the moving average 92 of the gas production for the vertical wells has historically been constant at about 650 thousand standard cubic feet (Mcf) per day. The moving average 94 of the gas production for the horizontal wells has increased modestly from about 1300 to about 1600 Mcf per day.

Examination of the historical data depicted in FIG. 2 indicates that, on average, stimulating horizontal wells provides about a 250% increase in daily gas production for each well. This represents a substantial improvement in production, and is one reason for the recent transition from vertical to horizontal drilling and fracturing. However, this increased production comes at the expense of decreased efficiency. For example, the majority of the horizontal wells were generally stimulated in five to twelve stages along the length of the horizontal wellbore segment, with each of the stages utilizing proppant mass and fracturing fluid volume each comparable to those used in a single stage vertical fracturing operation.

The historical data also indicates that the production per fracturing stage for horizontal wells is about 20-50% of that of the vertical wells. The historical data also indicates that a greater quantity of proppant and fracturing fluid was utilized per unit of gas production in the horizontal wells. In other words, with respect to the efficiency of production, there is a reduction in the quantity of gas produced per fracturing stage, as well as per pound of proppant and barrel of fracturing fluid in a horizontal completion as compared to a vertical completion. While the data depicted in FIG. 2 are for wells drilled in the Barnett Shale reservoir, it will be understood that the production statistics for wells drilled in other basins are similar (e.g., for the Woodford, Eagle Ford, Baaken and Haynesville Shale reservoirs).

The present disclosure introduces that, with regard to the production efficiency aspects described above, an influential factor is related to the nature of fracture propagation and closure in layered formations. Additionally, the nature of fracture propagation and the ultimate shape and geometry of the fracture is somewhat independent of the orientation of the wellbore from which the fractures are induced, and the fracture propagation depends primarily upon the properties of the formation (e.g., the maximum stress direction of the formation).

FIG. 3 is a schematic illustration of hypothetical fractures 202 induced and propagated through a formation 208 from a vertical wellbore 210, and FIG. 4 is a schematic illustration of hypothetical fractures 202 induced and propagated through a formation 208 from a horizontal wellbore 215. When the fracturing pressure is released, the fractures 202 close around proppant particles 206 (e.g., sand) in the fracturing fluid. The proppant 206 is intended to prevent the fractures 202 from fully closing so that formation fluids flow into the wellbore 210, 215. Notwithstanding, upon closure (or partial closure) of the fractures 202 about the proppant 206, the presence of pinch points 204 may restrict the flow of formation fluids between sedimentary layers (i.e., horizons) such that the production is generally from intersected layers (i.e., layers that are intersected by the wellbore). Because of the near-horizontal orientation of many sedimentary layers, fractures induced from a vertical or horizontal wellbore permit wellbore fluids to be produced from a greater number of sedimentary layers in the formation (because the vertical wellbore intersects a greater number of layers). This may result in a greater production per fracture in a vertical well than in a horizontal well, resulting in the production efficiency losses in horizontal wells as described above.

The present disclosure introduces the realization that production efficiency may be enhanced via drilling and fracturing a wellbore system that includes a plurality of lateral tunnels extending substantially vertically (e.g., having an inclination of less than 45 degrees or greater than 135 degrees as described in more detail below) drilled along the same horizon. For example, as described in more detail below, a wellbore system within the scope of the present disclosure may include a deviated wellbore (e.g., a substantially horizontal wellbore) extending from a substantially vertical wellbore (e.g., a substantially vertical pilot well). A plurality of lateral tunnels may be drilled, cut out, or otherwise formed extending from the deviated wellbore and then fractured. The wellbore system may further include a plurality of deviated wellbores extending from a single, substantially vertical wellbore, with each of the deviated wellbores including a plurality of lateral tunnels.

FIG. 5 is a flow-chart diagram of at least a portion of an example implementation of a method (100) according to one or more aspects of the present disclosure. The method (100) includes drilling (102) a deviated wellbore (e.g., extending from a previously drilled and cased substantially vertical wellbore). The deviated wellbore may have an inclination of greater than about 45 degrees (e.g., greater than about 60 degrees, or perhaps greater than about 75 degrees). A plurality of lateral tunnels are drilled or otherwise formed (104), each extending from the deviated wellbore. The lateral tunnels may be substantially vertical, in that the lateral tunnels may have an inclination of less than about 45 degrees (e.g., less than about 30 degrees, or perhaps less than about 15 degrees). The lateral tunnels are then fractured (106). While the implementations described herein are not limited to a particular plurality of lateral tunnels, it will be understood that increasing the number of lateral tunnels tends to increase the overall production efficiency gains. Thus, the wellbore system may advantageously include greater than five (e.g., ten, fifteen, or more) lateral tunnels extending from each deviated wellbore.

In the context of the present disclosure, the term vertical (or substantially vertical) is not intended to mean exactly along the direction of gravity, which may be referred to hereinafter as true vertical, and the term horizontal (or substantially horizontal) is not intended to mean exactly orthogonal to the direction of gravity, which may be referred to hereinafter as true horizontal. In other words, a vertical wellbore is not to be understood as necessarily having an inclination of exactly (or nearly) zero or 180 degrees. Likewise, a horizontal wellbore is not to be understood as necessarily having an inclination of exactly (or nearly) 90 degrees. Rather, these terms are intended to refer to wellbores having an inclination within a range of values relative to true vertical and true horizontal. For example, a vertical (or substantially vertical) wellbore may broadly be understood to have a wellbore inclination of less than 45 degrees or greater than 135 degrees (depending on whether the wellbore trajectory is downward or upward). A vertical (or substantially vertical) wellbore may also be understood to have a wellbore inclination of less than 30 degrees or greater than 150 degrees, less than 15 degrees or greater than 165 degrees, or perhaps less than 10 degrees or greater than 170 degrees. Likewise, a horizontal (or substantially horizontal) wellbore may broadly be understood to have a wellbore inclination of less than 135 degrees and greater than 45 degrees. A horizontal (or substantially horizontal) wellbore may also be understood to have a wellbore inclination of less than 120 degrees and greater than 60 degrees, less than 105 degrees and greater than 75 degrees, or perhaps less than 100 degrees and greater than 80 degrees.

Moreover, fractures often propagate along a direction of maximum formation stress (or along the plane of maximum formation stress). Thus, the deviated wellbore may be drilled along a direction of maximum formation stress, and the lateral tunnels may be drilled in a direction substantially orthogonal to the direction of maximum formation stress (or substantially orthogonal to the plane of maximum formation stress). For example, the direction of maximum formation stress may be measured while drilling (e.g., while drilling the substantially vertical wellbore), such as via acoustic or nuclear LWD measurements. These measurements may then be used to select the directions of the deviated wellbore and the lateral tunnels.

Referring to FIGS. 1 and 5, collectively, the lateral tunnels 46 may be fractured (106) sequentially or simultaneously. For example, a first lateral tunnel 46 may be drilled (104) and then fractured (106) using a FWD tool. A second lateral tunnel 46 may then be drilled (104) and fractured (106) using the FWD tool. This sequential process may continue until the wellbore system is completed, thus having a number of lateral tunnels (e.g., five, ten, fifteen, or more). Various FWD or fracturing-while-tripping (FWT) tools may be utilized, such as the FWD and FWT apparatus described in U.S. Patent Application Publication No. 2016/0053597, the entirety of which is hereby incorporated herein by reference. In another implementation, the lateral tunnels may first be drilled (104), and the lateral tunnels may then be fractured (106) using a single-stage or multi-stage fracturing operation in which multiple lateral tunnels are fractured in each stage.

The lateral tunnels 46 may be drilled (104) from “toe to heel” or from “heel to toe” along the deviated wellbore 44. For example, the deviated wellbore 44 may be drilled to its final length before drilling the lateral tunnels 46. After drilling the deviated wellbore 44 to its final length, the lateral tunnels 46 may be drilled toe to heal along the deviated wellbore 44 (i.e., beginning at the end of the deviated wellbore 44 having the greatest measured depth and proceeding back towards the substantially vertical wellbore 42 and, therefore, back towards the surface 25). The lateral tunnels 46 may also be drilled heel to toe, for example, by drilling the deviated wellbore 44 and steering the wellbore up or down to drill the lateral tunnel 46. The deviated wellbore 44 may then be extended and the wellbore steered to drill a subsequent lateral tunnel 46. This process may continue such that a number of lateral tunnels 46 are drilled along an incrementally extended deviated wellbore 44. As described, the lateral tunnels 46 may be fractured sequentially or simultaneously. One such implementation is described in more detail below with respect to FIGS. 15-18.

An implementation of the method (100) depicted in FIG. 5 is now described in further detail with respect to FIGS. 6-11. A substantially vertical wellbore 255 may be drilled via a drill string 250, and then cased. A deviated wellbore 265 extending from the substantially vertical wellbore 255 may then be drilled via the drill string 250 (or another drill string). While the substantially vertical wellbore 255 is depicted as being cased and cemented, the substantially vertical wellbore 255 may remain uncased while drilling the deviated wellbore 265. A first lateral tunnel 272 may then be drilled, as depicted in FIG. 7. The first lateral tunnel 272 may be isolated from the deviated wellbore 265, such as via expanding (e.g., inflating) packers 252 deployed on the drill string 250, as depicted in FIG. 8. High pressure fracturing fluid (or drilling fluid) may be pumped down through the drill string 250 into the isolated annular region 253 via fracturing ports 254 deployed on the drill string 250. This FWD operation may thus be employed to fracture a formation region 282 surrounding the first lateral tunnel, as depicted in FIG. 8.

After the first lateral tunnel 272 has been fractured, a second lateral tunnel 274 may be drilled from the deviated wellbore 265, as depicted in FIG. 9. As depicted in FIG. 10, a formation region 284 adjacent the second lateral tunnel 274 may then be fractured in the manner described above for the first lateral tunnel 272. As depicted in FIG. 11, a plurality of lateral tunnels 276 may be similarly drilled from the deviated wellbore 265 and fractured. The lateral tunnels 276 may extend substantially vertically in an upward or downward direction from the deviated wellbore 265. The disclosed implementations are not limited in this regard. For example, the deviated wellbore 265 may be drilled along (or near) the lower boundary of a formation of interest (e.g., as depicted in FIG. 1) with lateral tunnels 276 extending upward into the formation. However, the deviated wellbore 265 may be drilled along (or near) the upper boundary of a formation of interest, with lateral tunnels 276 extending downward into the formation. In still another implementation, the deviated wellbore 265 may be drilled near the center of the formation of interest, with lateral tunnels 276 extending upward and downward (e.g., as depicted in FIG. 11). In the context of the present disclosure, an upward-pointing lateral tunnel 276 may be defined as having a wellbore inclination of greater than about 135 degrees (e.g., greater than about 150 degrees, or perhaps greater than about 165 degrees), while a downward pointing lateral tunnel 276 may be defined as having a wellbore inclination of less than about 45 degrees (e.g., less than about 30 degrees, or perhaps less than about 15 degrees). However, a single quadrant wellbore inclination value may be used (which ranges from zero to 90 degrees, with zero degrees representing true vertical and 90 degrees representing true horizontal), in which case the lateral tunnels 276 (whether pointing upward or downward) have a wellbore inclination less than about 45 degrees (e.g., less than about 30 degrees, or perhaps less than about 15 degrees).

Another implementation of the method (100) shown in FIG. 5 is now described in further detail with respect to FIGS. 12-14. In this implementation, lateral tunnels may be fractured without the entry of a fracturing tool into the lateral tunnels. FIG. 12 depicts a wellbore system having an uncased (“open-hole”), deviated wellbore 305 extending from a cemented, cased, substantially vertical wellbore 302. A plurality of open-hole lateral tunnels 308 extend upward from the deviated wellbore 305. A fracturing tool 310 (e.g., a completion string) is shown deployed in the deviated wellbore 305. In such implementations, the fracturing tool 310 may employ a plurality of fracturing sleeves 312 deployed adjacent to individual lateral tunnels 308, as well as open-hole packers 314 deployed between adjacent ones of the lateral tunnels 308. The packers 314 may be expanded (as depicted) to fluidly isolate the individual lateral tunnels 308 from one another. The lateral tunnels 308 may be stimulated (and thereby fractured) by opening and closing ports in one or more of the fracturing sleeves 312 and pumping high-pressure fracturing fluid from the surface into the adjacent lateral tunnels 308. In this manner, a multi-stage fracturing operation may be utilized, in which the lateral tunnels 308 are fractured one by one, in pairs, in triplets, or in other combinations. In implementations in which the wellbore system employs relatively few lateral tunnels 308, a single-stage fracturing operation may also be utilized. FIGS. 13 and 14 depict implementations in which both upward and/or downward pointing lateral tunnels 308 are formed and utilized to fracture or otherwise stimulate the surrounding formation.

It will be understood that the decision regarding whether to fracture adjacent lateral tunnels sequentially or simultaneously (and how many lateral tunnels may be fractured simultaneously) may be based on numerous operational factors. For example, the decision may depend upon the existing rig or derrick height. Larger rigs may generally accommodate a hydraulic fracturing tool including a large number of fracture ports, and may therefore be utilized for simultaneous hydraulic fracturing, while a smaller rig may not. The decision may also depend upon the pump pressure utilized to propagate the fractures, and the intended depth of such fractures. For some formations or formation types (e.g., those utilizing higher pressures), it may be propitious to fracture the zones sequentially. Simultaneous hydraulic fracturing of multiple zones may permit a faster fracturing operation (assuming adequate rigging and pumping capabilities are in place, and assuming suitable formation fracturing can be achieved).

Another implementation of the method (100) of FIG. 5 is depicted in FIGS. 15-18. A substantially vertical wellbore 352 is drilled into a formation of interest. A short deviated wellbore 355 is sidetracked from the substantially vertical wellbore 352 and then steered to form a first lateral tunnel 362, as shown in FIG. 15. After the first lateral tunnel 362 is drilled, the deviated wellbore 355 is extended and a second lateral tunnel 364 is drilled, as shown in FIG. 16. The deviated wellbore 355 may then be further extended and a third lateral tunnel 366 may be drilled, and then still further extended and a fourth lateral tunnel 368 may be drilled, as shown in FIG. 17. The operation may continue to form a number of downward pointing and/or upward pointing lateral tunnels. For example, FIG. 18 depicts seven downward pointing lateral tunnels 360).

With further reference to FIGS. 15-18, the lateral tunnels 360 may be fractured sequentially or simultaneously as described above. For example, the lateral tunnels 360 may be fractured sequentially using an FWD tool as described above with respect to FIGS. 6-11. However, the lateral tunnels may be fractured using a multi-stage fracturing operation in which the lateral tunnels may be fractured one by one, in pairs, in triplets, or in other combinations, as described above with respect to FIGS. 12-14.

FIG. 19 is a plan view of an example multilateral wellbore system 350 according to one or more aspects of the present disclosure. The system 350 includes a substantially vertical wellbore 352 (shown as a solid circle), and a plurality of deviated wellbores 354 (i.e., deviated or substantially horizontal pilot wells). Each deviated wellbore 354 includes upward and/or downward extending lateral tunnels 356 (shown as open circles). The wellbore system 350 may be drilled and fractured using the methodology described above with respect to FIGS. 5-18. For example, deviated wellbore 354A may be drilled along with its corresponding lateral tunnels 356A. The lateral tunnels 356A may be hydraulically fractured back to junction 358 using the above-described procedure, such as described above with respect to FIGS. 6-11 or FIGS. 12-14. The deviated wellbore 354A may then be temporarily sealed, such as via a packer or a cement or gel plug. Deviated wellbores 354B and 354C and their corresponding lateral tunnels 356B and 356C may then be drilled and hydraulically fractured using a similar procedure. The other depicted deviated wellbores 354 in the system 350 may then be similarly drilled and their lateral tunnels 356 fractured.

FIG. 20 depicts another implementation of a wellbore system 370 including a plurality of fractured lateral tunnels according to one or more aspects of the present disclosure. Multiple deviated wellbores 374 or other deviated bores may be drilled outward from a substantially vertical wellbore 372 and steered laterally (e.g., downward or upward) to form a lateral tunnel 376. The wellbore system 370 may be formed by first drilling the substantially vertical wellbore 372. Each deviated wellbore 374 may then be drilled (e.g., sidetracked) from the substantially vertical wellbore 372 and steered downward to form the lateral tunnel 376. Each lateral tunnel 376 may be fractured when drilling of that lateral tunnel 376 is complete, such as using the FWD methodology described above. The wellbore system 370 may include one or more of the deviated wellbores 374, and each deviated wellbore 374 may include one or more lateral tunnels 376 that may be fractured.

FIG. 21 is a flow-chart diagram of at least a portion of an example implementation of a method (110) according to one or more aspects of the present disclosure. The method (110) may be utilized for forming a wellbore or a wellbore system through a subterranean formation, and utilizing such wellbore or wellbore system for performing stimulation operations of the subterranean formation, according to one or more aspects of the present disclosure. The method (110) includes drilling (112) a wellbore comprising a deviated wellbore portion, forming (114) a plurality of lateral tunnels extending from the deviated wellbore portion, installing (116) a completion string in the deviated wellbore, and then stimulating (118) the lateral tunnels.

Various methodologies for creating a wellbore or wellbore system are known to those skilled in the art, some of which are disclosed herein. Similarly as described above, a wellbore or a wellbore system within the scope of the present disclosure, including the substantially vertical and deviated wellbores or wellbore portions, may be formed in several steps or in a single step prior to or simultaneously with forming the lateral tunnels. The steps may include drilling a substantially vertical wellbore, casing and cementing the substantially vertical wellbore, drilling, casing and cementing a curvature section of the wellbore, drilling a deviated wellbore portion of the wellbore, forming lateral tunnels, and running and installing a completion string into the deviated wellbore portion. The number of steps and the order of such steps may be dictated by pressure limitations, formation stability, economics and other considerations. When utilizing multiple steps, each step may comprise drilling a portion of the wellbore, followed by running a casing segment in the formed portion, and then performing cementing operations. Steering the wellbore to horizontal direction can be achieved, for example, by using whipstocks that may be installed in a previously drilled, substantially vertical wellbore, or by utilizing a steerable drilling system that can facilitate forming the substantially vertical wellbore and at least a portion of the deviated wellbore portion of the wellbore in a single run without having to install additional wellbore equipment.

The length of the lateral tunnels may vary, such as between about 2 meters and about 200 meters. The lateral tunnels may be drilled using the same drilling tool that is used to drill the deviated wellbore, or the lateral tunnels may be formed using a different tool. For example, the drilling tool may comprise a drill string terminating with a bottom hole assembly (BHA) comprising a downhole motor connected with a drill bit. At least a portion of the drill string at the end of the drill string may comprise a diameter (e.g., narrowed diameter) that may permit an optimal rate of deviation of the lateral tunnel from the deviated wellbore, calculated as a change in degrees of deviation from the deviated wellbore divided by the change in length of the lateral tunnel. In an example implementation, the BHA may comprise a downhole motor installed on a 30- to 60-meter section of a 3.8 centimeter (cm) drill string/tubing installed at an end of a 6.4 cm drill string. The lateral tunnels may also be drilled using a coiled tubing drilling system comprising a drill bit, a mud motor, and a rotary steerable tool capable of achieving a high-degree dogleg, among other example implementations also within the scope of the present disclosure. The coiled tubing drilling system may be as described in U.S. Pat. No. 8,408,333, the entirety of which is hereby incorporated herein by reference. However, the lateral tunnels may be formed by other means, such as via hydraulic jetting, laser cutting or perforating, and electrical current rock disintegration, among other technologies that may be utilized to form passages through a subterranean rock formation.

The lateral tunnels may be formed after the entire deviated wellbore is formed, or the lateral tunnels may instead be formed after a portion of the deviated wellbore is formed, with a subsequent portion of the deviated wellbore being formed thereafter. However, the lateral tunnels may be formed at the same time the deviated wellbore is formed. For example, as the deviated wellbore is formed, each newly formed section of the deviated wellbore may be completed with casing and/or other completion systems (such as comprising sliding sleeves) prior to formation of a subsequent lateral tunnel. The casing may or may not be cemented.

FIGS. 22-24 are schematic sectional views of a portion of an example implementation of a downhole tool disposed within a deviated wellbore and operable to from lateral tunnels extending from the deviated wellbore, according to one or more aspects of the present disclosure. FIG. 22 shows a portion of a deviated wellbore 402 comprising a casing 404 (which may be secured by cement 405 or installed open-hole) extending through a subterranean formation 406. A drill string 408 extending through the deviated wellbore 402 comprises a deflecting tool 410 operable to deflect or otherwise direct a drilling, cutting, or other boring device toward a sidewall of the deviated wellbore 402 to form a lateral tunnel. The deflecting tool 410 may be rotatably oriented with respect to the deviated wellbore 402, as indicated by arrow 412, to rotatably align or orient an outlet port 414 of the deflecting tool 410 in an intended direction (e.g., a substantially vertical direction). As shown in FIG. 23, after the deflecting tool 410 is positioned at an intended longitudinal (e.g., axial) location within the deviated wellbore 402 and at an intended rotational orientation, a drilling tool 416 (e.g., a flexible casing drilling string) terminating with a drilling, milling, cutting, or other bit 417 may be deployed through the drill string 408, such as via a micro-coil or coiled tubing, to form a hole 418 through the casing 404. When the hole 418 is formed, the drilling tool 416 may be retracted from the deflecting tool 410 to the surface and a hydraulic jetting tool 420 (i.e., radial jet cutting tool) terminating with a nozzle 421 may be deployed downhole through the drill string 408, such as via a micro-coil or coiled tubing, to form a lateral tunnel 422 via pressurized streams 424 of water or another fluid. However, instead of utilizing both the drilling tool 416 and the jetting tool 420, a combinatory drilling tool (not shown) may be utilized to form both the casing hole 418 and the lateral tunnel 422, such as to minimize or reduce the number of lifting/tripping operations. Although the deflecting tool 410 is shown coupled along the drill string 408, the deflecting tool 410 may be deployed downhole as part of another tool string or otherwise separately from a drill string, such as via coiled tubing, and utilized in conjunction with the drilling tool 416 and the jetting tool 420 to form the lateral tunnels.

After the lateral tunnel 422 is formed, the deflecting tool 410 may be reoriented to form another lateral tunnel 422 or moved longitudinally along the deviated wellbore 402 to a selected location (e.g., at another formation zone). The process may be repeated until the intended number of lateral tunnels 422 are formed along the entire deviated wellbore 402 or into several formation zones. Stimulation (e.g., fracturing) operations may be performed after the lateral tunnels 422 are formed. However, fracture or other stimulation treatment operations may performed in one or more of the formation zones along the deviated wellbore 402 before forming lateral tunnels 422 in one or more subsequent formation zones.

It is to be understood that other downhole tools may be utilized to form the lateral tunnels within the scope of the present disclosure. FIG. 25 is a schematic sectional view of a portion of an example implementation of a laser cutting tool 430 disposed within a deviated wellbore 402 and operable to form lateral tunnels 422 extending from the deviated wellbore 402, according to one or more aspects of the present disclosure. The laser cutting tool 430 may be conveyed longitudinally along the deviated wellbore 402 (e.g., via coiled tubing 432). After an intended longitudinal position is reached, a portion of the laser cutting tool 430 comprising a laser emitting port 434 (e.g., optical opening) may be rotated with respect to the deviated wellbore 402, as indicated by arrow 436, to rotatably align or orient the laser emitting port 434 in an intended direction (e.g., a substantially vertical direction). After the intended longitudinal position and rotational orientation are established, the laser cutting tool 430 may be operated to emit a laser beam 438 to form the lateral tunnel 422. After the lateral tunnel 422 is formed, the laser cutting tool 430 may be reoriented to form another lateral tunnel 422, or moved longitudinally along the deviated wellbore 402 to a subsequent selected location (e.g., at another formation zone), and the process is repeated until the intended number of lateral tunnels 422 are formed along the entire deviated wellbore 402 or into several formation zones.

A deviated wellbore within the scope of the present disclosure may be completed with a casing string (or another completion string), installed before, after, and/or at the same time lateral tunnels are formed. FIGS. 26-28 are schematic sectional views of example implementations of wellbore systems 500, 510, 520, each comprising a deviated wellbore 504 completed with a corresponding casing string 508, 518, 528 according to one or more aspects of the present disclosure. Each wellbore system 500, 510, 520 further comprises a substantially vertical wellbore 502 and a plurality of lateral tunnels 506 extending from the deviated wellbore 504. The bores 502, 504 and tunnels 506 may be formed via one or more devices and/or methods described herein. Some of the lateral tunnels 506 may extend in an upward direction and some of the lateral tunnels 506 extend in a downward direction. As further shown, some of the lateral tunnels 506 may extend into a first formation zone 512, some of the lateral tunnels 506 may extend into a second formation zone 514, and some of the lateral tunnels 506 may extend into a third formation zone 516.

During casing installation operations, isolating material or elements may be provided within or along an annular space extending between each casing string 508, 518, 528 and a sidewall of the deviated wellbore 504, whereby the isolating material or elements may fluidly isolate the lateral tunnels 506 and, thus, the formation zones 512-516 from each other. The casing strings 508, 518 may be held in position and sealed against a sidewall of the deviated wellbore 504 by cement, such as cement 405 shown in FIGS. 22-25. The casing string 508 may be installed before the lateral tunnels 506 are formed and the casing string 518 may be installed after the lateral tunnels 506 are formed.

A casing string (or another completion string) within the scope of the present disclosure may also or instead be held within a deviated wellbore via a plurality of isolating elements comprising open-hole packers, which along with the casing string may be installed after or at the same time the lateral tunnels are formed. As shown in FIG. 28, the casing string 528 may be held within the deviated wellbore 504 via a plurality of isolating elements comprising open-hole packers 522. The casing string 528 may include a plurality of blank pipes 524 installed along the deviated wellbore 504, which may then be perforated by a perforating tool (not shown) at locations adjacent the lateral tunnels 506, such as may permit treatment fluid (e.g., fracturing fluid) to enter selected lateral tunnels 506 for treating corresponding formation zones 512, 514, 516. Following treatment, a plug (not shown) may be installed uphole from the treated formation zone 512, 514, 516 to isolate the treated formation zone 512, 514, 516 from a formation zone 512, 514, 516 selected for subsequent treatment. However, as shown in FIGS. 12-14, instead of perforating a casing string to form a fluid passage between the casing string and the annular space, a casing string within the scope of the present disclosure may include a plurality of selectively operable fracturing sleeves 312 having ports through which the fracturing fluid may exit the casing string 310 and flow into selected one or more of the lateral tunnels 308.

Referring again to FIGS. 26-28, one or more of the lateral tunnels 506 may also be completed with liners, casings, or other completion strings (not shown). For example, blank pipes and/or flexible metal tubing may be installed within the lateral tunnels 506, such as to control location and/or propagation of fractures along the lateral tunnels 506. The liners may be cemented in place or used open-hole.

A deviated wellbore within the scope of the present disclosure may contain two or more completion systems (i.e., completion strings). One of the completion systems may be installed before or during formation of a plurality of lateral tunnels and the other completion system may be installed after formation of the plurality of lateral tunnels. FIGS. 29 and 30 are schematic sectional views of example implementations of wellbore systems 530, 540, each comprising a deviated wellbore 504 completed with two casing string strings 532, 534 and 542, 544, respectively. The wellbore systems 530, 540 may comprise one or more similar features of the wellbore systems 500, 510, 520 shown in FIGS. 26-28, including where indicated by like reference numbers.

FIG. 29 shows the wellbore system 530 comprising an outer casing 532 (e.g., a liner) lining the substantially horizontal well 504, which may be maintained in position via cement or open-hole packers (neither shown) or installed open-hole. After the outer casing 532 is installed and the lateral tunnels 506 are formed, an inner casing string 534 may be installed within the outer casing string 532. The lateral tunnels 506 may then be stimulated 116 (e.g., fractured) using a multi-stage stimulation operations similar to that described above with respect to FIGS. 12-14. Performing the multi-stage fracturing operation may comprise establishing a single stage fluid accesses into a selected formation zone 512, 514, 516 with one or more lateral tunnels 506, isolating the selected formation zone 512, 516, 518 at the end of the fracturing stage, and establishing fluid access to another formation zone 512, 516, 518 comprising one or more corresponding lateral tunnels 506. For example, the inner casing string 534 may include a plurality of fracturing sleeves 536 having ports operable for selectively permitting stimulation fluid (e.g., fracturing fluid) to exit the inner casing string 534 and flow into selected one or more lateral tunnels 506 and, thus, selected one or more formation zones 512, 514, 516 during multi-stage fracturing treatment.

FIG. 30 shows the wellbore system 540 comprising an outer casing 542 lining the substantially horizontal well 504, which may be maintained in position via cement or open-hole packers (neither shown) or installed open-hole. After the outer casing 542 is installed and the lateral tunnels 506 are formed, an inner casing string 544 may be installed within the outer casing string 542. The inner casing string 544 may include a plurality of blank pipes 546 installed along the deviated wellbore 504, which may then be selectively perforated by a perforating tool (not shown) at locations adjacent the lateral tunnels 506, such as may permit treatment fluid (e.g., fracturing fluid) to enter selected one or more lateral tunnels 506 for treating selected one or more formation zones 512, 514, 516. Following treatment, a plug (not shown) may be installed uphole from the treated formation zone 512, 514, 516 to isolate the treated formation zone 512, 514, 516 from a formation zone 512, 514, 516 selected for subsequent treatment.

Casing strings (or other completion systems) comprising fracturing sleeves, such as casing string 310 shown in FIGS. 12-14 and casing string 534 shown in FIG. 29, may be utilized to sequentially stimulate selected lateral tunnels by sequentially opening and closing selected fracturing sleeves. The fracturing sleeves may be activated by drop balls and/or downhole shifting tools (not shown) conveyed via coiled tubing, a wireline, a slickline, and a hydraulic line, among other examples. The lateral tunnels may be stimulated sequentially from toe to heel by opening corresponding fracturing sleeves, setting a wellbore plug (not shown) below the formation zone(s) selected for stimulation (e.g., fracturing) to isolate such formation zone(s) from the previously stimulated zone(s) before pumping stimulation (e.g., fracturing) fluid into the substantially horizontal well.

Casing strings (or other completion systems) comprising a continuous pipe or a plurality of blank pipes, such as the casing string 518 shown in FIG. 27, the casing string 528 shown in FIG. 28, and the casing string 544 shown in FIG. 30, may be utilized to sequentially stimulate selected lateral tunnels by performing plugging and perforating (i.e., plug and perf) operations at selected longitudinal positions along the casing strings. During such plugging and perforating operations, selected lateral tunnels may be stimulated sequentially from toe to heel by first perforating the casing string adjacent the selected lateral tunnels extending into corresponding formation zones(s). A treatment (e.g., fracturing) fluid may then be pumped into the casing sting to stimulate the selected lateral tunnels and the corresponding formation zones(s). Thereafter, a wellbore plug (not shown) may be set above the perforated portion of the casing string to isolate the treated lateral tunnels and formation zone(s) from lateral tunnels and formation zone(s) selected for subsequent treatment. The fracturing fluid may then be again pumped into the casing string to stimulate the lateral tunnels and the corresponding formation zone(s). Such process may be repeated until all the intended formation zones are stimulated.

The rate of the fracturing fluid or another treatment fluid flowing into each lateral tunnel and/or formation zone may be controlled, such as by applying a limited entry process. Such flow rate control may be achieved by controlling the size of fluid passages connecting the deviated wellbore with the lateral tunnels. The fluid passages may include fluid passages (e.g., openings) in the fracturing sleeves and the perforated holes formed through the casing string. The size of the perforated holes may be controlled via selection of perforation charges of the perforating tools. The perforation charges may be selected based on the intended hole diameter and intended quantity of holes. The fluid passages may also include the holes in the casing string formed by the casing drilling tool 416 or by the laser cutting tool 430. The rate of the fracturing fluid or another treatment fluid flowing into each zone and/or lateral tunnel may be controlled via selection of the drilling bit 417 of the casing drilling tool 416 and via selection of the laser tool 430.

Although each deviated wellbore described herein is shown extending horizontally and each lateral tunnel described herein is shown extending vertically, it is to be understood that the terms vertical and horizontal (or substantially vertical and substantially horizontal) are not intended to mean exactly along the true vertical or exactly along the true horizontal. Rather, these terms are intended to refer to bores and tunnels extending along angles within a range of values with respect to the true vertical and the true horizontal.

FIG. 31 is a schematic sectional view of at least a portion of an example wellbore system 550 comprising a deviated wellbore 552 and a plurality of lateral tunnels 554 extending through a subterranean formation, according to one or more aspects of the present disclosure. It is to be understood that the lateral tunnels 554 may extend at angles 556, which may deviate between about zero degrees and about 45 degrees from the true vertical 558. In other words, the lateral tunnels 554 extending in the direction of gravity (i.e., downward) from the deviated wellbore 552 may deviate between about zero degrees and about 45 degrees from the direction of gravity. However, the lateral tunnels 554 extending opposite the direction of gravity (i.e., upward) from the deviated wellbore 552 may deviate between about 135 degrees and about 180 degrees from the direction of gravity. The angles 556 at which the lateral tunnels 554 extend from the deviated wellbore 552 with respect to the true vertical 558 may be formed in any direction (i.e., 360 degrees) around the true vertical 558. For example, assuming the wellbore system 550 is formed in a three-dimensional space X-Y-Z, if the deviated wellbore 552 extends along (i.e., is aligned with) an X-Y plane, the lateral tunnels 554 may extend along the X-Y plane and/or along a Y-Z plane. Similarly, the deviated wellbore 552 may extend at an angle 560, which may deviate between about −45 degrees and about 45 degrees from the true horizontal 562 (between about 45 degrees and about 135 degrees with respect to the true vertical 558).

Subterranean formations containing the wellbore systems described herein are confined and under stress. FIG. 32 illustrates a three dimensional element of subterranean formation 570 having X-Y-Z coordinates and being subjected to local stresses. The element of subterranean formation 570 is also shown with a portion of a lateral tunnel 580 extending therethrough. The stresses imparted to the element of subterranean formation 570 may be divided into three principal stresses, namely, a vertical stress 572, a minimum horizontal stress 574, and maximum horizontal stress 576. These stresses 572, 574, 576 are normally compressive, anisotropic, and nonhomogeneous, which means that the stresses on the formation 570 are not equal and vary in magnitude on the basis of direction, which controls pressure operable to form and propagate a fracture, the shape and vertical extent of the fracture, the direction of the fracture, and the stresses trying to crush and/or embed a propping agent during production. A hydraulic fracture will propagate along a direction of maximum horizontal formation stress 576 or along a plane 578 (or another parallel plane) of maximum horizontal formation stress 576 (along a plane 578 perpendicular to the minimum horizontal stress 574). The direction of maximum formation stress 576 may be measured while drilling or otherwise forming a subterranean bore, for example, via an acoustic or nuclear logging while drilling tools. The resulting measurements may then be used to select directions of the deviated wellbore and the lateral tunnels for optimal productivity.

Accordingly, as the hydraulic fractures propagate along the plane 578 of maximum horizontal formation stress 576, lateral tunnels within the scope of the present disclosure may be formed extending along (i.e., in alignment with, in direction of) a plane comprising the maximum horizontal formation stress. Such orientation of the lateral tunnel may result in a hydraulic fracture originating at the lateral tunnel propagating longitudinally along the lateral tunnel similarly to the fracture 202 propagating longitudinally along the vertical wellbore 210 shown in FIG. 3. As shown in FIG. 32, because a hydraulically induced fracture may propagate along the plane of maximum horizontal stress 576, at least a portion of the lateral tunnel 580 may be formed at an angle 582 with respect to the true vertical 584 such that the lateral tunnel 580 extends along (i.e., is aligned with, extends in a direction 585 along) the plane 578 (along the X-Y plane) and not such that the lateral tunnel 580 extends through, across, or diagonally to the plane 578 (along the Y-Z plane). Such orientation 585 of the lateral tunnel 580 may result in a hydraulic fracture propagating longitudinally along the lateral tunnel 580 (not diagonally across the lateral tunnel 580), facilitating longitudinal and, thus, optimal fluid connection between the lateral tunnel 580 and the fracture.

Although the lateral tunnels (e.g., lateral tunnels 506, 554, 580) within the scope of the present disclosure are described herein and shown in one or more of FIGS. 1-32 as being substantially vertical, deviating or otherwise extending at angles 556, 582 ranging between about zero degrees and about 45 degrees from true vertical 558, one or more of the lateral tunnels within the scope of the present disclosure may deviate or otherwise extend from true vertical 558 at angles 556, 582 that are greater than about 45 degrees, such as angles ranging between about zero degrees and about 90 degrees from true vertical 558 (i.e., angles ranging between about zero degrees and about 90 degrees from true horizontal 562). For example, one or more of the lateral tunnels within the scope of the present disclosure may deviate or otherwise extend at angles 556, 582 ranging between about 45 degrees and about 90 degrees from true vertical 558 (i.e., ranging between about zero degrees and about 45 degrees from true horizontal 562), resulting in lateral tunnels that may be substantially horizontal or closer to true horizontal 562 than to true vertical 558. Accordingly, one or more lateral tunnels within the scope of the present disclosure may also or instead be substantially horizontal. It is to be further understood that irrespective of the angle 556, 582 at which the lateral tunnels deviate from true vertical 558, one or more of the lateral tunnels within the scope of the present disclosure may extend along (i.e., be substantially aligned with) the plane 578 of maximum horizontal stress 576 of the subterranean formation, as described above.

The drilling and fracturing methods described herein may facilitate substantial production and efficiency gains in hydraulic fracturing operations. For example, use of the lateral tunnels within the scope of the present disclosure may substantially improve the efficiency of production, for example, by promoting production from a greater number of sedimentary layers in the formation. Forming these lateral tunnels from one or more deviated wellbores may also facilitate substantial production increase to be achieved. For example, based on the data compiled in FIG. 2, it may be estimated that each lateral tunnel is capable of producing about one-third to one-half that of a fully fractured deviated wellbore having no lateral tunnels. The production gains may therefore be substantial when multiple lateral tunnels are used. For example, drilling and fracturing ten lateral tunnels per deviated wellbore may result in a three to five fold increase in production volume. Moreover, the disclosed methods permit formation of well systems comprising a plurality of deviated wellbores each comprising a corresponding plurality of lateral tunnels resulting in production magnification.

Although a vertical drilling and fracturing methodology and certain advantages thereof have been described in detail, it should be understood that various changes, substitutions and alternations can be made herein without departing from the spirit and scope of the disclosure as defined by the appended claims.

In view of the entirety of the present disclosure, including the figures and the claims, a person having ordinary skill in the art will recognize that the present disclosure introduces a method comprising: drilling a wellbore comprising a deviated wellbore portion extending through a subterranean formation; forming a plurality of lateral tunnels extending from the deviated wellbore portion through the subterranean formation such that at least a portion of each of the plurality of lateral tunnels extends along a plane of maximum horizontal stress of the subterranean formation; and performing stimulation operations of the subterranean formation via the plurality of lateral tunnels.

At least a portion of each of the plurality of lateral tunnels may extend at an angle ranging between zero degrees and about 45 degrees with respect to true vertical.

At least a portion of each of the plurality of lateral tunnels may extend at an angle ranging between about 45 degrees and about 90 degrees with respect to true vertical.

Forming the plurality of lateral tunnels may be performed with a drilling tool comprising a rotating drill bit.

Forming the plurality of lateral tunnels may be performed with a hydraulic jetting tool.

Forming the plurality of lateral tunnels may be performed with a laser cutting tool.

The deviated wellbore portion may extend substantially horizontally.

The deviated wellbore portion may extend at an angle ranging between zero degrees and about 45 degrees with respect to true horizontal.

The method may comprise, before performing stimulation operations, completing the deviated wellbore portion with a casing string and isolation material between the casing string and a sidewall of the deviated wellbore portion, and the isolation material may fluidly isolate portions of annular space extending between the casing string and the sidewall of the deviated wellbore portion to fluidly isolate ones of the plurality of lateral tunnels from each other. Completing the deviated wellbore portion with a casing string may be performed before forming the plurality of lateral tunnels. The isolation material may comprise at least one of a plurality of packers and cement. The casing string may comprise fracturing sleeves.

Performing the stimulation operations of the subterranean formation may comprise pumping a fracturing fluid into the plurality of lateral tunnels to hydraulically fracture the subterranean formation.

The method may comprise: before forming the plurality of lateral tunnels, completing the deviated wellbore portion with a first casing string; after forming the plurality of lateral tunnels, installing a second casing string within the first casing string; expanding packers located between the first and second casing strings to fluidly isolate one or more of the plurality of lateral tunnels from each other; and forming a fluid passage extending through a wall of the second casing string to fluidly connect the second casing string with a selected one or more of the plurality of lateral tunnels, wherein performing stimulation operations of the subterranean formation may comprise stimulating the selected one or more of the plurality of lateral tunnels via the fluid passage. The method may comprise, before forming each of the plurality of lateral tunnels, drilling a corresponding hole through a wall of the first casing string. Forming the plurality of fluid passages may comprise at least one of: shifting a fracturing sleeve of the second casing string to an open position; and perforating the second casing string with a perforating tool. The fluid passage may be a first fluid passage, the selected one or more of the plurality of lateral tunnels may be a selected first one or more of the plurality of lateral tunnels, and performing stimulation operations may comprise: stimulating the selected first one or more of the plurality of lateral tunnels via the first fluid passage; forming a second fluid passage extending through the wall of the second casing string to fluidly connect the second casing string with a selected second one or more of the plurality of lateral tunnels; fluidly isolating the first fluid passage from the second fluid passage; and stimulating the selected second set of one or more of the plurality of lateral tunnels via the second fluid passage.

Performing stimulation operations may comprise performing multi-stage stimulation operations comprising: stimulating a first zone of the subterranean formation via a first set of one or more of the plurality of lateral tunnels; fluidly isolating the first set of one or more of the plurality of lateral tunnels from a second set of one or more of the plurality of lateral tunnels; and stimulating a second zone of the subterranean formation via the second set of one or more of the plurality of lateral tunnels.

The present disclosure also introduces a method comprising: drilling a wellbore comprising a deviated wellbore portion extending through a subterranean formation; forming a plurality of lateral tunnels extending from the deviated wellbore portion through the subterranean formation such that at least a portion of each of the plurality of lateral tunnels extends at an angle ranging between zero degrees and about 90 degrees with respect to true vertical; and performing stimulation operations of the subterranean formation via the plurality of lateral tunnels.

At least a portion of each of the plurality of lateral tunnels may be substantially aligned with a plane of maximum horizontal stress of the subterranean formation.

At least a portion of each of the plurality of lateral tunnels may extend at an angle ranging between about zero degrees and about 45 degrees with respect to the true vertical.

Forming the plurality of lateral tunnels may be performed with a drilling tool comprising a rotating drill bit.

Forming the plurality of lateral tunnels may be performed with a hydraulic jetting tool.

Forming the plurality of lateral tunnels may be performed with a laser cutting tool.

The deviated wellbore portion may extend substantially horizontally.

The deviated wellbore portion may extend at an angle ranging between zero degrees and about 45 degrees with respect to true horizontal.

The method may comprise, before performing stimulation operations, completing the deviated wellbore portion with a casing string and isolation material between the casing string and a sidewall of the deviated wellbore portion, and the isolation material may fluidly isolate portions of annular space extending between the casing string and the sidewall of the deviated wellbore portion to fluidly isolate ones of the plurality of lateral tunnels from each other. Completing the deviated wellbore portion with a casing string may be performed before forming the plurality of lateral tunnels. The isolation material may comprise at least one of a plurality of packers and cement. The casing string may comprise fracturing sleeves.

Performing the stimulation operations of the subterranean formation may comprise pumping a fracturing fluid into the plurality of lateral tunnels to hydraulically fracture the subterranean formation.

The method may comprise: before forming the plurality of lateral tunnels, completing the deviated wellbore portion with a first casing string; after forming the plurality of lateral tunnels, installing a second casing string within the first casing string; expanding packers located between the first and second casing strings to fluidly isolate one or more of the plurality of lateral tunnels from each other; and forming a fluid passage extending through a wall of the second casing string to fluidly connect the second casing string with a selected one or more of the plurality of lateral tunnels, wherein performing stimulation operations of the subterranean formation may comprise stimulating the selected one or more of the plurality of lateral tunnels via the fluid passage. The method may comprise, before forming each of the plurality of lateral tunnels, drilling a corresponding hole through a wall of the first casing string. Forming the plurality of fluid passages may comprise at least one of: shifting a fracturing sleeve of the second casing string to an open position; and perforating the second casing string with a perforating tool. The fluid passage may be a first fluid passage, the selected one or more of the plurality of lateral tunnels may be a selected first one or more of the plurality of lateral tunnels, and performing stimulation operations may comprise: stimulating the selected first one or more of the plurality of lateral tunnels via the first fluid passage; forming a second fluid passage extending through the wall of the second casing string to fluidly connect the second casing string with a selected second one or more of the plurality of lateral tunnels; fluidly isolating the first fluid passage from the second fluid passage; and stimulating the selected second set of one or more of the plurality of lateral tunnels via the second fluid passage.

Performing stimulation operations may comprise performing multi-stage stimulation operations comprising: stimulating a first zone of the subterranean formation via a first set of one or more of the plurality of lateral tunnels; fluidly isolating the first set of one or more of the plurality of lateral tunnels from a second set of one or more of the plurality of lateral tunnels; and stimulating a second zone of the subterranean formation via the second set of one or more of the plurality of lateral tunnels.

The present disclosure also introduces a method comprising: drilling a wellbore comprising a deviated wellbore portion extending through a subterranean formation; operating a hydraulic jetting tool to form a plurality of lateral tunnels extending from the deviated wellbore portion through the subterranean formation; and performing stimulation operations of the subterranean formation via the plurality of lateral tunnels.

At least a portion of each of the plurality of lateral tunnels may be substantially aligned with a plane of maximum horizontal stress of the subterranean formation.

At least a portion of each of the plurality of lateral tunnels may extend at an angle ranging between zero degrees and about 90 degrees with respect to true vertical.

At least a portion of each of the plurality of lateral tunnels may extend at an angle ranging between about zero degrees and about 45 degrees with respect to the true vertical.

The deviated wellbore portion may extend substantially horizontally.

The deviated wellbore portion may extend at an angle ranging between zero degrees and about 45 degrees with respect to true horizontal.

The method may comprise, before performing stimulation operations, completing the deviated wellbore portion with a casing string and isolation material between the casing string and a sidewall of the deviated wellbore portion, and the isolation material may fluidly isolate portions of annular space extending between the casing string and the sidewall of the deviated wellbore portion to fluidly isolate ones of the plurality of lateral tunnels from each other. Completing the deviated wellbore portion with a casing string may be performed before forming the plurality of lateral tunnels. The isolation material may comprise at least one of a plurality of packers and cement. The casing string may comprise fracturing sleeves.

Performing the stimulation operations of the subterranean formation may comprise pumping a fracturing fluid into the plurality of lateral tunnels to hydraulically fracture the subterranean formation.

The method may comprise: before forming the plurality of lateral tunnels, completing the deviated wellbore portion with a first casing string; after forming the plurality of lateral tunnels, installing a second casing string within the first casing string; expanding packers located between the first and second casing strings to fluidly isolate one or more of the plurality of lateral tunnels from each other; and forming a fluid passage extending through a wall of the second casing string to fluidly connect the second casing string with a selected one or more of the plurality of lateral tunnels, wherein performing stimulation operations of the subterranean formation may comprise stimulating the selected one or more of the plurality of lateral tunnels via the fluid passage. The method may comprise, before forming each of the plurality of lateral tunnels, drilling a corresponding hole through a wall of the first casing string. Forming the plurality of fluid passages may comprise at least one of: shifting a fracturing sleeve of the second casing string to an open position; and perforating the second casing string with a perforating tool. The fluid passage may be a first fluid passage, the selected one or more of the plurality of lateral tunnels may be a selected first one or more of the plurality of lateral tunnels, and performing stimulation operations may comprise: stimulating the selected first one or more of the plurality of lateral tunnels via the first fluid passage; forming a second fluid passage extending through the wall of the second casing string to fluidly connect the second casing string with a selected second one or more of the plurality of lateral tunnels; fluidly isolating the first fluid passage from the second fluid passage; and stimulating the selected second set of one or more of the plurality of lateral tunnels via the second fluid passage.

Performing stimulation operations may comprise performing multi-stage stimulation operations comprising: stimulating a first zone of the subterranean formation via a first set of one or more of the plurality of lateral tunnels; fluidly isolating the first set of one or more of the plurality of lateral tunnels from a second set of one or more of the plurality of lateral tunnels; and stimulating a second zone of the subterranean formation via the second set of one or more of the plurality of lateral tunnels.

The foregoing outlines features of several embodiments so that a person having ordinary skill in the art may better understand the aspects of the present disclosure. A person having ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same functions and/or achieving the same benefits of the embodiments introduced herein. A person having ordinary skill in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.

The Abstract at the end of this disclosure is provided to permit the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.

Claims

1. A method comprising: drilling a wellbore comprising a deviated wellbore portion extending through a subterranean formation;forming a plurality of lateral tunnels extending from the deviated wellbore portion through the subterranean formation such that at least a portion of each of the plurality of lateral tunnels extends along a plane of maximum horizontal stress of the subterranean formation; andperforming stimulation operations of the subterranean formation via the plurality of lateral tunnels.

2. The method of claim 1 wherein at least a portion of each of the plurality of lateral tunnels extends at an angle ranging between zero degrees and about 45 degrees with respect to true vertical.

3. The method of claim 1 wherein at least a portion of each of the plurality of lateral tunnels extends at an angle ranging between about 45 degrees and about 90 degrees with respect to true vertical.

4. The method of claim 1 wherein forming the plurality of lateral tunnels is performed with a drilling tool comprising a rotating drill bit.

5. The method of claim 1 wherein forming the plurality of lateral tunnels is performed with a hydraulic jetting tool.

6. The method of claim 1 wherein forming the plurality of lateral tunnels is performed with a laser cutting tool.

7. The method of claim 1 wherein the deviated wellbore portion extends substantially horizontally.

8. The method of claim 1 wherein the deviated wellbore portion extends at an angle ranging between zero degrees and about 45 degrees with respect to true horizontal.

9. The method of claim 1 further comprising, before performing stimulation operations, completing the deviated wellbore portion with a casing string and isolation material between the casing string and a sidewall of the deviated wellbore portion, wherein the isolation material fluidly isolates portions of annular space extending between the casing string and the sidewall of the deviated wellbore portion to fluidly isolate ones of the plurality of lateral tunnels from each other.

10. The method of claim 9 wherein completing the deviated wellbore portion with a casing string is performed before forming the plurality of lateral tunnels.

11. The method of claim 9 wherein the isolation material comprises at least one of a plurality of packers and cement.

12. The method of claim 9 wherein the casing string comprises fracturing sleeves.

13. The method of claim 1 wherein performing the stimulation operations of the subterranean formation comprises pumping a fracturing fluid into the plurality of lateral tunnels to hydraulically fracture the subterranean formation.

14. The method of claim 1 further comprising: before forming the plurality of lateral tunnels, completing the deviated wellbore portion with a first casing string;after forming the plurality of lateral tunnels, installing a second casing string within the first casing string;expanding packers located between the first and second casing strings to fluidly isolate one or more of the plurality of lateral tunnels from each other; andforming a fluid passage extending through a wall of the second casing string to fluidly connect the second casing string with a selected one or more of the plurality of lateral tunnels, wherein performing stimulation operations of the subterranean formation comprises stimulating the selected one or more of the plurality of lateral tunnels via the fluid passage.

15. The method of claim 14 further comprising, before forming each of the plurality of lateral tunnels, drilling a corresponding hole through a wall of the first casing string.

16. The method of claim 14 wherein forming the plurality of fluid passages comprises at least one of: shifting a fracturing sleeve of the second casing string to an open position; andperforating the second casing string with a perforating tool.

17. The method of claim 14 wherein: the fluid passage is a first fluid passage;the selected one or more of the plurality of lateral tunnels is a selected first one or more of the plurality of lateral tunnels; andperforming stimulation operations comprises: stimulating the selected first one or more of the plurality of lateral tunnels via the first fluid passage;forming a second fluid passage extending through the wall of the second casing string to fluidly connect the second casing string with a selected second one or more of the plurality of lateral tunnels;fluidly isolating the first fluid passage from the second fluid passage; andstimulating the selected second set of one or more of the plurality of lateral tunnels via the second fluid passage.

18. The method of claim 1 wherein performing stimulation operations comprises performing multi-stage stimulation operations comprising: stimulating a first zone of the subterranean formation via a first set of one or more of the plurality of lateral tunnels;fluidly isolating the first set of one or more of the plurality of lateral tunnels from a second set of one or more of the plurality of lateral tunnels; andstimulating a second zone of the subterranean formation via the second set of one or more of the plurality of lateral tunnels.

19. A method comprising: drilling a wellbore comprising a deviated wellbore portion extending through a subterranean formation;forming a plurality of lateral tunnels extending from the deviated wellbore portion through the subterranean formation such that at least a portion of each of the plurality of lateral tunnels extends at an angle ranging between zero degrees and about 90 degrees with respect to true vertical; andperforming stimulation operations of the subterranean formation via the plurality of lateral tunnels.

20. The method of claim 19 wherein at least a portion of each of the plurality of lateral tunnels is substantially aligned with a plane of maximum horizontal stress of the subterranean formation.

21. The method of claim 19 wherein at least a portion of each of the plurality of lateral tunnels extends at an angle ranging between about zero degrees and about 45 degrees with respect to the true vertical.

22. The method of claim 19 wherein forming the plurality of lateral tunnels is performed with a drilling tool comprising a rotating drill bit.

23. The method of claim 19 wherein forming the plurality of lateral tunnels is performed with a hydraulic jetting tool.

24. The method of claim 19 wherein forming the plurality of lateral tunnels is performed with a laser cutting tool.

25. The method of claim 19 wherein the deviated wellbore portion extends substantially horizontally.

26. The method of claim 19 wherein the deviated wellbore portion extends at an angle ranging between zero degrees and about 45 degrees with respect to true horizontal.

27. The method of claim 19 further comprising, before performing stimulation operations, completing the deviated wellbore portion with a casing string and isolation material between the casing string and a sidewall of the deviated wellbore portion, wherein the isolation material fluidly isolates portions of annular space extending between the casing string and the sidewall of the deviated wellbore portion to fluidly isolate ones of the plurality of lateral tunnels from each other.

28. The method of claim 27 wherein completing the deviated wellbore portion with a casing string is performed before forming the plurality of lateral tunnels.

29. The method of claim 27 wherein the isolation material comprises at least one of a plurality of packers and cement.

30. The method of claim 27 wherein the casing string comprises fracturing sleeves.

31. The method of claim 19 wherein performing the stimulation operations of the subterranean formation comprises pumping a fracturing fluid into the plurality of lateral tunnels to hydraulically fracture the subterranean formation.

32. The method of claim 19 further comprising: before forming the plurality of lateral tunnels, completing the deviated wellbore portion with a first casing string;after forming the plurality of lateral tunnels, installing a second casing string within the first casing string;expanding packers located between the first and second casing strings to fluidly isolate one or more of the plurality of lateral tunnels from each other; andforming a fluid passage extending through a wall of the second casing string to fluidly connect the second casing string with a selected one or more of the plurality of lateral tunnels, wherein performing stimulation operations of the subterranean formation comprises stimulating the selected one or more of the plurality of lateral tunnels via the fluid passage.

33. The method of claim 32 further comprising, before forming each of the plurality of lateral tunnels, drilling a corresponding hole through a wall of the first casing string.

34. The method of claim 32 wherein forming the plurality of fluid passages comprises at least one of: shifting a fracturing sleeve of the second casing string to an open position; andperforating the second casing string with a perforating tool.

35. The method of claim 32 wherein: the fluid passage is a first fluid passage;the selected one or more of the plurality of lateral tunnels is a selected first one or more of the plurality of lateral tunnels; andperforming stimulation operations comprises: stimulating the selected first one or more of the plurality of lateral tunnels via the first fluid passage;forming a second fluid passage extending through the wall of the second casing string to fluidly connect the second casing string with a selected second one or more of the plurality of lateral tunnels;fluidly isolating the first fluid passage from the second fluid passage; andstimulating the selected second set of one or more of the plurality of lateral tunnels via the second fluid passage.

36. The method of claim 19 wherein performing stimulation operations comprises performing multi-stage stimulation operations comprising: stimulating a first zone of the subterranean formation via a first set of one or more of the plurality of lateral tunnels;fluidly isolating the first set of one or more of the plurality of lateral tunnels from a second set of one or more of the plurality of lateral tunnels; andstimulating a second zone of the subterranean formation via the second set of one or more of the plurality of lateral tunnels.

37. A method comprising: drilling a wellbore comprising a deviated wellbore portion extending through a subterranean formation;operating a hydraulic jetting tool to form a plurality of lateral tunnels extending from the deviated wellbore portion through the subterranean formation; andperforming stimulation operations of the subterranean formation via the plurality of lateral tunnels.

38. The method of claim 37 wherein at least a portion of each of the plurality of lateral tunnels is substantially aligned with a plane of maximum horizontal stress of the subterranean formation.

39. The method of claim 37 wherein at least a portion of each of the plurality of lateral tunnels extends at an angle ranging between zero degrees and about 90 degrees with respect to true vertical.

40. The method of claim 39 wherein at least a portion of each of the plurality of lateral tunnels extends at an angle ranging between about zero degrees and about 45 degrees with respect to the true vertical.

41. The method of claim 37 wherein the deviated wellbore portion extends substantially horizontally.

42. The method of claim 37 wherein the deviated wellbore portion extends at an angle ranging between zero degrees and about 45 degrees with respect to true horizontal.

43. The method of claim 37 further comprising, before performing stimulation operations, completing the deviated wellbore portion with a casing string and isolation material between the casing string and a sidewall of the deviated wellbore portion, wherein the isolation material fluidly isolates portions of annular space extending between the casing string and the sidewall of the deviated wellbore portion to fluidly isolate ones of the plurality of lateral tunnels from each other.

44. The method of claim 43 wherein completing the deviated wellbore portion with a casing string is performed before forming the plurality of lateral tunnels.

45. The method of claim 43 wherein the isolation material comprises at least one of a plurality of packers and cement.

46. The method of claim 43 wherein the casing string comprises fracturing sleeves.

47. The method of claim 37 wherein performing the stimulation operations of the subterranean formation comprises pumping a fracturing fluid into the plurality of lateral tunnels to hydraulically fracture the subterranean formation.

48. The method of claim 37 further comprising: before forming the plurality of lateral tunnels, completing the deviated wellbore portion with a first casing string;after forming the plurality of lateral tunnels, installing a second casing string within the first casing string;expanding packers located between the first and second casing strings to fluidly isolate one or more of the plurality of lateral tunnels from each other; andforming a fluid passage extending through a wall of the second casing string to fluidly connect the second casing string with a selected one or more of the plurality of lateral tunnels, wherein performing stimulation operations of the subterranean formation comprises stimulating the selected one or more of the plurality of lateral tunnels via the fluid passage.

49. The method of claim 48 further comprising, before forming each of the plurality of lateral tunnels, drilling a corresponding hole through a wall of the first casing string.

50. The method of claim 48 wherein forming the plurality of fluid passages comprises at least one of: shifting a fracturing sleeve of the second casing string to an open position; andperforating the second casing string with a perforating tool.

51. The method of claim 48 wherein: the fluid passage is a first fluid passage;the selected one or more of the plurality of lateral tunnels is a selected first one or more of the plurality of lateral tunnels; andperforming stimulation operations comprises: stimulating the selected first one or more of the plurality of lateral tunnels via the first fluid passage;forming a second fluid passage extending through the wall of the second casing string to fluidly connect the second casing string with a selected second one or more of the plurality of lateral tunnels;fluidly isolating the first fluid passage from the second fluid passage; andstimulating the selected second set of one or more of the plurality of lateral tunnels via the second fluid passage.

52. The method of claim 37 wherein performing stimulation operations comprises performing multi-stage stimulation operations comprising: stimulating a first zone of the subterranean formation via a first set of one or more of the plurality of lateral tunnels;fluidly isolating the first set of one or more of the plurality of lateral tunnels from a second set of one or more of the plurality of lateral tunnels; andstimulating a second zone of the subterranean formation via the second set of one or more of the plurality of lateral tunnels.